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EX-31.2 - CERTIFICATION OF CFO - CLAYTON WILLIAMS ENERGY INC /DEmel9301031_2.htm
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EX-32.1 - CERTIFICATION OF CEO & CFO - CLAYTON WILLIAMS ENERGY INC /DEclaytonmel9301032_1.htm

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


FORM 10-Q

(Mark One)
   
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
 
 
OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
For the quarterly period ended September 30, 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

Not applicable
(Former name, former address and former fiscal year, if changed since last report)

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 Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
 
¨ Yes
 
¨ No
 

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

There were 12,153,536 shares of Common Stock, $.10 par value, of the registrant outstanding as of November 4, 2010.



 
 

 

CLAYTON WILLIAMS ENERGY, INC.
TABLE OF CONTENTS


PART I.  FINANCIAL INFORMATION
   
Page
       
   
       
     
 
and December 31, 2009                                                                                                
3
       
     
 
ended September 30, 2010 and 2009                                                                                                
5
       
     
 
ended September 30, 2010                                                                                                
6
       
     
 
ended September 30, 2010 and 2009                                                                                                
7
       
 
Notes to Consolidated Financial Statements                                                                                                    
8
       
   
 
Condition and Results of Operations                                                                                                
23
       
Quantitative and Qualitative Disclosures About Market Risks                                                                                                   
38
       
Controls and Procedures                                                                                                    
40
       
       
PART II.  OTHER INFORMATION
Risk Factors                                                                                                    
41
       
Exhibits                                                                                                    
41
       
 
Signatures                                                                                                    
42















 
2

 

PART I.  FINANCIAL INFORMATION

Item 1 -                 Financial Statements


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

ASSETS
 
   
September 30,
   
December 31,
 
   
2010
   
2009
 
   
(Unaudited)
       
CURRENT ASSETS
           
Cash and cash equivalents                                                                                     
  $ 22,004     $ 14,013  
Accounts receivable:
               
Oil and gas sales                                                                                
    28,766       28,721  
Joint interest and other, net                                                                                
    4,815       6,669  
Affiliates                                                                                
    690       624  
Inventory                                                                                     
    45,080       43,068  
Deferred income taxes                                                                                     
    168       1,362  
Fair value of derivatives                                                                                     
    14,239       -  
Assets held for sale                                                                                     
    7,411       7,411  
Prepaids and other                                                                                     
    2,724       1,729  
      125,897       103,597  
PROPERTY AND EQUIPMENT
               
Oil and gas properties, successful efforts method                                                                                     
    1,631,453       1,579,664  
Natural gas gathering and processing systems                                                                                     
    18,401       17,816  
Contract drilling equipment                                                                                     
    50,158       41,533  
Other                                                                                     
    20,196       16,550  
      1,720,208       1,655,563  
Less accumulated depreciation, depletion and amortization
    (1,008,119 )     (985,517 )
Property and equipment, net                                                                                
    712,089       670,046  
                 
OTHER ASSETS
               
Debt issue costs, net                                                                                     
    4,210       4,874  
Fair value of derivatives                                                                                     
    2,155       4,427  
Other                                                                                     
    1,836       1,660  
      8,201       10,961  
    $ 846,187     $ 784,604  



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

 
 
3

 

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


LIABILITIES AND STOCKHOLDERS’ EQUITY
 
   
September 30,
   
December 31,
 
   
2010
   
2009
 
   
(Unaudited)
       
CURRENT LIABILITIES
           
Accounts payable:
           
Trade                                                                                
  $ 48,389     $ 47,211  
Oil and gas sales                                                                                
    26,218       18,063  
Affiliates                                                                                
    1,015       1,097  
Fair value of derivatives                                                                                     
    -       5,907  
Accrued liabilities and other                                                                                     
    13,910       11,995  
      89,532       84,273  
NON-CURRENT LIABILITIES
               
Long-term debt                                                                                     
    385,000       395,000  
Deferred income taxes                                                                                     
    76,016       54,065  
Other                                                                                     
    41,103       38,991  
      502,119       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 – 12,145,536 shares in 2010
               
 and 2009                                                                                     
    1,215       1,215  
Additional paid-in capital                                                                                     
    152,051       152,051  
Retained earnings                                                                                     
    101,270       59,009  
      254,536       212,275  
    $ 846,187     $ 784,604  


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

 
 
4

 

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

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2010
   
2009
   
2010
   
2009
 
REVENUES
                       
Oil and gas sales                                                      
  $ 81,978     $ 59,436     $ 237,938     $ 167,438  
Natural gas services                                                      
    397       1,639       1,352       4,578  
Drilling rig services                                                      
    -       -       -       6,681  
Gain on sales of assets                                                      
    2,857       1,351       3,256       2,014  
Total revenues                                                
    85,232       62,426       242,546       180,711  
                                 
COSTS AND EXPENSES
                               
Production                                                      
    20,518       19,258       62,012       56,617  
Exploration:
                               
Abandonments and impairments
    364       24,149       6,133       41,066  
Seismic and other                                                
    1,361       898       3,995       6,556  
Natural gas services                                                      
    297       1,344       951       3,966  
Drilling rig services                                                      
    123       904       1,204       10,901  
Depreciation, depletion and amortization
    25,223       30,053       76,272       92,704  
Impairment of property and equipment
    794       -       11,908       32,068  
Accretion of abandonment obligations
    659       824       1,953       2,290  
General and administrative                                                      
    8,730       4,012       22,786       14,796  
Loss on sales of assets and impairment
                               
of inventory                                                   
    80       555       1,523       4,400  
Total costs and expenses                                                
    58,149       81,997       188,737       265,364  
                                 
Operating income (loss)                                                
    27,083       (19,571 )     53,809       (84,653 )
                                 
OTHER INCOME (EXPENSE)
                               
Interest expense                                                      
    (6,040 )     (6,526 )     (18,393 )     (17,700 )
Gain (loss) on derivatives                                                      
    (3,995 )     4,723       27,289       (14,537 )
Other                                                      
    972       (76 )     2,816       1,651  
Total other income (expense)                                                
    (9,063 )     (1,879 )     11,712       (30,586 )
                                 
Income (loss) before income taxes                                                           
    18,020       (21,450 )     65,521       (115,239 )
Income tax (expense) benefit                                                           
    (6,397 )     7,850       (23,260 )     42,171  
NET INCOME (LOSS)                                                           
    11,623       (13,600 )     42,261       (73,068 )
Less income attributable to
                               
noncontrolling interest, net of tax
    -       -       -       (1,455 )
                                 
NET INCOME (LOSS) attributable to Clayton
                               
Williams Energy, Inc.                                                      
  $ 11,623     $ (13,600 )   $ 42,261     $ (74,523 )
                                 
Net income (loss) per common share attributable to
                               
  Clayton Williams Energy, Inc. stockholders:
                               
Basic                                                      
  $ .96     $ (1.12 )   $ 3.48     $ (6.14 )
Diluted                                                      
  $ .96     $ (1.12 )   $ 3.48     $ (6.14 )
                                 
Weighted average common shares outstanding:
                               
Basic                                                      
    12,146       12,144       12,146       12,136  
Diluted                                                      
    12,146       12,144       12,146       12,136  

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

 
 
5

 


CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(Unaudited)
(In thousands)



   
Common Stock
   
Additional
       
   
No. of
   
Par
   
Paid-In
   
Retained
 
   
Shares
   
Value
   
Capital
   
Earnings
 
BALANCE,
                       
December 31, 2009
    12,146     $ 1,215     $ 152,051     $ 59,009  
Net income
    -       -       -       42,261  
BALANCE,
                               
September 30, 2010
    12,146     $ 1,215     $ 152,051     $ 101,270  





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

 
 
6

 

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


   
Nine Months Ended
 
   
September 30,
 
   
2010
   
2009
 
CASH FLOWS FROM OPERATING ACTIVITIES
           
Net income (loss)                                                                                       
  $ 42,261     $ (73,068 )
Adjustments to reconcile net income (loss) to cash
               
provided by operating activities:
               
Depreciation, depletion and amortization                                                                                 
    76,272       92,704  
Impairment of property and equipment                                                                                 
    11,908       32,068  
Exploration costs                                                                                 
    6,133       41,066  
(Gain) loss on sales of assets and impairment of inventory, net
    (1,733 )     2,386  
Deferred income tax expense (benefit)                                                                                 
    23,260       (42,171 )
Non-cash employee compensation                                                                                 
    8,066       953  
Unrealized (gain) loss on derivatives                                                                                 
    (17,874 )     8,314  
Amortization of debt issue costs                                                                                 
    1,174       1,163  
Accretion of abandonment obligations                                                                                 
    1,953       2,290  
                 
Changes in operating working capital:
               
Accounts receivable                                                                                 
    1,743       12,777  
Accounts payable                                                                                 
    5,247       (26,075 )
Other                                                                                 
    (4,242 )     15,800  
Net cash provided by operating activities                                                                           
    154,168       68,207  
                 
CASH FLOWS FROM INVESTING ACTIVITIES
               
Additions to property and equipment                                                                                       
    (208,641 )     (99,808 )
Proceeds from sales of assets                                                                                       
    75,670       2,109  
Change in equipment inventory                                                                                       
    (3,075 )     (25,868 )
Other                                                                                       
    (131 )     (109 )
Net cash used in investing activities                                                                           
    (136,177 )     (123,676 )
                 
CASH FLOWS FROM FINANCING ACTIVITIES
               
Proceeds from long-term debt                                                                                       
    -       75,900  
Repayments of long-term debt                                                                                       
    (10,000 )     (39,375 )
Proceeds from exercise of stock options                                                                                       
    -       152  
Net cash provided by (used in) financing activities
    (10,000 )     36,677  
                 
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
    7,991       (18,792 )
                 
CASH AND CASH EQUIVALENTS
               
Beginning of period                                                                                       
    14,013       41,199  
End of period                                                                                       
  $ 22,004     $ 22,407  
                 
SUPPLEMENTAL DISCLOSURES
               
Cash paid for interest, net of amounts capitalized                                                                                       
  $ 21,517     $ 21,826  

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

 
 
7

 

CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2010
(Unaudited)

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 demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil exporting countries, trading activities in commodities futures markets, the strength of the U.S. dollar, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic.

2.
Presentation

The preparation of these consolidated financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) 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 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 our 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.

In the opinion of management, our unaudited consolidated financial statements as of September 30, 2010 and for the interim periods ended September 30, 2010 and 2009 include all adjustments that are necessary for a fair presentation in accordance with GAAP.  These interim results are not necessarily indicative of the results to be expected for the year ending December 31, 2010.

Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”).  These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Form 10-K for the year ended December 31, 2009.


 
8

 


Adopted Accounting Pronouncement
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:

   
September 30,
   
December 31,
 
   
2010
   
2009
 
   
(In thousands)
 
7¾% Senior Notes due 2013                                                                      
  $ 225,000     $ 225,000  
Secured bank credit facility, due May 2012                                                                      
    160,000       170,000  
    $ 385,000     $ 395,000  

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.

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 September 30, 2010.

 
9

 


Secured Bank Credit Facility
We have a revolving credit facility with a syndicate of banks based on a borrowing base determined by the banks.  The borrowing base, which is based, in part, on the discounted present value of future net revenues 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) pledge additional collateral, (2) prepay the principal amount of the loans in an amount sufficient to eliminate the excess, or (3) prepay the excess in six equal monthly installments.  In April 2010, the borrowing base was increased by the banks from $250 million to $300 million.  After allowing for an outstanding letter of credit totaling $25,000, we had $140 million available under the credit facility at September 30, 2010.

The revolving credit facility is collateralized by substantially all of our assets, including at least 80% 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, interest under the revolving credit facility is determined by reference to (1) LIBOR plus an applicable margin between 2% and 3% per annum or (2) the greatest of (A) the prime rate, (B) the federal funds rate plus .5% or (C) one-month LIBOR plus 1% plus, in any of (A), (B) or (C), an applicable margin between 1.125% and 2.125% per annum.  We also pay a commitment fee on the unused portion of the revolving credit facility equal to .5%.  Interest and fees are payable quarterly, except that interest on LIBOR-based tranches are due at maturity of each tranche but no less frequently 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 nine months ended September 30, 2010 was 3%.

The revolving credit facility contains financial covenants that are computed quarterly.  One financial covenant requires us to 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 3.5 to 1 for any fiscal quarter ending on or prior to December 31, 2010, 3.25 to 1 for any fiscal quarter ending on or after March 31, 2011 through December 31, 2011, and 3 to 1 for any fiscal quarter thereafter.  The computations of current assets, current liabilities, EBITDAX and indebtedness are defined in the revolving credit facility.  We were in compliance with all financial and non-financial covenants at September 30, 2010.

4.
Other Non-Current Liabilities

Other non-current liabilities consist of the following:
   
September 30,
   
December 31,
 
   
2010
   
2009
 
   
(In thousands)
 
Abandonment obligations                                                                                   
  $ 40,284     $ 38,412  
Other                                                                                   
    819       579  
    $ 41,103     $ 38,991  

Changes in abandonment obligations for the nine months ended September 30, 2010 and 2009 are as follows:

   
Nine Months Ended
 
   
September 30,
 
   
2010
   
2009
 
   
(In thousands)
 
Beginning of period                                                                                   
  $ 38,412     $ 31,737  
Additional abandonment obligations from new properties
    1,377       1,239  
Sales or abandonments of properties                                                                               
    (1,138 )     (123 )
Revisions of previous estimates                                                                               
    (320 )     2,194  
Accretion expense                                                                               
    1,953       2,290  
End of period                                                                                   
  $ 40,284     $ 37,337  
 
 
 
10

 
 
5.
Compensation Plans
 
Stock-Based Compensation
We presently have options outstanding under a stock option plan for independent directors covering 24,000 shares of common stock.  As of September 30, 2010, the options had a weighted average exercise price of $26.66 per share (ranging from $12.14 per share to $41.74 per share), a weighted average remaining contractual term of 3.8 years, and an aggregate intrinsic value of $574,320 (based on a market price at September 30, 2010 of $50.59 per share).  No options were granted during the nine months ended September 30, 2010 or 2009, and options to purchase 27,638 shares of common stock were exercised during the nine months ended September 30, 2009 (intrinsic value - $541,772).

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.

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, 100% of the quarterly bonus amount is payable on a current basis to the participants, and 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.


 
11

 


We recognize compensation expense related to the APO Partnerships based on the estimated fair value of the economic interests conveyed to the participants, based upon Level 3 inputs.  Estimated compensation expense applicable to the APO Reward Plan and SWR Reward Plan is recognized over the vesting periods, which range from two years to five years.  We recorded compensation expense of $8.1 million for the nine months ended September 30, 2010 and $2.3 million for the nine months ended September 30, 2009 in connection with all non-equity award plans.

6.
Derivatives

Commodity Derivatives
From time to time, we utilize commodity derivatives in the form of swap contracts to attempt to optimize the price received for our oil and gas production.  Under swap contracts, 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.  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 September 30, 2010.  The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:
   
Oil
   
Gas
 
   
Bbls
   
Price
   
MMBtu (a)
   
Price
 
Production Period:
                       
4th Quarter 2010
    480,000     $ 76.24       1,680,000     $ 6.80  
2011                           
    2,376,000     $ 83.75       6,420,000     $ 7.07  
2012                           
    570,000     $ 87.60       -     $ -  
      3,426,000               8,100,000          
                                        
(a)    One MMBtu equals one Mcf at a Btu factor of 1,000.
 

In March 2009, we terminated certain fixed-priced oil swaps covering 77,000 barrels at a price of $57.35 from October 2010 through December 2010, resulting in an aggregate loss of approximately $312,000, which will be paid to the counterparty monthly as the applicable contracts are settled.

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.  We report our fair value of derivatives as either a net current asset or liability or a net non-current asset or liability in our consolidated balance sheets.  Cash flow is only impacted to the extent the actual derivative contract is settled by making or receiving a payment to or from the counterparty.  For the nine months ended September 30, 2010, we reported a $27.3 million net gain on derivatives, consisting of a $17.9 million non-cash gain related to changes in mark-to-market valuations and a $9.4 million realized gain for settled contracts.  For the nine months ended September 30, 2009, we reported a $14.5 million net loss on derivatives, consisting of an $8.3 million non-cash loss related to changes in mark-to-market valuations and a $6.2 million realized loss for settled contracts.


 
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Effect of Derivative Instruments on the Consolidated Balance Sheets

 
Fair Value of Derivative Instruments as of September 30, 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
  $     14,239  
Current
  $ -  
 
Non-current
         2,155  
Non-current
    -  
Total
    $ 16,394       $ -  


 
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

   
September 30, 2010
 
   
Assets
   
Liabilities
 
   
(In thousands)
 
Fair value of derivatives – gross presentation
  $ 24,160     $ 7,766  
Effects of netting arrangements
    (7,766 )     (7,766 )
Fair value of derivatives – net presentation
  $ 16,394     $ -  

   
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.  We have elected to net the outstanding positions with this counterparty between current and non-current assets or liabilities.

Effect of Derivative Instruments on the Consolidated Statements of Operations
 
 
   
Amount of Gain or (Loss) Recognized in Earnings
       
Nine Months Ended
   
Location of Gain or (Loss)
 
September 30,
   
Recognized in Earnings
 
2010
 
2009
       
(In thousands)
Derivatives not designated as
           
hedging instruments:
           
             
Commodity derivatives
 
Other income (expense) -
       
   
Gain (loss) on derivatives
 
$                27,289
 
$              (14,537)
Total
     
$                27,289
 
$              (14,537)
 

 
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7.
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 September 30, 2010 and December 31, 2009 was approximately $225 million and $198 million respectively, based on market valuations.

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.

The only financial assets and liabilities measured on a recurring basis at September 30, 2010 and December 31, 2009 were commodity derivatives.  Information regarding these assets and liabilities is summarized below:

   
September 30,
   
December 31,
 
   
2010
   
2009
 
   
Significant Other
   
Significant Other
 
   
Observable Inputs
   
Observable Inputs
 
Description
 
(Level 2)
   
(Level 2)
 
   
(In thousands)
 
Assets:
           
Fair value of commodity derivatives                                                              
  $ 16,394     $ 4,427  
Total assets                                                                
  $ 16,394     $ 4,427  
                 
Liabilities:
               
Fair value of commodity derivatives                                                              
  $ -     $ 5,907  
Total liabilities                                                                
  $ -     $ 5,907  


 
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8.
Income Taxes

Our effective federal and state income tax expense rate for the nine months ended September 30, 2010 of 35.5% 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.

We file federal income tax returns with the United States Internal Revenue Service (“IRS”) and state income tax returns in various state tax jurisdictions.  Our tax returns for fiscal years after 2005 currently remain subject to examination by appropriate taxing authorities.  None of our income tax returns are under examination at this time.

9.
Desta Drilling

We formed a joint venture in 2006 with Lariat Services, Inc. (“Lariat”) to construct, own and operate 12 new drilling rigs.  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”).  In order to assure the availability of drilling rigs for our exploration and development activities, we provided credit support to permit Desta Drilling to finance the construction of the 12 drilling rigs and related equipment, consisting of (1) a subordinated loan of $4.6 million to finance excess construction costs, (2) a limited guaranty to the secured lender in the original amount of $19.5 million, and (3) a drilling contract that expired in 2009 under which we were obligated to use the drilling rigs or pay idle rig rates.  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.  Lariat was designated as the operator of the rigs and provided all management services on behalf of Desta Drilling.

Initially, 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.  All of the assets of Desta Drilling are pledged as collateral 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 were 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.

In December 2009, we modified the prior plan of disposition established in April 2009.  Based on improved 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.  Assets held for sale at September 30, 2010 and December 31, 2009 consist of the remaining two 2,000 horsepower drilling rigs at a combined estimated fair value of $7.4 million.


 
15

 


10.
Purchases and Sales of Assets and Impairments of Inventory

Net gains and losses on sales of assets and impairments of inventory for the nine months ended September 30, 2010 and September 30, 2009 are as follows:

   
Nine Months Ended
 
   
September 30,
 
   
2010
   
2009
 
   
(In thousands)
 
             
Gain on sales of assets                                                
  $ 3,256     $ 2,014  
                 
Loss on sales of assets and impairment
               
of inventory:
               
Loss on sales of assets                                            
    (1,523 )     (261 )
Impairment of inventory                                            
    -       (4,139 )
      (1,523 )     (4,400 )
                 
Net gain (loss)                                                
  $ 1,733     $ (2,386 )

 
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 5), 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%.

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.  In 2009, we recorded a $4.1 million non-cash impairment of inventory to reduce the carrying cost to its fair market value at September 30, 2009.


 
16

 


11.
Oil and Gas Properties

The following sets forth the capitalized costs for oil and gas properties as of September 30, 2010 and December 31, 2009.

   
September 30,
   
December 31,
 
   
2010
   
2009
 
   
(In thousands)
 
Proved properties                                                                                
  $ 1,590,906     $ 1,532,508  
Unproved properties                                                                                
    40,547       47,156  
Total capitalized costs                                                                                
    1,631,453       1,579,664  
Accumulated depreciation, depletion and amortization
    (959,773 )     (945,047 )
Net capitalized costs                                                                           
  $ 671,680     $ 634,617  

12.
Impairment of Property and Equipment

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 $6 million in 2010 and $20.3 million in 2009, respectively, and charged these impairments to exploration costs in the accompanying statements of operations.

We also recorded an impairment of proved properties of $11.1 million during the second quarter of 2010 relating to a non-core area in the Permian Basin and $794,000 during the third quarter of 2010 for certain non-operated wells in Wyoming to reduce the carrying value of those properties to their estimated fair value.

In the second quarter of 2009, we recorded a charge for impairment of property and equipment of approximately $32.1 million in our statement of operations related to a plan of disposition to sell eight of the twelve drilling rigs operated by Desta Drilling (see Note 9).

13.
Contingency

Prior to the sale of substantially all of our North Louisiana  properties in June 2010 (see Note 10), we owned a 30.2% non-operated working interest in a unit on which we participated in the drilling of 12 wells from 2007 to 2008.  Subsequent to the effective date of the sale, the former operator of this unit made retroactive adjustments to reduce our working interest in the unit to 20.4%.  Although no claim has been made against us in connection with these retroactive adjustments, it is our understanding that the operator has reversed its original position with regards to the validity of certain of our leases in the unit.  We believe that the leases in question are valid and that the operator has no legitimate basis for reducing our working interest in this unit.  If a claim is asserted against us, we intend to vigorously defend the validity of the leases.  In the event the leases are ultimately proven to be invalid, we estimate that our economic exposure to this issue will not exceed $3 million.

 
17

 


14.
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 the three-month and nine-month periods ended September 30, 2010 and 2009.

For the Three Months Ended
                       
September 30, 2010
                       
(Unaudited)
       
Contract
   
Intercompany
   
Consolidated
 
(In thousands)
 
Oil and Gas
   
Drilling
   
Eliminations
   
Total
 
                         
Revenues
  $ 85,232     $ 9,285     $ (9,285 )   $ 85,232  
Depreciation, depletion and amortization (a)
    25,622       2,569       (2,174 )     26,017  
Other operating expenses (b)
    31,966       7,052       (6,886 )     32,132  
Interest expense
    6,039       1       -       6,040  
Other (income) expense
    3,023       -       -       3,023  
Income (loss) before income taxes
    18,582       (337 )     (225 )     18,020  
                                 
Income tax (expense) benefit
    (6,515 )     118       -       (6,397 )
                                 
Net income (loss)
    12,067       (219 )     (225 )     11,623  
                                 
Net income (loss) attributable to
                               
  Clayton Williams Energy, Inc
  $ 12,067     $ (219 )   $ (225 )   $ 11,623  
                                 
Total assets
  $ 808,843     $ 37,071     $ 273     $ 846,187  
Additions to property and equipment
  $ 66,605     $ 4,063     $ -     $ 70,668  
                                 


For the Nine Months Ended
                       
September 30, 2010
                       
(Unaudited)
       
Contract
   
Intercompany
   
Consolidated
 
(In thousands)
 
Oil and Gas
   
Drilling
   
Eliminations
   
Total
 
                         
Revenues
  $ 242,546     $ 23,668     $ (23,668 )   $ 242,546  
Depreciation, depletion and amortization (a)
    86,479       7,402       (5,701 )     88,180  
Other operating expenses (b)
    99,201       18,300       (16,944 )     100,557  
Interest expense
    18,389       4       -       18,393  
Other (income) expense
    (30,105 )     -       -       (30,105 )
Income (loss) before income taxes
    68,582       (2,038 )     (1,023 )     65,521  
                                 
Income tax (expense) benefit
    (23,973 )     713       -       (23,260 )
                                 
Net income (loss)
    44,609       (1,325 )     (1,023 )     42,261  
                                 
Net income (loss) attributable to
                               
  Clayton Williams Energy, Inc
  $ 44,609     $ (1,325 )   $ (1,023 )   $ 42,261  
                                 
Total assets
  $ 808,843     $ 37,071     $ 273     $ 846,187  
Additions to property and equipment
  $ 204,605     $ 11,642     $ -     $ 216,247  
                                 


 
18

 



For the Three Months Ended
                       
September 30, 2009
                       
(Unaudited)
       
Contract
   
Intercompany
   
Consolidated
 
(In thousands)
 
Oil and Gas
   
Drilling
   
Eliminations
   
Total
 
                         
Revenues
  $ 62,426     $ 4,596     $ (4,596 )   $ 62,426  
Depreciation, depletion and amortization (a)
    29,661       982       (590 )     30,053  
Other operating expenses (b)
    52,988       3,214       (4,258 )     51,944  
Interest expense
    5,917       609       -       6,526  
Other (income) expense
    (4,647 )     -       -       (4,647 )
Income (loss) before income taxes
    (21,493 )     (209 )     252       (21,450 )
                                 
Income tax (expense) benefit
    7,777       73       -       7,850  
Net income (loss)
    (13,716 )     (136 )     252       (13,600 )
                                 
Net income (loss) attributable to
                               
  Clayton Williams Energy, Inc
  $ (13,716 )   $ (136 )   $ 252     $ (13,600 )
                                 
Total assets
  $ 792,143     $ 42,950     $ (450 )   $ 834,643  
Additions to property and equipment
  $ 31,323     $ 122     $ -     $ 31,445  
                                 


For the Nine Months Ended
                       
September 30, 2009
                       
(Unaudited)
       
Contract
   
Intercompany
   
Consolidated
 
(In thousands)
 
Oil and Gas
   
Drilling
   
Eliminations
   
Total
 
                         
Revenues
  $ 174,030     $ 22,109     $ (15,428 )   $ 180,711  
Depreciation, depletion and amortization (a)
    90,533       37,004       (2,765 )     124,772  
Other operating expenses (b)
    146,287       7,104       (12,799 )     140,592  
Interest expense
    16,210       1,490       -       17,700  
Other (income) expense
    12,886       -       -       12,886  
Income (loss) before income taxes
    (91,886 )     (23,489 )     136       (115,239 )
                                 
Income tax (expense) benefit
    33,956       8,215       -       42,171  
Net income (loss)
    (57,930 )     (15,274 )     136       (73,068 )
Less income attributable to
                               
  noncontrolling interest, net of tax
    (2,910 )     1,455       -       (1,455 )
                                 
Net income (loss) attributable to
                               
  Clayton Williams Energy, Inc
  $ (60,840 )   $ (13,819 )   $ 136     $ (74,523 )
                                 
Total assets
  $ 792,143     $ 42,950     $ (450 )   $ 834,643  
Additions to property and equipment
  $ 86,370     $ 2,312     $ -     $ 88,682  
                                        
  (a)   Includes impairment of property and equipment.
 
(b)
Includes the following expenses:  production, exploration, natural gas services, drilling rig services, accretion of abandonment obligations, general and administrative and loss on sales of assets and impairment of inventory.



 
19

 


15.
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 reflect only the accounts of WCEP, LLC in the Non-Guarantor Subsidiary column in this Note 15.

The financial information which follows sets forth our condensed consolidating financial statements as of and for the periods indicated.

Condensed Consolidating Balance Sheet
September 30, 2010
(Unaudited)
             
Non-
             
(Dollars in thousands)
       
Guarantor
   
Guarantor
   
Adjustments/
       
   
Issuer
   
Subsidiaries
   
Subsidiary
   
Eliminations
   
Consolidated
 
                               
Current assets                                  
  $ 183,346     $ 145,785     $ 1,195     $ (204,429 )   $ 125,897  
Property and equipment, net
    376,274       329,669       6,146       -       712,089  
Investments in subsidiaries
    113,612       -       -       (113,612 )     -  
Other assets                                  
    8,047       154       -       -       8,201  
Total assets                              
  $ 681,279     $ 475,608     $ 7,341     $ (318,041 )   $ 846,187  
                                         
Current liabilities                                  
  $ 155,233     $ 138,609     $ 119     $ (204,429 )   $ 89,532  
Non-current liabilities:
                                       
Long-term debt                              
    385,000       -       -       -       385,000  
Other                              
    54,147       62,832       143       (3 )     117,119  
      439,147       62,832       143       (3 )     502,119  
                                         
Stockholders’ equity                                  
    86,899       274,167       7,079       (113,609 )     254,536  
                                         
Total liabilities and
                                       
  stockholders’ equity
  $ 681,279     $ 475,608     $ 7,341     $ (318,041 )   $ 846,187  

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  
                                         
Stockholders’ equity                                  
    74,921       242,382       6,988       (112,016 )     212,275  
                                         
Total liabilities and
                                       
  stockholders' equity
  $ 654,465     $ 484,622     $ 7,251     $ (361,734 )   $ 784,604  


 
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Condensed Consolidating Statement of Operations
Three Months Ended September 30, 2010
(Unaudited)
             
Non-
             
(In thousands)
       
Guarantor
   
Guarantor
   
Adjustments/
       
   
Issuer
   
Subsidiaries
   
Subsidiary
   
Eliminations
   
Consolidated
 
Total revenue                                  
  $ 56,490     $ 28,768     $ 173     $ (199 )   $ 85,232  
Costs and expenses                                  
    38,746       19,422       180       (199 )     58,149  
Operating income (loss)
    17,744       9,346       (7 )     -       27,083  
Other income (expense)
    (10,749 )     1,648       38       -       (9,063 )
Income tax (expense) benefit
    (6,397 )     -       -       -       (6,397 )
                                         
Net income (loss)                              
  $ 598     $ 10,994     $ 31     $ -     $ 11,623  

Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2010
(Unaudited)
             
Non-
             
(In thousands)
       
Guarantor
   
Guarantor
   
Adjustments/
       
   
Issuer
   
Subsidiaries
   
Subsidiary
   
Eliminations
   
Consolidated
 
Total revenue                                  
  $ 151,479     $ 91,084     $ 526     $ (543 )   $ 242,546  
Costs and expenses                                  
    126,865       61,909       506       (543 )     188,737  
Operating income (loss)
    24,614       29,175       20       -       53,809  
Other income (expense)
    6,962       4,642       108       -       11,712  
Income tax (expense) benefit
    (23,260 )     -       -       -       (23,260 )
                                         
Net income (loss)                              
  $ 8,316     $ 33,817     $ 128     $ -     $ 42,261  

Condensed Consolidating Statement of Operations
Three Months Ended September 30, 2009
(Unaudited)
             
Non-
             
(In thousands)
       
Guarantor
   
Guarantor
   
Adjustments/
       
   
Issuer
   
Subsidiaries
   
Subsidiary
   
Eliminations
   
Consolidated
 
Total revenue                                  
  $ 38,094     $ 24,549     $ 173     $ (390 )   $ 62,426  
Costs and expenses                                  
    61,527       20,676       184       (390 )     81,997  
Operating income (loss)
    (23,433 )     3,873       (11 )     -       (19,571 )
Other income (expense)
    (2,618 )     704       35       -       (1,879 )
Income tax (expense) benefit
    7,850       -       -       -       7,850  
Noncontrolling interest,
                                       
  net of tax                                  
    -       -       -       -       -  
                                         
Net income (loss)                              
  $ (18,201 )   $ 4,577     $ 24     $ -     $ (13,600 )

Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2009
(Unaudited)
             
Non-
             
(In thousands)
       
Guarantor
   
Guarantor
   
Adjustments/
       
   
Issuer
   
Subsidiaries
   
Subsidiary
   
Eliminations
   
Consolidated
 
Total revenue                                  
  $ 105,727     $ 75,463     $ 440     $ (919 )   $ 180,711  
Costs and expenses                                  
    171,970       93,514       799       (919 )     265,364  
Operating income (loss)
    (66,243 )     (18,051 )     (359 )     -       (84,653 )
Other income (expense)
    (33,287 )     2,592       109       -       (30,586 )
Income tax (expense) benefit
    42,171       -       -       -       42,171  
Noncontrolling interest,
                                       
  net of tax                                  
    (1,455 )     -       -       -       (1,455 )
                                         
Net income (loss)                              
  $ (58,814 )   $ (15,459 )   $ (250 )   $ -     $ (74,523 )


 
21

 


Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2010
(Unaudited)
             
Non-
             
(In thousands)
       
Guarantor
   
Guarantor
   
Adjustments/
       
   
Issuer
   
Subsidiaries
   
Subsidiary
   
Eliminations
   
Consolidated
 
Operating activities                                 
  $ 82,871     $ 65,255     $ 340     $ 5,702     $ 154,168  
Investing activities                                 
    (108,458 )     (21,962 )     (55 )     (5,702 )     (136,177 )
Financing activities                                 
    32,440       (42,426 )     (14 )     -       (10,000 )
Net increase (decrease) in
                                       
cash and cash equivalents
    6,853       867       271       -       7,991  
                                         
Cash at the beginning of
                                       
the period                                
    11,839       1,344       830       -       14,013  
                                         
Cash at end of the period
  $ 18,692     $ 2,211     $ 1,101     $ -     $ 22,004  

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2009
(Unaudited)
             
Non-
             
(In thousands)
       
Guarantor
   
Guarantor
   
Adjustments/
       
   
Issuer
   
Subsidiaries
   
Subsidiary
   
Eliminations
   
Consolidated
 
Operating activities                                 
  $ 51,471     $ 14,569     $ 17     $ 2,150     $ 68,207  
Investing activities                                 
    (145,698 )     24,228       (56 )     (2,150 )     (123,676 )
Financing activities                                 
    76,819       (40,138 )     (4 )     -       36,677  
Net increase (decrease) in
                                       
cash and cash equivalents
    (17,408 )     (1,341 )     (43 )     -       (18,792 )
                                         
Cash at the beginning of
                                       
the period                                
    35,381       5,054       764       -       41,199  
                                         
Cash at end of the period
  $ 17,973     $ 3,713     $ 721     $ -     $ 22,407  


16.
Subsequent Events

We have evaluated events and transactions that occurred after the balance sheet date of September 30, 2010.  We did not have any subsequent events that would require recognition in the financial statements or disclosures in these notes to the consolidated financial statements.

 
22

 

Item 2 -                 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-Q and in our Form 10-K for the year ended December 31, 2009.  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.

Forward-Looking Statements

The information in this Form 10-Q 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 or may occur in the future are forward-looking statements.  These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.  When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in our Form 10-K for the year ended December 31, 2009 and in this Form 10-Q.

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, many of which are beyond our control, 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;

 
23

 


 
domestic and worldwide economic conditions;

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

 
our level of indebtedness;

 
the impact of the current economic recession 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 our Form 10-K for the year ended December 31, 2009 and in this Form 10-Q.

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 geological 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.

Should one or more of the risks or uncertainties described above or elsewhere in our Form 10-K for the year ended December 31, 2009 and in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.  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.

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

Overview

We are an independent oil and natural gas exploration, development, acquisition, and production company.  Our basic business model is to increase shareholder value by finding and developing oil and gas reserves through exploration and development activities, and selling the production from those reserves at a profit.  To be successful, we must, over time, be able to find oil and gas reserves and then sell the resulting production at a price that is sufficient to cover our finding costs, operating expenses, administrative costs and interest expense, plus offer us a return on our capital investment.  From time to time, we may also acquire producing properties if we believe the acquired assets offer us the potential for reserve growth through additional developmental or exploratory drilling activities.

 
24

 


For most of 2008, the oil and gas industry was strong, with oil and gas prices and drilling activities at high levels.  In 2009, the business environment was drastically altered due to the global financial crisis that escalated in the second half of 2008.  In response to the negative effects of the recession on our operational model, we suspended our developmental drilling program in the Permian Basin and in the Austin Chalk (Trend) in late 2008 and turned our business focus toward preserving short-term liquidity and conserving capital resources.  By the end of the second quarter of 2009, operating margins on oil-prone properties had begun to improve somewhat due to a combination of higher oil prices and lower costs of field services caused by decreased demand for those services.  Since most of our developmental drilling locations are oil-prone, we elected to resume drilling developmental oil wells primarily in Andrews County, Texas in the Permian Basin and Burleson and Robertson Counties, Texas in the Austin Chalk (Trend).  In connection with the return to drilling activities in these areas, we have taken the following actions which we believe will enhance the development of these core areas:

•  
Entered into agreements with selected service providers to fix unit costs covering approximately 90% of the drilling and completion services provided by third parties through the second quarter of 2011;

•  
Improved drilling efficiencies by acquiring the noncontrolling interest in Desta Drilling, giving us full control over the management and operation of drilling services;

•  
Purchased casing and tubing for more than 175 wells at discounts to then-current market prices; and

•  
Entered into derivative contracts for a significant portion of our estimated proved developed oil production for 2010 and 2011 at average prices of $76.24 and $83.75 per barrel, respectively.

We currently plan to spend approximately $304.1 million on exploration and development activities in fiscal 2010.  By comparison, we spent $138.3 million in fiscal 2009 on exploration and development activities.  We continue to evaluate and manage our portfolio of assets and monitor the extent to which changes in commodity prices could affect our financial liquidity.  We believe we are taking appropriate actions to position our business for long-term growth and sustainability.

Key Factors to Consider

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

•  
Our oil and gas sales for the third quarter increased $22.5 million, or 38%, from 2009 due to a $12.3 million increase due to higher production and a $10.2 million increase derived from higher oil and gas prices.

•  
Our combined oil and gas production for the third quarter of 2010 was 4% higher on a barrel of oil equivalent (“BOE”) basis than in the comparable period in 2009.  Our oil production increased 38% compared to the third quarter of 2009 while gas production declined 35%.  On a comparable basis, after giving effect to the sale of properties in North Louisiana in June 2010, oil and gas production in 2010 (on a BOE basis) was 19% higher than 2009.

•  
We recorded a $4 million net loss on derivatives in the third quarter of 2010, consisting of an $8 million non-cash loss for changes in mark-to-market valuations and a $4 million realized gain on settled contracts.  For the same period in 2009, we reported a $4.7 million net gain on derivatives in the third quarter of 2009, consisting of a $10.6 million non-cash gain for changes in mark-to-market valuations and a $5.9 million realized loss on settled contracts.  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.

•  
We recorded a net gain of $2.8 million on sales of assets and impairment of inventory related primarily to the sale of our interest in a non-operated well and related leasehold interests in North Louisiana.


 
25

 


•  
During the third quarter of 2010, we increased borrowings under our revolving credit facility by $29 million from $131 million at June 30, 2010 to $160 million at September 30, 2010 to fund our on-going developmental drilling program.

Recent 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 (Trend).  We currently plan to spend approximately $304.1 million on exploration and development activities during fiscal 2010, $209 million of which was incurred during the first nine months of fiscal 2010.  Approximately 96% of the estimated expenditures for fiscal 2010 is 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.

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.  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 $126.2 million in the Permian Basin during the first nine months of 2010 on drilling and completion activities and $7.6 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 59 gross (55.7 net) operated wells in the Permian Basin and conducted various remedial operations on other wells in the first nine months of 2010.  We currently plan to spend approximately $192.9 million on drilling and completion activities and $20.2 million for seismic and leasing activities in the Permian Basin during fiscal 2010.  Our activities are expected to be concentrated in the following areas.

Andrews County - Wolfberry
We have a large acreage block in Andrews County, Texas on which we have identified more than 200 potential locations for Wolfberry wells.  A Wolfberry well is a well that commingles production from the Spraberry and Wolfcamp formations.  We spent approximately $102.7 million in the Andrews County – Wolfberry area on drilling and completion activities during the first nine months of 2010.  We currently plan to continue using seven of our rigs and certain contract rigs to drill and complete approximately 30 additional wells during the remainder of the year at an estimated cost of $52.5 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.  We have drilled and completed six wells during the first nine months of 2010.  We currently plan to drill 8 additional wells during the first quarter of 2011.

New Mexico
We currently plan to drill additional development wells in Eddy County, New Mexico targeting the Yeso, San Andres and Grayburg formations.  We expect to begin a nineteen well drilling program in the fourth quarter of 2010.

Austin Chalk (Trend)/ Eagle Ford Shale
Prior to 1998, we concentrated our drilling activities in an oil-prone area we refer to as the Austin Chalk (Trend) in Robertson, Burleson, Brazos, Lee, Milam and Leon Counties, Texas.  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.  We believe that 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.

 
26

 


The Eagle Ford Shale is a formation immediately beneath the Austin Chalk (Trend) 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 9 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 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.  We are continuing to evaluate the production data from these wells and may drill additional wells in order to determine if an Eagle Ford Shale drilling program is economically viable.

We spent $53.3 million in the Austin Chalk (Trend)/Eagle Ford Shale area during the first nine months of 2010 and we plan to use three of our rigs to drill and complete approximately 9 additional wells in the remainder of the year at an estimated cost of $18.9 million, net to our working interest.

South Louisiana
In the first quarter of 2010, we successfully drilled and completed the State Lease 17378 #4, a developmental well in Plaquemines Parish.  During the second quarter of 2010, we also drilled and are currently completing the State Lease 19964 #1, an exploratory well in Plaquemines Parish.  We plan to spend $7 million in fiscal 2010 in connection with the drilling and completion of these two wells, of which $6.4 million was incurred in the first nine months of 2010.

East Texas Bossier
We have an extensive acreage position in East Texas targeting the prolific deep Bossier sands which are encountered at depths ranging from 14,000 to 22,000 feet in this area.  Exploration for deep Bossier gas sands in this area is in its early stages and involves a high degree of risk.  The geological structures are complex, and limited drilling activity offers minimal subsurface control.  Deep Bossier wells are expensive to drill, with completed wells costing approximately $18 million each.  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.

Depressed natural gas prices have limited our opportunities to participate in drilling new gas wells, and we will continue to be very selective until we believe gas prices are more favorable.  We spent $1.6 million in the East Texas Bossier area during the first nine months of 2010 primarily for seismic and leasing activities.

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

The Andrews County – Wolfberry developmental drilling program is very sensitive to oil prices and drilling costs.  We believe that the steps we have taken to (1) fix unit costs with selected service providers, (2) improve drilling efficiencies through Desta Drilling, and (3) 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 at or near current levels.  Our ability to sustain an economically viable drilling program in the Andrews-Wolfberry area beyond mid-year 2011 is uncertain.  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.

 
27

 


Supplemental Information

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

   
Three Months Ended
 
   
September 30,
 
   
2010
   
2009
 
Oil and Gas Production Data:
           
Oil (MBbls)                                                                                       
    915       662  
Gas (MMcf)                                                                                       
    2,530       3,900  
Natural gas liquids (MBbls)                                                                                       
    90       63  
Total (MBOE)                                                                                       
    1,427       1,375  
                 
Average Realized Prices (a):
               
Oil ($/Bbl)                                                                                       
  $ 73.18     $ 64.60  
Gas ($/Mcf)                                                                                       
  $ 4.56     $ 3.79  
Natural gas liquids ($/Bbl)                                                                                       
  $ 36.88     $ 31.89  
                 
Gain (Loss) on Settled Derivative Contracts (a):
               
($ in thousands, except per unit)
               
Oil:    Net realized loss                                                                                
  $ (227 )   $ (8,861 )
Per unit produced ($/Bbl)                                                                                
  $ (.25 )   $ (13.39 )
Gas:   Net realized gain
  $ 4,230     $ 2,992  
Per unit produced ($/Mcf)                                                                                
  $ 1.67     $ .77  
                 
Average Daily Production:
               
Oil (Bbls):
               
Permian Basin                                                                                
    6,092       3,526  
Austin Chalk (Trend)                                                                                
    3,044       2,585  
North Louisiana                                                                                
    -       230  
South Louisiana                                                                                
    727       773  
Other                                                                                
    83       82  
Total                                                                          
    9,946       7,196  
                 
Gas (Mcf):
               
Permian Basin                                                                                
    13,931       14,374  
Austin Chalk (Trend)                                                                                
    2,325       2,306  
North Louisiana                                                                                
    -       10,076  
South Louisiana                                                                                
    5,650       10,755  
Cotton Valley Reef Complex                                                                                
    3,708       3,916  
Other                                                                                
    1,886       964  
Total                                                                          
    27,500       42,391  
                 
Natural Gas Liquids (Bbls):
               
Permian Basin                                                                                
    535       246  
Austin Chalk (Trend)                                                                                
    258       288  
North Louisiana                                                                                
    -       26  
South Louisiana                                                                                
    119       116  
Other                                                                                
    66       9  
Total                                                                          
    978       685  




 
 
 
 
(Continued)

 
28

 


   
Three Months Ended
   
September 30,
   
2010
   
2009
Exploration Costs (in thousands):
         
Abandonment and impairment costs:
         
North Louisiana                                                                                 
  $ -     $ 3,172  
South Louisiana                                                                                 
    85       18,955  
Permian Basin                                                                                 
    5       4  
East Texas Bossier                                                                                 
    274       958  
Utah                                                                                 
    -       750  
Other                                                                                 
    -       310  
Total                                                                           
    364       24,149  
                   
Seismic and other                                                                                        
    1,361       898  
Total exploration costs                                                                           
  $ 1,725     $ 25,047  
                   
Depreciation, Depletion and Amortization (in thousands):
                 
Oil and gas depletion                                                                                        
  $ 24,647     $ 29,481    
Contract drilling depreciation                                                                                        
    393       392    
Other depreciation                                                                                        
    183       180    
Total DD&A                                                                           
  $ 25,223     $ 30,053    
                   
Oil and Gas Costs ($/BOE Produced):
                 
Production costs                                                                                        
  $ 14.38     $ 14.01    
Production costs (excluding production taxes)                                                                                        
  $ 11.29     $ 11.46    
Oil and gas depletion                                                                                        
  $ 17.27     $ 21.44    
                   
Net Wells Drilled (b):
                 
Exploratory Wells                                                                                        
    -       1.1    
Developmental Wells                                                                                        
    24.0       16.6    
 

   
Nine Months Ended
 
   
September 30,
 
   
2010
   
2009
 
Oil and Gas Production Data:
           
Oil (MBbls)                                                                                       
    2,475       2,129  
Gas (MMcf)                                                                                       
    8,665       12,369  
Natural gas liquids (MBbls)                                                                                       
    207       175  
Total (MBOE)                                                                                       
    4,126       4,366  
                 
Average Realized Prices (a):
               
Oil ($/Bbl)                                                                                       
  $ 74.39     $ 52.10  
Gas ($/Mcf)                                                                                       
  $ 5.21     $ 4.11  
Natural gas liquids ($/Bbl)                                                                                       
  $ 40.38     $ 26.70  
                 
Gain (Loss) on Settled Derivative Contracts (a):
               
($ in thousands, except per unit)
               
Oil:      Net realized loss                                                                                
  $ (3,098 )   $ (13,701 )
  Per unit produced ($/Bbl)                                                                                
  $ (1.25 )   $ (6.44 )
Gas:    Net realized gain
  $ 12,514     $ 7,478  
  Per unit produced ($/Mcf)                                                                                
  $ 1.44     $ .60  








(Continued)

 
29

 


   
Nine Months Ended
   
September 30,
   
2010
   
2009
Average Daily Production:
         
Oil (Bbls):
         
Permian Basin                                                                                
    5,469       4,010  
Austin Chalk (Trend)                                                                                
    2,827       2,821  
North Louisiana                                                                                
    94       257  
South Louisiana                                                                                
    596       624  
Other                                                                                
    80       87  
Total                                                                          
    9,066       7,799  
                   
Gas (Mcf):
                 
Permian Basin                                                                                
    13,702       15,157  
Austin Chalk (Trend)                                                                                
    2,222       2,580  
North Louisiana                                                                                
    4,790       12,007  
South Louisiana                                                                                
    6,024       10,342  
Cotton Valley Reef Complex                                                                                
    3,770       3,989  
Other                                                                                
    1,232       1,233  
Total                                                                          
    31,740       45,308  
                   
Natural Gas Liquids (Bbls):
                 
Permian Basin                                                                                
    388       241  
Austin Chalk (Trend)                                                                                
    238       296  
North Louisiana                                                                                
    10       21  
South Louisiana                                                                                
    95       73  
Other                                                                                
    27       10  
Total                                                                          
    758       641  
                   
Exploration Costs (in thousands):
                 
Abandonment and impairment costs:
                 
North Louisiana                                                                                 
  $ 1,748     $ 4,280  
South Louisiana                                                                                 
    1,233       19,768  
Permian Basin                                                                                 
    18       768  
East Texas Bossier                                                                                 
    2,522       11,742  
Utah                                                                                 
    64       3,082  
Mississippi                                                                                 
    327       311  
Other                                                                                 
    221       1,115  
Total                                                                           
    6,133       41,066  
                   
Seismic and other                                                                                        
    3,995       6,556  
Total exploration costs                                                                           
  $ 10,128     $ 47,622  
                   
Depreciation, Depletion and Amortization (in thousands):
                 
Oil and gas depletion                                                                                        
  $ 74,048     $ 89,914    
Contract drilling depreciation                                                                                        
    1,700       2,171    
Other depreciation                                                                                        
    524       619    
Total DD&A                                                                           
  $ 76,272     $ 92,704    
                   
Oil and Gas Costs ($/BOE Produced):
                 
Production costs                                                                                        
  $ 15.03     $ 12.97    
Production costs (excluding production taxes)                                                                                        
  $ 11.90     $ 10.76    
Oil and gas depletion                                                                                        
  $ 17.95     $ 20.59    
                   
Net Wells Drilled (b):
                 
Exploratory Wells                                                                                        
    2.2       2.5    
Developmental Wells                                                                                        
    76.6       28.5    
                        
(a)   No derivatives were designated as cash flow hedges in 2010 or 2009. 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.
   
 
 
 
30

 
Operating Results – Three-Month Periods

The following discussion compares our results for the three months ended September 30, 2010 to the comparative period in 2009.  Unless otherwise indicated, references to 2010 and 2009 within this section refer to the respective quarterly period.

Oil and gas operating results

Oil and gas sales in 2010 increased $22.5 million, or 38%, from 2009.  Production variances accounted for an increase of $12.3 million while price variances accounted for the remaining $10.2 million increase.  Production in 2010 (on a BOE basis) was 4% higher than 2009, primarily from additions to our developmental drilling programs.  Oil production increased 38% in 2010 from 2009 while gas production decreased 35% 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 the third quarter of 2009, the sold wells produced 230 barrels of oil per day and 10,076 Mcf of gas per day.  On a comparable basis, after giving effect to the sale of these properties, oil and gas production in 2010 (on a BOE basis) was 19% higher than 2009.  In 2010, our realized oil price was 13% higher than 2009, and our realized gas price was 20% 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 7% in 2010 as compared to 2009 due primarily to an increase in production taxes caused by increases in commodity prices.  After giving effect to a 4% increase in oil and gas production on a BOE basis, production costs per BOE increased 3% from $14.01 per BOE in 2009 to $14.38 per BOE in 2010.

Oil and gas depletion expense decreased $4.8 million from 2009 to 2010, of which rate variances accounted for a $5.9 million decrease, offset in part by a $1.1 million increase for production variances.  On a BOE basis, depletion expense decreased 19% from $21.44 per BOE in 2009 to $17.27 per BOE 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 $794,000 during 2010 for certain non-operated oil and gas properties in Wyoming to reduce the carrying value of those properties to their estimated fair value at September 30, 2010.

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 $1.7 million of exploration costs, as compared to $25 million in 2009.

At September 30, 2010, our capitalized unproved oil and gas properties totaled $40.5 million, of which approximately $13.2 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.


 
31

 


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 118% from $4 million in 2009 to $8.7 million in 2010.  Employee compensation expense related to non-equity incentive plans was $3 million in 2010 compared to $338,000 in 2009.  Excluding employee compensation related to non-equity incentive plans, G&A expenses increased from $3.7 million in 2009 to $5.7 million in 2010 due to a combination of factors including a $1 million donation to the National Rifle Association’s Freedom Action Foundation and 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.

Interest expense

Interest expense decreased 7% from $6.5 million in 2009 to $6 million in 2010 primarily due to the repayment of all of Desta Drilling’s debt in August 2009.  Interest expense associated with Desta Drilling’s secured term loan was $609,000 in 2009.  The average daily principal balance outstanding under our revolving credit facility for 2010 was $150.4 million compared to $156.5 million for 2009.  Decreased borrowings on our revolving credit facility accounted for a $44,000 decrease in interest expense, while lower interest rates and fees resulted in a decrease of approximately $46,000.

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.  For the three months ended September 30, 2010, we reported a $4 million net loss on derivatives, consisting of an $8 million non-cash loss to mark our derivative positions to their fair value at September 30, 2010 and a $4 million realized gain on settled contracts.  For the three months ended September 30, 2009, we reported a $4.7 million net gain on derivatives, consisting of a $10.6 million non-cash gain to mark our derivative positions to their fair value at September 30, 2009 and a $5.9 million realized loss on settled contracts.  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 $2.8 million on sales of assets and impairment of inventory compared to a net gain of $796,000 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.  The 2009 gain included a $1.3 million gain on the sale of a prospect in South Louisiana offset by a $749,000 loss related to the write-down of inventory to its estimated market value at September 30, 2009.

Income tax expense

Our estimated effective income tax rate in 2010 of 35.5% 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.


Operating Results – Nine-Month Periods

The following discussion compares our results for the nine months ended September 30, 2010 to the comparative period in 2009.  Unless otherwise indicated, references to 2010 and 2009 within this section refer to the respective nine-month period.

 
32

 


Oil and gas operating results

Oil and gas sales in 2010 increased $70.5 million, or 42%, from 2009.  Price variances accounted for an increase of $67.7 million while production variances accounted for a $2.8 million increase.  Production in 2010 (on a BOE basis) was 5% lower than 2009, despite additions from our developmental drilling programs.  Oil production increased 16% in 2010 from 2009 while gas production decreased 30% 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.  On a comparable basis, production in 2010 (on a BOE basis) was relatively flat compared to 2009 excluding production from the sold properties in North Louisiana.  In 2010, our realized oil price was 43% higher than 2009, and our realized gas price was 27% 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 10% in 2010 as compared to 2009 due primarily to higher production taxes caused by increases in commodity prices and the cost of oilfield services.  After giving effect to a 5% decrease in oil and gas production on a BOE basis, production costs per BOE increased 16% from $12.97 per BOE in 2009 to $15.03 per BOE in 2010.

Oil and gas depletion expense decreased $15.9 million from 2009 to 2010, of which rate variances accounted for a $10.9 million decrease and production variances accounted for a $5 million decrease.  On a BOE basis, depletion expense decreased 13% from $20.59 per BOE in 2009 to $17.95 per BOE in 2010 due to a decrease in production volumes and a combination of lower depletable costs and higher estimated reserve quantities in 2010 compared to the 2009 period.  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 the second quarter of 2009, we recorded a $32.1 million impairment of property and equipment to write-down rigs to their estimated fair value.

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 $10.1 million of exploration costs, as compared to $47.6 million in 2009.

At September 30, 2010, our capitalized unproved oil and gas properties totaled $40.5 million, of which approximately $13.2 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.

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.

 
33

 


General and Administrative

G&A expenses increased 54% from $14.8 million in 2009 to $22.8 million in 2010.  Employee compensation expense related to non-equity incentive plans was $8.1 million in 2010 compared to $2.3 million in 2009.  Excluding employee compensation related to non-equity incentive plans, G&A expenses increased from $12.5 million in 2009 to $14.7 million in 2010 due primarily to a combination of factors including a $1 million donation to the National Rifle Association’s Freedom Action Foundation and 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.

Interest expense

Interest expense increased 4% from $17.7 million in 2009 to $18.4 million in 2010 primarily due to higher average levels of debt.  The average daily principal balance outstanding under our revolving credit facility for 2010 was $174.4 million compared to $123.1 million for 2009.  Increased borrowings on our revolving credit facility accounted for an $852,000 increase in interest expense, while higher interest rates and fees resulted in an increase of approximately $620,000.  In addition, interest expense associated with Desta Drilling’s secured term loan was $1.3 million in 2009, and capitalized interest for 2010 was $294,000 compared to $562,000 in 2009.  In August 2009, we repaid all of Desta Drilling’s debt.

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.  For the nine months ended September 30, 2010, we reported a $27.3 million net gain on derivatives, consisting of a $17.9 million non-cash gain to mark our derivative positions to their fair value at September 30, 2010 and a $9.4 million realized gain on settled contracts.  For the nine months ended September 30, 2009, we reported a $14.5 million net loss on derivatives, consisting of an $8.3 million non-cash loss to mark our derivative positions to their fair value at September 30, 2009 and a $6.2 million realized loss on settled contracts.  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 $1.7 million on sales of assets and impairment of inventory compared to a net loss of $2.4 million in 2009.  The 2010 gain related primarily to the sale of our interest in a non-operated well and related leasehold interest in North Louisiana for a gain of $3.1 million, offset by a loss of $1.4 million related to the sale of our interests in 22 operated and 76 non-operated producing wells in North Louisiana for net proceeds of $73.1 million.  The 2009 loss was related primarily to the write-down of inventory to its estimated market value at September 30, 2009.

Income tax expense

Our estimated effective income tax rate in 2010 of 35.5% 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.



 
34

 


Liquidity and Capital Resources

Overview

Our primary financial resource is our base of oil and gas reserves.  We pledge our producing oil and gas properties to a syndicate of banks led by JPMorgan Chase Bank, N.A. to secure our revolving credit facility.  The banks establish a borrowing base, in part, 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 program 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 the issuance of our 7¾% Senior Notes due 2013 contains covenants that restrict our ability to incur indebtedness.  We currently have, and expect to have in 2010, the ability under the Indenture to incur indebtedness as needed in 2010 to fund our exploration and development activities.

Capital expenditures

We incurred expenditures for exploration and development activities of $209 million during the first nine months of 2010 and we currently plan to spend $304.1 million for fiscal 2010.  The following table summarizes, by area, our actual expenditures for exploration and development activities for the first nine months of 2010 and our planned expenditures for the year ending December 31, 2010.

   
Actual
   
Planned
       
   
Expenditures
   
Expenditures
   
2010
 
   
Nine Months Ended
   
Year Ended
   
Percentage
 
   
September 30, 2010
   
December 31, 2010
   
of Total
 
   
(In thousands)
       
Permian Basin                                                
  $ 143,400     $ 213,100       70 %
Austin Chalk (Trend)/ Eagle Ford Shale
    53,300       77,100       25 %
South Louisiana                                                
    6,400       7,000       3 %
Other                                                
    5,900       6,900       2 %
    $ 209,000     $ 304,100       100 %

Our actual expenditures during fiscal 2010 may be substantially higher or lower than these estimates since our plans for exploration and development activities may change during the remainder of the year.  Factors, such as changes in operating margins and the availability of capital resources, could also increase or decrease the ultimate level of expenditures during the remainder of fiscal 2010.

Our expenditures for exploration and development activities for the nine months ended September 30, 2010 totaled $209 million, of which approximately 95% was on developmental drilling. We financed these expenditures with cash flow from operating activities and advances under the revolving credit facility.  Based on preliminary estimates, our internal cash flow forecasts indicate that the amount of funds available to us under our revolving credit facility, when combined with our anticipated operating cash flow, will be sufficient to finance our exploration and development activities and provide us with adequate liquidity through 2010.  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 2010, we will consider options for obtaining alternative capital resources, including selling assets or accessing capital markets.


 
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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.

Cash flow provided by operating activities for the nine months ended September 30, 2010 increased $86 million, or 126%, as compared to the corresponding period in 2009 due primarily to a 42% increase in oil and gas sales caused by higher commodity prices.

Credit facility

We have a revolving credit facility with a syndicate of banks led by JPMorgan Chase Bank, N.A.  We have historically relied on the revolving credit facility for both our short-term liquidity (working capital) and our long-term financial needs.  The funds available to us at any time under the revolving credit facility are limited to the amount of the borrowing base determined by the banks.  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 banks redetermine the borrowing base under the revolving credit facility on a semi-annual basis, in May and November.  In addition, we or the banks may 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) pledge additional collateral, (2) prepay the principal amount of the loans in an amount sufficient to eliminate the excess, or (3) prepay the excess in six equal monthly installments.  At September 30, 2010, our borrowing base was $300 million.

The revolving credit facility is collateralized by substantially all of our assets, including at least 80% of the adjusted engineered value (as defined in the revolving credit facility) of our oil and gas interests evaluated in determining the borrowing base for the revolving credit facility.  The obligations under the revolving credit facility are guaranteed by each of our domestic subsidiaries, excluding WCEP, LLC.

At our election, interest under the revolving credit facility is determined by reference to (1) LIBOR plus an applicable margin between 2% and 3% per annum or (2) the greatest of (A) the prime rate, (B) the federal funds rate plus .5% or (C) one-month LIBOR plus 1% plus, in any of (A), (B) or (C), an applicable margin between 1.125% and 2.125% per annum.  We also pay a commitment fee on the unused portion of the revolving credit facility equal to .5%.  Interest and fees are payable quarterly, except that interest on LIBOR-based tranches are due at maturity of each tranche but no less frequently 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 nine months ended September 30, 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, (3) exclude current maturities of loans under the revolving credit facility, if any, and (4) exclude current assets and liabilities attributable to vendor financing transactions, if any.

 
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Working capital computed for loan compliance purposes differs from our working capital in accordance with generally accepted accounting principles (“GAAP”).  Since compliance with financial covenants is a material requirement under the credit facility, 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 increased from $19.3 million at December 31, 2009 to $36.4 million at September 30, 2010.  After giving effect to the adjustments, our working capital computed for loan compliance purposes was $162.1 million at September 30, 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 September 30, 2010 and December 31, 2009.

   
September 30,
   
December 31,
 
   
2010
   
2009
 
   
(In thousands)
 
Working capital per GAAP
  $ 36,365     $ 19,324  
Add funds available under the revolving credit facility
    139,975       79,196  
Exclude fair value of derivatives classified as current assets or current liabilities
    (14,239 )     5,907  
Working capital per loan covenant
  $ 162,101     $ 104,427  
                 

The revolving credit facility also prohibits the ratio of our consolidated funded indebtedness to consolidated EBITDAX (the “Leverage Ratio”) (determined as of the end of each fiscal quarter for the then most-recently ended four fiscal quarters) from being greater than (1) 3.5 to 1 for any fiscal quarter ending on or prior to December 31, 2010, (2) 3.25 to 1 for any fiscal quarter ending on or after March 31, 2011 through December 31, 2011 and (3) 3 to 1 for any fiscal quarter thereafter.

We were in compliance with all financial and non-financial covenants at September 30, 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., BNP Paribas, Union Bank, N.A., Bank of Scotland, Natixis, Compass Bank, Bank of Texas, N.A., The Frost National Bank, Keybank, N.A., and UBS Loan Finance, LLC.

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 September 30, 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 the first nine months in 2010, we decreased indebtedness outstanding under the revolving credit facility by $10 million.  At September 30, 2010, we had $160 million of borrowings outstanding under the revolving credit facility, leaving $140 million available on the facility after allowing for an outstanding letter of credit totaling $25,000.  In April 2010, the borrowing base established by the banks was increased to $300 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.


 
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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).  Based on our PV-10 Value at December 31, 2009, this alternative to the EBITDAX coverage test would not be available since our outstanding borrowings under the revolving credit facility currently exceed the maximum permitted.  We currently have, and expect to have in 2010, sufficient EBITDAX coverage under the Indenture to permit us to borrow funds as needed in 2010 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 September 30, 2010.

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.

Item 3 -                 Quantitative and Qualitative Disclosures 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 effect 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 that 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, 2009 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 2009 would reduce our gross revenues for the year ending December 31, 2010 by $8.6 million.


 
38

 


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 September 30, 2010.  The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:
   
Oil
   
Gas
 
   
Bbls
   
Price
   
MMBtu (a)
   
Price
 
Production Period:
                       
4th Quarter 2010
    480,000     $ 76.24       1,680,000     $ 6.80  
2011                           
    2,376,000     $ 83.75       6,420,000     $ 7.07  
2012                           
    570,000     $ 87.60       -     $ -  
      3,426,000               8,100,000          
                                      
(a)   One MMBtu equals one Mcf at a Btu factor of 1,000.
 

In March 2009, we terminated certain fixed-priced oil swaps covering 77,000 barrels at a price of $57.35 from October 2010 through December 2010, resulting in an aggregate loss of approximately $312,000, which will be paid to the counterparty monthly as the applicable contracts are settled.

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 commodity derivatives by approximately $6.3 million.

Interest Rates

We are exposed to interest rate risk on our long-term debt with a variable interest rate.  At September 30, 2010, our fixed rate debt had a carrying value of $225 million and an approximate fair value of $225 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 $5.5 million.  Based on our outstanding variable rate indebtedness at September 30, 2010 of $160 million, a change in interest rates of 100-basis points would affect annual interest payments by $1.6 million.


 
39

 


Item 4 -                 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 officer and our chief financial officer 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.

Changes in Internal Control Over Financial Reporting

No changes in internal control over financial reporting were made during the quarter ended September 30, 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


 
40

 


PART II.  OTHER INFORMATION


Item 1A -              Risk Factors

In evaluating all forward-looking statements, you should specifically consider various factors that may cause actual results to vary from those contained in the forward-looking statements.  Our risk factors are included in our Annual Report on Form 10-K for the year ended December 31, 2009, as filed with the U.S. Securities and Exchange Commission on March 12, 2010, and our Quarterly Report on Form 10Q for the quarterly period ended June 30, 2010, as filed with the U.S. Securities and Exchange Commission on August 9, 2010, each of which is available at www.sec.gov.

Item 6 -                 Exhibits

Exhibits
**3.1
 
Second Restated Certificate of Incorporation of the Company, filed as Exhibit 3.1 to our 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 our 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 our Current Report on Form 8-K filed with the Commission on March 14, 2008††
     
**4.1
 
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 our Current Report on Form 8-K filed with the Commission on July 22, 2005††
     
**10.1
 
CWEI Andrews Fee Reward Plan dated October 19, 2010, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on October 22, 2010††
     
**10.2
 
CWEI Andrews Samson Reward Plan dated October 19, 2010, filed as Exhibit 10.2 to our Current Report on Form 8-K filed with the Commission on October 22, 2010††
     
**10.3
 
CWEI Austin Chalk Reward Plan dated October 19, 2010, filed as Exhibit 10.3 to our Current Report on Form 8-K filed with the Commission on October 22, 2010††
     
*31.1
 
Certification by the President and Chief Executive Officer of the Company pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934
     
*31.2
 
Certification by the Chief Financial Officer of the Company pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934
     
***32.1
 
Certifications by the Chief Executive Officer and Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350
         
 
 
*
Filed herewith
 
**
Incorporated by reference to the filing indicated
 
***
Furnished herewith
 
Identifies an Exhibit that consists of or includes a management contract or compensatory plan or arrangement
 
††
Filed under our Commission File No. 001-10924
 
 
 
41

 
CLAYTON WILLIAMS ENERGY, INC.
SIGNATURES



Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereto duly authorized.



   
CLAYTON WILLIAMS ENERGY, INC.



Date:
November 5, 2010
By:
/s/ L. Paul Latham
     
L. Paul Latham
     
Executive Vice President and Chief
     
  Operating Officer



Date:
November 5, 2010
By:
/s/ Mel G. Riggs
     
Mel G. Riggs
     
Senior Vice President and Chief Financial
     
  Officer


 
42

 


INDEX TO EXHIBITS

Exhibits No.
 
Description
**3.1
 
Second Restated Certificate of Incorporation of the Company, filed as Exhibit 3.1 to our 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 our 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 our Current Report on Form 8-K filed with the Commission on March 14, 2008††
     
**4.1
 
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 our Current Report on Form 8-K filed with the Commission on July 22, 2005††
     
**10.1
 
CWEI Andrews Fee Reward Plan dated October 19, 2010, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on October 22, 2010††
     
**10.2
 
CWEI Andrews Samson Reward Plan dated October 19, 2010, filed as Exhibit 10.2 to our Current Report on Form 8-K filed with the Commission on October 22, 2010††
     
**10.3
 
CWEI Austin Chalk Reward Plan dated October 19, 2010, filed as Exhibit 10.3 to our Current Report on Form 8-K filed with the Commission on October 22, 2010††
     
*31.1
 
Certification by the President and Chief Executive Officer of the Company pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934
     
*31.2
 
Certification by the Chief Financial Officer of the Company pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934
     
***32.1
 
Certifications by the Chief Executive Officer and Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350
          
 
 
*
Filed herewith
 
**
Incorporated by reference to the filing indicated
 
***
Furnished herewith
 
Identifies an Exhibit that consists of or includes a management contract or compensatory plan or arrangement
 
††
Filed under our Commission File No. 001-10924
 
 
 
 
 
43