CLAYTON WILLIAMS ENERGY INC /DE - FORM 8-K - EX-99.1 - CWEI FINANCIAL GUIDANCE FOR 2012 - August 7, 2012

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EXHIBIT 99.1
CLAYTON WILLIAMS ENERGY, INC.

FINANCIAL GUIDANCE DISCLOSURES FOR 2012

Overview

Clayton Williams Energy, Inc. and its subsidiaries have prepared this document to provide public disclosure of certain financial and operating estimates in order to permit the preparation of models to forecast our operating results for the year ending December 31, 2012.  These estimates are based on information available to us as of the date of this filing, and actual results may vary materially from these estimates.  We do not undertake any obligation to update these estimates as conditions change or as additional information becomes available.

The estimates provided in this document are based on assumptions that we believe are reasonable.  Until our actual results of operations for this period have been compiled and released, all of the estimates and assumptions set forth herein constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.  All statements, other than statements of historical facts, included in this document that address activities, events, outcomes and other matters that we plan, expect, intend, assume, believe, budget, predict, forecast, project, estimate or anticipate (and other similar expressions) will, should, could or may occur in the future, including such matters as production of oil and gas, product prices, oil and gas reserves, drilling and completion results, capital expenditures, operating costs and other such matters, are forward-looking statements.  Such forward-looking statements involve known and unknown risks, uncertainties, and other factors that may cause our actual results, performance, or achievements to be materially different from the results, performance, or achievements expressed or implied by such forward-looking statements.  Such factors include, among others, the following:  the volatility of oil and gas prices; the unpredictable nature of our exploratory drilling results; the reliance upon estimates of proved reserves; operating hazards and uninsured risks; competition; government regulation; and other factors referenced in filings made by us with the Securities and Exchange Commission.

As a matter of policy, we generally do not attempt to provide guidance on:

 
(a)
production which may be obtained through future exploratory drilling;
 
(b)
dry hole and abandonment costs that may result from future exploratory drilling;
 
(c)
the effects of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” superseded by topic 815-10 of the Financial Accounting Standards Board Accounting Standards Codification;
 
(d)
gains or losses from sales of property and equipment unless the sale has been consummated prior to the filing of financial guidance;
 
(e)
capital expenditures related to completion activities on exploratory wells or acquisitions of proved properties until the expenditures are estimable and likely to occur; and
 
(f)
revenues and operating expenses related to Desta Drilling, L.P., a wholly-owned subsidiary of the Company which provides contract drilling services for the Company and third parties.




 
 
 

Summary of Estimates

The following table sets forth certain estimates being used to model our anticipated results of operations for the fiscal year ending December 31, 2012.  Each range of values provided represents the expected low and high estimates for such financial or operating factor.


 
Estimated Ranges
 
Year Ending
 
December 31, 2012
   
   
(Dollars in thousands, except per unit data)
  
Average Daily Production:
    
Oil (Bbls)                                                  
  
10,850 to 11,050
Gas (Mcf)                                                  
  
22,000 to 24,000
Natural gas liquids (Bbls)                                                  
  
1,000 to 1,100
Total oil equivalents (BOE)                                                  
  
15,517 to 16,150
     
Price Differentials to NYMEX:
    
Oil                                                  
  
93% to 95%
Gas                                                  
  
120% to 140%
Natural gas liquids (based on oil)
  
40% to 50%
     
Other Costs and Expenses:
    
Production expenses:
    
Direct costs ($/BOE)                                                
$
18.00 to 19.00
Production taxes (% of sales)                                                
  
5% to 6%
     
General and Administrative:
    
Excluding non-cash compensation
$
28,000 to 30,000
Non-cash compensation                                                
$
7,000 to 9,000
     
DD&A:
    
Oil and gas ($/BOE)                                                
$
21.00 to 23.00
Other                                                
$
5,000 to 7,000
     
Exploration costs:
    
Abandonments and impairments
$
2,000 to 4,000
Seismic and other                                                
$
10,000 to 12,000
     
Interest expense (cash rates):
    
$350 million Senior Notes due 2019
  
7.75%
Bank credit facility                                                
  
LIBOR plus (175 to 275 bps)
     
Effective Federal and State Income
    
  Tax Rate:
    
Current                                                  
  
0%
Deferred                                                  
  
36%
     




 
 
 

Capital Expenditures

The following table sets forth, by area, our planned capital expenditures for the year ending December 31, 2012.


   
Planned
        
   
Expenditures
    
2012
  
   
Year Ending
    
Percentage
  
   
December 31, 2012
    
of Total
  
   
(In thousands)
        
Drilling and Completion:
            
Permian Basin Area:
            
Delaware Basin
   $ 230,100       51 %
Other
     86,600       20 %
Austin Chalk/Eagle Ford Shale
     22,200       5 %
Other
     9,700       2 %
      348,600       78 %
Leasing and seismic                                                
     80,700       18 %
Exploration and development                                                
     429,300       96 %
Facilities and other                                                
     20,200       4 %
Total capital expenditures                                            
   $ 449,500       100 %
                 

We currently plan to spend approximately $429.3 million on exploration and development activities during fiscal 2012 as compared to our previous estimate of $384.6 million.  Most of the $44.7 million increase in estimated expenditures relates to higher drilling and completion costs in the Delaware Basin due in part to our bearing a higher percentage of drilling and completion costs in wells in which Chesapeake elected not to participate for its 25% retained working interest.  Our actual expenditures during 2012 may vary significantly from 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 increase or decrease our actual expenditures during the remainder of fiscal 2012.

Accounting for Derivatives

The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to June 30, 2012.  The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:
   
Oil
    
Gas
  
   
Bbls
    
Price
    
MMBtu (a)
    
Price
  
Production Period:
                        
3rd Quarter 2012                              
     757,000     $ 90.30       -     $ -  
4th Quarter 2012                              
     702,000     $ 90.40       -     $ -  
2013                              
     1,913,000     $ 97.20       1,480,000     $ 3.34  
2014                              
     600,000     $ 99.30       -     $ -  
      3,972,000               1,480,000          
                                        
(a)   One MMBtu equals one Mcf at a Btu factor of 1,000.
  

We did not designate any of the derivatives shown in the preceding table 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, will be recorded as other income (expense) in our statement of operations.

 
 
 


Volumetric production payment

In March 2012, we entered into a volumetric production payment (“VPP”) with a third party.  Under the terms of the VPP, we conveyed a term overriding royalty interest covering approximately 725,000 barrels of oil equivalents (“BOE”) of estimated future oil and gas production from certain properties related to production months from March 2012 through December 2019.  The scheduled remaining volumes for production months from July 2012 through December 2019 are shown below.

   
Oil
    
Gas
  
   
Bbls
    
Mcf
  
Production Period:
            
3rd Quarter 2012                              
     32,788       14,826  
4th Quarter 2012                              
     31,979       17,558  
2013                              
     116,941       33,619  
2014                              
     102,011       45,392  
2015                              
     88,954       60,218  
2016                              
     64,808       112,928  
2017                              
     56,785       96,792  
2018                              
     49,455       84,734  
2019                              
     43,820       72,874  
      587,541       538,941  
   

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