CLAYTON WILLIAMS ENERGY INC /DE - FORM 8-K - EX-99.1 - EXHIBIT 99.1 - August 29, 2011

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8-K - FORM 8-K - CLAYTON WILLIAMS ENERGY INC /DEcwei8k82911.htm
EXHIBIT 99.1
CLAYTON WILLIAMS ENERGY, INC.

FINANCIAL GUIDANCE DISCLOSURES FOR 2011

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 each quarter during the year ending December 31, 2011.  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 these periods 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 expenses related to Desta Drilling, L.P., a wholly-owned subsidiary of the Company which provides contract drilling services for the Company.




 
 
 

Summary of Estimates

The following table sets forth actual and certain estimates being used by us to model our anticipated results of operations for each quarter during the fiscal year ending December 31, 2011.  When a single value is provided, such value represents the mid-point of the approximate range of estimates.  Otherwise, each range of values provided represents the expected low and high estimates for such financial or operating factor.  See “Supplementary Information.”

   
Year Ending December 31, 2011
  
   
Actual
    
Actual
    
Estimated
    
Estimated
  
   
First Quarter
    
Second Quarter
    
Third Quarter
    
Fourth Quarter
  
   
(Dollars in thousands, except per unit data)
  
Average Daily Production:
                        
Oil (Bbls)                                    
     9,989       9,736    
9,425 to 9,625
    
10,250 to 10,450
  
Gas (Mcf)                                    
     23,478       24,846    
20,500 to 24,500
    
19,500 to 23,500
  
Natural gas liquids (Bbls)
     922       802    
750 to 850
    
750 to 850
  
Total oil equivalents (BOE)
     14,824       14,679    
13,592 to 14,558
    
14,250 to 15,217
  
                             
Differentials:
                            
Oil (Bbls)                                    
   $ (5.17 )   $ (2.49 )     $(3.50) to $(4.50)       $(3.50) to $(4.50)  
Gas (Mcf)                                    
   $ 1.04     $ 1.18       $0.15 to $0.45       $0.15 to $0.45  
Natural gas liquids (Bbls)
   $ (45.76 )   $ (45.40 )     $(42.00) to $(48.00)       $(42.00) to $(48.00)  
                                 
Costs Variable by Production ($/BOE):
                                
Production expenses (excluding
                                
  production taxes) (a)                                    
   $ 14.67     $ 15.61       $14.75 to $15.75       $14.75 to $15.75  
DD&A – Oil and gas properties
   $ 17.46     $ 18.31       $17.50 to $18.50       $17.50 to $18.50  
                                 
Other Revenues (Expenses):
                                
Natural gas services:
                                
Revenues                                
   $ 409     $ 365       $450 to $550       $450 to $550  
Operating costs                                
   $ (263 )   $ (285 )     $(300) to $(500)       $(300) to $(500)  
Exploration costs:
                                
Abandonments and impairments
   $ (877 )   $ (174 )     $(250) to $(750)       $(250) to $(750)  
Seismic and other                                 
   $ (1,278 )   $ (2,167 )        $(500) to $(2,500)          $(500) to $(2,500)  
DD&A – Other (b)                                    
   $ (193 )   $ (153 )     $(250) to $(350)       $(250) to $(350)  
General and administrative (b) (c)
   $ (5,025 )   $ (5,405 )     $(5,100) to $(5,300)       $(5,900) to $(6,100)  
Interest expense                                    
   $ (6,412 )   $ (9,175 )     $(9,200) to $(9,400)       $(8,800) to $(9,000)  
Other income (expense)
   $ 1,087     $ 1,900       $(450) to $(550)       $(450) to $(550)  
Gain (loss) on sales of assets, net
   $ 13,376     $ 842       -       -  
                                 
                                 
Effective Federal and State Income
                                
  Tax Rate:
                                
Current                                    
     0 %     0 %     0%       0%  
Deferred                                    
     36 %     36 %     36%       36%  
                                 
Weighted Average Shares Outstanding
                                
  (In thousands):
                                
Basic                                    
     12,156       12,162       12,162       12,162  
Diluted                                    
     12,156       12,163       12,163       12,163  
                                       
(a)    Our current guidance for production expenses excludes production taxes. Historically, production taxes have ranged from 5% to 6 % of oil and gas sales.
  
(b)    Excludes amounts derived from Desta Drilling, L.P.
  
(c)    Excludes non-cash employee compensation.
  
   

Oil and Gas Production

We have revised downward our expected oil and gas production for the remainder of 2011 in connection with the shift in capital spending to the Reeves County Wolfbone play.  Since our last guidance in May 2011, we have reduced the planned rig count in Andrews County from 3 rigs to 1 and have dropped both rigs previously allocated to the Austin Chalk in order to allocate resources to our Wolfbone play.  In addition, estimated production from the Andrews Wolfberry play was revised downward due to continuing frac delays and revisions in production based on well performance.


 
 
 

Capital Expenditures

The following table sets forth, by area, our actual expenditures for exploration and development activities for the first six months of 2011 and our planned expenditures for the year ending December 31, 2011.

   
Actual
    
Planned
        
   
Expenditures
    
Expenditures
    
2011
  
   
Six Months Ended
    
Year Ended
    
Percentage
  
   
June 30, 2011
    
December 31, 2011
    
of Total
  
   
(In thousands)
        
Permian Basin Area:
                  
West Texas - Reeves                                              
   $ 44,300     $ 188,400       49 %
West Texas - Andrews                                              
     77,300       112,300       29 %
West Texas - Other                                              
     13,700       17,700       5 %
Giddings Area:
                        
Austin Chalk/Eagle Ford Shale
     25,900       41,400       11 %
Deep Bossier                                              
     200       13,800       3 %
South Louisiana                                                
     3,400       6,800       2 %
Other                                                
     3,700       4,600       1 %
    $ 168,500     $ 385,000       100 %

We currently plan to spend approximately $385 million on exploration and development activities in fiscal 2011, as compared to $439.4 million reported in our Form 10-Q for the second quarter of 2011.  Substantially all of these cost reductions relate to our planned activities in the Reeves County Wolfbone play and are based on several factors, including a reduction in the total number of wells that we expect to be able to drill in the area during the remainder of the year and an increase in the estimated number of those wells in which we will own a 75% net working interest versus 100%.  These reductions were partially offset by an increase in the estimated cost to drill and complete each of the Wolfbone wells from $3.8 million to $4.2 million as a result of changes in the planned frac design.

We are also purchasing two drilling rigs for our Desta Drilling fleet at a cost of approximately $15.3 million, of which approximately $8 million was spent during the second quarter of 2011.  In addition, we plan to spend approximately $15 million during the remainder of 2011 to begin constructing a gas gathering and treating system to facilitate the transportation and marketing of our Wolfbone oil and gas production in Reeves County.

Our actual expenditures during fiscal 2011 may be substantially higher or lower than these estimates since our plans for exploration and development activities may change during the year.  Other factors, such as prevailing product prices and the availability of capital resources, could also increase or decrease the ultimate level of expenditures during fiscal 2011.  Based on these current estimates, approximately 94% of our planned expenditures for exploration and development activities for fiscal 2011 will relate to developmental prospects, as compared to approximately 95% in fiscal 2010.

 
 
 




Supplementary Information

Oil and Gas Production
The following table summarizes, by area, our actual and estimated daily net production for each quarter during the year ending December 31, 2011.  These estimates represent the approximate mid-point of the estimated production range.

   
Daily Net Production for 2011
  
   
Actual
    
Actual
    
Estimated
    
Estimated
  
   
First Quarter
    
Second Quarter
    
Third Quarter
    
Fourth Quarter
  
Oil (Bbls):
                        
Permian Basin Area:
                        
West Texas - Andrews                                           
     2,607       2,585       2,744       3,014  
West Texas - Reeves                                           
     -       11       141       1,087  
West Texas - Other                                           
     3,570       3,095       3,217       3,010  
Austin Chalk/Eagle Ford Shale
     3,329       3,335       2,978       3,011  
South Louisiana                                             
     414       493       380       163  
Other                                             
     69       217       65       65  
Total                                           
     9,989       9,736       9,525       10,350  
                                 
Gas (Mcf):
                                
Permian Basin Area:
                                
West Texas - Andrews                                           
     1,588       1,719       2,011       2,207  
West Texas - Reeves                                           
     7       25       -       -  
West Texas - Other                                           
     12,333       10,457       10,272       9,690  
Giddings Area:
                                
Austin Chalk/Eagle Ford Shale
     1,940       2,177       2,195       2,190  
Cotton Valley Reef Complex
     2,953       2,931       2,435       2,315  
South Louisiana                                             
     3,149       6,134       4,576       4,087  
Other                                             
     1,508       1,403       1,011       1,011  
Total                                           
     23,478       24,846       22,500       21,500  
                                 
Natural Gas Liquids (Bbls):
                                
Permian Basin Area:
                                
West Texas - Andrews                                           
     364       368       344       355  
West Texas - Other                                           
     255       151       195       184  
Austin Chalk/Eagle Ford Shale
     226       183       196       196  
Other                                             
     77       100       65       65  
Total                                           
     922       802       800       800  

Accounting for Derivatives
The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to June 30, 2011.  The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:
   
Oil
    
Gas
  
   
Bbls
    
Price
    
MMBtu (a)
    
Price
  
Production Period:
                        
3rd Quarter 2011                              
     547,000     $ 83.78       1,560,000     $ 7.07  
4th Quarter 2011                              
     729,000     $ 87.56       1,500,000     $ 7.07  
2012                              
     2,649,000     $ 95.75       -     $ -  
2013                              
     1,189,000     $ 99.92       -     $ -  
      5,114,000               3,060,000          
                                        
(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.

CLAYTON WILLIAMS ENERGY INC /DE Reports