CORRESP 1 filename1.htm BPI Energy Holdings, Inc. Corresp
[Letterhead of BPI Energy Holdings, Inc.]
August 27, 2008
By EDGAR and Fax
United States Securities and Exchange Commission
Division of Corporation Finance
Mail Stop 7010
100 F Street, N.E.
Washington, D.C. 20549-7010
Attention: Christopher J. White, Branch Chief
RE:   BPI Energy Holdings, Inc.
Form 10-K for Fiscal Year Ended July 31, 2007
Filed October 29, 2007
File No. 001-32695
Dear Mr. White,
We have received your comments to the above reference filing set forth in your letter dated July 31, 2008 and addressed to Mr. James G. Azlein, Chief Executive Officer and President of BPI Energy Holdings, Inc. (the “Company”). This letter is on behalf of the Company, and the Company’s responses set forth below correspond with the headings and numbers in your letter. For convenience of review, this letter includes your comments in bold and italics with the Company’s responses below.
Form 10-K for the Fiscal Year Ended July 31, 2007
Engineering Comments
Business, page 1
Recent Developments – GasRock Financing, page 2
1.   We note that “All amounts then outstanding under the Credit Agreement are due and payable on July 25, 2008 (the “Loan Termination Date”), which GasRock may in its discretion extend until July 29, 2011.” Please tell us whether you have repaid these due amounts. If GasRock has extended the due date, explain the additional conditions, if any, that they required as well as any reserve data and technical support you may have furnished. Address whether the royalty due GasRock (page 3) was excluded from your disclosed proved reserves.
 
    As further described in Note 6 and Note 14 to the Company’s unaudited financial statements filed with its first quarter Form 10-Q, on November 29, 2007, the Company entered into an amendment to its Advancing Term Credit Agreement with GasRock LLC (“Credit Agreement”), originally entered into as of July 27, 2007. The amendment

 

 

    extended the date until which the Company may request advances under the Credit Agreement, and the date upon which all amounts outstanding under the Credit Agreement will be due and payable, from July 25, 2008 to January 30, 2009. The date to which GasRock may, at its option, extend the Credit Agreement was extended from July 29, 2011 to January 30, 2013. The amendment also increased the initial commitment under the Credit Agreement from $10.2 million to $10.7 million. The Company drew $9.1 million from this initial commitment on July 27, 2007 and an additional $1.7 million on December 19, 2007. In addition, approximately $1.2 million of interest has been deferred and added to principal under the Credit Agreement. As of July 31, 2008, the balance outstanding under the Credit Agreement is approximately $12.0 million.
 
    GasRock did not impose any additional conditions and the Company was not required to furnish GasRock with any additional technical data in connection with the amendment described above. However, under the terms of the Credit Agreement, the Company is required to furnish GasRock with petroleum engineering reports (“Reserve Reports”) on or before March 31 of each year (but effective as of the preceding December 31) and on or before September 30 of each year (but effective for the preceding July 31). During fiscal year 2008, the Company furnished GasRock with its Reserve Report as of July 31, 2007, which is our normal year-end Reserve Report used as the basis for our disclosures included in the July 31, 2007 Form 10-K, and a Reserve Report as of December 31, 2007. Both Reserve Reports were prepared by Data & Consulting Services, Division of Schlumberger Technology Corporation, Pittsburgh, Pennsylvania (“Schlumberger”). A comparison of remaining gas reserves (MMscf) reported in the two Reserve Reports is as follows:
                 
    December 31,   July 31,
    2007   2007
     
Proved Producing Reserves
     11,971.49       4,555.75  
Proved Non-Producing Reserves
     1,615.22       6,083.13  
Proved Undeveloped Reserves
     4,801.50       5,634.91  
     
Total Proved Reserves
     18,388.21       16,273.79  
       
    Our future royalties due to GasRock have been excluded from proved reserves reported in the July 31, 2007 Reserve Report and disclosed in the July 31, 2007 Form 10-K, as well as the proved reserves reported to GasRock in the December 31, 2007 Reserve Report.
Status of CBM Operations, page 8
2.   We note that you have 91 and 20 productive wells in your Southern and Northern Illinois Basin projects, respectively. Please explain to us, as of your fiscal 2008 year-end, the number of wells in each project that have substantially dewatered. Please compare these projects’ performance with that projected in your year-end 2007 reserve report.

 

 

    As defined in note 2 to the table on page 9 of the Company’s Form 10-K for the fiscal year ended July 31, 2007, a productive well is an exploratory or development well that has been completed and is tied into a gas and/or dewatering system. A productive well may produce only water for a period of time before gas begins to flow through the gas gathering system.
 
    As described under the section titled “Northern Illinois Basin Project” on page 7 of the Company’s Form 10-K for the fiscal year ended July 31, 2007, the 20 productive wells at the Northern Illinois Basin project are comprised of a 10-well pilot project in Shelby County referred to as the Shelby Project and a 10-well pilot project in Macoupin County referred to as the Macoupin Project. These 20 wells have been tied into a dewatering system but have not been tied into a gas gathering system and any unused gas that is produced from these wells is being flared. Consequently, the 20 productive wells at the Company’s Northern Illinois Basin project were excluded from the estimate of the Company’s proved reserves as of July 31, 2007.
 
    Of the 91 productive wells drilled at the Company’s Southern Illinois Basin project as of July 31, 2007, 84 wells were classified as proved developed producing (“PDP”) wells in the reserve report prepared by Schlumberger. The remaining seven wells were classified as proved developed non-producing (“PDNP”) wells. The Company believes that the majority of the 84 PDP wells have substantially dewatered as of July 31, 2008. Average gas production from these 84 wells for the fiscal year ended July 31, 2008 was approximately 70% of projected production in the Company’s July 31, 2007 reserve report.
 
    The forecasted production of PDP wells at the Southern Illinois Basin project is a factor of the type curve developed by Schlumberger based on a reservoir simulation model which utilizes known reservoir data and history matching of zero-time production data of existing producing wells. This type curve was then applied to all PDP wells based on their producing rate at July 31, 2007.
Average Sales Prices and Production Costs, page 10
3.   We note your statement, “Production costs include a significant amount of fixed expenses required to operate a minimum number of our wells. As the number of wells and production increase, these costs are expected to decrease on a per unit basis as they are spread over a greater amount of production.” Please furnish us with fixed and variable portions of your unit production costs and compare them with the production costs you used in your standardized measure.
 
    During the fiscal year ended July 31, 2007, the Company completed a comprehensive review of its historical production costs for purposes of estimating the fixed and variable components of such costs. The results of this review were used as the basis for forecasting production costs in its July 31, 2007 reserve report, including the standardized measure of discounted future net cash flows relating to proved gas reserves disclosed in summary on page 10 and in detail on page F-34 of the Company’s July 31, 2007 Form 10-K. The following summary of the fixed and variable components of the Company’s

 

 

    forecasted production costs is representative of actual costs for the fiscal year ended July 31, 2007 after adjustments for known non-recurring items:
         
Monthly fixed costs per well:
        
Labor and benefits
   $ 265  
Repairs and maintenance
     190  
Other
     120  
 
      
Total monthly fixed costs per well
   $ 575  
 
      
 
        
Variable costs of gas production per Mcf —
        
Compression rental
   $ 0.40  
 
      
 
        
Variable costs of water production per barrel:
        
Workovers
   $ 0.10  
Fuels and utilities
     0.05  
 
      
Total variable costs of water production per barrel
   $ 0.15  
 
      
Financial Statements, page F-1
Note 19 – Supplemental Gas data, page F-31
Summary of Changes in Proved Reserves (Unaudited), page F-32
4.   We note significant changes in your 2006 and 2007 proved reserves due to “Extensions and discoveries” and to “Revisions of previous estimates.” Please tell us the reasons for these changes and your consideration of disclosing such reasons pursuant to SFAS 69, paragraph 11.
 
    Extensions and Discoveries
 
    Extensions and discoveries for each year represent additions to proved reserves resulting from the net increase in the total wells drilled on our Southern Illinois Basin project as follows:
                         
    July 31,   July 31,   Increase
    2006   2005   (Decrease)
     
PDP Wells
     86       27       59  
PDNP Wells
     —       16       (16 )
PUD Wells
     38       51       (13 )
     
Total Wells – Proved
     124       94       30  
     
                         
    July 31,   July 31,   Increase
    2007   2006   (Decrease)
     
PDP Wells
     84       86       (2 )
PDNP Wells
     25       —       25  
PUD Wells
     42       38       4  
     
Total Wells – Proved
     151       124       27  
     

 

 

    Each new well drilled during the fiscal year ended July 31, 2006 represented approximately 151 MMcf of proved reserves, resulting in an increase to proved reserves due to extensions and discoveries of approximately 4,528 MMcf during the year.
 
    Each new well drilled during the fiscal year ended July 31, 2007 represented approximately 135 MMcf of proved reserves, resulting in an increase to proved reserves of approximately 3,645 MMcf during the year. In addition, the Company completed additional seams and identified additional proved reserves in existing PDP wells during the fiscal year ended July 31, 2007, resulting in an increase to proved reserves of approximately 1,789 MMcf for a total increase to proved reserves due to extensions and discoveries of approximately 5,434 MMcf.
 
    The Company believes that its disclosure in Note 17 of the financial statements included in its Form 10-K for the fiscal year ended July 31, 2007 that all of its proved reserves are located at its Southern Illinois Basin project provides a reasonable basis for a reader to conclude that all extensions and discoveries of proved reserves relate to new wells being drilled at this project.
 
    Revisions of Previous Estimates
 
    Revisions of previous estimates resulted in downward adjustments to proved reserves of 2,808 MMcf and 2,186 MMcf during the fiscal years ended July 31, 2007 and 2006, respectively. These adjustments are primarily the result of lower production than previously estimated and, to a lesser extent, shorter estimated economic lives of wells due to decreases in the Henry Hub spot prices as of each respective fiscal year-end.
 
    As discussed in Item 7 of the Company’s Form 10-K for the fiscal year ended July 31, 2007, the Company is an early stage CBM exploration and production company with limited production history. The Company generated its initial sales of CBM in January 2005. Also, as discussed in Note 1 (under “Use of Estimates”) to the financial statements filed with the Company’s Form 10-K for the fiscal year ended July 31, 2007, there are numerous uncertainties in estimating the quantity of reserves and in projecting future rates of production. Although the Company’s intention is to disclose proved reserves as accurately as possible, it believes that due to these facts and circumstances, revisions to previous estimates are not contrary to the normal course of business at this early stage of development in the Illinois Basin. However, the Company acknowledges that the aggregation of current disclosures and/or additional disclosures for certain significant changes in reserves may be helpful to readers and will be incorporated into future filings where appropriate.
In connection with these responses to your letter, the Company acknowledges that:
  §   The Company is responsible for the adequacy and accuracy of the disclosure in the filing;
 
  §   Staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and

 

 

  §   The Company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.
If you have any questions regarding these responses, please call me at (440) 248-4200.
Very truly yours,
/s/ Randall L. Elkins
 
    
Randall L. Elkins
    
Controller and Acting Chief Financial Officer
    
BPI Energy Holdings, Inc.
    
cc:      James G. Azlein, President and Chief Executive Officer