| Re: | Callon Petroleum Company Form 10-K for the Fiscal Year Ended December 31, 2009 Filed March 12, 2010 Response Letter Dated October 22, 2010 File No. 001-14039 |
| 1. | Your response to comment four in our September 28, 2010 letter states that you estimated “type curve” parameters for Haynesville recoverable reserves estimation. |
| • | As “recoverable reserves” are not categorized per the definitions in Rule 4-10(a) of Regulation S-X, please explain how you have complied with the Instruction to |
| Item 1202 pertaining to the non-disclosure of estimates of oil or gas resources other than reserves. | |||
| • | Please furnish to us decline curves that illustrate the values for IP, hyperbolic exponent and initial decline rate as well curves for the Haynesville wells you have drilled to date; and describe the methods you used to establish the 6% terminal decline rate. | ||
| • | Please reconcile by line item the $9.9 million and $8.8 million well costs with the costs you actually incurred. | ||
| Please direct these items and those requested below to: | |||
| Ronald M. Winfrey, P.E. Petroleum Engineer Division of Corporation Finance U.S. Securities & Exchange Commission 100 F Street, N.E. Washington, DC 20549-4628 |
| Response: | With respect to the first bullet point, the disclosure related to recoverable reserves in the Haynesville Shale Unit is intended to present an idea of the general economics of drilling wells in that area. The number presented is an average number relating to hypothetical wells. Accordingly, because no actual reserve number is estimated for specific interests owned by the Company, we believe Item 1202 is not applicable to this type of general disclosure. | |
| With respect to the second bullet point, the values for hyperbolic exponent and initial decline rate were based on data from 72 producing Haynesville wells that had sufficient monthly production data to fit a decline curve. The production data was downloaded from IHS Energy web site, which provides public data for producing wells in Louisiana through an online database. Exhibit A (provided supplementally) is a map of those 72 wells. IP was based on 12 wells in close proximity to the section where Callon has working interests in the Haynesville shale. Those 12 wells are highlighted in green color on Exhibit A. | ||
| Exhibit B (provided supplementally) lists each of the 72 wells with property details including API number, location and operator. The list also includes IP values for each well. These IP values were obtained from Scout Tickets downloaded from IHS Energy Online database. |
| Exhibit C (provided supplementally) is the plot of ARIES Trend Analysis based on the production data of aforementioned 72 wells. The trend line shows that hyperbolic exponent, b=1.0 and initial decline, De=77%. Since this trend line is based on monthly data, it does not directly provide an IP rate. The IP rate of 15,000 Mcf/d is conservatively based on 80% of the average IP of the 12 wells highlighted in Exhibit A as map locations and in Exhibit B as line items. | ||
| Exhibit D (provided supplementally) is 72 pages with each page showing the production data and decline curve fit along with hyperbolic decline parameters for the Haynesville wells downloaded from IHS. | ||
| Exhibit E (provided supplementally) shows the current daily production data and decline curve forecast for George R Mills 1H #1 well that Callon drilled this year. This is the only Haynesville shale gas well in the current 2010 plan of the company. | ||
| The 6% terminal decline rate is based on the current industry practices of using hyperbolic decline fit and 4% to 8% terminal decline rate in shale gas formations. Callon chose to use 6%. The practice of using terminal decline rate stems primarily from tight gas sands. Studies (e.g. SPE paper No. 109625 or SPE Paper No. 138149) have shown that terminal decline rates ranged from about 1.5% to 5% in hydraulic fractured tight-gas sand reservoirs. Although there is not sufficient history of terminal decline rates in shale gas reservoirs, the practice used in tight-gas formations is carried over to shale gas since the fluid flow and production performance behavior is very similar. | ||
| With respect to the third bullet point, the line by line cost comparison is attached as Exhibit F (provided supplementally). The costs defined in the first tab of the spreadsheet were developed in October 2009, and compares the cost to drill the initial well with a pilot hole with the cost to drill subsequent wells without a pilot hole. The costs detailed in the second tab were developed in May 2010, and compares the cost of the actual AFE distributed to partners for approval to the original cost estimate developed in October 2009. Finally, the third tab compares the costs of the approved AFE to the actual costs incurred to drill and complete the George Mills #1 well which was completed in November 2010. |
| In summary, the actual cost to drill and complete the well exceeded the original estimate developed in October 2009, by $2.7 MM or 27.5%. The additional costs are due to significant inflationary pressures on completion services due to increased industry activity; the operating efficiency of the drill rig due to crew attrition and continuity; the added 900 feet of horizontal section; and the addition of two fracture stimulation stages to efficiently complete the extended horizontal section. | ||
| The additional horizontal section was required since the surface location for the well was moved to the north on the adjacent lease in order to gain access from local landowners and facilitate permitting which subsequently required additional fracture stimulation stages to efficiently complete the well. | ||
| The operating efficiency of the drill rig was significantly reduced due to excessive crew attrition as a result of the sale of the rig to a Nigerian company. Due to the inexperienced crews, additional safety leadership was added and daily operations activities were performed at a measured pace to ensure crew safety resulting in additional days to complete the project. |
| 2. | Your response to prior comment five indicates that you attributed Medusa reserves to your mid-2009 “subsurface technical re-evaluation of the Medusa Field”. Please furnish to us engineering and geological exhibits that support your Medusa prove reserve estimates; and explain the extent to which you utilized seismic analysis including productive area estimation in calculating these quantities. |
| Response: | The requested information has been provided separately as Exhibits G and H pursuant to a request for confidential treatment pursuant to 17 CFR 200.83. The Company hereby requests that Exhibits G and H be returned to the Company upon completion of the Staff’s review and that, pending their return, Exhibits G and H be withheld from release as containing competitively sensitive, proprietary business information of the Company. |
| 3. | In our prior comment 10 we asked for an illustration of your adjustments to bench mark pricing for use in the standardized measure. The bench mark prices implicit in your presentation appear to differ from West Texas Intermediate and Henry Hub. Please tell us the source of these bench mark prices. | |
| Response: | ||
| For gas prices, the sources are as follows (the gas price is adjusted to reflect the value of plant products): |
| Medusa: | Tennessee 500 | |
| Medusa Lease fuel: | Tennessee 500 | |
| Habanero: | ANR, LA/Transco Zone 3 | |
| EC 257: | NGPL, LA/Tennessee 800 | |
| EC #2: | Tennessee 800 | |
| WC 295: | Tennessee 800/Transco Zone 2 | |
| EC 109: | Transco Zone 2 | |
| Mobile 908: | Flordia Gas Zone 3 | |
| Mobile 908 Lease fuel: | Flordia Gas Zone 3 | |
| HI 494: | ANR, LA | |
| Permian: | El Paso Natural Gas/Northern Natural Gas/OPIS Index | |
| Other: | Various |
| For oil pricing, the sources are as follows: |
| Medusa: | (ConocoPhilips West Texas/New Mexico Intermediate +/- Platts P+) +/- (Platts MARS/WTI Trade Differential) | |
| Habanero: | (Flint Hills Resources West Texas/New Mexico Intermediate + Argus P+) +/- (Argus Bonita WTI Trade Differential) |
| HI 119: | (ConocoPhilips West Texas/New Mexico Intermediate +/- Platts P+) +/- (Platts LLS/WTI Trade Differential) | |
| EC #2: | NYMEX | |
| Permian: | Enterprise WTI + Argus Plus + Argus Midland Cushing WTI differential | |
| Other: | Various |
| 4. | We note the lease fuel designation for the Medusa and Mobile 908 properties’ natural gas prices. Please tell us the volumes of proved lease fuel reserves you have claimed and your treatment of these reserves in the standardized measure. |
| Response: | Callon’s reserve report includes 1,406.7 MMcf and 183.8 MMcf of proved lease fuel for Medusa and Mobile, respectively. The lease fuel is a reduction of produced gas which equals the sales gas column in the reserve report. The sales gas column is the total proved gas volumes Callon uses for reporting. In the standardized measure table, the lease fuel would be netted in the future cash inflows. Callon only receives cash inflows for sales volumes. In the changes in standardized measure table, the lease fuel would be in the line “sales and transfers, net of production costs.” |
| Sincerely, | ||||
| /s/ George G. Young III | ||||
| George G. Young III | ||||
| Haynes and Boone LLP 1221 McKinney Street, Suite 2100 Houston, Texas 77010 (713) 547-2081 (Direct) (713) 547-2600 (Fax) guy.young@haynesboone.com | ||||
| cc: | Karl Hiller Craig H. Arakawa Lily Dang Division of Corporation Finance Securities and Exchange Commission |
