February 21, 2012
Via EDGAR and Fax
United States Securities and Exchange Commission
Division of Corporation Finance
100 F. St., N.E.
Washington, D.C. 20549
Attn: Mr. H. Roger Schwall
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Re:
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Comstock Resources, Inc.
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Form 10-K for the Fiscal Year Ended December 31, 2010
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Filed February 22, 2011
Response Letter Dated January 19, 2012
File No.: 1-03262
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Ladies and Gentlemen:
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The following are the responses of Comstock Resources, Inc. ("Comstock" or the "Company") to the comments contained in the Staff's comment letter dated February 17, 2012 (the "Comment Letter") concerning the above-referenced Form 10-K (the "10-K"), and our Response Letter dated January 19, 2012 (the "January 12 Response Letter") to the Staff comments dated December 28, 2011. The responses are numbered to correspond to the numbers of the Comment Letter.
Form 10-K for the Fiscal Year Ended December 31, 2010
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1.
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For your operated property production costs, we have assumed that have included expenses you incurred performing activities similar to those for which you are proportionally reimbursed by the COPAS charges paid by your non-operating partners. If you have not, please address the reasons for this omission.
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We can confirm to you that the producing overhead costs attributed to our operated wells are determined on the same basis as producing overhead that is billable to third parties under joint operating agreements. We have included producing overhead costs, even on 100% owned wells which may not have a contracted producing overhead rate, using rates that are similar to those we use to bill out producing overhead to third parties who are working interest owners.
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2.
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The first response in your January 19, 2012 letter indicates you attribute overhead to each of your fields “due to the generally fixed nature of these costs.” It is our experience that the property operator applies producing well overhead on a well basis to the monthly joint interest billing charged to non-operating partners (“COPAS overhead). Please explain to us the reasons that you do not attribute such overhead on a well basis and compare the figures for the two cases. Address the number of marginal wells (if any) that would be uneconomic due to these COPAS charges.
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Securities and Exchange Commission
February 21, 2012
Page 2
Our reserves engineering department has recomputed our reserve reports as of December 31, 2010 and 2011 in order to attribute the producing overhead charges to each well in the reserve report during the period that the reserve estimates assume that the well has been producing in order to reflect how these costs would actually be billed. Accordingly the expense would be taken into account in determining when each well reaches its economic limits of production based on the assumed constant oil and natural gas prices used in this estimate. The effect of this change in methodology was as follows:
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Oil
(MBbls)
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Natural
Gas
(MMcf)
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FNR Value
(000's)
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PV 10 Value
(000's)
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| 2010 Constant Price Reserves | |||||||||||
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Original estimates
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4,219
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1,025,633
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$
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1,608,859
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$
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797,626
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Revised estimates
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4,219
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1,025,633
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1,806,724
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821,523
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Difference
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—
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—
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$
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197,865
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$
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23,897
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| % Difference | — | — | 12% | 3% | |||||||
| 2011 Constant Price Reserves | |||||||||||
| Original estimates | 32,019 | 1,118,632 | $ | 3,222,850 | $ | 1,486,973 | |||||
| Revised estimates | 32,019 | 1,118,632 | 3,384,193 | 1,510,622 | |||||||
| Difference | — | — | $ | 161,343 | $ | 23,649 | |||||
| % Difference | — | — | 5% | 2% | |||||||
We did not observe any individual wells in either of our reserve reports dated December 31, 2010 or December 31, 2011 that became uneconomic due to the change in methodology for applying overhead costs.
We also noted that the field level overhead costs were higher in our original reserve reports than they were in the revised reserve reports that applied these costs to the individual wells. This was due to the fact that the field level overhead in our original reserves estimates had not been properly declining as the number of producing wells declined in future periods.
We believe the differences in undiscounted (FNR Value) and discounted (PV 10 Value) for the years ended December 31, 2010 and 2011 are immaterial, as all differences are less than 5% of the totals except for the FNR Value in 2010, and these differences have no significant effect on disclosures other than that they would increase the amounts disclosed in our standardized measure presentations. We accordingly do not believe it is necessary to amend our reserves information for 2010 or modify our methodology for our 2011 reporting. We also observe that, since both methods had no effect on proved reserve quantities, there was no impact on our depletion and impairment computations in either of these two calendar years.
Securities and Exchange Commission
February 21, 2012
Page 3
Based upon this analysis, we acknowledge that attributing overhead costs to each well over the life of its production results in a more accurate application of these costs in computing estimates of proved oil and natural gas reserves, and we would accordingly change our methodology in years beginning after December 31, 2011.
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3.
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In part, your second response states “We can verify to you that the proved undeveloped locations reflected in our 2010 SEC reserve estimates were either drilled in 2011 or will be drilled in future years.” Also, your third response includes “We anticipate drilling such [proved undeveloped] wells based on our expectation of future oil and natural gas prices as well as the need to meet certain drilling obligations in order to retain leasehold interests and to properly manage reservoir performance.” Please affirm to us that you will drill your disclosed year-end 2010 and year-end 2011 proved undeveloped reserves within five years of booking if the prevailing market prices at scheduled spud date are equal to or higher than the prices at which the PUD reserves were booked.
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We can affirm to you that we intend to drill our disclosed year-end 2010 and year-end 2011 proved undeveloped reserves within five years of booking if the prevailing market prices at scheduled spud date are equal to or higher than the prices at which the proved undeveloped reserves were booked. As previously communicated, we also propose to include a disclosure similar to the following in future filings (which has been updated from our response dated January 19, 2012):
"Our estimates of crude oil and natural gas reserves include [218 Bcfe as of December 31, 2010] related to undrilled wells that have positive undiscounted future cash flows but which, based upon natural gas prices that we use to prepare reserve estimates in accordance with SEC guidelines, have a rate of return that is less than the 10% discount rate used in the Standardized Measure. We anticipate drilling these proved undeveloped locations based on our expectation of future oil and natural gas prices as well as the need to meet certain drilling obligations in order to retain leasehold interests and to properly manage reservoir performance. The Company plans to drill these wells to the extent that prevailing market prices for oil and natural gas are equal to or higher than the prices used in the Standardized Measure. To the extent that oil or natural gas prices are substantially weaker, we may not recover our investment in drilling these wells from future cash flows."
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The Company is responsible for the adequacy and accuracy of the disclosures in its filings;
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staff comments or changes to disclosures in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and
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Securities and Exchange Commission
February 21, 2012
Page 4
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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.
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If you have any questions, please do not hesitate to contact the undersigned at (972) 668-8811.
Very truly yours,
/s/ ROLAND O. BURNS
Roland O. Burns
Senior Vice President and Chief Financial Officer
RDS/
cc: Jack E. Jacobsen, Esq.
Locke Lord LLP