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September 15, 2011
Via EDGAR and Fedex
United States Securities and Exchange Commission
Division of Corporation Finance
100 F. St., N.E.
Mail Stop 2682
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
Definitive Proxy Statement on Schedule 14A
Filed April 4, 2011
File No.: 1-03262
Ladies and Gentlemen:
The following are the responses of Comstock Resources, Inc. ("Comstock" or the "Company") to the comments contained in the Staff's comment letter dated August 31, 2011 (the "Comment Letter") concerning the above-referenced 10-K (the "10-K") and Definitive Proxy Statement on Schedule 14A. The responses are numbered to correspond to the numbers of the Comment Letter.
Form 10-K for the Fiscal Year Ended December 31, 2010
Business and Properties, page 6
Oil and Natural Gas Reserves, page 14
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1.
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Item 1202(a)(6) of Regulation S-K requires a registrant disclosing material additions to its reserve estimates to provide a general discussion of the technologies used to establish the appropriate level of certainty for reserves estimates from material properties included in the total reserves disclosed. With a view toward possible disclosure, please explain to us the methods you used to establish reasonable certainty of economic producibility of the incremental natural gas reserves. Address your historical results in applying these methods.
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Lee Keeling and Associates Inc. ("Lee Keeling"), an independent petroleum engineering firm, prepares our annual reserve estimates in accordance with the definitions and guidelines established by the Securities and Exchange Commission ("SEC"). It is our understanding that, in connection with estimating future production for establishing proved oil and gas reserves, Lee Keeling employs technologies that have historically been demonstrated to show results with consistency and repeatability.
Securities and Exchange Commission
September 15, 2011
Page 2
Proved reserves that are attributable to existing producing wells are primarily determined using decline curve analysis and rate transient analysis, which incorporates the principles of hydrocarbon flow. Proved reserves attributable to producing wells with limited production history and for undeveloped locations are estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. Technologies relied on to establish reasonable certainty of economic producibility include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available production data, seismic data and well test
data.
In connection with estimating proved undeveloped reserves for our December 31, 2010 reserve report, reserves on undrilled acreage were limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled. Using empirical evidence, we utilize control points and sample sizes to show continuity in the reservoir. We have experienced a very high rate of success developing the undeveloped reserves that were reflected in our December 31, 2010 reserve report to date in 2011.
Lee Keeling has prepared our reserve estimates for the past 14 years, and except for changes required to maintain compliance with the SEC guidance on reserves estimation, the procedures described above have been consistently applied during this period.
In our future filings on Form 10-K we will include this, or similar language, as appropriate.
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2.
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We note your disclosure stating that your reservoir management group, comprised of qualified petroleum engineers, works with Lee Keeling and Associates, Inc. to ensure that all data you provide is properly reflected in the final reserves estimates, and you consult with Lee Keeling throughout the reserves estimation process on technical questions regarding the reserve estimates. Please expand your disclosure to include more detailed descriptions of the internal controls you use in your reserves estimation effort and the qualifications of the technical person primarily responsible for overseeing the preparation of your reserve estimates.
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In response to your comments, we propose to include the following language in our filing on Form 10-K for the year ending December 31, 2011 with respect to internal controls over the reserve estimation process and the qualifications of personnel involved in the reserves estimation process:
"The estimates of our oil and natural gas reserves were determined by Lee Keeling and Associates, Inc. ("Lee Keeling"), an independent petroleum engineering firm. Lee Keeling has been providing consulting engineering and geological services for over fifty years. Lee Keeling's professional staff is comprised of qualified petroleum engineers who are experienced in all productive areas of the United States. The technical person responsible for review of our reserve estimates at Lee Keeling meets the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to Estimating and Auditing of Oil and Gas Reserves Information
promulgated by the Society of Petroleum Engineers. Lee Keeling does not own any interests in our properties and is not employed on a contingent fee basis.
Securities and Exchange Commission
September 15, 2011
Page 3
We have established, and maintain, internal controls designed to provide reasonable assurance that the estimates of proved reserves are computed and reported in accordance with rules and regulations promulgated by the SEC. These internal controls include documented process workflows, employing qualified professional engineering and geological personnel, and on-going education for personnel involved in our reserves estimation process. Our internal audit function routinely tests our processes and controls. Inputs to our reserves estimation process, which we provide to Lee Keeling for use in their reserves evaluation, are based upon our historical results for production history, oil and natural
gas prices, lifting and development costs, ownership interests and other required data. Our Asset Management Group, comprised of qualified petroleum engineers, works with our accounting, land, marketing and other groups in order to accumulate the information required for the reserves estimation process. During the reserves estimation process our petroleum engineers work with Lee Keeling to ensure that all data we provide is properly reflected in the final reserves estimates and they consult with Lee Keeling throughout the reserves estimation process on technical questions regarding the reserve estimates. We also regularly communicate with Lee Keeling throughout the year about our operations and the potential impact of operational changes and events on our reserve estimates.
Our Asset Manager, who reports to our Vice President of Operations, is the primary person in charge of overseeing our reserve estimates. He has a degree in Petroleum Engineering and has over seventeen years of experience in various technical and commercial roles within the oil and gas industry. He is a member of the Society of Petroleum Engineers and he currently holds an EIT/FE certificate while he continues to work towards becoming a registered engineer in the State of Texas. Working with our Asset Manager is a staff of three petroleum engineering professionals. The average experience of our petroleum engineers is 18 years. Our Vice President of Operations also
reviews and approves our final reserve estimates. Our Vice President of Operations has a degree in Petroleum Engineering and has over 27 years of experience holding various technical and managerial roles in the oil and gas industry."
Securities and Exchange Commission
September 15, 2011
Page 4
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Risk Factors, page 27
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Federal hydraulic fracturing legislation could increase our costs, page 28
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3.
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Please tell us, with a view toward disclosure:
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• your acreage subject to hydraulic fracturing;
At this time, substantially all of our undeveloped acreage would require the use of hydraulic fracturing techniques to be developed economically.
• the percentage of your reserves subject to hydraulic fracturing;
At this time, we believe that substantially all of our nonproducing proved reserves would require the use of hydraulic fracturing techniques to be converted to proved producing reserves.
• the anticipated costs and funding associated with hydraulic fracturing activities; and
The amount and timing of the costs that we will incur for hydraulic fracturing services will vary over time based upon our well drilling schedule, the availability of completion services, and the availability of completion materials. We estimate we will incur approximately $277.0 million for hydraulic fracturing services in connection with our 2011 drilling and completion program. This represents the estimated net costs to us expected to be incurred completing 103 wells (75.1 wells net to us), including the costs to complete approximately 80 wells (71.6 net to us) which we operate. As stated in our filing on Form 10-Q for the quarter ended June 30, 2011, our 2011 capital program
is being funded through a combination of cash flows from operating activity, sales of available for sale marketable securities, a debt offering completed in March 2011 and borrowings under our bank credit facility.
• whether there have been any incidents, citations, or suits related to your hydraulic fracturing operations for environmental concerns, and if so, what your response has
been.
We are not aware of any material incidents, citations or suits related to our hydraulic fracturing operations.
Securities and Exchange Commission
September 15, 2011
Page 5
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4.
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With regard to your use of hydraulic fracturing, please also tell us what steps you, or the third-party contractors you hire, have taken to minimize any potential environmental impact. For example, and without limitation, please explain if you:
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• have steps in place to ensure that your drilling, casing, and cementing adhere to known best practices;
• monitor the rate and pressure of the fracturing treatment in real time for any abrupt change in rate or pressure;
• evaluate the environmental impact of additives to the hydraulic fracturing fluid; and
• minimize the use of water and/or dispose of it in a way that minimizes the impact to nearby surface water.
With regards to hydraulic fracturing, we take the following steps to minimize the potential environmental impact:
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We adhere to all state and federal regulatory requirements with regards to drilling, casing and cementing operations. We employ experienced engineers to plan and supervise our operations and utilize high quality service providers to perform our drilling and cementing functions. All cement that we utilize in our wells meets regulatory requirements and American Petroleum Institute (“API”) specifications. We only use casing that meets API specifications which is inspected and tested as needed.
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We utilize a combination of on-site supervision and remote real-time monitoring to provide the necessary level of supervision for all hydraulic fracturing treatments. Treating rates and pressures are monitored to identify, diagnose and correct inconsistencies during the treatment. Comstock personnel also monitor the volumes of all water, proppant and chemicals that are used.
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Because of the extremely low concentration of chemical additives used in hydraulic fracturing and the placement of the hydraulic fracturing treatment in the target formation located several thousand feet below the base of groundwater in our operating areas, we have not evaluated the environmental impact of additives to the hydraulic fracturing fluid.
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We use the volume of water in our hydraulic fracturing operations that is designed to provide the highest overall return on investment. We dispose of all produced water in commercial disposal wells, which to the best of our knowledge are properly permitted and operated under applicable state and/or federal regulations. We do not employ the use of surface water discharge to dispose of produced water.
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Securities and Exchange Commission
September 15, 2011
Page 6
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5.
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Please supplementally provide us with a report detailing all chemicals used in your hydraulic fracturing fluid formulation/mixture, in the volume/concentration and total amounts utilized, for representative wells in each of the major resource plays in which you operate.
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This information will be provided to you in a document which is supplemental to this formal response.
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6.
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In light of the public concern over the risks relating to hydraulic fracturing, please review your disclosure to ensure that you have disclosed all material information regarding your potential liability. This would include, for example, your potential liability in connection with any environmental contamination related to your fracturing operations. For example, and without limitation, please address the following with respect to your hydraulic fracturing operations:
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• disclose the applicable policy limits and deductibles related to your insurance coverage;
We maintain insurance in the event of any environmental contamination which could occur in connection with our drilling or completion operations which would include hydraulic fracturing operations. Currently our insurance limits for pollution liability aggregate $26.0 million with a deductible of $25,000 for each occurrence.
• disclose your related indemnification obligations and those of the third parties who perform hydraulic fracturing operations on your wells, if applicable;
All of our hydraulic fracturing operations are conducted by third party contractors. Our third party contractors are responsible for and indemnify us against all claims arising out of personal injury, illness or death of their employees or employees of their subcontractors or claims relating to damage or loss to property caused by the contractor or their subcontractors, unless the property is inside our well bore or is being transported by us. We are responsible for and indemnify our third party contractors against all claims arising out of personal injury, illness or death of our personnel or employees of other contractors that are not a part of their contract or claims relating to damage
or loss of our property or property of other contractors that are not a part of their contract.
Securities and Exchange Commission
September 15, 2011
Page 7
We are responsible for and indemnify our contractors against all claims arising from well control issues or pollution.
• clarify your insurance coverage with respect to any liability related to any resulting negative environmental effects; and
Please refer to the discussion above.
• provide further detail on the risks for which you are insured for your hydraulic fracturing operations.
We also maintain insurance for damage or loss of property for well control issues which would include hydraulic fracturing operations. Such coverage has insurance limits of $26.0 million with a deductible of $25,000 and applies not only to sudden and accidental events, but also gradual events.
Further, in response to the comments received above, and our responses thereto, we propose to revise the Risk Factors included in our future filings with the SEC related to hydraulic fracturing as follows:
"Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as restrict our access to our oil and gas reserves.
Hydraulic fracturing is an essential and common practice that is used to stimulate production of oil and natural gas from dense subsurface rock formations such as shale and tight sands. We routinely apply hydraulic-fracturing techniques in completing our wells. The process involves the injection of water, sand and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations, which are held open by the grains of sand, enabling the oil or natural gas to flow to the wellbore. The use of hydraulic fracturing is necessary to produce commercial quantities of crude oil and natural gas from many reservoirs
including the Haynesville shale, Bossier shale, Eagle Ford shale, Cotton Valley and other tight natural gas reservoirs. Substantially all of our proved oil and gas reserves that are currently not producing and our undeveloped acreage require hydraulic fracturing to be productive. All of the wells being drilled by us in 2011 utilize hydraulic fracturing in their completion. We estimate we will incur approximately $277.0 million for hydraulic fracturing services in connection with our 2011 drilling and completion program. This represents the estimated net costs to us expected to be incurred completing 103 wells (75.1 wells net to us), including the costs to complete approximately 80 wells (71.6 net to us) which we operate.
Securities and Exchange Commission
September 15, 2011
Page 8
The use of hydraulic fracturing in our well completion activities could expose us to liability for negative environmental effects that might occur. Although we have not had any incidents related to hydraulic fracturing operations that we believe have caused any negative environmental effects, we have established operating procedures to respond and report any unexpected fluid discharge which might occur during our operations, including plans to remediate any spills that might occur. In the event that we were to suffer a loss related to hydraulic fracturing operations, our insurance will be net of a $25,000 deductible and our ability to recover costs will be limited to a total aggregate policy
limit of $26.0 million, which may or may not be sufficient to pay the full amount of our losses incurred.
Drilling and completion activities are typically regulated by state oil and natural gas commissions. Our drilling and completion activities are conducted primarily in Louisiana and Texas. Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas and the public of certain information regarding the components used in the hydraulic-fracturing process. Several proposals are before the United States Congress that, if implemented, would subject the process of hydraulic fracturing to regulation under the Safe Drinking Water Act. At the direction of Congress, the EPA is currently conducting an extensive, multi-year study into the potential
effects of hydraulic fracturing on underground sources of drinking water, and the results of that study have the potential to impact the likelihood or scope of future legislation or regulation."
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7.
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In this regard, discuss what remediation plans or procedures you have in place to deal with the environmental impact that would occur in the event of a spill or leak from your hydraulic fracturing operations.
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We have a formal written policy for responding to all types of fluid leaks or spills. In the event of a spill or leak occurring at one of our sites during well drilling and completion operations, our on-site supervisor immediately notifies the Comstock Regulatory Manager of the incident; specifically, what happened, the fluid spilled, the estimated amount spilled, the area impacted and proposed cleanup/remediation actions to be taken. This information is then reported immediately to the appropriate federal and/or state regulatory agencies. The spill/leak is monitored until cleanup/remediation actions have been completed. A written report is then filed with the federal and/or state regulatory agencies
that were initially notified.
Securities and Exchange Commission
September 15, 2011
Page 9
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Financial Statements, page F-1
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Notes to Consolidated Financial Statements, page F-7
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Note (2) Dispositions of Oil and Gas Properties, page F-15
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8.
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We note your discussion of the sale of your oil and gas properties in Mississippi in December 2010 and the related impairment charge. Please provide us with a timeline and a description of the significant events surrounding this transaction. Your response should address, but not necessarily be limited to, the following:
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• When and why the properties involved were first identified for possible sale;
We routinely review the value of our oil and gas properties, and based upon their relative worth, and future development opportunities, we attempt to divest those properties with the lowest prospects for future growth. This is part of our asset management program, which is intended to maximize stockholder value over time.
Our oil and gas properties in Mississippi had been declining as a percentage of our total proved reserves since they were acquired in 2005. At the time of their acquisition, they represented approximately 8% of our total proved reserves. By December 31, 2009 this had declined to just over 4% of our total proved reserves. As these properties are not in a core area for us, in early 2010 we decided to explore a divestiture of these assets. In April 2010 we decided to engage an investment advisor to assist us in soliciting bids for the potential sale of these properties.
• Whether and, if so, when, management initially established a range or other assessment of the terms under which the properties would be sold;
We engaged Scotia Waterous (USA) Inc. on April 26, 2010 to actively market our Mississippi oil and natural gas properties. Based on initial discussions with Scotia Waterous we initially believed the properties could be divested at an amount that approximated our book value of these properties (approximately $100.0 million). Since we had no requirement to sell the Mississippi properties, we did not set a specific price target for these properties but instead elected to make them available for sale and then evaluate the bids to determine whether there were any offers that we would consider to be acceptable. Accordingly, any decision to sell these properties was contingent on the
evaluation of any bids that we received.
• Whether, and, if so, when, you made or received any offers or proposals to sell or buy the properties other than that which ultimately resulted in the transaction. Describe the material terms of any such offers or proposals;
Securities and Exchange Commission
September 15, 2011
Page 10
Solicitations were initiated on or about June 9, 2010, through the transmittal of an introductory letter, which was sent to seven hundred seventy (770) industry representatives. Thirty-four (34) industry representatives responded by executing Confidentiality Agreements. Of the thirty-four (34) industry representatives executing Confidentiality Agreements, twelve (12) accessed the data room which was established for purposes of evaluating these properties. On August 10, 2010, bids to purchase the Mississippi properties were received from a total of six (6) industry representatives. These offers, other than the offer that was ultimately accepted (which is discussed in more detail
below), were generally consistent in the terms and conditions with respect to the offer to purchase, and the bid amounts ranged in value between $25.0 million and $40.0 million.
• When you made or received the initial offer or proposal that ultimately resulted in the transaction. Describe the terms of the initial offer or proposal;
The offer which we ultimately accepted was received on August 10, 2010, and upon concluding preliminary negotiations with the bidder we arrived at a final sale price of $75.0 million on August 18, 2010. This price was finalized in a Purchase and Sale Agreement with Petro Harvester Laurel Holdings, LLC that was executed on October 12, 2010. Our Mississippi oil and gas properties represented the first acquisition by this entity. The purchaser was responsible for securing all of the financing for this transaction, as we typically desire to have no on-going involvement following the divestiture of oil and gas properties. With respect to the transaction, there were several
terms in the Purchase and Sale Agreement that could potentially delay and/or terminate final closing. These included a lengthy due diligence period (60 days) and several key thresholds of materiality with respect to termination rights which, if exceeded, provided that the seller or the purchaser could cancel the transaction. Given the lengthy period of negotiations leading to the finalization of the Purchase and Sale Agreement, the uncertainty of whether the purchaser would be able to obtain the financing in order to close the transaction, the potential for exceeding the termination rights thresholds, and the lengthy due diligence process, substantial uncertainties existed at September 30, 2010, and up and until the actual closing in December, 2010, as to whether this transaction would close. We had no intention of accepting any of the other offers
received in the sales process, and in the event that this transaction did not close, our intent was to retain these properties as part of our on-going oil and natural gas operations.
We evaluated whether the Mississippi properties should be classified as assets held for sale at September 30, 2010 and concluded that we did not satisfy the criteria in Accounting Standards Codification 360-10-45-9 in that as of September 30, 2010 we had not adopted a formal plan of disposal, we were still in negotiations with the ultimate purchaser over material contract terms, and it was uncertain that completion of the sale of these properties within one year was probable.
Securities and Exchange Commission
September 15, 2011
Page 11
As described more fully below, our oil and gas proved properties are assessed for indications of impairment at the end of each fiscal quarter. Based upon the reserve estimates and the capitalized cost of the proved properties located in Mississippi, there were no proved property impairments indicated for these properties during the period of time that we owned them.
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10.
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We note from the table on page F-24 that your net proved oil and gas properties balances as of December 31, 2010 and 2009 exceed your standardized measures of discounted future net cash flows by substantial amounts. In view of this, explain to us the extent to which you have subjected any of your proved properties to impairment testing as of December 31, 2009, December 31, 2010 or at any interim period between those dates. Tell us the book value as of December 31, 2010 and 2009 for any properties not subjected to impairment testing, as well as your basis for concluding that impairment testing was not necessary. Similarly, tell us the book value as of December 31, 2010 and 2009 for any properties subjected to
impairment testing. Additionally, describe for us, in reasonable detail, the material assumptions underlying the impairment tests, including the assumptions regarding future prices and costs and the extent to which quantities other than proved reserves were considered. To the extent that quantities other than proved reserves were considered, tell us whether and, if so, how such quantities were risk adjusted. Finally, tell us the results of the impairment tests.
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We observe that the standardized measure of oil and gas properties is defined as an amount that represents the future value of crude oil and natural gas reserves using constant prices, net of income taxes, and discounted using a 10% discount factor. Accordingly, we recognize that the standardized measure amount could by definition always be less than the historical cost basis or net book value of our proved oil and natural gas properties due to the deduction of income taxes and the discounting of the future net cash flows.
Securities and Exchange Commission
September 15, 2011
Page 12
Since we utilize the successful efforts method of accounting, our asset impairment procedures are defined under Accounting Standards Codification Section 360-10 (Impairment or Disposal of Long-Lived Assets) rather than by the full cost ceiling test rules. Our asset impairment policy for proved oil and natural gas properties is summarized in Footnote (1) to the Notes To Consolidated Financial Statements under the sub-caption of Property and Equipment (located on page F-10 of our financial statements). Generally, the successful efforts method of accounting for oil and gas properties requires that we capitalize costs incurred in the successful exploration for and development of proved oil and
natural gas reserves. We deplete, depreciate and amortize these capitalized costs using the units-of-production method over the remaining life of the reserves based upon our asset groups, which are generally defined by the field areas where the reserves are located. As part of our impairment process, we monitor business conditions and our operations in order to assess whether there are indications of impairment. Examples of indications of impairment include, but are not limited to, price volatility for crude oil and natural gas, significant fluctuations in the volumes produced or expected to be produced from our oil and gas properties, inflationary pressures on exploration and development costs, etc.
On a quarterly basis, we review all of our evaluated oil and gas properties to determine whether there are indications of impairment. The initial test of impairment is performed by comparing the projected undiscounted future net cash flows which are derived based on our latest quarterly estimates of total proved oil and natural gas reserves, using longer term market forward prices, to the net book value of our oil and gas properties. Oil and natural gas prices used in our evaluation are based on forward market prices for crude oil and natural gas for the next three years adjusted for price differentials specific for each property. Such prices are then escalated at 5% per year
until such prices reach a cap which reflects historical market price ceilings. Operating costs and development costs are also inflated in these cash flow projections based upon future estimated cost inflation factors. In addition, we also consider future production from probable reserves, which generally are subject to a risk weighted adjustment of 50%. Using these future cash flow projections, we compare the capitalized cost of the oil and gas property groups to the escalated undiscounted future cash flows.
Historically, this review has not identified indications of impairment for the vast majority of our properties, both in terms of the number of properties and the percentage of the carrying value of proved properties. Based upon this initial review, we perform further analyses on those properties for which the initial review indicated that the net capitalized cost exceeded the undiscounted future net cash flows.
In the event that there remains an excess of net capitalized costs above the undiscounted future cash flows, we estimate the current fair value of the asset group using the future net cash flows discounted at a risk-adjusted rate that we believe to be consistent with the rate that would be used by a market participant. We then recognize an impairment charge to reflect the difference between capitalized costs and fair value.
Securities and Exchange Commission
September 15, 2011
Page 13
For the years ended December 31, 2008, 2009, and 2010, we recognized immaterial impairment charges related to our proved oil and gas properties of $0.9 million, $0.1 million and $0.1 million, respectively.
As also described in our Property and Equipment policy footnote, unproved oil and gas properties are periodically assessed for changes in circumstances (such as changes in drilling plans, unsuccessful drilling results on nearby properties, pending lease term expirations, etc.) and any impairment in value is charged to exploration expense. We recognized $4.1 million for impairments of unproved oil and gas properties during the year ended December 31, 2008 which was included in exploration expense in our Statement of Operations. We did not have any unproved leasehold impairments in the years ended December 31, 2009 or 2010, respectively. As disclosed in our filings on Form
10-Q for the quarters ended March 31, 2011 and June 30, 2011, we have recognized impairments of unproved properties in the amount of $9.5 million in 2011 which were included in exploration expense in our Statements of Operations.
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Note (12) Oil and Gas Reserves Information (Unaudited), page F-23
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11.
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We note your disclosure regarding prices used to determine your reserve quantities as of December 31, 2010 and December 31, 2009. Expand this disclosure to clarify whether these prices are before or after adjustments from posted prices for differences in location and quality. To the extent that these prices are before adjustment, further expand the disclosure to provide prices after adjustment for location and quality.
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All prices reflected in our Form 10-K for the Fiscal Year ended December 31, 2010 which were disclosed with respect to our estimates of crude oil and natural gas reserves were reported after adjustments from posted prices for differences in location and quality. This includes prices disclosed both in Part I, Items 1. and 2. as well as the unaudited disclosures of oil and gas reserves contained in the Notes to Consolidated Financial Statements.
We propose to add the following language when describing these prices in our future filings with the SEC:
"Prices used in determining quantities of oil and natural gas reserves and future cash inflows from oil and natural gas reserves represent prices received at the terminal point, which is the wellhead. These prices have been adjusted from posted prices for both location and quality differences."
Securities and Exchange Commission
September 15, 2011
Page 14
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Definitive Proxy Statement on Schedule 14A
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Related Party Transaction, page 11
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12.
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Please provide further details regarding your written policy for the approval of related party transactions. Describe the standards the audit committee applies when deciding whether to approve a related party transaction.
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The following is our written policy with respect to related party transactions, which is available on our website (www.comstockresources.com):
Comstock Resources, Inc.
Related Party Transactions Policy
A. Introduction.
The Board of Directors recognizes that related party transactions present a heightened risk of conflicts of interest and/or improper valuation (or the perception thereof). The Company already has in place a broad policy with respect to conflicts of interest for all employees. In addition, based upon the recommendation by its Governance/Nominating committee, the Board of Directors has determined that a separate policy regarding related party transactions, as documented below, is appropriate.
Under this policy, any “Related Party Transaction” shall be consummated or shall continue only if the Audit Committee shall approve or ratify such transaction in accordance with the guidelines set forth in the policy and if the transaction is on terms believed to be comparable to those that could be obtained in arm’s length dealings with an unrelated third party.
For these purposes, a "Related Party" is:
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1.
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an executive officer (which shall include at a minimum each executive vice president and
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Section 16 officer) or director of the Company,
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2.
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any nominee for director,
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3.
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a stockholder owning in excess of five percent of the Company (or its controlled affiliates),
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4.
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a person who is an immediate family member of an executive officer, director or director nominee, or
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Securities and Exchange Commission
September 15, 2011
Page 15
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5.
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an entity which is owned or controlled by someone listed in 1, 2, 3 or 4 above, or an entity in which someone listed in 1, 2, 3 or 4 above has a substantial ownership interest or control of such entity.
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For these purposes, a "Related Party Transaction" is a transaction between the Company and any Related Party (including any transactions requiring disclosure under Item 404 of Regulation S-K under the Securities Exchange Act of 1934), other than:
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1.
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transactions available to all employees generally, or
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2.
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transactions involving less than $5,000 when aggregated with all similar transactions.
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B. Audit Committee Approval
The Board of Directors has determined that the Audit Committee of the Board is best suited to review and approve Related Party Transactions. Accordingly, at any regularly scheduled Audit Committee meeting, management shall recommend Related Party Transactions to be entered into by the Company, including the proposed aggregate value of such transactions if applicable. After review, the Committee shall approve or disapprove such transactions and at each subsequently scheduled meeting, management shall update the Committee as to any material change to those proposed transactions.
C. Loans from the Company to Executive Officers and members of the Board of Directors
Loans to executive officers and members of the board of directors of the Company shall be prohibited in accordance with the provisions contained in Section 402 of the Sarbanes-Oxley Act of 2002.
D. Disclosure
All Related Party Transactions are to be disclosed in the Company’s applicable filings as required by the Securities Act of 1933 and the Securities Exchange Act of 1934 and related rules. Furthermore, all Related Party Transactions shall be disclosed to the Audit Committee of the Board and any material Related Party Transaction shall be disclosed to the full Board of Directors.
Securities and Exchange Commission
September 15, 2011
Page 16
E. Other Agreements
Management shall assure that all Related Party Transactions are approved in accordance with any requirements of the Company’s financing agreements.
With respect to the standards applied by the Audit Committee when deciding whether to approve a related party transaction, the audit committee generally focuses upon three broad concepts, as follows:
· Ensuring that the transaction will not interfere with the objectivity and independence of any related party's judgment or conduct in carrying out his or her duties and responsibilities to Comstock,
· Determining whether the transaction is fair to the Company, and
· Assessing whether the transaction otherwise would be against the best interests of the Company and its stockholders.
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Engineering Comments
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General
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13.
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Please provide a copy of your 2010 reserve report. Please include cash flow statements for all wells.
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We are providing under separate cover a copy of the Reserve Report issued by Lee Keeling and Associates, as well as copies of the cash flow statements for all wells within each reserve category (proved developed producing, proved developed non-producing, proved developed behind-pipe, and proved undeveloped reserves).
The Company acknowledges that:
· The Company is responsible for the adequacy and accuracy of the disclosures in its filings;
· 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
· 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.
Securities and Exchange Commission
September 15, 2011
Page 17
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
Locke Lord Bissell & Liddell LLP