correspfeb192013.htm

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 5, 2013 (the "Comment Letter") concerning the above-referenced Form 10-K (the "10-K"), and our Response Letter dated December 6, 2012 (the "Response Letter"). The responses are numbered to correspond to the numbers of the Comment Letter.

Your response to prior comment number one from our letter dated November 21, 2012 indicates, in one section, that “formal business planning is primarily focused on a one year forward looking period”. In a separate section, your response indicates that “our business plan, which supports our drilling plan for future development of reserves, is based upon our impairment case price forecasts”. Explain to us how your “formal business planning” differs from your “business plan”, and explain in greater detail why you use different pricing assumptions for each of these purposes.

Comstock relies upon projected future cash flows for all of its business planning and forecasting activities, as the Company's sole focus is on the economic production of crude oil and natural gas. Key inputs to these projected cash flows are commodity prices, which are based on oil and natural gas futures prices, which are adjusted to the wellhead value based on historical price differentials. For our near term business projections and forecasts, which we had previously described as our "formal business planning" process, in which we are forecasting near term results, we use NYMEX future prices as our key inputs. Depending upon the duration of the forecast, we may use up to three years of NYMEX future prices for our near term forecasts. For planning and forecasting longer than three years we escalate prices and costs. We can confirm to you that there are no differences in the oil and gas price and costs assumptions that we use for any of our planning purposes and those we use for impairment testing.

With regard to your statement that “our business plan, which supports our drilling plan for future development of reserves, is based upon our impairment case price forecasts”, clarify for us whether this means that your business plan uses the same pricing assumptions as those used for your impairment testing, or that your business plan uses pricing assumptions that are modified from, and different than, those used for your impairment testing. To the extent that the pricing assumptions for your business plan are different, clearly describe these differences to us and explain your reasons for them.

As described in our response to Item 2. of the Response Letter, we have observed in some instances that certain reserves which previously met the definition of proved undeveloped reserves based on the then prevailing first of the month average prices may become uneconomic in subsequent periods, primarily due to decreases in the first of the month average prices used for purposes of determining proved reserve quantities. For purposes of performing a test of recoverability, we re-evaluate the estimated future cash flows from these proved undeveloped well locations, and when the reserves from these well locations prove to be economic under the impairment case pricing and cost escalation assumptions, we include them in the risk-adjusted future cash flows from our probable reserves.

Clarify for us whether the quantities of probable reserves used in your impairment testing include any quantities beyond those included as a result of the process described above. If so, explain to us the source of and basis for these additional probable reserves. As part of your response, describe the specific uncertainties associated with the reserves and explain the significant actions, events or conditions necessary to bring them to production.

As part of our response to question two in the Response Letter, on page 10 we commented that in our Step 2 test of recoverability, we prepare estimates of quantities of probable oil and gas reserves. These probable reserves are determined based upon the definition of probable reserves as defined in Accounting Codification Standards ("ASC") 932-10-S99-1. As also explained in this same discussion, projects that would qualify as proved undeveloped reserves, as defined in ASC 932-10-S99, but which are uneconomic based upon the average first of the month prices used to estimate reserves for purposes of making reserve disclosures to the Commission, are also included as part of our Step 2 test of recoverability if these reserves are economic under our impairment pricing assumptions. Also as previously discussed, we risk adjust the value of both the probable reserves and any additional proved undeveloped reserves included under the impairment pricing assumptions as part of determining the Step 2 value of these reserves.

Probable reserves, as defined, are "those additional reserves that are less certain to be recovered than proved reserves, but which, together with proved reserves, are as likely as not to be recovered." We apply deterministic methods in our evaluation of reserves that we consider to be probable. The technical risks associated with well locations containing probable reserves primarily relate to the geologic risk associated with wells that are situated beyond locations that are considered to be proved reserves. Recovery of these probable reserves requires new wells to be drilled on undrilled locations. Our proved undeveloped reserves are similarly determined based upon the definitions contained in ASC 932-10-S99-1. These reserves can be estimated with reasonable certainty based on geosciences and engineering data. Recovery of these undeveloped reserves also requires new wells to be drilled on undrilled acreage. We believe that the additional proved undeveloped reserves determined using our impairment pricing assumptions meet the definitions contained in ASC 932-10-S99-1 and therefore should be included along with our probable reserves when assessing recoverability. Our practice of discounting these reserves on the same basis as the probable reserves would be on the basis of being conservative rather than what is justified by the uncertainties associated with these reserves.

In your response to prior comment one you state that you prepare multiple alternative estimates of future cash flows to determine final bid values for strategic acquisitions. Please clarify whether you typically apply multiple price scenarios to evaluate other estimates such as the recovery of deferred taxes or to prepare budgets or other projections. As FASB ASC 360-10-35-30 requires you to use reasonable assumptions that are consistent to those used in developing other information, please explain how you concluded your impairment model, which appear to use a single price case scenario to compute undiscounted future cash flows is consistent with this guidance.

For purposes of evaluating acquisitions, our valuation objectives are focused upon determination of a market participant value, which we believe will allow us to successfully acquire oil and natural gas reserves in a competitive bid situation. Our estimates of future cash flows in this instance are based upon the same price scenario we use in our impairment testing. In determining the market participant value, the value of the reserves is generally based upon the estimated future cash flows, which are typically risk adjusted by applying different discount rate factors to different categories of reserves that are evaluated. In the case of acquisitions, we might run alternative cash flow models in order to test the sensitivity of the projected future cash flows under different scenarios but do not use these to determine the bid value or the market participant value. For analysis of the recovery of deferred taxes and other planning, forecast and project analysis we use oil and natural gas price scenarios that are consistent with those used in our impairment testing.

5.	In addition, you state you use multiple alternative estimates of future cash flows with the objective of evaluating the sensitivity of the cash flows to price risk, cost risk and reserve risk. Please explain how these factors are considered and incorporated into your impairment testing model.

Our reference in the Response Letter to evaluating sensitivities to price risk, cost risk and reserve risk were provided as examples of alternative cases we might perform in determining the competitive bid value of an acquisition. We address this subject in our response to question 4 above.

As discussed in question 1. above, our short term forecasts are based upon near term futures prices. These are the same prices that we include in the pricing forecast for the first three years that is part of our determination of future cash flows when we perform our Step 2 valuation process. Since our Step 2 impairment test begins with those reserves that we determine to be economic using the guidance for proved reserves included in ASC 932-10-S99, we believe our impairment valuation is based upon reserves determined using conservative assumptions. We then add to the cash flows from our proved reserves the incremental cash flows of projects that would be classified as proved undeveloped if such reserve quantities were economic using average first of the month prices, and probable reserves, the values for both of which are then risk-adjusted as described in question 8. below. We believe that this approach appropriately considers all relevant factors in determining whether the undiscounted value of our reserves is sufficient to recover their carrying value (our Step 2 valuation analysis).

Our Step 2 impairment test is performed to determine whether the future cash flows from our reserves are sufficient to recover their carrying value. We utilize the same impairment price forecast assumptions for purposes of estimating future cash flows when we are evaluating acquisitions and for the allocation of purchase price to assets acquired. A market participant valuation of oil and natural gas reserves is typically based upon estimated future cash flows to which each of the reserve categories are valued using various net present values and different discount factors. The Company applies this methodology when performing market participant valuations of reserves (various discount rates applied to different reserve categories). We apply the same discount rates to any valuations performed to determine the market participant value when determining the impairment to be recognized in those instances when an asset group fails a Step 2 valuation analysis.

In response to a comment from a prior review you had stated that oil and gas prices used to estimate undiscounted future cash flows for impairment testing purposes are escalated at 5% per year until the prices reach a specified cap. Please explain in greater detail your basis for using a 5% long term growth rate in your calculation and indicate whether this growth rate has been adjusted over time. In addition, tell us how you considered recent price trends when developing the 5% growth rate. Finally, tell us what your break even growth rate is in relation to this 5% growth rate.

In our January 19, 2012 response letter, our response to your question 4 indicated that we do not believe that there is sufficient liquidity and trading volumes in the futures markets for oil and natural gas beyond the first three years, and we further commented that we have elected to use a fixed escalation rate beyond the first three years. We believe that it is reasonable to project price growth based upon historical price trends. In that same response, we commented that the implied annual escalation factor for natural gas had been indicating an average annual escalation factor of between 4% and 8%, over the past several years. We have continued to monitor this trend, which continues to indicate that natural gas prices beyond the first three years will escalate at approximately 5%, and we have accordingly retained the escalation of prices in our impairment case model at a 5% rate per annum.

The returns on our projects are specific to each separate well or major property group. Our oil projects have high returns with the current market price for crude oil. For our natural gas projects, which are primarily focused in the Haynesville/Bossier shale, we estimate the break-even price for these projects to be approximately $3.35 per Mcf.

Your response to prior comment number two suggests that you have applied risk factors to the future net cash flows from probable reserves, rather than to the reserve quantities themselves. However, this is not clear. Please clarify for us the process through which you risk-adjust probable reserves, including the specific risk factor(s) applied. Please note that risk adjusting future net cash flows, rather than quantities, may not properly reflect the impact that capital and other fixed costs will have in the event that actual quantities are less than projected. See FASB ASC paragraph 932-360-35-8.

We risk our probable reserves using two separate approaches. In those instances where the geologic risk of the reserves is assessed as being low, we apply our risk factors to the cash flows from those projects. This includes reserves that would otherwise be classified as proved undeveloped except for a lower oil or natural gas price used in the reserve redetermination. In cases of asset groups where the geologic risk is not considered low, we risk adjust the quantities of reserves within our cash flow projection model. We have assessed the geologic risk of each of our asset groups, and apply this methodology consistently. The risk adjustment factor used for our 2011 impairment tests, which we have also used consistently throughout 2012 has been 75%. This factor reflects the continued high success rate for our drilling program and the generally low geologic risk in our asset base.

The probable reserves used in our year end 2011 impairment analysis, which relate only to asset groups which had indications of impairment when we performed our Level 1 test of impairment, represent less than 1% of our total year end 2011 proved crude oil reserves and approximately 4% of our total year end proved natural gas reserves.

10.

In your response to prior comment two you state your pricing assumptions for estimating economically recoverable reserves is consistent in the manner in which reserves are estimated under the Petroleum Resources Management System (PRMS). When computing undiscounted future cash flows for impairment testing purposes, please tell us whether your estimate of reserve quantities is determined using an economic producibility or commercial producibility pricing assumption. That is, tell us whether you factor in a profit margin or rate of return when estimating reserves to be included in the computation of undiscounted future cash flows. If so, tell us the profit margin or rate of return used.

The Company's estimates of future cash flows are determined using an economic producibility approach, in that the cash flows are projected to the end of the economic life of the reserves based on price and cost assumptions, and the underlying engineering estimates of each project's future production. The assumptions used in these computations are prices for oil and natural gas, pricing differentials, cost assumptions for future development costs and operating costs, and the production forecasts. There is no separate profit margin input that is a part of these assumptions. The cash flow model projects cash flows based upon estimated future production and the price and cost assumptions. Reserves for each project are limited to those that have an undiscounted future value greater than zero (economic limit of production) where management intends to proceed with the development and is financially capable of doing so.

	Reserve Quantities		Undiscounted Future Net Revenues
	Oil (Mbbls)	Natural Gas (MMcf)	Amounts in $000
Proved Reserves	32,304	1,160,899	$5,713,100
Probable Reserves on Certain Asset Groups	81	49,678	$173,476