October 11, 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
Re: Comstock Resources, Inc.
Form 10-K for Fiscal Year Ended December 31, 2011
Filed February 27, 2012
Form 10-Q for the Quarter Ended June 30, 2012
Filed August 3, 2012
File No. 001-03262
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 September 20, 2012 (the "Comment Letter") concerning the above-referenced Form 10-K (the "10-K") and Form 10-Q (the "10-Q"). The responses are numbered to correspond to the numbers of the Comment Letter.
Form 10-K for the Fiscal Year Ended December 31, 2011
Financial Statements, page F-1
Note 1 – Summary of Significant Accounting Policies, page F-8
Reserve for Future Abandonment Costs, page F-10
|
1.
|
Please revise the reconciliation of the beginning and ending balances of your asset retirement obligations to present the changes in estimates separate from the liabilities incurred in the new period from new wells placed in service to comply with the disclosure requirements set forth in FASB ASC 410-20-50-1. In addition, tell us and disclose the specific factors that resulted in the significant increase in the liability balance during the year ended December 31, 2011.
|
Securities and Exchange Commission
October 11, 2012
Page 2
For the new wells drilled each year, we estimate the fair value of our asset retirement obligations quarterly based upon the key inputs that were available as of the end of the previous year. Due to the relatively small number of wells that we drill each year, the fair value of the asset retirement obligation incurred for wells drilled has not been material. By way of example, during the year ended December 31, 2011, the estimated fair value of the asset retirement obligation for the 87 wells (47.7 net to us) we drilled was approximately $0.4 million, which was approximately 6% of the beginning asset retirement liability, 6% of the total changes in the liability during the year, and 3% of the ending liability at December 31, 2011. We recognize that FASB ASC 410-20-50-1 specifies that the amount of liabilities incurred in the current period should be separately disclosed, and we agree to disclose this amount separately in our future filings.
The significant increase in the fair value of asset retirement obligations during the year ended December 31, 2011 was the result of changes in some of the inputs used to estimate the fair value of our asset retirement obligations. Based upon our third party vendor estimates, which we updated in December 2011, there were significant increases in the estimated costs to plug and abandon our wells in all of our areas of operations, which are focused in Louisiana and Texas. The volumetric forecasts of the future production of our proved reserves contained in our reserve estimates as of December 31, 2011 also indicated that our reserves would deplete at dates that were earlier than the comparable dates contained in our estimates of proved reserves as of December 31, 2010. This change in the expected depletion dates had the effect of reducing the period of time used to discount our future estimated asset retirement costs. The inclusion of these higher plugging and abandonment costs and the change in the present value of these costs due to the earlier abandonment dates resulted in an increase of approximately $5.9 million to our asset retirement obligations. Such amount when compared to our assets was not material as it represents less than 1% of our total assets of $2.6 billion at the end of 2011.
Form 10-Q for the Quarter Ended June 30, 2012
Financial Statements, page
Note 1 – Summary of Significant Accounting Policies, page 9
Property and Equipment, page 10
|
2.
|
We note your disclosure in which you state proved undeveloped gas reserves decreased by 59% from the total proved undeveloped reserves as of December 31, 2011 due to significant price declines. Identify for us the specific proved undeveloped natural gas reserves that were removed, and tell us when these reserves were initially booked. Also, please explain why this material downward revision in reserves did not materially impact your assessment of impairment during the three months ended June 30, 2012.
|
Securities and Exchange Commission
October 11, 2012
Page 3
The reduction in natural gas reserves that we disclosed in our Form 10-Q for the three months ended June 30, 2012 was the change in our proved undeveloped reserves that was solely due to a decline in the twelve month average of first of the month natural gas prices used to estimate proved reserves. During the six months ended June 30, 2012, the average price that we used to estimate our quantities of proved natural gas reserves decreased by $0.93 per thousand cubic feet ("Mcf") or 22% from $4.18 per Mcf at December 31, 2011 to $3.25 per Mcf at June 30, 2012. The decrease of 330 billion cubic feet ("Bcf"), which represented 59% of our proved undeveloped natural gas reserves of 568 Bcf as of December 31, 2011, included a reduction of approximately 312 Bcf of natural gas associated with future projects that were removed from our estimated proved undeveloped reserves as of June 30, 2012 and the remaining 18 Bcf reduction was attributed to proved undeveloped reserves that remain in our estimates but which declined due to the lower natural gas price used to prepare our June 30, 2012 estimated proved reserves.
Approximately 92% of the 312 Bcf of reserves that were estimated to become uneconomic during the six months ended June 30, 2012 were located in our Haynesville and Bossier shale properties, which were focused in the Logansport, Mansfield, and Toledo Bend field areas. Of the 312 Bcf of reserves that are estimated to have become uneconomic during the six months ended June 30, 2012, approximately 67% were in our Logansport field area and approximately 26% were located in our Toledo Bend field area. The remaining 7% was located in several of our smaller field areas in our East Texas/North Louisiana region. The 312 Bcf of natural gas reserves that are estimated to have become uneconomic during the first six months of 2012 were added to our proved undeveloped reserves by year as follows: 2007 – 2 Bcf, 2009 – 66 Bcf, 2010 – 164 Bcf, and 2011 – 80 Bcf.
A discussion of our oil and natural gas asset impairment procedures is contained in Footnote 1 to the financial statements contained on page F-10 in our Form 10-K. We have also previously provided additional details about our impairment testing procedures in our responses to comments from the Securities and Exchange Commission (the "Commission") in our letters to the Commission dated September 15, 2011 and January 19, 2012. Our procedures to assess asset impairment include the use of price forecasts that are different from those prescribed by the Commission for use in estimating oil and natural gas reserves quantities. Our impairment assessment procedures also include risk adjusted future production from wells that contain reserves that are classified as probable. We consistently apply these impairment assessment procedures at the end of each quarter and have not made any changes to those procedures from those previously disclosed to the Commission.
Natural gas prices declined significantly during the six months ended June 30, 2012. The effect of this decline was to reduce the twelve month average of first of the month natural gas prices used to compute quantities of oil and natural gas reserves, which in turn had the effect of making certain of our natural gas reserves uneconomic. In several of our field areas, the reduction in proved undeveloped reserves resulted in indications of impairments. The proved undeveloped reserves that were uneconomic at the prices used to determine the quantities of oil and natural gas reserves as of June 30, 2012 remained economic based upon the escalated price forecasts used for impairment testing. Accordingly, these proved undeveloped reserves were reclassified as probable reserves, and after risk adjusting these reserves, the estimated combined future undiscounted value of proved and risk adjusted probable reserves for most of these field areas exceeded the net book value of assets. Note that in risking probable reserves we used the same risk factor regardless of whether the reserves had previously been classified as proved undeveloped, even though the technical risk of the wells with reserves previously classified as proved undeveloped reserves is likely to be less than the technical risk of the other reserves classified as probable. After considering the risk adjusted value of probable reserves, most of our field areas had no indications of impairment during the three months ended June 30, 2012. We had several smaller, marginal fields where the value of the proved and probable reserves, including reserves that had been reclassified from proved undeveloped to probable, no longer exceeded the net book value of the fields, and in those instances we recognized an impairment charge totaling $5.3 million during the three months ended June 30, 2012.
Securities and Exchange Commission
October 11, 2012
Page 4
We will continue to consistently apply our impairment assessment procedures, and in the future we will recognize impairments which are appropriate at the end of each reporting period. In addition, we intend to continue to disclose at the end of each calendar year the sensitivity to impairment of our proved oil and gas properties based upon the approach which we previously agreed with the Commission, which is based upon an impairment price case using three years of the then futures prices for crude oil and natural gas, and then holding prices constant in subsequent periods.
|
3.
|
Send us a schedule which shows, as of December 31, 2009, December 31, 2010 and December 31, 2011, the following:
|
|
·
|
Total estimated proved undeveloped reserves;
|
|
As of December 31,
|
||||||||||||
|
2009
|
2010
|
2011
|
||||||||||
|
Oil
(Mbbls)
|
Natural Gas
(MMcf)
|
Oil
(Mbbls)
|
Natural Gas
(MMcf)
|
Oil
(Mbbls)
|
Natural
Gas
(MMcf)
|
|||||||
|
Total Proved Undeveloped Reserves
|
2,320
|
315,287
|
1,258
|
518,824
|
23,694
|
568,158
|
||||||
|
PUD Reserves Removed as of 06/30/2012
|
—
|
69,844
|
9
|
224,642
|
16
|
311,598
|
||||||
Securities and Exchange Commission
October 11, 2012
Page 5
|
·
|
The timing, by year, when the proved undeveloped reserve quantities are planned to be converted to proved developed reserves;
|
|
Total Proved Undeveloped Reserves
|
||||||||||||||||||||||||
|
2009
|
2010
|
2011
|
||||||||||||||||||||||
|
Year ended December 31,
|
Oil
(Mbbls)
|
Natural Gas
(MMcf)
|
Oil
(Mbbls)
|
Natural Gas
(MMcf)
|
Oil
(Mbbls)
|
Natural Gas
(MMcf)
|
||||||||||||||||||
|
2010
|
10
|
42,046
|
—
|
—
|
—
|
—
|
||||||||||||||||||
|
2011
|
1,577
|
113,815
|
527
|
107,729
|
—
|
—
|
||||||||||||||||||
|
2012
|
261
|
77,685
|
426
|
163,984
|
8,250
|
51,034
|
||||||||||||||||||
|
2013
|
467
|
70,466
|
306
|
138,831
|
4,909
|
264,497
|
||||||||||||||||||
|
2014
|
5
|
11,073
|
—
|
93,547
|
9,329
|
215,756
|
||||||||||||||||||
|
2015
|
—
|
201
|
—
|
14,734
|
925
|
36,311
|
||||||||||||||||||
|
2016
|
—
|
—
|
—
|
—
|
201
|
402
|
||||||||||||||||||
|
2017
|
—
|
—
|
—
|
—
|
79
|
158
|
||||||||||||||||||
|
Total
|
2,320
|
315,287
|
1,258
|
518,824
|
23,694
|
568,158
|
||||||||||||||||||
|
PUD Reserves Removed as of 06/30/2012
|
||||||||||||||||||||||||
|
2009
|
2010
|
2011
|
||||||||||||||||||||||
|
Year ended December 31,
|
Oil
(Mbbls)
|
Natural Gas
(MMcf)
|
Oil
(Mbbls)
|
Natural Gas
(MMcf)
|
Oil
(Mbbls)
|
Natural Gas
(MMcf)
|
||||||||||||||||||
|
2010
|
—
|
749
|
—
|
—
|
—
|
—
|
||||||||||||||||||
|
2011
|
—
|
35,051
|
—
|
29,723
|
—
|
—
|
||||||||||||||||||
|
2012
|
—
|
11,776
|
1
|
70,753
|
1
|
13,408
|
||||||||||||||||||
|
2013
|
—
|
18,488
|
8
|
59,418
|
9
|
128,885
|
||||||||||||||||||
|
2014
|
—
|
3,780
|
—
|
57,877
|
—
|
145,957
|
||||||||||||||||||
|
2015
|
—
|
—
|
—
|
6,871
|
6
|
23,247
|
||||||||||||||||||
|
Total
|
—
|
69,844
|
9
|
224,642
|
16
|
311,598
|
||||||||||||||||||
|
·
|
Development costs, by year and in total, expected to be incurred to convert proved undeveloped reserves to proved developed reserves;
|
|
Future Development Costs
Total Proved Undeveloped Reserves
|
Change in Future Development Costs Total Proved
Undeveloped Reserves
|
|||||||||||||||||||
|
Amounts in $ Millions
|
Amounts in $ Millions
|
|||||||||||||||||||
|
Year ended December 31,
|
2009
|
2010
|
2011
|
2010
|
2011
|
|||||||||||||||
|
2010
|
$
|
85.1
|
$
|
—
|
$
|
—
|
$
|
(85.1
|
)
|
$
|
—
|
|||||||||
|
2011
|
245.8
|
237.3
|
—
|
(8.5
|
)
|
(237.3
|
)
|
|||||||||||||
|
2012
|
169.4
|
381.0
|
395.4
|
211.6
|
14.4
|
|||||||||||||||
|
2013
|
145.1
|
299.6
|
734.4
|
154.5
|
434.8
|
|||||||||||||||
|
2014
|
24.0
|
199.0
|
742.4
|
175.0
|
543.4
|
|||||||||||||||
|
2015
|
0.4
|
28.4
|
117.9
|
28.0
|
89.5
|
|||||||||||||||
|
2016
|
—
|
—
|
9.4
|
—
|
9.4
|
|||||||||||||||
|
2017
|
—
|
—
|
4.2
|
—
|
4.2
|
|||||||||||||||
|
Total
|
$
|
669.8
|
$
|
1,145.3
|
$
|
2,003.7
|
$
|
475.5
|
$
|
858.4
|
||||||||||
Securities and Exchange Commission
October 11, 2012
Page 6
|
Future Development Costs
PUD Reserves Removed as of 06/30/2012
|
Change in Future Development Costs PUD Reserves
Removed as of 06/30/2012
|
|||||||||||||||||||
|
Amounts in $ Millions
|
Amounts in $ Millions
|
|||||||||||||||||||
|
Year ended December 31,
|
2009
|
2010
|
2011
|
2010
|
2011
|
|||||||||||||||
|
2010
|
$
|
1.6
|
$
|
—
|
$
|
—
|
$
|
(1.6
|
)
|
$
|
—
|
|||||||||
|
2011
|
65.2
|
61.6
|
—
|
(3.7
|
)
|
(61.6
|
)
|
|||||||||||||
|
2012
|
24.6
|
154.1
|
30.0
|
129.5
|
(124.1
|
)
|
||||||||||||||
|
2013
|
37.1
|
130.7
|
284.9
|
93.6
|
154.2
|
|||||||||||||||
|
2014
|
8.0
|
130.4
|
316.0
|
122.4
|
185.6
|
|||||||||||||||
|
2015
|
—
|
14.5
|
54.0
|
14.5
|
39.5
|
|||||||||||||||
|
2016
|
—
|
—
|
—
|
—
|
—
|
|||||||||||||||
|
2017
|
—
|
—
|
—
|
—
|
—
|
|||||||||||||||
|
Total
|
$
|
136.6
|
$
|
491.3
|
$
|
684.9
|
$
|
354.6
|
$
|
193.6
|
||||||||||
|
·
|
A reasonably detailed explanation of the reasons for material changes between years in the quantities of undeveloped reserves expected to be converted to developed reserves and in expected development costs,
|
The following tables present the changes in our estimated proved undeveloped crude oil and natural gas reserves, and the future development capital cost estimates associated with those reserves for the years ended December 31, 2010 and 2011. In the discussion following these tables we provide additional detailed information regarding these changes.
|
Total Proved Undeveloped Reserves
|
||||||||||||||||
|
2010
|
2011
|
|||||||||||||||
|
Oil
(Mbbls)
|
Natural Gas
(MMcf)
|
Oil
(Mbbls)
|
Natural Gas
(MMcf)
|
|||||||||||||
|
Beginning Balance
|
2,320
|
315,287
|
1,258
|
518,824
|
||||||||||||
|
Sales and Disposals
|
(1,996
|
)
|
(2,378
|
)
|
—
|
—
|
||||||||||
|
Acquisitions
|
—
|
—
|
16,959
|
45,792
|
||||||||||||
|
Extension & Discoveries
|
1,012
|
241,160
|
5,151
|
66,978
|
||||||||||||
|
Conversions from PUD to PDP
|
—
|
(8,825
|
)
|
—
|
(39,761
|
)
|
||||||||||
|
Price, Performance and Other Revisions
|
(78
|
)
|
(26,419
|
)
|
326
|
(23,675
|
)
|
|||||||||
|
Total Change
|
(1,062
|
)
|
203,537
|
22,436
|
49,334
|
|||||||||||
|
Ending Balance
|
1,258
|
518,824
|
23,694
|
568,158
|
||||||||||||
Securities and Exchange Commission
October 11, 2012
Page 7
|
Future Development Costs - Proved Undeveloped Reserves - $MM
|
||||||||||||||||||||
|
Haynesville Shale
|
Eagle Ford Shale
|
West Texas Properties Acquired in 2011
|
All Other Properties
|
Total
|
||||||||||||||||
|
Total as of 12/31/2009
|
$
|
170.1
|
$
|
—
|
$
|
—
|
$
|
499.7
|
$
|
669.8
|
||||||||||
|
Development Costs Incurred
|
(14.3
|
)
|
—
|
—
|
(2.6
|
)
|
(16.9
|
)
|
||||||||||||
|
Asset Disposals
|
—
|
—
|
—
|
(13.6
|
)
|
(13.6
|
)
|
|||||||||||||
|
Additions and Revisions
|
543.2
|
49.0
|
—
|
(86.2
|
)
|
506.0
|
||||||||||||||
|
Total Changes
|
528.9
|
49.0
|
—
|
(102.4
|
)
|
475.5
|
||||||||||||||
|
Total as of 12/31/2010
|
698.9
|
49.0
|
—
|
397.3
|
1,145.3
|
|||||||||||||||
|
Development Costs Incurred
|
(56.3
|
)
|
—
|
—
|
—
|
(56.3
|
)
|
|||||||||||||
|
Additions and Revisions
|
243.5
|
169.0
|
653.5
|
(151.2
|
)
|
914.7
|
||||||||||||||
|
Total Changes
|
187.2
|
169.0
|
653.5
|
(151.2
|
)
|
858.4
|
||||||||||||||
|
Total as of 12/31/2011
|
$
|
886.2
|
$
|
218.0
|
$
|
653.5
|
$
|
246.0
|
$
|
2,003.7
|
||||||||||
Changes in Proved Undeveloped Reserves Quantities and
Future Capital Expenditures - Year ended December 31, 2010
As of December 31, 2010, our proved undeveloped reserves included 1.3 million barrels ("MMBbls") of crude oil and 519 Bcf of natural gas, for a total of 526 billion cubic feet equivalent ("Bcfe") of undeveloped reserves. Approximately 83% of our proved undeveloped reserves at December 31, 2010 were associated with the future development of our Haynesville or Bossier shale properties. The remaining proved undeveloped reserves were primarily associated with developing reserves in our Cotton Valley and Hosston sand reservoirs in East Texas/North Louisiana and our Eagle Ford shale, Wilcox and Vicksburg reservoirs in South Texas. Following the initial success of our Haynesville shale evaluation wells, our 2010 drilling program was focused primarily to further evaluate and develop acreage that is prospective in the Haynesville shale formation. As a result, only three of the wells we drilled in 2010 resulted in conversions of proved undeveloped reserves to proved developed producing reserves at the end of 2010.
Our crude oil proved undeveloped reserves decreased by 1.1 MMBbls during the year ended December 31, 2010. The sale of our Mississippi properties during 2010, which reduced our crude oil reserves by approximately 2.0 MMBbls, was partially offset by reserve additions of approximately 1.0 MMBbls from our successful drilling program in the Eagle Ford shale in South Texas. We also had downward revisions to previous estimates of other crude oil reserves of approximately 0.1 MMBbls during 2010. Our natural gas proved undeveloped reserves increased by 204 Bcf during the year ended December 31, 2010, primarily from our successful Haynesville and Bossier shale drilling program which added 225 Bcf of natural gas reserves, and other extensions and discoveries of approximately 16 Bcf. Our natural gas reserves additions were partially offset by downward revisions to previous estimates of approximately 26 Bcf, conversions to proved reserves of 9 Bcf and 2 Bcf of natural gas reserves sold during 2010.
Securities and Exchange Commission
October 11, 2012
Page 8
Our estimated future capital costs to develop proved undeveloped reserves as of December 31, 2010 of $1.1 billion increased by $475 million from our estimated future capital costs of $670 million as of December 31, 2009. During 2010, we incurred approximately $17 million to develop proved undeveloped reserves, mainly in our Haynesville shale properties. Due to the success of our drilling programs, we increased our proved undeveloped reserve estimates in the Haynesville shale and the Eagle Ford shale, and we accordingly increased our estimated future capital expenditures by approximately $543 million and $49 million, respectively, in these areas. As a result of the refocusing of our drilling plans towards the unconventional shale plays during 2010, we reduced our planned capital expenditures by approximately $100 million on our remaining conventional natural gas undeveloped reserves.
Changes in Proved Undeveloped Reserves Quantities and
Future Capital Expenditures - Year ended December 31, 2011
As of December 31, 2011, our proved undeveloped reserves included 23.7 MMBbls of crude oil and 568 Bcf of natural gas, for a total of 710 Bcfe of undeveloped reserves. Approximately 72% of our proved undeveloped crude oil reserves at December 31, 2011 were associated with the future development of our West Texas properties that we acquired in December, 2011 and an additional 25% were associated with our Eagle Ford shale properties in South Texas. The proved undeveloped natural gas reserves associated with our Haynesville or Bossier shale properties represented approximately 75% of our total natural gas proved undeveloped reserves at December 31, 2011. The remaining proved undeveloped reserves are primarily associated with developing reserves in our Cotton Valley and Hosston sand reservoirs in East Texas/North Louisiana and our Wilcox and Vicksburg reservoirs in South Texas. During the year ended December 31, 2011, the price of crude oil increased significantly, and the value of crude oil relative to natural gas on a heating equivalent basis widened to historic levels. This, coupled with a growing over-supply of natural gas in the United States, drove a change in our strategic focus towards crude oil and away from natural gas. As a result, our drilling program during 2011, which was initially focused on our Haynesville and Bossier shale reserves, was refocused during the year towards our oil prone properties in the Eagle Ford shale in South Texas. Eleven of the Haynesville shale wells we drilled in 2011 resulted in conversions of proved undeveloped reserves to proved developed producing reserves at the end of 2011. To better position our company for future growth of crude oil production, in late 2011 we acquired 70,036 acres (43,591 net to us) in West Texas which are prospective for crude oil. A portion of this acquisition was determined to contain proved undeveloped reserves.
Our crude oil proved undeveloped reserves increased by 22.4 MMBbls during the year ended December 31, 2011. This increase was primarily due to our acquisition of proved undeveloped reserves in West Texas of 17.0 MMBbls, proved undeveloped reserves additions of 4.7 MMBbls in our Eagle Ford shale properties and 0.7 MMBbls of crude oil additions and revisions on our other properties. Our natural gas proved undeveloped reserves increased by 49 Bcf during the year ended December 31, 2011. This increase was primarily related to our successful Haynesville and Bossier shale drilling program which added 44 Bcf of natural gas reserves, our acquisition in West Texas which added 46 Bcf and other additions of approximately 23 Bcf. Our proved undeveloped natural gas reserves additions were partially offset by conversions to proved developed reserves of approximately 40 Bcf during 2011 and other downward revisions to previous estimates of approximately 23 Bcf.
Securities and Exchange Commission
October 11, 2012
Page 9
Our estimated future capital costs to develop proved undeveloped reserves as of December 31, 2011 of $2.0 billion increased by $858 million from our estimated future capital costs of $1.1 billion as of December 31, 2010. During 2011 we incurred approximately $56 million to develop proved undeveloped reserves in our Haynesville shale properties. Due to the success of our oil focused drilling programs, we increased our proved undeveloped reserve estimates in the Eagle Ford shale and we acquired properties in West Texas with significant potential for crude oil during 2011. During 2011 our oil focused future capital expenditures increased by $169 million in the Eagle Ford shale and $654 million in West Texas. Our future capital expenditures in the Haynesville and Bossier shales increased by $244 million during 2011 reflecting our 2011 drilling success on these properties, while we further reduced our forecast of capital expenditures on our remaining conventional natural gas undeveloped reserves by $151 million during 2011.
We intended to drill the proved undeveloped wells in the time frame reflected in the estimates of proved oil and natural gas reserves as of December 31, 2009, 2010 and 2011 based upon the crude oil and natural gas prices that we used to prepare these reserve estimates. We anticipated drilling such proved undeveloped locations based on our then current development plans for our properties. Certain of these wells may be drilled to retain leasehold interests or to properly manage reservoir performance. To the extent that actual crude oil or natural gas prices change from those used to support our development plans, we modify our development plans to reflect these changing market conditions.
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and; Actual proved undeveloped reserve quantities converted to proved developed and actual development costs incurred in 2010 and 2011.
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2010
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2011
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Oil
(Mbbls)
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Natural Gas
(MMcf)
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Oil
(Mbbls)
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Natural Gas
(MMcf)
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Proved Undeveloped Reserve Quantities Converted to Proved Developed
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—
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8,825
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—
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39,761
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Amounts in $ Millions
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2010
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2011
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Development Costs Incurred to Convert Undeveloped Reserves to Proved Developed Reserves
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$
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16.9
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$
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56.3
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For each year presented, indicate when the proved undeveloped natural gas reserves removed during the quarter ended June 30, 2012 were expected to be developed.
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Securities and Exchange Commission
October 11, 2012
Page 10
This information is included in the tabular presentations shown above and referenced as the "PUD Reserves Removed as of June 30, 2012".
In our Annual Report on Form 10-K to be filed for the year ended December 31, 2012, we will include the information disclosed above to discuss the changes in proved undeveloped reserves from December 31, 2011.
The Company acknowledges that:
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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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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