GMX Resources (GMXRW) CORRESP Correspondence with SEC

	James A. Merrill
	CFO
	One Benham Place, Suite 600
	9400 North Broadway
	Oklahoma City, OK 73114
	Main office 405.600.0711
	Office 405.254-5805
	Fax 405.600.0600
	Cell 405.919.5638
	jmerrill@gmxresources.com
	www.gmxresources.com

April 8, 2009

H. Roger Schwall, Assistant Director

United States Securities and Exchange Commission

Division of Corporation Finance

Mail Stop 7010

Washington, D.C. 20549-7010

Re:	Response to your letter to GMX Resources Inc. dated February 24, 2009 regarding: Form 10-K for fiscal year ended December 31, 2007, filed March 14, 2008 Form 10-Q for Fiscal Quarter Ended September 30, 2008, filed November 10, 2008
	Definitive Proxy Statement on Schedule 14A, filed April 25, 2008 File No. 001-32977

Dear Mr. Schwall:

On behalf ofGMX Resources Inc. (the “Company”, “we” or “us”), enclosed are the Company’s responses to the comments of the staff (the “Staff”) of the Securities and Exchange Commission (the “Commission”) in its comment letter dated February 24, 2009. We have repeated each of the Staff’s comments in italics below in the order in which they were raised in the comment letter and have included the Company’s response to each such comment immediately below the comment.

Form 10-K for the Fiscal Year Ended December 31, 2007

Controls and Procedures

1. We note your response to our prior comment 5 and your proposal to provide revised language in your management’s report on internal control over financial reporting. Because your conclusions regarding the effectiveness of your disclosure controls and procedures are set forth under Item 9A in your Form 10-K, please comply with prior comment 5 with respect to disclosure in your future filings on Form 10-K by revising your disclosure in Item 9A. Such disclosure should state clearly, if true, that your disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and that your principle executive officer and principal financial officer concluded that your disclosure controls and procedures are effective at

GMXR: NASDAQ OMX Group

H. Roger Schwall, Assistant Director	April 8, 2009
Securities and Exchange Commission	Page 2

the reasonable assurance level. In the alternative, remove the reference to the level of assurance of your disclosure controls and procedures from your management’s report on internal control over financial reporting.

Please note that prior comment 5 also applies to your disclosure regarding the effectiveness of your disclosure controls and procedures in your future filings on Form 10-Q.

Response:

In the Company’s 2008 Form 10-K, Item 9A was revised to reflect the above comment and read as follows:

Item 9A.        Controls and Procedures.

Controls and Procedures

Our principal executive officer and principal financial officer have reviewed and evaluated the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of December 31, 2008. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide us with reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and is accumulated and communicated to our management, including our principal executive officer and principal financial officer, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosures. Based on that evaluation, our principal executive officer and principal financial officer have concluded that our current disclosure controls and procedures are effective to provide us with this reasonable assurance.

Changes in Internal Control Over Financial Reporting

During the fourth quarter of 2008, no change occurred in our internal control over financial reporting that materially affected, or is likely to materially affect, our internal control over financial reporting.

Management’s Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, we evaluated the effectiveness of the design and operation of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that evaluation, our chief executive officer and chief financial officer concluded that our internal control over financial reporting was effective as of December 31, 2008, as reflected in our report included in Item 8.

Smith, Carney & Co., p.c., our independent registered public accounting firm, audited internal control over financial reporting and, based on that audit, issued the report set forth in Item 8.

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H. Roger Schwall, Assistant Director	April 8, 2009
Securities and Exchange Commission	Page 3

Financial Statements

Note D – Long Term Debt, page F-17

2. We note your proposed disclosure responding to prior comment 7. Please expand your disclosure to discuss any stated events of default which would permit the lenders to accelerate the debt if not cured within applicable grace periods, as requested in prior comment 7.

Response:

In response to the above comment, Note E – Long Term Debt (page F-18 thru F-21) in the Company’s 2008 Form 10-K included the following paragraphs to address stated events of default which would permit the lenders to accelerate the debt if not cured within applicable grace periods for the Revolving Bank Credit Facility and the Senior Subordinated Secured Notes:

Revolving Bank Credit Facility

Our lenders may accelerate all of the indebtedness under our revolving bank credit facility upon the occurrence of any event of default unless we cure any such default within any applicable grace period. For payments of principal and interest under the revolving bank credit facility, we generally have a three business day grace period, and we have a 30-day cure period for most covenant defaults, but not for defaults of certain specific covenants, including our financial covenants and negative covenants.

Senior Subordinated Secured Notes

The holders of our Secured Notes may declare the Secured Notes immediately due and payable upon the occurrence of any event of default under the Note Agreement unless we cure any such default within any applicable grace period. For payments of interest (but not principal and other required amounts) on the Secured Notes, we generally have a three-day grace period from the due date.

Engineering Comments

General Summary for Engineering Comments

With respect to the year-end 2006 reserve report, following are the statistics for estimated and actual production for 2007 (all numbers in net wellhead MMCFE):

Projected total production for 2007 (MMCFE)	15,633
Actual production for 2007	9,715
Total discrepancy	5,919

GMXR: NASDAQ OMX Group

H. Roger Schwall, Assistant Director	April 8, 2009
Securities and Exchange Commission	Page 4

With respect to the year-end 2007 reserve report, following are the statistics for estimated and actual production for 2008 (all numbers in net wellhead MMCFE):

Projected total production for 2008 (MMCFE)	15,312
Actual production for 2008	13,634
Total discrepancy	1,678

Following is a table showing the relative significance of the key factors in the shortage of production for the YE 2006 and YE 2007 reports:

Reason for Shortage	Percent of overestimation
2007 Estimate (YE 2006 Report) vs. 2007 Actual
Type Curve (PDP)	6.2	%
Type Curve (PUD)	40.9	%
PUDs not drilled	27.1	%
Delays in PUDs	19.6	%
Behind pipe delays/not completing	6.3	%
Total discrepancy	100.0	%
2008 Estimate (YE 2007 Report) vs. 2008 Actual
Type Curve (PDP)	24.3	%
Type Curve (PUD)	-39.7	%
PUDs not drilled	44.9	%
Delays in PUDs	48.9	%
Behind pipe delays/not completing	21.6	%
Total discrepancy	100.0	%
*       Note that the negative percent shown in the table is correct – actual was greater than predicted

There were two key reasons for the shortfall in gas production in year 2007 vs. what was estimated for that year in the YE 2006 report. One was the type curve used. At the time, there were a relatively small number of wells on GMX property which had enough production history to see the later time characteristics of the production curve. With more data, we now know that the curve shape is different from that original type curve. The other key reasons for the over projection was a shortfall in actual versus planned Proved Undeveloped (PUD) wells, and delays in drilling the PUD wells.

The primary reason for the shortfall in gas production in year 2008 vs. what was estimated for that year in the YE 2007 report was the refocus on the Haynesville drilling in the middle of 2008.

GMXR: NASDAQ OMX Group

H. Roger Schwall, Assistant Director	April 8, 2009
Securities and Exchange Commission	Page 5

SEC Question #3: GMX has broken this question down into three parts, which relate back to the original Question 15 in the Staff’s December 30, 2008 letter.

1) Question restated:Please tell us for the category of proved developed producing reserves in the 2006 and 2007 reserve reports, the decline rate you utilized for each year that resulted in the proved developed producing reserves for those years.

Response: This issue was clarified during the conference call with Jim Murphy of the Staff on March 24, 2009. GMX uses individual decline curves for each well in the Cotton Valley, and not just one curve on field summary of production. The individual decline curves all typically have the same shape, which is based on the type curve derived from those Cotton Valley wells on GMX property. Figures 1-5 (appended to this letter in paper format only, as these files are not in a file type conducive to electronic filing via EDGAR) show the progression of these curves through the past three years (gas rate only). Starting in the YE2007 report, the type curve was split into two separate areas, as it was recognized that the wells in the southern area of GMX’s property (labeled as “Area 2” on the plots) had a higher production profile. These type curves change each year as more data is added (both in the form of new wells and more data on the older wells).

The assumption has been made that there is no interference in these wells (with the exception of the 20 acre well locations, where the EUR has been reduced by about 10%). This assumption is based on volumetrics and the behavior of Cotton Valley wells offsetting GMX’s property which have more history available.

2) Question restated:Please tell us if all the wells drilled in prior years were included in establishing those declines rates and how many of those wells were added in each year in 2006 and 2007.

Response: Yes, generally the newer wells each year were used to update the type curve, except wells on leases that have no PUD reserves. The wells that were added in each year were then given their own decline curves, and added to the PDP reserves individually.

For the wells added in 2006 and 2007, please see part 2B in response to Question #5 below.

3) Question restated:Please also tell us the decline rate of your proved producing reserves if the wells you drilled in the last two years are not included when calculating the decline rate for each year in 2006 and 2007.

Response: This issue was clarified during the conference call with Jim Murphy of the Staff – see the response to part 1 of this question.

GMXR: NASDAQ OMX Group

H. Roger Schwall, Assistant Director	April 8, 2009
Securities and Exchange Commission	Page 6

SEC Question #4:

Question restated:Regarding prior comment 15, we requested information by individual well, not the average of all wells drilled. Please provide the requested information for each well.

Original questions from December 30, 2008 letter restated:For all your proved undeveloped wells that you drilled in 2007 please provide us with their pre-drill estimates of reserves and first year average production rate and their post-drill reserve estimates and actual first year average production rates. Please note the spacing of each well.Also:For all your proved undeveloped wells that you drilled in 2008 please provide us with their pre-drill estimates of reserves and first year average production rate and their post-drill reserve estimates and actual first year average production rates. Please note the spacing of each well.

Response: GMX has created Tables 1A, 1B, 2A and 2B which show this information for all individual wells completed in the Cotton Valley. They are included at the end of this letter.

SEC Question #5: GMX has broken this question down into five parts, which are referenced below as 1, 2A, 2B, 2C and 2D.

1) Question restated: Also regarding your response to prior comment 15 as to your actual total production in 2007 that was 44% below your estimate, the volumes that are in the reserve report are sales volumes, not net wellhead volumes as you seem to claim in your response. Therefore the difference between projected and actual total production is 44%, not 40% as you claim. Therefore, we consider this portion of your response to be an inadequate explanation for this large difference, while you seem to feel it is the major reason for the large difference.

Response: As was discussed in our conference call with Jim Murphy of the Staff, this was a misunderstanding. What GMX meant by the statement was that 40% of the difference was due to the change in the type curve used for the projection. The comment on sales volumes vs. wellhead volumes was simply to clarify what GMX reports.

2) Question restated:Also, as you know, there will always be operational, weather, labor, material shortages and other problems which will delay almost all forecasts. We therefore expect these to be built into any forecast that may be used for reporting and investing purposes. Therefore, we consider this response to also be an inadequate explanation for this large difference. Please be more specific in your

GMXR: NASDAQ OMX Group

H. Roger Schwall, Assistant Director	April 8, 2009
Securities and Exchange Commission	Page 7

response by further explaining the four bullet points that you seem to feel are only minor contributors to this large overestimation of production rates.

A. Question:Please tell us the length of delay between each well’s projected drilling and the actual drilling and how much this contributed to the overestimation.

Response: Table 3A appended to this letter shows a listing of the YE 2006 PUD wells that were actually drilled in 2007, with a comparison of the date of projected drilling vs. the date actually drilled, and an estimation of the lost gas volume as a result of the delay. Table 3B appended to this letter shows the same for the YE 2007 PUD wells that were drilled in 2008. These tables also show the PUD locations that were not drilled. All volumes shown on these tables are Net MMCFE.

B. Question:Please tell us how many PUD locations were projected to be drilled and how many were not drilled; the reasons for not drilling each one and how much this contributed to the overestimation.

Response: The table below shows the PUD locations projected in the YE 2006 report for drilling in 2007:

	Projected PUDs in 2007	Wells Actually Drilled in 2007	Difference	Approximate 2007 Gas Production lost due to PUDs not drilled (Net MMCFE)
Total	138	116	22	1584
Cotton Valley	132	112	20	1501

Most of the wells cited in the table are Cotton Valley wells.

For 2007, drilling statistics from the Unit rig #309 were used to project the number of Proved Undeveloped (PUD) drilling locations that could be drilled by the anticipated number of drilling rigs for each area. At this time no statistics were available for GMX rig #11 that started in November of 2006, or GMX rig #9 that began drilling in September of 2007. The average time projected for 2007 drilling for a conventional rig was 26 days. The historical data for Unit rig #309 for 2005 and 2006 showed an average of 24 ³/4 days. For the estimated 2007 PUD drilling in the YE 2006 report vs. 2007 actual drilling, the 20 Cotton Valley wells that were not drilled were due to the following unusual delays:

GMXR: NASDAQ OMX Group

H. Roger Schwall, Assistant Director	April 8, 2009
Securities and Exchange Commission	Page 8

Reason	# Wells delayed or displaced
1) GMX rig #9 construction was delayed from an anticipated delivery date of 3/1/2007 to 8/30/2007.	7
2) A salt water disposal well was drilled.	1
3) A horizontal well drilling in 2006 went into 2007	1
4) The fishing and sidetrack operations on the Gill #2	1 1/2
5) The Gill #7D had stuck pipe and sidetracking operations	1
6) The Joann Scott #5 had the entire CV interval cored	1/2
7) The Joann Scott #7 had stuck pipe and sidetracking operations	1
8) Directional drilling for 20 acre locations in 2007 not anticipated in the 2006 projections	1
9) Rig diversion to other projects	1
10) Unanticipated low drilling efficiencies	1
11) Loss of rig #229 from the Penn Virginia (PVA) joint venture area	4
Total	20

The table below shows the PUD locations projected in the YE 2007 report for drilling in 2008:

	Projected PUDs in 2008	Wells Actually Drilled in 2008	Difference	Approximate 2007 Gas Production lost due to PUDs not drilled (Net MMCFE)
Total	126	96	30	755
Cotton Valley	121	92	29	703

For 2008 PUD locations, conventional rigs were projected to need 24 days to drill a well, and optimized rigs were projected to need 22 days. The drilling rigs for 2008 became more efficient and unusual and unanticipated drilling issues were greatly reduced. Diversion to Haynesville/Bossier drilling, rig conversions and hurricanes were the key reasons for delays in 2008. For the estimated 2008 PUD drilling in the YE 2007 report vs. 2008 actual drilling, the 29 Cotton Valley wells that were not drilled were due to the following:

GMXR: NASDAQ OMX Group

H. Roger Schwall, Assistant Director	April 8, 2009
Securities and Exchange Commission	Page 9

Reason	# Wells delayed or displaced
1) In late summer 2008 PVA (GMX’s joint interest partner) diverted 4 rigs to Haynesville Bossier (HB) drilling. This negated drilling 23 additional wells, but drilling efficiencies in the PVA area had actually resulted in 8 additional wells drilled over projected as of the time of diverting the 4 rigs.	15
2) In late summer 2008 GMX diverted 2 rigs to Haynesville Bossier (HB) drilling.	11
3) Conversion to top drives on 4 GMX rigs	1
4) Hurricanes in the Gulf caused delays due to safety considerations to rig down and rig up after the storm	1
5) One horizontal well was drilled that was not scheduled resulting in the delay of drilling CV wells	1
Total	29

C. Question:Please further explain the meaning of behind-pipe projections and the impact on the overestimation of production rates.

Response: GMX projected several behind pipe additions for both the YE2006 and YE2007 reports. The majority of these additions were for sub-zones in the Cotton Valley, with the remainder being in the Travis Peak. The following tables summarize the predicted gas volumes in excess of actual, which are relatively small.

	YE 2006 Report
Scheduled Recompletions for 2007 (Includes some wells that were already drilled in 2006, but were not completed until 2007)	6
Actually Done in 2007	14
Approximate Gross Predicted Gas Volume not realized (MMCFE) (Year 2007)	417
Approximate Net Predicted Gas Volume not realized (MMCFE) (Year 2007)	370

GMXR: NASDAQ OMX Group

H. Roger Schwall, Assistant Director	April 8, 2009
Securities and Exchange Commission	Page 10

	YE 2007 Report
Scheduled Recompletions for 2008	18
Actually Done in 2008	2
Approximate Gross Predicted Gas Volume not realized (MMCFE) (Year 2008)	563
Approximate Net Predicted Gas Volume not realized (MMCFE) (Year 2008)	363

The “actual” volumes produced in the years 2007 and 2008 were calculated by comparing the new production curve with the added zone to the curve without the added zone. The difference in the two curves was considered the “actual” incremental production. This was not calculated rigorously, but estimated.

In similar fashion to the PUD wells, the behind pipe recompletions scheduled for year 2008 were affected by the shift in focus to the Haynesville reservoir. For the YE 2007 values, most of the scheduled behind pipe recompletions were actually wells that had been drilled in late 2006, but not yet completed.

D. Question:Please further explain the difference between the PDP forecast and the actual production rates in terms of the amount of difference in the decline rates and the reasons for the overestimation of the projected forecast versus the actual forecast.

Response: The following table compares the total amount of PDP gas predicted in the YE 2006 and YE 2007 reports with the amounts actually produced in each of years 2007 and 2008:

	# PDP Wells	Difference in 2007 Gross Production (MMCFE)	Difference in 2007 Net Production (MMCFE)	Difference in 2008 Gross Production (MMCFE)	Difference in 2008 Net Production (MMCFE)
YE 2006 Report	153	1392	370
YE 2007 Report	273			767	520

For the answer to Question 2D about projected versus actual production, see response below in answer to Question #6.

GMXR: NASDAQ OMX Group

H. Roger Schwall, Assistant Director	April 8, 2009
Securities and Exchange Commission	Page 11

SEC Question #6:

Question restated:We also note that although the actual average production rates for the Cotton Valley wells were approximately 30% lower than the pre-drill estimated production rates your reserve estimates for these wells have only apparently been lowered by approximately 1%. Please tell us why these reserve estimates were not lowered by more significant amounts given that the production rates were 30% lower than what you had originally projected. In this regard, we note that initial rates are often times an indication of the ultimate reserves a well will recover.

Response: The reserve estimates for the wells were reduced by a small amount because the type curve that was used to forecast the wells (which consists of the producing Cotton Valley wells on GMX property) was adjusted based on having newer wells, plus approximately another year of data. The results showed that the type curve changed in two ways. First, the average initial decline of the wells has increased, meaning that the first several months of production volumes are lower in the type curve used for YE 2007 that that used for YE 2006. Second, the hyperbolic exponent “b” has also increased, showing that the production from the wells tends to flatten out faster. This curve change year over year had the effect of showing similar reserves for the wells, despite the first year’s reduction in production. GMX attributes this behavior to productive zones which contain similar amounts of gas as other areas, but may show lower permeability in some of the sub zones, such that there is a time lag before these lower permeability zones begin contributing significantly to the production. Once they do begin contributing, they produce steadily for long periods of time at relatively low decline rates. Figures 1-5 (appended to this letter in paper format only, as these files are not in a file type conducive to electronic filing via EDGAR) show the progression of these type curves for the GMX properties.

SEC Question #7:

Question restated:Also regarding response to prior comment 15 and the table showing the YE 2007 production, please tell us the average daily rate of production for those Cotton Valley wells that had been on production for less than a year.

Response:Based on further discussion and clarification on the conference call with Jim Murphy of the Staff, the initial monthly rates of the wells drilled in 2008 are shown in Table 4 (appended to this letter) and are compared with the standard value which is from the type curve. As expected, there is a statistical variation, but the average for all the wells shows actual production data slightly higher than the forecast.

GMXR: NASDAQ OMX Group

H. Roger Schwall, Assistant Director	April 8, 2009
Securities and Exchange Commission	Page 12

SEC Question #8:

Question restated:It appears from the last portion of your response to prior comment 15 that you may have begun to de-emphasize the development of your Cotton Valley acreage. Please tell us if this is the case and if so, please disclose this fully in the MD&A portion of your 2008 10-K report.

Response: GMX has shifted resources that were previously earmarked for the Cotton Valley to the development of the Haynesville shale. This does not change the plans for the Cotton Valley other than reducing the rate of drilling and recompletion, which has been addressed in GMX’s YE2008 reserve report and disclosed in its Exchange Act filings.

Closing Comments

In connection with the Staff’s comments and our responses, the Company confirms that: (i) the Company is responsible for the adequacy and accuracy of the disclosures in the filing; and (ii) Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to the filing. We also acknowledge the Staff’s position that we 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.

Please feel free to contact me at 405-600-0711 (ext 305) if you have any questions or need additional information.

Sincerely,

/s/ James A. Merrill

James A. Merrill

Chief Financial Officer

GMX Resources Inc.

Table 1A

Comparison of EURs and 1st Year Production for YE2006 PUDs vs 2007 Actual Drills (FF0000Gross01+000 Volumes)

Table showing individual well volumes for response to SEC Question 3, Letter of February 24, 2009
		Pre-drill Gross EUR Volumes		Post Drill Gross EUR Volumes		Projected 1st Year Avg. Prod Rate		Actual 1st Year Avg. Prod Rate
Well	YE2006 Spacing	Gas (MMCF)	Oil (MBO)	Gas (MMCF)	Oil (MBO)	Gross Gas (MMCF)	Gross Oil (MBO)	Gross Gas (MMCF)	Gross Oil (MBO)
ABNEY # 2	40 Acres	1231.1	12.3	851.0	9.8	202.3	2.0	94.1	1.5
ABNEY # 3	40 Acres	1231.1	12.3	952.8	10.5	202.3	2.0	104.3	1.6
ABNEY # 4	40 Acres	1231.1	12.3	1305.7	11.6	202.3	2.0	117.4	1.4
ABNEY # 5	40 Acres	1225.4	12.3	1173.6	11.6	202.3	2.0	104.3	2.2
ABNEY # 6	40 Acres	1225.4	12.3	1905.6	16.9	202.3	2.0	158.2	2.7
ABNEY # 7	40 Acres	1238.1	12.4	996.4	10.0	202.3	2.0	231.8	1.5
ABNEY # 8	40 Acres	1231.1	12.3	825.3	8.3	202.3	2.0	82.7	1.6
ABNEY # 9	40 Acres	1231.1	12.3	1045.7	7.2	195.5	2.0	96.0	1.5
ARNOLD WILLIAMS #10	40 Acres	1219.1	12.2	3389.5	22.4	202.3	2.0	324.1	3.3
ARNOLD WILLIAMS #11	40 Acres	1219.9	12.2	2614.8	24.9	202.3	2.0	258.2	3.1
BLOCKER HEIRS # 6	40 Acres	1226.2	12.3	1134.7	11.7	202.3	2.0	145.7	1.6
BLOCKER HEIRS # 7	40 Acres	1226.2	12.3	1165.8	9.3	202.3	2.0	131.9	0.9
BLOCKER HEIRS # 9D	40 Acres	1234.5	12.3	1173.6	9.4	202.3	2.0	142.9	1.0
BLOCKER WARE # 5	40 Acres	1231.1	12.3	970.4	9.5	181.9	1.8	105.1	0.9
BLOCKER WARE # 7	40 Acres	1234.5	12.3	532.9	5.3	202.3	2.0	58.5	1.0
BOOKOUT # 1	40 Acres	1237.4	12.4	1488.3	14.9	202.3	2.0	190.5	1.9
BOOKOUT # 2	40 Acres	1238.1	12.4	1920.3	13.2	202.3	2.0	239.2	1.6
BOOKOUT # 3	40 Acres	1237.4	12.4	2275.8	12.0	202.3	2.0	241.1	1.6
BOOKOUT # 4	40 Acres	1238.1	12.4	2663.2	9.4	202.3	2.0	319.2	1.6
BOSH # 3	40 Acres	1231.1	12.3	644.7	6.5	202.3	2.0	73.0	0.4
BOSH # 5	40 Acres	1231.1	12.3	1242.2	13.5	202.3	2.0	141.8	0.6
BOSH # 7	40 Acres	1211.9	12.1	730.2	5.0	202.3	2.0	92.9	0.9
BOSH # 8	40 Acres	1226.2	12.3	586.3	5.8	202.3	2.0	82.4	0.9
BOSH #10D	40 Acres	1231.1	12.3	1452.6	7.2	194.8	2.0	108.4	2.3
BRADLEY # 2	40 Acres	1231.1	12.3	1726.9	19.1	202.3	2.0	226.2	1.5
BRADLEY # 7	40 Acres	1231.1	12.3	1149.1	5.7	196.1	2.0	110.3	1.1
BRYANT #4	40 Acres	1225.4	12.3	1158.4	8.5	202.3	2.0	88.5	0.8
BRYANT #5	40 Acres	1225.4	12.3	1398.9	8.2	202.3	2.0	82.4	0.7
CADENHEAD # 8	40 Acres	1228.5	12.3	1373.2	16.7	202.3	2.0	161.9	1.8
CALLISON # 1	40 Acres	1226.2	12.3	1146.9	5.8	202.3	2.0	119.4	0.9
ELLA NOLTE # 1	40 Acres	1228.5	12.3	6294.8	51.6	202.3	2.0	728.3	6.6
ELLA NOLTE # 2	40 Acres	1226.2	12.3	960.2	9.6	202.3	2.0	99.9	0.8
ELLA NOLTE # 3	40 Acres	1211.9	12.1	2275.8	22.8	202.3	2.0	201.7	2.4
ELLA NOLTE # 4	40 Acres	1231.1	12.3	1138.0	11.4	182.6	1.8	107.4	1.3
ELLA NOLTE # 8D	40 Acres	1231.1	12.3	1466.9	12.0	193.9	2.0	130.5	0.9
EOG #4	40 Acres	1225.4	12.3	921.0	6.2	202.3	2.0	82.3	1.0
FOSTER # 1	40 Acres	1226.2	12.3	1731.7	16.6	169.9	1.7	160.9	3.5
FOSTER # 2	40 Acres	1219.9	12.2	3147.4	44.4	202.3	2.0	596.3	13.9
FOSTER # 3	40 Acres	1272.8	12.7	3147.4	47.2	202.3	2.0	458.3	14.8
FURRH GU3 # 2	40 Acres	1219.9	12.2	1183.1	28.1	202.3	2.0	115.9	3.9
FURRH GU3 # 3	40 Acres	1219.9	12.2	1371.5	25.6	202.3	2.0	139.8	3.2

Cotton Valley wells only Table 1A - Page 1 of 3

Table 1A

Comparison of EURs and 1st Year Production for YE2006 PUDs vs 2007 Actual Drills (FF0000Gross01+000 Volumes)

Table showing individual well volumes for response to SEC Question 3, Letter of February 24, 2009

		Pre-drill Gross EUR Volumes		Post Drill Gross EUR Volumes		Projected 1st Year Avg. Prod Rate		Actual 1st Year Avg. Prod Rate
Well	YE2006 Spacing	Gas (MMCF)	Oil (MBO)	Gas (MMCF)	Oil (MBO)	Gross Gas (MMCF)	Gross Oil (MBO)	Gross Gas (MMCF)	Gross Oil (MBO)
FURRH GU3 #12	40 Acres	1226.2	12.3	957.7	18.8	198.0	2.0	228.8	7.3
FURRH GU3 #13	40 Acres	1226.2	12.3	837.4	15.0	198.0	2.0	182.6	7.6
FURRH GU3 #14	40 Acres	1219.9	12.2	602.1	9.9	202.3	2.0	114.7	2.8
FURRH GU3 #15	40 Acres	1219.9	12.2	720.3	12.6	202.3	2.0	147.2	3.1
FURRH GU3 #16	40 Acres	1226.2	12.3	1711.4	15.9	198.9	2.0	203.9	3.0
GULLEY # 9	40 Acres	1232.2	12.3	984.1	6.4	202.3	2.0	146.0	0.6
GULLEY #10	40 Acres	1236.7	12.4	1018.5	3.9	202.3	2.0	134.3	0.6
GULLEY #14	40 Acres	1231.1	12.3	717.8	2.8	191.6	1.9	81.8	0.5
GULLEY #15	40 Acres	1231.1	12.3	946.0	9.5	182.1	1.8	76.5	0.4
HEISMAN # 1	40 Acres	1231.1	12.3	1007.0	10.0	202.3	2.0	117.0	0.5
HEISMAN # 2	40 Acres	1226.2	12.3	691.1	7.0	202.3	2.0	74.9	0.6
HERRIN MARGARET # 7	40 Acres	1225.4	12.3	926.7	9.6	202.3	2.0	101.1	0.6
HERRIN SYLVIA # 6	40 Acres	1225.4	12.3	1365.1	11.8	202.3	2.0	160.1	1.4
HERRIN SYLVIA # 7	40 Acres	1237.4	12.4	519.9	3.8	202.3	2.0	81.8	0.9
HERRIN SYLVIA # 8	40 Acres	1231.1	12.3	1286.3	12.5	202.3	2.0	152.5	1.2
HH GILL # 2	40 Acres	1226.2	12.3	1042.6	6.3	202.3	2.0	115.0	0.5
HH GILL # 4	40 Acres	1226.2	12.3	852.0	13.6	202.3	2.0	98.3	0.8
HH GILL # 6	40 Acres	1226.2	12.3	482.7	4.8	202.3	2.0	57.9	0.5
HH GILL # 7D	40 Acres	1212.7	12.1	1040.1	12.7	202.3	2.0	104.9	1.8
HH GILL #12D	40 Acres	1231.1	12.3	1138.0	10.9	184.6	1.9	116.2	1.6
JF ROBERTS #1	40 Acres	1226.2	12.3	834.9	6.7	195.5	2.0	61.3	0.6
JF ROBERTS #2	40 Acres	1226.2	12.3	485.7	3.9	188.1	1.9	58.4	0.5
JOANN SCOTT # 4	40 Acres	1226.2	12.3	476.4	3.6	202.3	2.0	65.1	1.0
JOANN SCOTT # 5	40 Acres	1226.2	12.3	888.9	8.9	202.3	2.0	95.0	1.2
JOANN SCOTT # 7	40 Acres	1226.2	12.3	184.5	1.3	202.3	2.0	28.9	0.2
JOANN SCOTT # 9	40 Acres	1212.7	12.1	496.7	3.5	202.3	2.0	60.1	1.0
K #2	40 Acres	1226.2	12.3	808.1	8.6	202.3	2.0	94.1	0.7
LANCASTER #2	40 Acres	1225.4	12.3	753.6	6.6	202.3	2.0	88.6	0.5
LAWLESS RHOADES # 1	40 Acres	1219.1	12.2	511.9	5.3	202.3	2.0	123.9	2.4
LAWLESS RHOADES # 2	40 Acres	1219.9	12.2	1006.5	9.3	202.3	2.0	155.4	1.8
LAWLESS RHOADES # 3	40 Acres	1219.9	12.2	1824.3	6.1	202.3	2.0	212.9	2.0
LAWLESS RHOADES # 4	40 Acres	1219.1	12.2	1164.3	6.2	202.3	2.0	213.1	2.1
LAWLESS RHOADES # 5	40 Acres	1219.9	12.2	1125.7	9.3	202.3	2.0	159.5	1.8
LAWLESS RHOADES # 6	40 Acres	1219.9	12.2	1290.7	18.3	202.3	2.0	128.4	2.4
MARGIE #8	40 Acres	1231.1	12.3	1222.5	5.9	195.2	2.0	108.8	0.9
MCCLENDON #1	40 Acres	1219.9	12.2	1393.6	35.2	202.3	2.0	127.8	4.2
MCCLENDON #2	40 Acres	1219.9	12.2	2978.6	32.3	202.3	2.0	253.5	3.9
MCCLENDON #3	40 Acres	1219.1	12.2	1512.9	33.8	202.3	2.0	139.3	4.2
MCCLENDON #4	40 Acres	1219.9	12.2	2810.8	30.4	202.3	2.0	222.2	4.2
MCCLENDON #5	40 Acres	1226.2	12.3	1271.4	19.5	193.7	1.9	282.9	4.1
MCJIMSEY # 2	40 Acres	1272.8	12.7	973.1	9.9	202.3	2.0	90.3	1.1

Cotton Valley wells only Table 1A - Page 2 of 3

Table 1A

Comparison of EURs and 1st Year Production for YE2006 PUDs vs 2007 Actual Drills (FF0000Gross01+000 Volumes)

Table showing individual well volumes for response to SEC Question 3, Letter of February 24, 2009

		Pre-drill Gross EUR Volumes		Post Drill Gross EUR Volumes		Projected 1st Year Avg. Prod Rate		Actual 1st Year Avg. Prod Rate
Well	YE2006 Spacing	Gas (MMCF)	Oil (MBO)	Gas (MMCF)	Oil (MBO)	Gross Gas (MMCF)	Gross Oil (MBO)	Gross Gas (MMCF)	Gross Oil (MBO)
MCJIMSEY # 3	40 Acres	1219.9	12.2	697.6	6.8	202.3	2.0	49.7	0.9
MCJIMSEY # 4	40 Acres	1219.9	12.2	915.4	4.7	202.3	2.0	78.8	0.6
MCJIMSEY # 5	40 Acres	1219.1	12.2	342.8	1.8	202.3	2.0	71.6	0.6
MCJIMSEY # 6	40 Acres	1226.2	12.3	578.0	4.0	198.3	2.0	65.3	0.5
MCJIMSEY # 7	40 Acres	1219.9	12.2	783.8	4.5	202.3	2.0	86.1	0.5
MCJIMSEY # 8	40 Acres	1226.2	12.3	591.5	3.7	186.9	1.9	75.3	0.4
RICHARDSON # 7	40 Acres	1232.2	12.3	1958.5	8.0	202.3	2.0	100.4	0.7
RICHARDSON # 8	40 Acres	1237.4	12.4	1084.2	5.1	202.3	2.0	123.4	0.6
ROSEHAVEN # 4	40 Acres	1225.4	12.3	1228.6	15.9	202.3	2.0	121.3	2.0
ROSEHAVEN # 5	40 Acres	1242.4	12.4	778.2	8.5	202.3	2.0	60.3	1.2
ROSEHAVEN # 6	40 Acres	1225.4	12.3	1204.7	11.5	202.3	2.0	57.5	1.0
ROSEHAVEN # 7	40 Acres	1225.4	12.3	888.3	6.2	202.3	2.0	82.0	0.8
ROSEHAVEN # 8	40 Acres	1238.8	12.4	1078.1	3.3	202.3	2.0	108.0	0.5
ROSEHAVEN # 9	40 Acres	1231.1	12.3	771.8	2.9	193.0	1.9	61.2	0.6
SPARKS #2	40 Acres	1219.1	12.2	453.1	5.3	202.3	2.0	90.6	1.5
SPARKS #3	40 Acres	1272.8	12.7	924.0	9.2	202.3	2.0	100.5	1.4
SPARKS #4	40 Acres	1272.8	12.7	1259.0	11.2	202.3	2.0	105.7	1.6
SPARKS #5	40 Acres	1219.9	12.2	2143.8	22.1	202.3	2.0	186.6	2.8
SPENCER # 1	40 Acres	1237.4	12.4	1484.3	12.6	202.3	2.0	238.6	6.9
SPENCER # 2	40 Acres	1238.8	12.4	1936.9	19.4	202.3	2.0	183.5	5.1
SPENCER # 3	40 Acres	1231.1	12.3	1936.9	19.4	202.3	2.0	217.0	4.3
TILLER #2	40 Acres	1219.9	12.2	499.2	5.4	202.3	2.0	61.3	1.3
TILLER #3	40 Acres	1219.9	12.2	785.9	6.5	202.3	2.0	62.1	0.9
TIMMONS #1	40 Acres	1219.1	12.2	787.0	7.9	202.3	2.0	85.0	2.0
TIMMONS #2	40 Acres	1226.2	12.3	321.6	3.2	182.3	1.8	43.1	0.8
TIMMONS B #1	40 Acres	1226.2	12.3	380.7	3.8	202.3	2.0	66.2	1.0
UNDERWOOD # 5	40 Acres	1212.7	12.1	1019.4	7.0	202.3	2.0	115.1	0.6
UNDERWOOD # 6	40 Acres	1233.0	12.3	520.7	4.2	202.3	2.0	96.0	0.6
UNDERWOOD # 8	40 Acres	1230.0	12.3	606.2	6.0	202.3	2.0	76.3	0.6
UNDERWOOD #10	40 Acres	1231.1	12.3	977.0	9.5	183.7	1.9	94.3	1.4
Totals		137569.0	1375.7	136431.8	1307.4	22393.8	224.4	15481.1	217.6

Cotton Valley wells only Table 1A - Page 3 of 3

Table 1B

Comparison of EURs and 1st Year Production for YE2006 PUDs vs 2007 Actual Drills (FF0000Net01+000 Volumes)

Table showing individual well volumes for response to SEC Question 3, Letter of February 24, 2009
		Pre-drill Net EUR Volumes		Post Drill Net EUR Volumes		Projected 1st Year Avg. Prod Rate		Actual 1st Year Avg. Prod Rate
Well	YE2006 Spacing	Gas (MMCF)	Oil (MBO)	Gas (MMCF)	Oil (MBO)	Net Gas (MMCF)	Net Oil (MBO)	Net Gas (MMCF)	Net Oil (MBO)
ABNEY # 2	40 Acres	295.5	3.0	204.2	2.3	48.6	0.5	22.6	0.4
ABNEY # 3	40 Acres	295.5	3.0	228.7	2.5	48.6	0.5	25.0	0.4
ABNEY # 4	40 Acres	295.5	3.0	313.4	2.8	48.6	0.5	28.2	0.3
ABNEY # 5	40 Acres	294.1	2.9	281.7	2.8	48.6	0.5	25.0	0.5
ABNEY # 6	40 Acres	294.1	2.9	457.4	4.1	48.6	0.5	38.0	0.6
ABNEY # 7	40 Acres	297.1	3.0	239.1	2.4	48.6	0.5	55.6	0.3
ABNEY # 8	40 Acres	295.5	3.0	198.1	2.0	48.6	0.5	19.9	0.4
ABNEY # 9	40 Acres	295.5	3.0	251.0	1.7	46.9	0.5	23.0	0.4
ARNOLD WILLIAMS #10	40 Acres	487.7	4.9	1355.8	9.0	80.9	0.8	129.6	1.3
ARNOLD WILLIAMS #11	40 Acres	488.0	4.9	1045.9	10.0	80.9	0.8	103.3	1.2
BLOCKER HEIRS # 6	40 Acres	980.9	9.8	907.8	9.3	161.9	1.6	116.5	1.3
BLOCKER HEIRS # 7	40 Acres	980.9	9.8	932.6	7.4	161.9	1.6	105.6	0.7
BLOCKER HEIRS # 9D	40 Acres	987.6	9.9	938.9	7.5	161.9	1.6	114.3	0.8
BLOCKER WARE # 5	40 Acres	984.9	9.8	776.3	7.6	145.5	1.5	84.1	0.7
BLOCKER WARE # 7	40 Acres	987.6	9.9	426.3	4.3	161.9	1.6	46.8	0.8
BOOKOUT # 1	40 Acres	297.0	3.0	357.2	3.6	48.6	0.5	45.7	0.5
BOOKOUT # 2	40 Acres	297.1	3.0	460.9	3.2	48.6	0.5	57.4	0.4
BOOKOUT # 3	40 Acres	297.0	3.0	546.2	2.9	48.6	0.5	57.9	0.4
BOOKOUT # 4	40 Acres	297.1	3.0	639.2	2.3	48.6	0.5	76.6	0.4
BOSH # 3	40 Acres	984.9	9.8	515.8	5.2	161.9	1.6	58.4	0.3
BOSH # 5	40 Acres	984.9	9.8	993.8	10.8	161.9	1.6	113.4	0.5
BOSH # 7	40 Acres	969.5	9.7	584.2	4.0	161.9	1.6	74.4	0.7
BOSH # 8	40 Acres	980.9	9.8	469.0	4.6	161.9	1.6	65.9	0.7
BOSH #10D	40 Acres	984.9	9.8	1162.1	5.8	155.8	1.6	86.7	1.8
BRADLEY # 2	40 Acres	984.9	9.8	1381.6	15.3	161.9	1.6	181.0	1.2
BRADLEY # 7	40 Acres	984.9	9.8	919.3	4.6	156.9	1.6	88.2	0.9
BRYANT #4	40 Acres	294.1	2.9	278.0	2.0	48.6	0.5	21.2	0.2
BRYANT #5	40 Acres	294.1	2.9	335.7	2.0	48.6	0.5	19.8	0.2
CADENHEAD # 8	40 Acres	982.8	9.8	1098.6	13.4	161.9	1.6	129.5	1.4
CALLISON # 1	40 Acres	980.9	9.8	917.5	4.6	161.9	1.6	95.5	0.7
ELLA NOLTE # 1	40 Acres	982.8	9.8	5035.8	41.3	161.9	1.6	582.6	5.3
ELLA NOLTE # 2	40 Acres	980.9	9.8	768.1	7.7	161.9	1.6	79.9	0.6
ELLA NOLTE # 3	40 Acres	969.5	9.7	1820.6	18.2	161.9	1.6	161.3	1.9
ELLA NOLTE # 4	40 Acres	984.9	9.8	910.4	9.1	146.1	1.5	85.9	1.0
ELLA NOLTE # 8D	40 Acres	984.9	9.8	1173.6	9.6	155.1	1.6	104.4	0.7
EOG #4	40 Acres	294.1	2.9	221.0	1.5	48.6	0.5	19.8	0.2
FOSTER # 1	40 Acres	490.5	4.9	692.7	6.6	67.9	0.7	64.4	1.4
FOSTER # 2	40 Acres	488.0	4.9	1259.0	17.8	80.9	0.8	238.5	5.5
FOSTER # 3	40 Acres	509.1	5.1	1259.0	18.9	80.9	0.8	183.3	5.9
FURRH GU3 # 2	40 Acres	488.0	4.9	473.2	11.2	80.9	0.8	46.4	1.6
FURRH GU3 # 3	40 Acres	488.0	4.9	548.6	10.2	80.9	0.8	55.9	1.3

Cotton Valley wells only Table 1B - Page 1 of 3

Table 1B

Comparison of EURs and 1st Year Production for YE2006 PUDs vs 2007 Actual Drills (FF0000Net01+000 Volumes)

Table showing individual well volumes for response to SEC Question 3, Letter of February 24, 2009

		Pre-drill Net EUR Volumes		Post Drill Net EUR Volumes		Projected 1st Year Avg. Prod Rate		Actual 1st Year Avg. Prod Rate
Well	YE2006 Spacing	Gas (MMCF)	Oil (MBO)	Gas (MMCF)	Oil (MBO)	Net Gas (MMCF)	Net Oil (MBO)	Net Gas (MMCF)	Net Oil (MBO)
FURRH GU3 #12	40 Acres	490.5	4.9	383.1	7.5	79.2	0.8	91.5	2.9
FURRH GU3 #13	40 Acres	490.5	4.9	335.0	6.0	79.2	0.8	73.0	3.0
FURRH GU3 #14	40 Acres	488.0	4.9	240.8	4.0	80.9	0.8	45.9	1.1
FURRH GU3 #15	40 Acres	488.0	4.9	288.1	5.0	80.9	0.8	58.9	1.3
FURRH GU3 #16	40 Acres	490.5	4.9	684.6	6.3	79.6	0.8	81.5	1.2
GULLEY # 9	40 Acres	295.7	3.0	236.2	1.5	48.6	0.5	35.0	0.2
GULLEY #10	40 Acres	296.8	3.0	244.4	0.9	48.6	0.5	32.2	0.2
GULLEY #14	40 Acres	295.5	3.0	172.3	0.7	46.0	0.5	19.6	0.1
GULLEY #15	40 Acres	295.5	3.0	227.0	2.3	43.7	0.4	18.4	0.1
HEISMAN # 1	40 Acres	984.9	9.8	805.6	8.0	161.9	1.6	93.6	0.4
HEISMAN # 2	40 Acres	980.9	9.8	552.9	5.6	161.9	1.6	59.9	0.5
HERRIN MARGARET # 7	40 Acres	294.1	2.9	222.4	2.3	48.6	0.5	24.3	0.1
HERRIN SYLVIA # 6	40 Acres	294.1	2.9	327.6	2.8	48.6	0.5	38.4	0.3
HERRIN SYLVIA # 7	40 Acres	297.0	3.0	124.8	0.9	48.6	0.5	19.6	0.2
HERRIN SYLVIA # 8	40 Acres	295.5	3.0	308.7	3.0	48.6	0.5	36.6	0.3
HH GILL # 2	40 Acres	980.9	9.8	834.0	5.1	161.9	1.6	92.0	0.4
HH GILL # 4	40 Acres	980.9	9.8	681.6	10.9	161.9	1.6	78.6	0.6
HH GILL # 6	40 Acres	980.9	9.8	386.2	3.9	161.9	1.6	46.3	0.4
HH GILL # 7D	40 Acres	970.2	9.7	832.1	10.2	161.9	1.6	83.9	1.4
HH GILL #12D	40 Acres	984.9	9.8	910.4	8.7	147.7	1.5	93.0	1.3
JF ROBERTS #1	40 Acres	490.5	4.9	334.0	2.7	78.2	0.8	24.5	0.2
JF ROBERTS #2	40 Acres	490.5	4.9	194.3	1.6	75.2	0.8	23.4	0.2
JOANN SCOTT # 4	40 Acres	980.9	9.8	381.2	2.9	161.9	1.6	52.1	0.8
JOANN SCOTT # 5	40 Acres	980.9	9.8	711.1	7.1	161.9	1.6	76.0	0.9
JOANN SCOTT # 7	40 Acres	980.9	9.8	147.6	1.1	161.9	1.6	23.1	0.2
JOANN SCOTT # 9	40 Acres	970.2	9.7	397.4	2.8	161.9	1.6	48.0	0.8
K #2	40 Acres	980.9	9.8	646.5	6.9	161.9	1.6	75.3	0.6
LANCASTER #2	40 Acres	294.1	2.9	180.9	1.6	48.6	0.5	21.3	0.1
LAWLESS RHOADES # 1	40 Acres	487.7	4.9	204.8	2.1	80.9	0.8	49.5	1.0
LAWLESS RHOADES # 2	40 Acres	488.0	4.9	402.6	3.7	80.9	0.8	62.1	0.7
LAWLESS RHOADES # 3	40 Acres	488.0	4.9	729.7	2.4	80.9	0.8	85.2	0.8
LAWLESS RHOADES # 4	40 Acres	487.7	4.9	465.7	2.5	80.9	0.8	85.2	0.8
LAWLESS RHOADES # 5	40 Acres	488.0	4.9	450.3	3.7	80.9	0.8	63.8	0.7
LAWLESS RHOADES # 6	40 Acres	488.0	4.9	516.3	7.3	80.9	0.8	51.4	1.0
MARGIE #8	40 Acres	295.5	3.0	293.4	1.4	46.9	0.5	26.1	0.2
MCCLENDON #1	40 Acres	488.0	4.9	557.5	14.1	80.9	0.8	51.1	1.7
MCCLENDON #2	40 Acres	488.0	4.9	1191.4	12.9	80.9	0.8	101.4	1.5
MCCLENDON #3	40 Acres	487.7	4.9	605.2	13.5	80.9	0.8	55.7	1.7
MCCLENDON #4	40 Acres	488.0	4.9	1124.3	12.2	80.9	0.8	88.9	1.7
MCCLENDON #5	40 Acres	490.5	4.9	508.5	7.8	77.5	0.8	113.2	1.6
MCJIMSEY # 2	40 Acres	509.1	5.1	389.2	4.0	80.9	0.8	36.1	0.4

Cotton Valley wells only Table 1B - Page 2 of 3

Table 1B

Comparison of EURs and 1st Year Production for YE2006 PUDs vs 2007 Actual Drills (FF0000Net01+000 Volumes)

Table showing individual well volumes for response to SEC Question 3, Letter of February 24, 2009

		Pre-drill Net EUR Volumes		Post Drill Net EUR Volumes		Projected 1st Year Avg. Prod Rate		Actual 1st Year Avg. Prod Rate
Well	YE2006 Spacing	Gas (MMCF)	Oil (MBO)	Gas (MMCF)	Oil (MBO)	Net Gas (MMCF)	Net Oil (MBO)	Net Gas (MMCF)	Net Oil (MBO)
MCJIMSEY # 3	40 Acres	488.0	4.9	279.0	2.7	80.9	0.8	19.9	0.4
MCJIMSEY # 4	40 Acres	488.0	4.9	366.2	1.9	80.9	0.8	31.5	0.2
MCJIMSEY # 5	40 Acres	487.7	4.9	137.1	0.7	80.9	0.8	28.6	0.2
MCJIMSEY # 6	40 Acres	490.5	4.9	231.2	1.6	79.3	0.8	26.1	0.2
MCJIMSEY # 7	40 Acres	488.0	4.9	313.5	1.8	80.9	0.8	34.4	0.2
MCJIMSEY # 8	40 Acres	490.5	4.9	236.6	1.5	74.8	0.8	30.1	0.2
RICHARDSON # 7	40 Acres	295.7	3.0	470.0	1.9	48.6	0.5	24.1	0.2
RICHARDSON # 8	40 Acres	297.0	3.0	260.2	1.2	48.6	0.5	29.6	0.1
ROSEHAVEN # 4	40 Acres	294.1	2.9	294.9	3.8	48.6	0.5	29.1	0.5
ROSEHAVEN # 5	40 Acres	298.2	3.0	186.8	2.1	48.6	0.5	14.5	0.3
ROSEHAVEN # 6	40 Acres	294.1	2.9	289.1	2.8	48.6	0.5	13.8	0.2
ROSEHAVEN # 7	40 Acres	294.1	2.9	213.2	1.5	48.6	0.5	19.7	0.2
ROSEHAVEN # 8	40 Acres	297.3	3.0	258.7	0.8	48.6	0.5	25.9	0.1
ROSEHAVEN # 9	40 Acres	295.5	3.0	185.2	0.7	46.3	0.5	14.7	0.1
SPARKS #2	40 Acres	487.7	4.9	181.2	2.1	80.9	0.8	36.2	0.6
SPARKS #3	40 Acres	509.1	5.1	369.6	3.7	80.9	0.8	40.2	0.6
SPARKS #4	40 Acres	509.1	5.1	503.6	4.5	80.9	0.8	42.3	0.6
SPARKS #5	40 Acres	488.0	4.9	857.5	8.8	80.9	0.8	74.6	1.1
SPENCER # 1	40 Acres	297.0	3.0	356.2	3.0	48.6	0.5	57.3	1.7
SPENCER # 2	40 Acres	297.3	3.0	464.8	4.6	48.6	0.5	44.0	1.2
SPENCER # 3	40 Acres	295.5	3.0	464.8	4.6	48.6	0.5	52.1	1.0
TILLER #2	40 Acres	488.0	4.9	199.7	2.2	80.9	0.8	24.5	0.5
TILLER #3	40 Acres	488.0	4.9	314.4	2.6	80.9	0.8	24.8	0.3
TIMMONS #1	40 Acres	487.7	4.9	314.8	3.1	80.9	0.8	34.0	0.8
TIMMONS #2	40 Acres	490.5	4.9	128.6	1.3	72.9	0.7	17.2	0.3
TIMMONS B #1	40 Acres	490.5	4.9	152.3	1.5	80.9	0.8	26.5	0.4
UNDERWOOD # 5	40 Acres	970.2	9.7	815.5	5.6	161.9	1.6	92.1	0.5
UNDERWOOD # 6	40 Acres	986.4	9.9	416.5	3.4	161.9	1.6	76.8	0.5
UNDERWOOD # 8	40 Acres	984.0	9.8	485.0	4.8	161.9	1.6	61.1	0.5
UNDERWOOD #10	40 Acres	984.9	9.8	781.6	7.6	147.0	1.5	75.4	1.1
Totals		65105.7	651.0	63135.8	610.3	10593.9	106.2	7188.7	94.8

Cotton Valley wells only Table 1B - Page 3 of 3

Table 2A

Comparison of EURs and 1st Year Production for YE2007 PUDs vs 2008 Actual Drills (FF0000Gross01+000 Volumes)

Table showing individual well volumes for response to SEC Question 3, Letter of February 24, 2009

		Pre-drill Gross EUR Volumes		Post Drill Gross EUR Volumes		Projected 1st Year (or portion thereof) Avg. Prod Rate		Actual 1st Year (or portion thereof) Avg. Prod Rate
Well	YE2007 Spacing	Gas (MMCF)	Oil (MBO)	Gas (MMCF)	Oil (MBO)	Gross Gas (MMCF)	Gross Oil (MBO)	Gross Gas (MMCF)	Gross Oil (MBO)
ABNEY #10	40A	1153.3	11.5	532.6	5.3	86.8	0.9	50.3	0.7
ABNEY #11	20A	1031.4	10.3	832.5	8.3	76.1	0.8	93.2	0.5
ABNEY #13	20A	1033.0	10.3	941.3	9.4	55.8	0.6	64.9	0.3
ABNEY #14	20A	1033.0	10.3	427.4	4.3	55.5	0.6	24.1	0.2
ABNEY #15	20A	1031.4	10.3	699.4	7.0	76.1	0.8	66.0	0.6
ARNOLD WILLIAMS # 9	40A	1389.8	20.8	1114.9	16.7	150.4	2.6	124.7	2.6
ARNOLD WILLIAMS #14	20A	1288.0	19.3	1799.5	21.6	139.0	2.4	194.1	2.3
ARNOLD WILLIAMS #15	20A	1288.8	19.3	1920.1	28.8	139.0	2.4	175.0	2.3
BALDWIN # 8D	40A	1153.3	11.5	1752.5	17.5	105.2	1.1	199.1	1.5
BALDWIN # 9	40A	1153.3	11.5	1794.2	17.9	78.8	0.8	160.5	1.0
BALDWIN #10	20A	1035.6	10.4	2157.5	21.6	72.2	0.7	173.2	0.4
BALDWIN #11	20A	1035.6	10.4	2035.9	20.4	67.3	0.7	152.0	1.3
BALDWIN #12	20A	1035.6	10.4	2008.5	20.1	86.1	0.9	185.5	0.8
BELL # 7	20A	1034.6	10.3	324.7	3.2	108.6	1.1	62.0	1.2
BLOCKER HEIRS #10	20A	1034.6	10.3	659.3	6.6	98.0	1.0	76.8	0.7
BLOCKER HEIRS #11D	20A	1035.6	10.4	912.3	9.1	79.6	0.8	80.4	0.8
BLOCKER HEIRS #15D	40A	1153.3	11.5	637.6	6.4	88.2	0.9	53.9	0.6
BLOCKER HEIRS #19	20A	1033.0	10.3	499.7	5.0	35.4	0.4	25.7	0.2
BLOCKER HEIRS #28D	40A	1153.3	11.5	1005.0	10.1	96.5	1.0	115.2	0.5
BLOCKER HEIRS #30D	40A	1153.3	11.5	881.2	8.8	69.2	0.7	65.5	0.3
BOOKOUT # 5	20A	1020.4	10.2	1007.2	10.1	111.4	1.1	123.4	1.0
BOOKOUT # 6	20A	1032.6	10.3	750.5	7.5	111.4	1.1	116.2	1.1
BOOKOUT # 7	20A	1033.0	10.3	915.0	9.1	111.0	1.1	123.0	1.2
BOOKOUT # 8	40A	1153.3	11.5	1097.2	11.0	98.7	1.0	92.2	1.9
BOOKOUT # 9	20A	1032.6	10.3	1280.1	12.8	98.4	1.0	120.5	2.2
BOOKOUT #10	20A	1033.0	10.3	944.1	9.4	98.2	1.0	98.4	1.9
BOSH # 6	40A	1153.0	11.5	690.1	6.9	1.4	0.0	3.5	0.0
BOSH # 9	40A	1153.0	11.5	1150.4	11.5	0.0	0.0	0.0	0.0
BRADLEY # 5	20A	1041.8	10.4	1220.9	12.2	115.6	1.2	137.1	1.2
BRADLEY #11D	20A	1041.8	10.4	500.6	5.0	111.0	1.1	45.0	0.5
CADENHEAD #12	40A	1153.0	11.5	972.4	9.7	54.8	0.5	57.2	0.3
CADENHEAD #14D	20A	1035.6	10.4	851.5	8.5	74.3	0.7	68.9	0.7
CADENHEAD #15	40A	1153.0	11.5	1153.8	11.5	49.5	0.5	53.8	0.1
CALLISON # 2R	20A	1040.3	10.4	1218.2	12.2	96.5	1.0	158.7	0.6
CALLISON # 3	20A	1035.6	10.4	791.2	7.9	84.2	0.8	64.0	0.6
CALLISON # 5D	20A	1035.6	10.4	1322.8	13.2	81.7	0.8	131.8	0.5
CALLISON # 8D	20A	1033.0	10.3	880.6	8.8	63.8	0.6	60.8	0.2
CALLISON #11	40A	1153.0	11.5	1150.4	11.5	0.0	0.0	0.0	0.0
CALLISON #13D	20A	1035.6	10.4	1035.5	10.4	90.5	0.9	107.3	0.7
ELLA NOLTE # 6	20A	1034.6	10.3	1220.0	12.2	106.9	1.1	101.5	1.5

Cotton Valley wells only Table 2A - Page 1 of 3

Table 2A

Comparison of EURs and 1st Year Production for YE2007 PUDs vs 2008 Actual Drills (FF0000Gross01+000 Volumes)

Table showing individual well volumes for response to SEC Question 3, Letter of February 24, 2009

		Pre-drill Gross EUR Volumes		Post Drill Gross EUR Volumes		Projected 1st Year (or portion thereof) Avg. Prod Rate		Actual 1st Year (or portion thereof) Avg. Prod Rate
Well	YE2007 Spacing	Gas (MMCF)	Oil (MBO)	Gas (MMCF)	Oil (MBO)	Gross Gas (MMCF)	Gross Oil (MBO)	Gross Gas (MMCF)	Gross Oil (MBO)
ELLA NOLTE # 7D	20A	1029.7	10.3	946.2	9.5	113.0	1.1	100.6	2.0
ELLA NOLTE #10	20A	1040.3	10.4	1553.2	15.5	92.6	0.9	155.4	0.9
ELLA NOLTE #11D	20A	1034.6	10.3	3200.1	32.0	100.1	1.0	229.0	2.3
FOSTER # 4	20A	1288.0	19.3	1184.2	11.8	101.4	1.7	117.5	1.5
FOSTER # 5	20A	1288.8	19.3	1368.4	20.5	101.0	1.7	117.1	1.6
FOSTER # 6	20A	1288.0	19.3	1246.8	15.0	115.1	2.0	133.0	2.0
FOSTER # 7	20A	1288.8	19.3	1003.5	15.1	114.7	2.0	96.4	1.9
FOSTER # 8	20A	1288.0	19.3	1166.4	14.0	114.4	1.9	133.3	2.0
FOSTER # 9	20A	1288.8	19.3	1281.3	15.4	114.0	1.9	115.9	2.0
FOSTER #10	20A	1288.0	19.3	646.3	9.7	85.9	1.5	73.9	2.2
FURRH GU3 #10	40A	1389.0	20.8	790.9	14.2	145.4	2.5	87.0	1.9
FURRH GU3 #18	20A	1288.0	19.3	503.3	12.6	91.6	1.6	69.5	2.6
FURRH GU3 #19	20A	1288.8	19.3	807.1	20.2	91.2	1.6	67.3	2.5
FURRH GU3 #20	40A	1389.8	20.8	1073.6	26.8	90.8	1.5	71.4	2.5
FURRH, JAMES MADISON # 1	40A	1389.0	20.8	1332.6	22.7	17.8	0.3	0.6	0.0
GERRY # 1	40A	1153.0	11.5	1183.3	11.8	40.5	0.4	48.7	0.4
GLORIA FRAZIER # 1	20A	1031.4	10.3	1979.6	19.8	97.7	1.0	230.6	1.6
GLORIA FRAZIER # 2	40A	1153.0	11.5	1522.7	15.2	92.3	0.9	153.4	1.7
GLORIA FRAZIER # 3	20A	1033.0	10.3	1065.1	10.7	92.1	0.9	115.1	2.1
GRANBERRY # 1	40A	1153.0	11.5	1366.4	13.7	53.4	0.5	32.2	0.1
GULLEY #11	40A	1153.3	11.5	1.7	0.0	0.0	0.0	0.0	0.0
GULLEY #12	20A	1032.6	10.3	694.7	6.9	110.0	1.1	87.0	0.3
GULLEY #13	20A	1032.6	10.3	604.5	6.0	108.1	1.1	73.0	0.4
HEISMAN # 4	40A	1153.3	11.5	946.2	9.5	112.8	1.1	104.7	0.9
HEISMAN # 5	20A	1034.6	10.3	701.5	7.0	106.4	1.1	80.4	0.5
HEISMAN # 6	40A	1153.0	11.5	461.8	4.6	50.9	0.5	35.6	0.0
JF ROBERTS #3	40A	1389.0	20.8	184.8	1.8	151.3	2.6	48.1	0.6
JF ROBERTS #4	40A	1389.8	20.8	195.1	2.0	143.8	2.4	41.4	0.5
LAWLESS RHOADES #14	40A	1389.0	20.8	709.1	10.6	108.7	1.8	55.7	0.8
LAWLESS RHOADES #15	40A	1389.8	20.8	547.4	6.6	110.1	1.9	55.6	0.6
LAWLESS RHOADES #16	20A	1288.0	19.3	575.2	5.8	109.8	1.9	44.8	0.7
LAWLESS RHOADES #17	40A	1389.8	20.8	529.5	4.2	109.1	1.9	45.0	0.5
LAWLESS RHOADES #18	20A	1288.0	19.3	593.0	8.9	108.7	1.8	64.2	0.8
LAWLESS RHOADES #19	20A	1288.8	19.3	669.0	10.0	108.4	1.8	53.2	0.6
MERCER # 1	20A	1035.6	10.4	1340.0	13.4	91.8	0.9	124.6	1.2
MERCER # 3	20A	1035.6	10.4	1306.6	13.1	66.1	0.7	92.6	0.1
MERCER # 4	40A	1153.0	11.5	1518.2	15.2	55.5	0.6	87.0	0.5
MERCER # 5	40A	1153.0	11.5	1668.8	16.7	31.5	0.3	53.6	0.1
MERCER # 7D	20A	1033.0	10.3	880.6	8.8	58.7	0.6	67.0	0.1
MERCER # 9	20A	1033.0	10.3	970.9	9.7	31.5	0.3	27.7	0.3

Cotton Valley wells only Table 2A - Page 2 of 3

Table 2A

Comparison of EURs and 1st Year Production for YE2007 PUDs vs 2008 Actual Drills (FF0000Gross01+000 Volumes)

Table showing individual well volumes for response to SEC Question 3, Letter of February 24, 2009

		Pre-drill Gross EUR Volumes		Post Drill Gross EUR Volumes		Projected 1st Year (or portion thereof) Avg. Prod Rate		Actual 1st Year (or portion thereof) Avg. Prod Rate
Well	YE2007 Spacing	Gas (MMCF)	Oil (MBO)	Gas (MMCF)	Oil (MBO)	Gross Gas (MMCF)	Gross Oil (MBO)	Gross Gas (MMCF)	Gross Oil (MBO)
MERCER #10	40A	1153.0	11.5	1395.7	14.0	24.2	0.2	24.0	0.0
ROSEHAVEN #10	20A	1031.4	10.3	761.4	7.6	95.8	1.0	82.7	0.4
SANGSTER # 1	40A	1153.0	11.5	572.3	5.7	95.1	1.0	59.4	1.5
SPENCER # 5	40A	1153.0	11.5	1113.1	11.1	58.3	0.6	18.2	0.3
SPENCER # 6	20A	1033.0	10.3	1150.4	11.5	58.3	0.6	75.9	0.8
SPENCER # 8	40A	1153.0	11.5	884.7	8.8	58.0	0.6	64.6	0.9
STEELE # 1	40A	1389.0	20.8	409.1	4.9	79.2	1.3	47.9	0.6
THOMPSON # 1	20A	1031.4	10.3	668.5	6.7	74.0	0.7	73.2	0.5
THOMPSON # 2	40A	1153.3	11.5	1033.2	10.3	74.6	0.7	97.5	0.5
THOMPSON # 3	20A	1033.3	10.3	881.2	8.8	74.3	0.7	93.3	0.4
THOMPSON # 4	20A	1033.3	10.3	1455.5	14.6	73.7	0.7	131.1	0.4
Totals		104186.6	1200.4	93733.2	1040.7	7727.3	95.8	7962.7	84.7

Cotton Valley wells only Table 2A - Page 3 of 3

Table 2B

Comparison of EURs and 1st Year Production for YE2007 PUDs vs 2008 Actual Drills (FF0000Net01+000 Volumes)

Table showing individual well volumes for response to SEC Question 3, Letter of February 24, 2009
		Pre-drill Net EUR Volumes		Post Drill Net EUR Volumes		Projected 1st Year (or portion thereof) Avg. Prod Rate		Actual 1st Year (or portion thereof) Avg. Prod Rate
Well	YE2007 Spacing	Gas (MMCF)	Oil (MBO)	Gas (MMCF)	Oil (MBO)	Net Gas (MMCF)	Net Oil (MBO)	Net Gas (MMCF)	Net Oil (MBO)
ABNEY #10	40A	276.8	2.8	127.8	1.3	20.8	0.2	12.1	0.2
ABNEY #11	20A	247.5	2.5	199.8	2.0	18.3	0.2	22.4	0.1
ABNEY #13	20A	247.9	2.5	225.9	2.3	13.4	0.1	15.6	0.1
ABNEY #14	20A	247.9	2.5	102.6	1.0	13.3	0.1	5.8	0.1
ABNEY #15	20A	247.5	2.5	167.9	1.7	18.3	0.2	15.8	0.1
ARNOLD WILLIAMS # 9	40A	555.9	8.3	446.0	6.7	60.2	1.0	49.9	1.0
ARNOLD WILLIAMS #14	20A	515.2	7.7	719.8	8.6	55.6	0.9	77.7	0.9
ARNOLD WILLIAMS #15	20A	515.5	7.7	768.0	11.5	55.6	0.9	70.0	0.9
BALDWIN # 8D	40A	922.7	9.2	1402.0	14.0	84.2	0.8	159.3	1.2
BALDWIN # 9	40A	922.7	9.2	1435.3	14.4	63.0	0.6	128.4	0.8
BALDWIN #10	20A	828.5	8.3	1726.0	17.3	57.8	0.6	138.6	0.3
BALDWIN #11	20A	828.5	8.3	1628.7	16.3	53.9	0.5	121.6	1.0
BALDWIN #12	20A	828.5	8.3	1606.8	16.1	68.8	0.7	148.4	0.6
BELL # 7	20A	827.7	8.3	259.8	2.6	86.9	0.9	49.6	1.0
BLOCKER HEIRS #10	20A	827.7	8.3	527.4	5.3	78.4	0.8	61.4	0.6
BLOCKER HEIRS #11D	20A	828.5	8.3	729.8	7.3	63.7	0.6	64.3	0.6
BLOCKER HEIRS #15D	40A	922.7	9.2	510.1	5.1	70.5	0.7	43.1	0.4
BLOCKER HEIRS #19	20A	826.4	8.2	399.8	4.0	28.3	0.3	20.6	0.1
BLOCKER HEIRS #28D	40A	922.7	9.2	804.0	8.0	77.2	0.8	92.1	0.4
BLOCKER HEIRS #30D	40A	922.7	9.2	705.0	7.0	55.4	0.6	52.4	0.2
BOOKOUT # 5	20A	244.9	2.4	241.7	2.4	26.7	0.3	29.6	0.2
BOOKOUT # 6	20A	247.8	2.5	180.1	1.8	26.7	0.3	27.9	0.3
BOOKOUT # 7	20A	247.9	2.5	219.6	2.2	26.6	0.3	29.5	0.3
BOOKOUT # 8	40A	276.8	2.8	263.3	2.6	23.7	0.2	22.1	0.5
BOOKOUT # 9	20A	247.8	2.5	307.2	3.1	23.6	0.2	28.9	0.5
BOOKOUT #10	20A	247.9	2.5	226.6	2.3	23.6	0.2	23.6	0.5
BOSH # 6	40A	922.4	9.2	552.1	5.5	1.1	0.0	2.8	0.0
BOSH # 9	40A	922.4	9.2	920.3	9.2	0.0	0.0	0.0	0.0
BRADLEY # 5	20A	833.4	8.3	976.7	9.8	92.5	0.9	109.7	1.0
BRADLEY #11D	20A	833.4	8.3	400.5	4.0	88.8	0.9	36.0	0.4
CADENHEAD #12	40A	922.4	9.2	777.9	7.8	43.8	0.4	45.8	0.3
CADENHEAD #14D	20A	828.5	8.3	681.2	6.8	59.5	0.6	55.2	0.6
CADENHEAD #15	40A	922.4	9.2	923.1	9.2	39.6	0.4	43.0	0.1
CALLISON # 2R	20A	832.2	8.3	974.6	9.7	77.2	0.8	126.9	0.5
CALLISON # 3	20A	828.5	8.3	633.0	6.3	67.3	0.7	51.2	0.5
CALLISON # 5D	20A	828.5	8.3	1058.3	10.6	65.4	0.7	105.4	0.4
CALLISON # 8D	20A	826.4	8.2	704.4	7.0	51.1	0.5	48.7	0.2
CALLISON #11	40A	922.4	9.2	920.3	9.2	0.0	0.0	0.0	0.0
CALLISON #13D	20A	828.5	8.3	828.4	8.3	72.4	0.7	85.9	0.5
ELLA NOLTE # 6	20A	827.7	8.3	976.0	9.8	85.5	0.9	81.2	1.2

Cotton Valley wells only Table 2B - Page 1 of 3

Table 2B

Comparison of EURs and 1st Year Production for YE2007 PUDs vs 2008 Actual Drills (FF0000Net01+000 Volumes)

Table showing individual well volumes for response to SEC Question 3, Letter of February 24, 2009
		Pre-drill Net EUR Volumes		Post Drill Net EUR Volumes		Projected 1st Year ( or portion thereof) Avg. Prod Rate		Actual 1st Year (or portion thereof) Avg. Prod Rate
Well	YE2007 Spacing	Gas (MMCF)	Oil (MBO)	Gas (MMCF)	Oil (MBO)	Net Gas (MMCF)	Net Oil (MBO)	Net Gas (MMCF)	Net Oil (MBO)
ELLA NOLTE # 7D	20A	823.7	8.2	757.0	7.6	90.4	0.9	80.5	1.6
ELLA NOLTE #10	20A	832.2	8.3	1242.6	12.4	74.1	0.7	124.3	0.7
ELLA NOLTE #11D	20A	827.7	8.3	2560.1	25.6	80.1	0.8	183.2	1.8
FOSTER # 4	20A	515.2	7.7	473.7	4.7	40.6	0.7	47.0	0.6
FOSTER # 5	20A	515.5	7.7	547.4	8.2	40.4	0.7	46.8	0.7
FOSTER # 6	20A	515.2	7.7	498.7	6.0	46.0	0.8	53.2	0.8
FOSTER # 7	20A	515.5	7.7	401.4	6.0	45.9	0.8	38.6	0.8
FOSTER # 8	20A	515.2	7.7	466.6	5.6	45.7	0.8	53.3	0.8
FOSTER # 9	20A	515.5	7.7	512.5	6.2	45.6	0.8	46.4	0.8
FOSTER #10	20A	515.2	7.7	258.5	3.9	34.3	0.6	29.6	0.9
FURRH GU3 #10	40A	555.6	8.3	316.4	5.7	58.1	1.0	34.8	0.8
FURRH GU3 #18	20A	515.2	7.7	201.3	5.0	36.6	0.6	27.8	1.0
FURRH GU3 #19	20A	515.5	7.7	322.8	8.1	36.5	0.6	26.9	1.0
FURRH GU3 #20	40A	555.9	8.3	429.4	10.7	36.3	0.6	28.5	1.0
FURRH, JAMES MADISON # 1	40A	555.6	8.3	533.1	9.1	7.1	0.1	0.3	0.0
GERRY # 1	40A	922.4	9.2	946.7	9.5	32.4	0.3	39.0	0.4
GLORIA FRAZIER # 1	20A	247.5	2.5	475.1	4.8	23.5	0.2	55.3	0.4
GLORIA FRAZIER # 2	40A	276.7	2.8	365.5	3.7	22.2	0.2	36.8	0.4
GLORIA FRAZIER # 3	20A	247.9	2.5	255.6	2.6	22.1	0.2	27.6	0.5
GRANBERRY # 1	40A	276.7	2.8	327.9	3.3	12.8	0.1	7.7	0.0
GULLEY #11	40A	276.8	2.8	0.4	0.0	0.0	0.0	0.0	0.0
GULLEY #12	20A	247.8	2.5	166.7	1.7	26.4	0.3	20.9	0.1
GULLEY #13	20A	247.8	2.5	145.1	1.5	26.0	0.3	17.5	0.1
HEISMAN # 4	40A	922.7	9.2	757.0	7.6	90.2	0.9	83.8	0.7
HEISMAN # 5	20A	827.7	8.3	561.2	5.6	85.1	0.9	64.3	0.4
HEISMAN # 6	40A	922.4	9.2	369.4	3.7	40.7	0.4	28.5	0.0
JF ROBERTS #3	40A	555.6	8.3	73.9	0.7	60.5	1.0	19.2	0.2
JF ROBERTS #4	40A	555.9	8.3	78.0	0.8	57.5	1.0	16.6	0.2
LAWLESS RHOADES #14	40A	555.6	8.3	283.6	4.3	43.5	0.7	22.3	0.3
LAWLESS RHOADES #15	40A	555.9	8.3	218.9	2.6	44.1	0.7	22.2	0.3
LAWLESS RHOADES #16	20A	515.2	7.7	230.1	2.3	43.9	0.7	17.9	0.3
LAWLESS RHOADES #17	40A	555.9	8.3	211.8	1.7	43.6	0.7	18.0	0.2
LAWLESS RHOADES #18	20A	515.2	7.7	237.2	3.6	43.5	0.7	25.7	0.3
LAWLESS RHOADES #19	20A	515.5	7.7	267.6	4.0	43.4	0.7	21.3	0.2
MERCER # 1	20A	828.5	8.3	1072.0	10.7	73.4	0.7	99.7	1.0
MERCER # 3	20A	828.5	8.3	1045.3	10.5	52.8	0.5	74.0	0.1
MERCER # 4	40A	922.4	9.2	1214.6	12.1	44.4	0.4	69.6	0.4
MERCER # 5	40A	922.4	9.2	1335.0	13.4	25.2	0.3	42.9	0.1
MERCER # 7D	20A	826.4	8.2	704.4	7.0	46.9	0.5	53.6	0.1
MERCER # 9	20A	826.4	8.2	776.7	7.8	25.2	0.3	22.2	0.2

Cotton Valley wells only Table 2B - Page 2 of 3

Table 2B

Comparison of EURs and 1st Year Production for YE2007 PUDs vs 2008 Actual Drills (FF0000Net01+000 Volumes)

Table showing individual well volumes for response to SEC Question 3, Letter of February 24, 2009
		Pre-drill Net EUR Volumes		Post Drill Net EUR Volumes		Projected 1st Year ( or portion thereof) Avg. Prod Rate		Actual 1st Year (or portion thereof) Avg. Prod Rate
Well	YE2007 Spacing	Gas (MMCF)	Oil (MBO)	Gas (MMCF)	Oil (MBO)	Net Gas (MMCF)	Net Oil (MBO)	Net Gas (MMCF)	Net Oil (MBO)
MERCER #10	40A	922.4	9.2	1116.6	11.2	19.3	0.2	19.2	0.0
ROSEHAVEN #10	20A	247.5	2.5	182.7	1.8	23.0	0.2	19.8	0.1
SANGSTER # 1	40A	276.7	2.8	137.4	1.4	22.8	0.2	14.3	0.3
SPENCER # 5	40A	276.7	2.8	267.1	2.7	14.0	0.1	4.4	0.1
SPENCER # 6	20A	247.9	2.5	276.1	2.8	14.0	0.1	18.2	0.2
SPENCER # 8	40A	276.7	2.8	212.3	2.1	13.9	0.1	15.5	0.2
STEELE # 1	40A	555.6	8.3	163.6	2.0	31.7	0.5	19.2	0.2
THOMPSON # 1	20A	247.5	2.5	160.4	1.6	17.8	0.2	17.6	0.1
THOMPSON # 2	40A	276.8	2.8	248.0	2.5	17.9	0.2	23.4	0.1
THOMPSON # 3	20A	248.0	2.5	211.5	2.1	17.8	0.2	22.4	0.1
THOMPSON # 4	20A	248.0	2.5	349.3	3.5	17.7	0.2	31.5	0.1
Totals		54364.5	607.0	52224.1	563.6	3895.9	46.4	4235.8	40.4

Cotton Valley wells only Table 2B - Page 3 of 3

TABLE 3A

YE 2006 report vs. 2007 Actuals

Comparison of PUD well projected vs. actual drill dates

(Net Volumes - MMCFE)

Area	Ref. Name	Drilled Well Name	Projected Start Date	First Production	Days of Delay	Volume difference because of delay (negative value indicates shortfall vs. projection) (Net, MMCFE)		Volume difference because of well not drilled (negative value indicates shortfall vs. projection) (Net, MMCFE)
CTI-A1	CV#041-A1 PUD	ABNEY # 4	2/1/2007	2/11/2007	10	(0.5	)
CTI-A1	CV#042-A1 PUD	ABNEY # 2	2/1/2007	2/20/2007	19	(0.8	)
CTI-A1	CV#043-A1 PUD	ABNEY # 3	3/1/2007	3/12/2007	11	(0.5	)
CTI-A1	CV#036-A1 PUD	ABNEY # 5	1/1/2007	4/15/2007	104	(5.0	)
CTI-A1	CV#039-A1 PUD	ABNEY # 6	2/1/2007	5/10/2007	98	(6.8	)
CTI-A1	CV#029-A1 PUD	ABNEY # 7	1/1/2007	8/25/2007	236	(16.6	)
CTI-A1	CV#063-A1 PUD	BOOKOUT # 1	8/1/2007	9/17/2007	47	(9.3	)
CTI-A1	CV#064-A1 PUD	BOOKOUT # 2	8/1/2007	9/18/2007	48	(9.9	)
CTI-A1	CV#065-A1 PUD	BOOKOUT # 3	8/1/2007	9/17/2007	47	(10.1	)
CTI-A1	CV#072-A1 PUD	BOOKOUT # 4	10/1/2007	9/17/2007	-14	4.6
CTI-A1	CV#052-A1 PUD	LANCASTER #2	5/1/2007	3/4/2007	-58	1.9
CTI-A1	CV#037-A1 PUD	ROSEHAVEN # 4	1/1/2007	1/17/2007	16	(0.8	)
CTI-A1	CV#044-A1 PUD	ROSEHAVEN # 5	3/1/2007	2/14/2007	-15	0.4
CTI-A1	CV#045-A1 PUD	EOG #4	3/1/2007	3/21/2007	20	(0.8	)
CTI-A1	CV#046-A1 PUD	HERRIN MARGARET # 7	3/1/2007	4/6/2007	36	(1.8	)
CTI-A1	CV#047-A1 PUD	ROSEHAVEN # 7	4/1/2007	4/9/2007	8	(0.3	)
CTI-A1	CV#048-A1 PUD	BRYANT #4	4/1/2007	4/21/2007	20	(0.9	)
CTI-A1	CV#049-A1 PUD	ROSEHAVEN # 6	4/1/2007	4/29/2007	28	(0.7	)
CTI-A1	CV#050-A1 PUD	BRYANT #5	4/1/2007	5/11/2007	40	(1.3	)
CTI-A1	CV#051-A1 PUD	RICHARDSON # 7	5/1/2007	5/26/2007	25	(1.4	)
CTI-A1	CV#053-A1 PUD	GULLEY # 9	5/1/2007	6/4/2007	34	(3.0	)
CTI-A1	CV#054-A1 PUD	GULLEY #10	5/1/2007	6/22/2007	52	(4.5	)
CTI-A1	CV#055-A1 PUD	SPENCER # 1	6/1/2007	7/15/2007	44	(2.5	)
CTI-A1	CV#056-A1 PUD	RICHARDSON # 8	6/1/2007	7/27/2007	56	(4.0	)
CTI-A1	CV#057-A1 PUD	HERRIN SYLVIA # 7	6/1/2007	8/12/2007	72	(3.2	)
CTI-A1	CV#058-A1 PUD	HERRIN SYLVIA # 8	6/1/2007	8/26/2007	86	(9.0	)
CTI-A1	CV#059-A1 PUD	HERRIN SYLVIA # 9	7/1/2007	9/29/2007	90	(0.4	)
CTI-A1	CV#060-A1 PUD	ROSEHAVEN # 8	7/1/2007	10/2/2007	93	(8.0	)
CTI-A1	CV#061-A1 PUD	SPENCER # 2	7/1/2007	10/15/2007	106	(14.8	)
CTI-A1	CV#062-A1 PUD	SPENCER # 3	7/1/2007	10/27/2007	118	(22.1	)
CTI-A1	CV#066-A1 PUD	ABNEY # 8	8/1/2007	10/30/2007	90	(6.5	)
CTI-A1	CV#067-A1 PUD	ABNEY # 9	9/1/2007	11/12/2007	72	(7.7	)
CTI-A1	CV#068-A1 PUD	MARGIE #8	9/1/2007	11/13/2007	73	(8.9	)

Table 3A - Page 1 of 4

TABLE 3A

YE 2006 report vs. 2007 Actuals

Comparison of PUD well projected vs. actual drill dates

(Net Volumes - MMCFE)

Area	Ref. Name	Drilled Well Name	Projected Start Date	First Production	Days of Delay	Volume difference because of delay (negative value indicates shortfall vs. projection) (Net, MMCFE)		Volume difference because of well not drilled (negative value indicates shortfall vs. projection) (Net, MMCFE)
CTI-A1	CV#069-A1 PUD	ROSEHAVEN # 9	9/1/2007	11/23/2007	83	(6.1	)
CTI-A1	CV#070-A1 PUD	GULLEY #14	9/1/2007	11/29/2007	89	(9.9	)
CTI-A1	CV#071-A1 PUD	GULLEY #15	10/1/2007	12/20/2007	80	(12.3	)
CTI-A1	CV#074-A1 PUD	NO WELL DRILLED ****	10/1/2007	1/1/2008	92			(19.2	)
CTI-A1	CV#073-A1 PUD	NO WELL DRILLED ****	10/1/2007	1/1/2008	92			(19.2	)
CTI-A1	CV#077-A1 PUD	NO WELL DRILLED ****	11/1/2007	1/1/2008	61			(13.7	)
CTI-A1	CV#078-A1 PUD	NO WELL DRILLED ****	11/1/2007	1/1/2008	61			(13.7	)
CTI-A1	CV#075-A1 PUD	NO WELL DRILLED ****	11/1/2007	1/1/2008	61			(13.7	)
CTI-A1	CV#076-A1 PUD	NO WELL DRILLED ****	11/1/2007	1/1/2008	61			(13.7	)
CTI-A1	CV#079-A1 PUD	NO WELL DRILLED ****	12/1/2007	1/1/2008	31			(7.5	)
CTI-A1	CV#080-A1 PUD	NO WELL DRILLED ****	12/1/2007	1/1/2008	31			(7.5	)
CTI-A1	CV#081-A1 PUD	NO WELL DRILLED ****	12/1/2007	1/1/2008	31			(7.5	)
CTI-A1	CV#082-A1 PUD	NO WELL DRILLED ****	12/1/2007	1/1/2008	31			(7.5	)
CTI-A2	CV#043-A2 PUD	FURRH GU3 #16	11/1/2007	11/4/2007	3	(0.8	)
CTI-A2	CV#036-A2 PUD	MCJIMSEY # 5	9/1/2007	9/3/2007	2	(0.1	)
CTI-A2	CV#046-A2 PUD	MCJIMSEY # 8	12/1/2007	12/6/2007	5	(0.7	)
CTI-A2	CV#031-A2 PUD	MCJIMSEY # 7	7/1/2007	7/1/2007	0	—
CTI-A2	CV#015-A2 PUD	SPARKS #2	2/1/2007	2/25/2007	24	(1.4	)
CTI-A2	CV#041-A2 PUD	FURRH GU3 # 3	11/1/2007	2/12/2007	-262	37.7
CTI-A2	CV#023-A2 PUD	ARNOLD WILLIAMS #10	5/1/2007	9/26/2007	148	(47.2	)
CTI-A2	CV#026-A2 PUD	ARNOLD WILLIAMS #11	6/1/2007	10/8/2007	129	(25.7	)
CTI-A2	CV#027-A2 PUD	ARNOLD WILLIAMS #13	6/1/2007	10/6/2007	127	(19.9	)
CTI-A2	CV#044-A2 PUD	FURRH GU3 #12	12/1/2007	11/7/2007	-24	5.7
CTI-A2	CV#045-A2 PUD	FURRH GU3 #13	12/1/2007	11/7/2007	-24	5.7
CTI-A2	CV#021-A2 PUD	MCJIMSEY # 2	4/1/2007	3/7/2007	-25	1.5
CTI-A2	CV#024-A2 PUD	MCJIMSEY # 3	5/1/2007	3/25/2007	-37	1.4
CTI-A2	CV#039-A2 PUD	MCJIMSEY # 4	10/1/2007	6/14/2007	-109	9.5
CTI-A2	CV#038-A2 PUD	MCJIMSEY # 6	10/1/2007	11/6/2007	36	(3.6	)
CTI-A2	CV#007-A2 PUD	TIMMONS #1	1/1/2007	8/16/2007	227	(19.7	)
CTI-A2	CV#012-A2 PUD	TIMMONS #2	1/1/2007	12/22/2007	355	(27.7	)
CTI-A2	CV#013-A2 PUD (Timmins #6 R/D)	FURRH GU3 # 2	1/1/2007	1/20/2007	19	(3.4	)
CTI-A2	CV#014-A2 PUD	FURRH GU3 # 2	2/1/2007	1/20/2007	-12	0.6
CTI-A2	CV#016-A2 PUD (Timmins #7 R/D)	MCCLENDON #1	2/1/2007	3/15/2007	42	(8.8	)
CTI-A2	CV#017-A2 PUD	MCCLENDON #2	3/1/2007	4/1/2007	31	(5.8	)
CTI-A2	CV#018-A2 PUD	SPARKS #3	3/1/2007	4/14/2007	44	(3.5	)
CTI-A2	CV#019-A2 PUD	MCCLENDON #3	3/1/2007	4/16/2007	46	(4.5	)
CTI-A2	CV#022-A2 PUD	MCCLENDON #4	4/1/2007	4/30/2007	29	(5.0	)
CTI-A2	CV#020-A2 PUD	SPARKS #4	4/1/2007	5/23/2007	52	(2.5	)
CTI-A2	CV#025-A2 PUD	TILLER #2	5/1/2007	6/2/2007	32	(1.0	)

Table 3A - Page 2 of 4

TABLE 3A

YE 2006 report vs. 2007 Actuals

Comparison of PUD well projected vs. actual drill dates

(Net Volumes - MMCFE)

Area	Ref. Name	Drilled Well Name	Projected Start Date	First Production	Days of Delay	Volume difference because of delay (negative value indicates shortfall vs. projection) (Net, MMCFE)		Volume difference because of well not drilled (negative value indicates shortfall vs. projection) (Net, MMCFE)
CTI-A2	CV#028-A2 PUD	LAWLESS RHOADES # 6	6/1/2007	6/7/2007	6	(0.8	)
CTI-A2	CV#029-A2 PUD	LAWLESS RHOADES # 1	7/1/2007	6/8/2007	-23	3.1
CTI-A2	CV#030-A2 PUD	LAWLESS RHOADES # 2	7/1/2007	6/23/2007	-8	1.0
CTI-A2	CV#032-A2 PUD	LAWLESS RHOADES # 4	8/1/2007	7/11/2007	-21	5.0
CTI-A2	CV#033-A2 PUD	TILLER #3	8/1/2007	7/15/2007	-17	1.1
CTI-A2	CV#034-A2 PUD	LAWLESS RHOADES # 5	8/1/2007	7/24/2007	-8	1.1
CTI-A2	CV#035-A2 PUD	SPARKS #5	9/1/2007	7/26/2007	-37	6.5
CTI-A2	CV#037-A2 PUD	LAWLESS RHOADES # 3	9/1/2007	9/11/2007	10	(1.2	)
CTI-A2	CV#040-A2 PUD	FURRH GU3 #15	10/1/2007	9/24/2007	-7	0.9
CTI-A2	CV#042-A2 PUD	FOSTER # 2	11/1/2007	10/11/2007	-21	6.4
CTI-A2	CV#022-A2 PUD	FOSTER # 3	1/1/2008	10/11/2007	-82	36.5
CTI-A2	CV#023-A2 PUD	FURRH GU3 #14	1/1/2008	10/15/2007	-78	8.7
CTI-A2	CV#028-A2 PUD	JF ROBERTS #1	1/1/2008	11/16/2007	-46	7.0
CTI-A2	CV#026-A2 PUD	MCCLENDON #5	1/1/2008	11/22/2007	-40	15.0
CTI-A2	CV#027-A2 PUD	JF ROBERTS #2	1/1/2008	12/2/2007	-30	4.5
CTI-A2	CV#029-A2 PUD	TIMMONS B #1	1/1/2008	12/8/2007	-24	11.6
CTI-A2	CV#030-A2 PUD	FOSTER # 1	1/1/2008	12/23/2007	-9	—
CTI-A2	CV#032-A2 PUD	NO WELL DRILLED ****	1/1/2008	1/1/2008	0	—
CTII-A3	CV#035-A3 PUD	BLOCKER HEIRS # 7	5/1/2007	5/11/2007	10	(2.4	)
CTII-A3	CV#058-A3 PUD	BOSH #10D	11/1/2007	11/15/2007	14	(6.0	)
CTII-A3	CV#018-A3 PUD	BLOCKER HEIRS # 6	1/1/2007	7/2/2007	182	(47.1	)
CTII-A3	CV#053-A3 PUD	BLOCKER HEIRS # 9D	10/1/2007	6/10/2007	-113	36.4
CTII-A3	BLOCKER WARE #5	BLOCKER WARE # 5	3/1/2007	12/21/2007	295	(156.2	)
CTII-A3	CV#030-A3 PUD	BLOCKER WARE # 7	4/1/2007	9/18/2007	170	(21.9	)
CTII-A3	CV#059-A3 PUD	BOSH # 3	11/1/2007	3/21/2007	-225	33.3
CTII-A3	CV#050-A3 PUD	BOSH # 7	9/1/2007	7/19/2007	-44	9.8
CTII-A3	CV#051-A3 PUD	BOSH # 8	9/1/2007	8/18/2007	-14	3.0
CTII-A3	CV#063-A3 PUD	BRADLEY # 2	12/1/2007	3/8/2007	-268	135.9
CTII-A3	CV#064-A3 PUD	BRADLEY # 7	12/1/2007	11/9/2007	-22	9.6
CTII-A3	CV#020-A3 PUD	CADENHEAD # 8	1/1/2007	2/28/2007	58	(13.4	)
CTII-A3	CV#022-A3 PUD	HH GILL # 2	2/1/2007	4/7/2007	65	(11.5	)
CTII-A3	CV#046-A3 PUD	JOANN SCOTT # 4	8/1/2007	9/10/2007	40	(6.8	)
CTII-A3	CV#057-A3 PUD	JOANN SCOTT # 5	11/1/2007	10/19/2007	-13	4.5
CTII-A3	CV#026-A3 PUD	UNDERWOOD # 5	3/1/2007	4/16/2007	46	(8.8	)
CTII-A3	CV#038-A3 PUD	UNDERWOOD # 6	6/1/2007	5/4/2007	-28	5.6
CTII-A3	CV#055-A3 PUD	UNDERWOOD # 8	10/1/2007	5/20/2007	-134	23.6
CTI-A1	CV#038-A1 PUD	HH GILL # 4	1/1/2007	3/24/2007	82	(12.7	)
CTII-A3	CV#007-A3 PUD	HH GILL # 6	1/1/2007	4/14/2007	103	(8.8	)
CTII-A3	CV#019-A3 PUD	HEISMAN # 2	1/1/2007	6/9/2007	159	(21.2	)

Table 3A - Page 3 of 4

TABLE 3A

YE 2006 report vs. 2007 Actuals

Comparison of PUD well projected vs. actual drill dates

(Net Volumes - MMCFE)

Area	Ref. Name	Drilled Well Name	Projected Start Date	First Production	Days of Delay	Volume difference because of delay (negative value indicates shortfall vs. projection) (Net, MMCFE)		Volume difference because of well not drilled (negative value indicates shortfall vs. projection) (Net, MMCFE)
CTI-A1	CV#040-A1 PUD	K #2	2/1/2007	6/23/2007	142	(25.5	)
CTII-A3	CV#024-A3 PUD	HH GILL # 7D	2/1/2007	7/2/2007	151	(30.6	)
CTII-A3	CV#021-A3 PUD	JOANN SCOTT # 9	1/1/2007	7/29/2007	209	(23.4	)
CTII-A3	CV#023-A3 PUD	ELLA NOLTE # 1	2/1/2007	8/21/2007	201	(227.1	)
CTII-A3	CV#027-A3 PUD	JOANN SCOTT # 7	3/1/2007	8/21/2007	173	(9.3	)
CTII-A3	CV#025-A3 PUD	ELLA NOLTE # 2	3/1/2007	9/20/2007	203	(42.2	)
CTII-A3	CV#028-A3 PUD	BELL # 4A	3/1/2007	10/5/2007	218	(8.1	)
CTII-A3	CV#029-A3 PUD	ELLA NOLTE # 3	4/1/2007	10/8/2007	190	(83.7	)
CTII-A3	CV#031-A3 PUD	CALLISON # 1	4/1/2007	10/9/2007	191	(59.2	)
CTII-A3	CV#032-A3 PUD	UNDERWOOD # 6A	4/1/2007	11/6/2007	219	(0.6	)
CTII-A3	CV#033-A3 PUD	ELLA NOLTE # 8D	5/1/2007	11/19/2007	202	(78.7	)
CTII-A3	CV#034-A3 PUD	HH GILL #12D	5/1/2007	12/9/2007	222	(119.2	)
CTII-A3	CV#036-A3 PUD	UNDERWOOD #10	5/1/2007	12/13/2007	226	(100.6	)
CTII-A3	CV#037-A3 PUD	ELLA NOLTE # 4	6/1/2007	12/18/2007	200	(98.1	)
CTII-A3	Sanders Moore #4R	NO WELL DRILLED ****	6/1/2007	1/1/2008	214			(48.2	)
CTII-A3	CV#039-A3 PUD	NO WELL DRILLED ****	6/1/2007	1/1/2008	214			(119.0	)
CTII-A3	CV#040-A3 PUD	NO WELL DRILLED ****	6/1/2007	1/1/2008	214			(119.0	)
CTII-A3	CV#062-A3 PUD	NO WELL DRILLED ****	12/1/2007	1/1/2008	31			(24.0	)
CTII-A3	CV#041-A3 PUD	NO WELL DRILLED ****	7/1/2007	1/1/2008	184			(100.3	)
CTII-A3	CV#042-A3 PUD	NO WELL DRILLED ****	7/1/2007	1/1/2008	184			(100.8	)
CTII-A3	CV#043-A3 PUD	NO WELL DRILLED ****	7/1/2007	1/1/2008	184			(106.5	)
CTII-A3	CV#044-A3 PUD	NO WELL DRILLED ****	7/1/2007	1/1/2008	184			(106.5	)
CTII-A3	CV#048-A3 PUD	NO WELL DRILLED ****	8/1/2007	1/1/2008	153			(96.0	)
CTII-A3	CV#045-A3 PUD	NO WELL DRILLED ****	8/1/2007	1/1/2008	153			(93.0	)
CTII-A3	CV#047-A3 PUD	NO WELL DRILLED ****	8/1/2007	1/1/2008	153			(93.0	)
CTII-A3	CV#049-A3 PUD	NO WELL DRILLED ****	9/1/2007	1/1/2008	122			(78.4	)
CTII-A3	CV#052-A3 PUD	NO WELL DRILLED ****	9/1/2007	1/1/2008	122			(78.4	)
CTII-A3	CV#056-A3 PUD	NO WELL DRILLED ****	10/1/2007	1/1/2008	92			(62.4	)
CTII-A3	CV#054-A3 PUD	NO WELL DRILLED ****	10/1/2007	1/1/2008	92			(59.0	)
CTII-A3	GILL #2	NO WELL DRILLED ****	10/1/2007	1/1/2008	92			(22.0	)
CTII-A3	CV#060-A3 PUD	NO WELL DRILLED ****	11/1/2007	1/1/2008	61			(44.9	)
CTII-A3	HANCOCK #2	NO WELL DRILLED ****	11/1/2007	1/1/2008	61			(14.9	)
CTII-A3	CV#061-A3 PUD	NO WELL DRILLED ****	12/1/2007	1/1/2008	31			(22.8	)
CTII-A3	ANDERSON #1	NO WELL DRILLED ****	12/1/2007	1/1/2008	31			(7.3	)
NM	WILL #2A	NO WELL DRILLED ****	6/1/2007	1/1/2008	213			(83.5	)
		Totals				(1,157.8	)	(1,603.0	)

Table 3A - Page 4 of 4

TABLE 3B

YE 2007 report vs. 2008 Actuals

Comparison of PUD well projected vs. actual drill dates

(Net Volumes - MMCFE)

Area	Ref. Name	Drilled Well Name	Projected Start Date	Actual First Production	Days of Delay	Volume difference because of delay (negative value indicates shortfall vs. projection) (Net, MMCFE)		Volume difference because of well not drilled (negative value indicates shortfall vs. projection) (Net, MMCFE)
CTI-A1	CVA1 PUD #030	ABNEY #10	1/1/2008	4/28/2008	118	(3.8	)
CTI-A1	CVA1 PUD #031	ABNEY #11	1/1/2008	6/6/2008	157	(10.4	)
CTI-A1	CVA1 PUD #034	ABNEY #13	2/1/2008	8/9/2008	190	(12.7	)
CTI-A1	CVA1 PUD #033	ABNEY #14	2/1/2008	8/10/2008	191	(5.5	)
CTI-A1	CVA1 PUD #035	ABNEY #15	2/1/2008	6/6/2008	126	(6.0	)
CTI-A1	CVA1 PUD #035	Bookout #5	1/1/2008	1/19/2008	18	(0.9	)
CTI-A1	CVA1 PUD #036	GULLEY #11	3/1/2008	1/1/2008	-60	0.1
CTI-A1	CVA1 PUD #038	BOOKOUT # 6	3/1/2008	1/18/2008	-43	2.4
CTI-A1	CVA1 PUD #039	BOOKOUT # 7	3/1/2008	1/20/2008	-41	2.4
CTI-A1	CVA1 PUD #045	GULLEY #12	4/1/2008	1/24/2008	-68	2.9
CTI-A1	CVA1 PUD #047	GULLEY #13	4/1/2008	1/30/2008	-62	2.2
CTI-A1	CVA1 PUD #048	BOOKOUT # 8	5/1/2008	3/12/2008	-50	2.8
CTI-A1	CVA1 PUD #053	BOOKOUT # 9	5/1/2008	3/13/2008	-49	3.6
CTI-A1	CVA1 PUD #049	BOOKOUT #10	5/1/2008	3/14/2008	-48	2.9
CTI-A1	CVA1 PUD #054	GLORIA FRAZIER # 1	6/1/2008	3/16/2008	-77	10.5
CTI-A1	CVA1 PUD #057	ROSEHAVEN #10	6/1/2008	3/24/2008	-69	3.5
CTI-A1	CVA1 PUD #060	SANGSTER # 1	6/1/2008	3/27/2008	-66	2.8
CTI-A1	CVA1 PUD #061	GLORIA FRAZIER # 2	7/1/2008	4/7/2008	-85	8.7
CTI-A1	CVA1 PUD #063	GLORIA FRAZIER # 3	7/1/2008	4/8/2008	-84	6.9
CTI-A1	CVA1 PUD #066	THOMPSON # 2	8/1/2008	6/10/2008	-52	4.4
CTI-A1	CVA1 PUD #064	THOMPSON # 3	8/1/2008	6/12/2008	-50	4.1
CTI-A1	CVA1 PUD #065	THOMPSON # 1	8/1/2008	6/13/2008	-49	3.2
CTI-A1	CVA1 PUD #067	THOMPSON # 4	9/1/2008	6/14/2008	-79	9.8
CTI-A1	CVA1 PUD #070	GRANBERRY # 1	9/1/2008	8/1/2008	-31	1.4
CTI-A1	CVA1 PUD #074	SPENCER # 5	9/1/2008	8/1/2008	-31	0.9
CTI-A1	CVA1 PUD #078	SPENCER # 6	10/1/2008	8/1/2008	-61	6.2
CTI-A1	CVA1 PUD #082	SPENCER # 8	10/1/2008	8/1/2008	-61	5.5
CTI-A1	CVA1 PUD #098	NO WELL DRILLED ****	11/1/2008	1/1/2009	61			(9.0	)
CTI-A1	CVA1 PUD #090	NO WELL DRILLED ****	11/1/2008	1/1/2009	61			(9.2	)
CTI-A1	CVA1 PUD #094	NO WELL DRILLED ****	11/1/2008	1/1/2009	61			(9.2	)
CTI-A1	CVA1 PUD #099	NO WELL DRILLED ****	12/1/2008	1/1/2009	31			(5.4	)
CTI-A1	CVA1 PUD #100	NO WELL DRILLED ****	12/1/2008	1/1/2009	31			(5.4	)
CTI-A1	CVA1 PUD #102	NO WELL DRILLED ****	12/1/2008	1/1/2009	31			(5.4	)

Table 3B - Page 1 of 4

TABLE 3B

YE 2007 report vs. 2008 Actuals

Comparison of PUD well projected vs. actual drill dates

(Net Volumes - MMCFE)

Area	Ref. Name	Drilled Well Name	Projected Start Date	Actual First Production	Days of Delay	Volume difference because of delay (negative value indicates shortfall vs. projection) (Net, MMCFE)		Volume difference because of well not drilled (negative value indicates shortfall vs. projection) (Net, MMCFE)
CTI-A2	CVA2 PUD #041	ARNOLD WILLIAMS # 9	1/1/2008	1/10/2008	9	(0.8	)
CTI-A2	CVA2 PUD #060	FOSTER # 6	5/1/2008	4/30/2008	-1	0.1
CTI-A2	CVA2 PUD #062	FOSTER # 7	5/1/2008	5/1/2008	0	—
CTI-A2	CVA2 PUD #064	FOSTER # 8	5/1/2008	5/2/2008	1	(0.1	)
CTI-A2	CVA2 PUD #066	FOSTER # 4	6/1/2008	6/7/2008	6	(0.9	)
CTI-A2	CVA2 PUD #070	FOSTER # 5	6/1/2008	6/8/2008	7	(1.1	)
CTI-A2	CVA2 PUD #072	FURRH GU3 #18	7/1/2008	7/2/2008	1	(0.1	)
CTI-A2	CVA2 PUD #074	FURRH GU3 #19	7/1/2008	7/3/2008	2	(0.2	)
CTI-A2	CVA2 PUD #043	ARNOLD WILLIAMS #14	1/1/2008	2/16/2008	46	(6.6	)
CTI-A2	CVA2 PUD #045	ARNOLD WILLIAMS #15	2/1/2008	2/17/2008	16	(2.1	)
CTI-A2	CVA2 PUD #053	FOSTER # 6	3/1/2008	4/30/2008	60	(8.3	)
CTI-A2	CVA2 PUD #057	FOSTER # 9	4/1/2008	5/3/2008	32	(4.0	)
CTI-A2	CVA2 PUD #059	FOSTER #10	4/1/2008	7/16/2008	106	(12.6	)
CTI-A2	CVA2 PUD #068	FURRH GU3 #10	6/1/2008	1/27/2008	-126	8.6
CTI-A2	CVA2 PUD #076	FURRH GU3 #20	8/1/2008	7/4/2008	-28	3.3
CTI-A2	CVA2 PUD #091	LAWLESS RHOADES #14	10/1/2008	5/18/2008	-136	9.3
CTI-A2	CVA2 PUD #097	LAWLESS RHOADES #15	11/1/2008	5/14/2008	-171	11.7
CTI-A2	CVA2 PUD #099	LAWLESS RHOADES #16	12/1/2008	5/15/2008	-200	12.2
CTI-A2	CVA2 PUD #101	LAWLESS RHOADES #17	12/1/2008	5/17/2008	-198	12.2
CTI-A2	CVA2 PUD #102	LAWLESS RHOADES #18	12/1/2008	5/18/2008	-197	18.8
CTI-A2	CVA2 PUD #047	FURRH, JAMES MADISON # 1	2/1/2008	11/7/2008	280	(0.5	)
CTI-A2	CVA2 PUD #049	JF ROBERTS #3	2/1/2008	1/7/2008	-25	0.8
CTI-A2	CVA2 PUD #055	JF ROBERTS #4	3/1/2008	2/2/2008	-28	0.9
CTI-A2	CVA2 PUD #051	STEELE # 1	3/1/2008	8/1/2008	153	(11.6	)
CTI-A2	CVA2 PUD #078	LAWLESS RHOADES #19	8/1/2008	5/19/2008	-74	4.6
CTI-A2	CVA2 PUD #080	NO WELL DRILLED ****	8/1/2008	1/1/2009	153			(29.1	)
CTI-A2	CVA2 PUD #081	NO WELL DRILLED ****	9/1/2008	1/1/2009	122			(24.8	)
CTI-A2	CVA2 PUD #083	NO WELL DRILLED ****	9/1/2008	1/1/2009	122			(24.8	)
CTI-A2	CVA2 PUD #085	NO WELL DRILLED ****	9/1/2008	1/1/2009	122			(24.8	)
CTI-A2	CVA2 PUD #087	NO WELL DRILLED ****	10/1/2008	1/1/2009	92			(20.3	)
CTI-A2	CVA2 PUD #089	NO WELL DRILLED ****	10/1/2008	1/1/2009	92			(20.3	)
CTI-A2	CVA2 PUD #093	NO WELL DRILLED ****	11/1/2008	1/1/2009	61			(14.9	)
CTI-A2	CVA2 PUD #095	NO WELL DRILLED ****	11/1/2008	1/1/2009	61			(14.9	)
CTII-A3	CVA3 PUD #047	BALDWIN # 8D	2/1/2008	2/13/2008	12	(4.0	)
CTII-A3	CVA3 PUD #051	BELL # 7	2/1/2008	1/29/2008	-3	0.3
CTII-A3	CVA3 PUD #054	BLOCKER HEIRS #10	3/1/2008	3/15/2008	14	(2.0	)
CTII-A3	CVA3 PUD #055	BLOCKER HEIRS #28D	3/1/2008	3/21/2008	20	(4.2	)
CTII-A3	CVA3 PUD #057	BLOCKER HEIRS #15D	4/1/2008	4/23/2008	22	(2.6	)
CTII-A3	CVA3 PUD #061	BLOCKER HEIRS #11D	5/1/2008	5/25/2008	24	(4.9	)

Table 3B - Page 2 of 4

TABLE 3B

YE 2007 report vs. 2008 Actuals

Comparison of PUD well projected vs. actual drill dates

(Net Volumes - MMCFE)

Area	Ref. Name	Drilled Well Name	Projected Start Date	Actual First Production	Days of Delay	Volume difference because of delay (negative value indicates shortfall vs. projection) (Net, MMCFE)		Volume difference because of well not drilled (negative value indicates shortfall vs. projection) (Net, MMCFE)
CTII-A3	CVA3 PUD #070	BLOCKER HEIRS #30D	7/1/2008	6/29/2008	-2	0.4
CTII-A3	CVA3 PUD #084	BLOCKER HEIRS #19	10/1/2008	9/30/2008	-1	0.2
CTII-A3	BRADLEY #11D	BRADLEY #11D	1/1/2008	1/20/2008	19	(1.5	)
CTII-A3	ELLA NOLTE #7D	ELLA NOLTE # 7D	1/1/2008	1/11/2008	10	(1.4	)
CTII-A3	CVA3 PUD #044	BALDWIN # 9	1/1/2008	5/28/2008	148	(54.6	)
CTII-A3	CVA3 PUD #045	BALDWIN #10	1/1/2008	6/18/2008	169	(72.9	)
CTII-A3	CVA3 PUD #046	BALDWIN #11	1/1/2008	7/4/2008	185	(78.9	)
CTII-A3	CVA3 PUD #048	BALDWIN #12	2/1/2008	5/1/2008	90	(34.7	)
CTII-A3	BLOCKER WARE TP PUD #1	HEISMAN # 4	1/1/2008	1/12/2008	11	(1.8	)
CTII-A3	CVA3 PUD #049	ELLA NOLTE # 6	2/1/2008	2/7/2008	6	(1.1	)
CTII-A3	CVA3 PUD #050	HEISMAN # 5	2/1/2008	2/9/2008	8	(1.1	)
CTII-A3	CVA3 PUD #052	ELLA NOLTE #11D	3/1/2008	3/6/2008	5	(2.2	)
CTII-A3	CVA3 PUD #053	ELLA NOLTE # 1A	3/1/2008	3/7/2008	6	(1.4	)
CTII-A3	BLOCKER WARE TP PUD #2	CALLISON # 2R	3/1/2008	3/21/2008	20	(5.7	)
CTII-A3	CVA3 PUD #056	ELLA NOLTE #10	4/1/2008	4/6/2008	5	(1.6	)
CTII-A3	CVA3 PUD #060	MERCER # 1	4/1/2008	4/9/2008	8	(2.2	)
CTII-A3	CVA3 PUD #058	CALLISON #13D	4/1/2008	4/14/2008	13	(2.8	)
CTII-A3	CVA3 PUD #059	CALLISON # 3	4/1/2008	5/8/2008	37	(5.5	)
CTII-A3	CVA3 PUD #064	CALLISON # 5D	5/1/2008	5/17/2008	16	(5.2	)
CTII-A3	CVA3 PUD #062	CADENHEAD #14D	5/1/2008	6/12/2008	42	(7.5	)
CTII-A3	CVA3 PUD #063	MERCER # 3	5/1/2008	7/10/2008	70	(19.8	)
CTII-A3	CVA3 PUD #065	CALLISON # 8D	5/1/2008	7/15/2008	75	(14.6	)
CTII-A3	BLOCKER HEIRS TP PUD #1	MERCER # 7D	5/1/2008	7/31/2008	91	(19.9	)
CTII-A3	CVA3 PUD #068	MERCER # 4	6/1/2008	8/9/2008	69	(22.1	)
CTII-A3	CVA3 PUD #066	CADENHEAD #12	6/1/2008	8/12/2008	72	(16.9	)
CTII-A3	CVA3 PUD #067	HEISMAN # 6	6/1/2008	8/24/2008	84	(13.0	)
CTII-A3	CVA3 PUD #069	CADENHEAD #15	6/1/2008	8/28/2008	88	(21.6	)
CTII-A3	CVA3 PUD #072	MERCER # 5	7/1/2008	9/1/2008	62	(18.5	)
CTII-A3	CVA3 PUD #071	GERRY # 1	7/1/2008	9/18/2008	79	(23.3	)
CTII-A3	CVA3 PUD #073	MERCER # 9	7/1/2008	10/1/2008	92	(18.6	)
CTII-A3	CVA3 PUD #074	MERCER #10	7/1/2008	10/1/2008	92	(16.7	)
CTII-A3	JA SCOTT TP PUD #1	CALLISON # 3A	7/1/2008	10/17/2008	108	(20.7	)
CTII-A3	CVA3 PUD #076	HEISMAN # 5A	8/1/2008	11/8/2008	99	(14.7	)
CTII-A3	CVA3 PUD #075	CALLISON # 9H	8/1/2008	11/20/2008	111	(194.1	)
CTII-A3	CVA3 PUD #077	BROWN # 2D	8/1/2008	11/27/2008	118	—
CTII-A3	CVA3 PUD #078	BOSH # 6	8/1/2008	11/28/2008	119	(39.6	)
CTII-A3	CVA3 PUD #079	BROWN # 1	8/1/2008	12/6/2008	127	(8.2	)
CTII-A3	CVA3 PUD #080	BOSH # 9	9/1/2008	12/15/2008	105	(57.8	)
CTII-A3	CVA3 PUD #081	CALLISON #11	9/1/2008	12/24/2008	114	(64.0	)

Table 3B - Page 3 of 4

TABLE 3B

YE 2007 report vs. 2008 Actuals

Comparison of PUD well projected vs. actual drill dates

(Net Volumes - MMCFE)

Area	Ref. Name	Drilled Well Name	Projected Start Date	Actual First Production	Days of Delay	Volume difference because of delay (negative value indicates shortfall vs. projection) (Net, MMCFE)		Volume difference because of well not drilled (negative value indicates shortfall vs. projection) (Net, MMCFE)
CTII-A3	CVA3 PUD #082	NO WELL DRILLED ****	9/1/2008	1/1/2009	122			(50.2	)
CTII-A3	CVA3 PUD #083	NO WELL DRILLED ****	9/1/2008	1/1/2009	122			(50.2	)
CTII-A3	UNDERWOOD TP PUD #1	NO WELL DRILLED ****	9/1/2008	1/1/2009	122			(51.7	)
CTII-A3	CVA3 PUD #088	NO WELL DRILLED ****	10/1/2008	1/1/2009	92			(41.4	)
CTII-A3	CVA3 PUD #085	NO WELL DRILLED ****	10/1/2008	1/1/2009	92			(41.0	)
CTII-A3	CVA3 PUD #086	NO WELL DRILLED ****	10/1/2008	1/1/2009	92			(41.0	)
CTII-A3	CVA3 PUD #087	NO WELL DRILLED ****	10/1/2008	1/1/2009	92			(41.0	)
CTII-A3	CVA3 PUD #093	NO WELL DRILLED ****	11/1/2008	1/1/2009	61			(30.4	)
CTII-A3	CVA3 PUD #089	NO WELL DRILLED ****	11/1/2008	1/1/2009	61			(30.1	)
CTII-A3	CVA3 PUD #091	NO WELL DRILLED ****	11/1/2008	1/1/2009	61			(30.1	)
CTII-A3	CVA3 PUD #092	NO WELL DRILLED ****	11/1/2008	1/1/2009	61			(30.1	)
CTII-A3	CVA3 PUD #094	NO WELL DRILLED ****	11/1/2008	1/1/2009	61			(30.1	)
CTII-A3	CVA3 PUD #096	NO WELL DRILLED ****	12/1/2008	1/1/2009	31			(17.5	)
CTII-A3	CVA3 PUD #097	NO WELL DRILLED ****	12/1/2008	1/1/2009	31			(17.5	)
CTII-A3	CVA3 PUD #098	NO WELL DRILLED ****	12/1/2008	1/1/2009	31			(17.5	)
CTII-A3	CVA3 PUD #099	NO WELL DRILLED ****	12/1/2008	1/1/2009	31			(17.5	)
		Totals				(821.7	)	(755.1	)

Table 3B - Page 4 of 4

Table 4

Comparison of First Month’s Production Rate to Type Curve

(Cotton Valley wells which started production in 2008)

Well	Rsv Cat	Area	Reservoir	Start of Production	First 30.4 Days Production	Type Curve Prediction	Difference
ABNEY #10	1PDP	CTI-A1	Cotton Valley	4/28/2008	17,447	20,273	(2,826	)
ABNEY #11	1PDP	CTI-A1	Cotton Valley	6/6/2008	36,186	20,273	15,913
ABNEY #13	1PDP	CTI-A1	Cotton Valley	8/9/2008	31,141	20,273	10,868
ABNEY #14	1PDP	CTI-A1	Cotton Valley	8/10/2008	8,470	20,273	(11,803	)
ABNEY #15	1PDP	CTI-A1	Cotton Valley	6/6/2008	26,223	20,273	5,950
ARNOLD WILLIAMS # 9	1PDP	CTI-A2	Cotton Valley	1/10/2008	13,882	24,429	(10,547	)
ARNOLD WILLIAMS #14	1PDP	CTI-A2	Cotton Valley	2/16/2008	40,926	24,429	16,497
ARNOLD WILLIAMS #15	1PDP	CTI-A2	Cotton Valley	2/17/2008	37,127	24,429	12,698
BALDWIN # 8D	1PDP	CTII-A3	Cotton Valley	2/13/2008	47,589	20,273	27,316
BALDWIN # 9	1PDP	CTII-A3	Cotton Valley	5/28/2008	51,170	20,273	30,897
BALDWIN #10	1PDP	CTII-A3	Cotton Valley	6/18/2008	55,852	20,273	35,579
BALDWIN #11	1PDP	CTII-A3	Cotton Valley	7/4/2008	52,411	20,273	32,138
BALDWIN #12	1PDP	CTII-A3	Cotton Valley	5/1/2008	52,498	20,273	32,225
BELL # 7	1PDP	CTII-A3	Cotton Valley	1/29/2008	16,392	20,273	(3,881	)
BLOCKER HEIRS #10	1PDP	CTII-A3	Cotton Valley	3/15/2008	20,074	20,273	(199	)
BLOCKER HEIRS #11D	1PDP	CTII-A3	Cotton Valley	5/25/2008	25,620	20,273	5,347
BLOCKER HEIRS #15D	1PDP	CTII-A3	Cotton Valley	4/23/2008	18,107	20,273	(2,166	)
BLOCKER HEIRS #19	1PDP	CTII-A3	Cotton Valley	9/30/2008	16,976	20,273	(3,297	)
BLOCKER HEIRS #28D	1PDP	CTII-A3	Cotton Valley	3/21/2008	28,914	20,273	8,641
BLOCKER HEIRS #30D	1PDP	CTII-A3	Cotton Valley	6/29/2008	23,511	20,273	3,238
BOOKOUT # 5	1PDP	CTI-A1	Cotton Valley	1/19/2008	34,309	20,273	14,036
BOOKOUT # 6	1PDP	CTI-A1	Cotton Valley	1/18/2008	33,418	20,273	13,145
BOOKOUT # 7	1PDP	CTI-A1	Cotton Valley	1/20/2008	31,802	20,273	11,529
BOOKOUT # 8	1PDP	CTI-A1	Cotton Valley	3/12/2008	25,966	20,273	5,693
BOOKOUT # 9	1PDP	CTI-A1	Cotton Valley	3/13/2008	30,669	20,273	10,396
BOOKOUT #10	1PDP	CTI-A1	Cotton Valley	3/14/2008	27,340	20,273	7,067
BOSH # 6	1PDP	CTII-A3	Cotton Valley	11/28/2008	23,450	20,273	3,177
BOSH # 9	1PDP	CTII-A3	Cotton Valley	12/15/2008	30,581	20,273	10,308
BRADLEY # 5	1PDP	CTII-A3	Cotton Valley	1/1/2008	22,129	20,273	1,856
BRADLEY #11D	1PDP	CTII-A3	Cotton Valley	1/20/2008	5,558	20,273	(14,715	)
CADENHEAD #12	1PDP	CTII-A3	Cotton Valley	8/12/2008	23,256	20,273	2,983
CADENHEAD #14D	1PDP	CTII-A3	Cotton Valley	6/12/2008	25,853	20,273	5,580
CADENHEAD #15	1PDP	CTII-A3	Cotton Valley	8/28/2008	24,210	20,273	3,937
CALLISON # 2R	1PDP	CTII-A3	Cotton Valley	3/21/2008	47,742	20,273	27,469
CALLISON # 3	1PDP	CTII-A3	Cotton Valley	5/8/2008	17,310	20,273	(2,963	)
CALLISON # 5D	1PDP	CTII-A3	Cotton Valley	5/17/2008	43,908	20,273	23,635

Table 4 - Page 1 of 3

Table 4

Comparison of First Month’s Production Rate to Type Curve

(Cotton Valley wells which started production in 2008)

Well	Rsv Cat	Area	Reservoir		Start of Production	First 30.4 Days Production	Type Curve Prediction	Difference
CALLISON # 8D	1PDP	CTII-A3	Cotton Valley		7/15/2008	23,982	20,273	3,709
CALLISON #11	1PDP	CTII-A3	Cotton Valley		12/24/2008	26,669	20,273	6,396
CALLISON #13D	1PDP	CTII-A3	Cotton Valley		4/14/2008	31,018	20,273	10,745
ELLA NOLTE # 6	1PDP	CTII-A3	Cotton Valley		2/7/2008	28,370	20,273	8,097
ELLA NOLTE # 7D	1PDP	CTII-A3	Cotton Valley		1/11/2008	20,472	20,273	199
ELLA NOLTE #10	1PDP	CTII-A3	Cotton Valley		4/6/2008	40,246	20,273	19,973
ELLA NOLTE #11D	1PDP	CTII-A3	Cotton Valley		3/6/2008	41,642	20,273	21,369
FOSTER # 4	1PDP	CTI-A2	Cotton Valley		6/7/2008	34,002	24,429	9,573
FOSTER # 5	1PDP	CTI-A2	Cotton Valley		6/8/2008	49,522	24,429	25,093
FOSTER # 6	1PDP	CTI-A2	Cotton Valley		4/30/2008	31,368	24,429	6,939
FOSTER # 7	1PDP	CTI-A2	Cotton Valley		5/1/2008	23,741	24,429	(688	)
FOSTER # 8	1PDP	CTI-A2	Cotton Valley		5/2/2008	32,864	24,429	8,435
FOSTER # 9	1PDP	CTI-A2	Cotton Valley		5/3/2008	24,162	24,429	(267	)
FOSTER #10	1PDP	CTI-A2	Cotton Valley		7/16/2008	22,432	24,429	(1,997	)
FURRH GU3 #10	1PDP	CTI-A2	Cotton Valley	��	1/27/2008	15,914	24,429	(8,515	)
FURRH GU3 #18	1PDP	CTI-A2	Cotton Valley		7/2/2008	21,931	24,429	(2,498	)
FURRH GU3 #19	1PDP	CTI-A2	Cotton Valley		7/3/2008	18,346	24,429	(6,083	)
FURRH GU3 #20	1PDP	CTI-A2	Cotton Valley		7/4/2008	22,871	24,429	(1,558	)
FURRH, JAMES MADISON # 1	1PDP	CTI-A2	Cotton Valley		11/7/2008	0	24,429	(24,429	)
GERRY # 1	1PDP	CTII-A3	Cotton Valley		9/18/2008	25,976	20,273	5,703
GLORIA FRAZIER # 1	1PDP	CTI-A1	Cotton Valley		3/16/2008	67,012	20,273	46,739
GLORIA FRAZIER # 2	1PDP	CTI-A1	Cotton Valley		4/7/2008	42,040	20,273	21,767
GLORIA FRAZIER # 3	1PDP	CTI-A1	Cotton Valley		4/8/2008	32,351	20,273	12,078
GRANBERRY # 1	1PDP	CTI-A1	Cotton Valley		8/1/2008	8,364	20,273	(11,909	)
GULLEY #11	1PDP	CTI-A1	Cotton Valley		1/1/2008	0	20,273	(20,273	)
GULLEY #12	1PDP	CTI-A1	Cotton Valley		1/24/2008	24,311	20,273	4,038
GULLEY #13	1PDP	CTI-A1	Cotton Valley		1/30/2008	19,524	20,273	(749	)
HEISMAN # 4	1PDP	CTII-A3	Cotton Valley		1/12/2008	21,935	20,273	1,662
HEISMAN # 5	1PDP	CTII-A3	Cotton Valley		2/9/2008	20,520	20,273	247
HEISMAN # 6	1PDP	CTII-A3	Cotton Valley		8/24/2008	17,788	20,273	(2,485	)
JF ROBERTS #3	1PDP	CTI-A2	Cotton Valley		1/7/2008	10,298	24,429	(14,131	)
JF ROBERTS #4	1PDP	CTI-A2	Cotton Valley		2/2/2008	14,057	24,429	(10,372	)
LAWLESS RHOADES #14	1PDP	CTI-A2	Cotton Valley		5/18/2008	15,486	24,429	(8,943	)
LAWLESS RHOADES #15	1PDP	CTI-A2	Cotton Valley		5/14/2008	17,338	24,429	(7,091	)
LAWLESS RHOADES #16	1PDP	CTI-A2	Cotton Valley		5/15/2008	15,894	24,429	(8,535	)
LAWLESS RHOADES #17	1PDP	CTI-A2	Cotton Valley		5/17/2008	15,826	24,429	(8,603	)
LAWLESS RHOADES #18	1PDP	CTI-A2	Cotton Valley		5/18/2008	15,663	24,429	(8,766	)
LAWLESS RHOADES #19	1PDP	CTI-A2	Cotton Valley		5/19/2008	18,667	24,429	(5,762	)

Table 4 - Page 2 of 3

Table 4

Comparison of First Month’s Production Rate to Type Curve

(Cotton Valley wells which started production in 2008)

Well	Rsv Cat	Area	Reservoir	Start of Production	First 30.4 Days Production	Type Curve Prediction	Difference
MERCER # 1	1PDP	CTII-A3	Cotton Valley	4/9/2008	31,712	20,273	11,439
MERCER # 3	1PDP	CTII-A3	Cotton Valley	7/10/2008	33,401	20,273	13,128
MERCER # 4	1PDP	CTII-A3	Cotton Valley	8/9/2008	37,072	20,273	16,799
MERCER # 5	1PDP	CTII-A3	Cotton Valley	9/1/2008	36,890	20,273	16,617
MERCER # 7D	1PDP	CTII-A3	Cotton Valley	7/31/2008	29,766	20,273	9,493
MERCER # 9	1PDP	CTII-A3	Cotton Valley	10/1/2008	18,708	20,273	(1,565	)
MERCER #10	1PDP	CTII-A3	Cotton Valley	10/1/2008	20,463	20,273	190
ROSEHAVEN #10	1PDP	CTI-A1	Cotton Valley	3/24/2008	26,056	20,273	5,783
SANGSTER # 1	1PDP	CTI-A1	Cotton Valley	3/27/2008	11,363	20,273	(8,910	)
SPENCER # 5	1PDP	CTI-A1	Cotton Valley	8/1/2008	2,879	20,273	(17,394	)
SPENCER # 6	1PDP	CTI-A1	Cotton Valley	8/1/2008	35,146	20,273	14,873
SPENCER # 8	1PDP	CTI-A1	Cotton Valley	8/1/2008	30,756	20,273	10,483
STEELE # 1	1PDP	CTI-A2	Cotton Valley	8/1/2008	20,578	24,429	(3,851	)
THOMPSON # 1	1PDP	CTI-A1	Cotton Valley	6/13/2008	32,828	20,273	12,555
THOMPSON # 2	1PDP	CTI-A1	Cotton Valley	6/10/2008	36,364	20,273	16,091
THOMPSON # 3	1PDP	CTI-A1	Cotton Valley	6/12/2008	38,589	20,273	18,316
THOMPSON # 4	1PDP	CTI-A1	Cotton Valley	6/14/2008	47,167	20,273	26,894
				Total	2,470,357	1,944,587	525,770
				Average	27,147	21,369	5,778

Table 4 - Page 3 of 3