 | Jim Merrill Chief Financial Officer One Benham Place, Suite 600 9400 North Broadway Oklahoma City, OK 73114 Of 405.254.5805 Fax 405.600.0600 Cell 405.401.5980 Email:jmerrill@gmxresources.com |
September 1, 2011
Via EDGAR
Anne Nguyen Parker
Branch Chief
United States Securities and Exchange Commission
Division of Corporation Finance
100 F Street, N.E.
Washington, D.C. 20549
| Re: | GMX Resources Inc. |
Amendment No. 1 to Registration Statement on Form S-3
Filed August 2, 2011
File No. 333-175157
Annual Report on Form 10-K for Fiscal Year ended December 31, 2010
Filed March 11, 2011
Definitive Proxy Statement on Schedule 14A
Filed April 22, 2011
Current Report on Form 8-K
Filed January 28, 2011
File No. 001-32977
Dear Ms. Nguyen Parker:
Set forth below are the responses of GMX Resources Inc., an Oklahoma corporation (“GMXR,” the “Company,” “we,” “us,” or “our”), to the comments received from the staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “Commission”) by letter dated August 18, 2011, with respect to GMXR’s (i) Registration Statement on Form S-3 filed with the Commission on June 27, 2011, File No. 333-175157 (the “Registration Statement”), (ii) Annual Report on Form 10-K for Fiscal Year ended December 31, 2010 filed with the Commission on March 11, 2011 (the “Annual Report”), and (iii) Definitive Proxy Statement on Schedule 14A filed with the Commission on April 22, 2011, File No. 001-32977 (the “Proxy Statement”).
For the Staff’s convenience, each response is prefaced by the exact text of the Staff’s corresponding comment in bold, italicized text. All references to page numbers and captions correspond to Amendment No. 1, unless indicated otherwise.
September 1, 2011
Page 2
Amendment No. 1 to Registration Statement on Form S-3
General
| 1. | We remind you of prior comment 1 from our letter to you dated July 25, 2011. |
Response:
We acknowledge that you will not be able to accelerate the effectiveness of the Registration Statement until we have cleared all comments, including comments on our periodic reports, below.
Annual Report on Form 10-K
General
| 1. | We note your responses to prior comments 5, 6, 7 and 9 from our letter to you dated July 25, 2011. Please include the information in your response in your future filings. |
Response:
We will include our responses on questions 5, 6, 7 and 9 from your letter dated July 25, 2011 in future filings. We included the requested insurance information from comment 9 in our Form 10-Q filed on August 9, 2011.
| 2. | We note your response to prior comment 18 from our letter to you dated July 25, 2011. Please amend your Form 10-K to incorporate your proposed draft disclosures and include the complete applicable line item. |
Response:
GMXR has filed a Form 10-K/A on September 1, 2011 that incorporates the disclosures from GMXR’s response to prior comment 18 from your letter dated July 25, 2011.
Engineering Comments
Annual Report on Form 10-K
Estimated Quantities of Oil and Natural Gas, page F-40
| 2. | As the industry’s interest in the Haynesville Shale has been ongoing for a number of years, please tell us why the non-operated Cotton Valley Shale reserves were not removed from your proved reserves in 2009. Please also tell us how much of the negative revisions in 2008 and 2009 were due to performance revisions. |
September 1, 2011
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Response:
With respect to year end 2009, we note that “industry” interest in the Haynesville actually started in late 2007 with Chesapeake’s announcement coming in March 2008. The Company’s non-operated Cotton Valley well PUD reserves were all associated with Penn Virginia’s activities in east Texas. Penn Virginia (PVA) had a consistent program of development starting in 2004 and had drilled over 200 vertical Cotton Valley wells on GMXR’s acreage through 2008. In late 2007, PVA invested over $20 million in a liquids facility anticipating future development in a liquids rich Cotton Valley resource buoyed by their success in the area of mutual interest (AMI) with GMXR over the prior four-year period. Moreover, in December 2009 PVA represented in public presentations that they were the 30th largest public company in terms of year-end 2008 proved reserves, with 46% of those reserves located in east Texas (419 billion cubic feet equivalent (Bcfe)). In April 2010, PVA represented that proved reserves in east Texas were 403 Bcfe, a slight 4% decrease.
At year end 2009, GMXR was not prepared to assume that PVA would maintain the same pace of development seen during the previous three years to further develop the AMI. However, GMXR had the right to propose and, if necessary, operate on the entire AMI. In light of the pause in drilling and falling natural gas prices, GMXR removed a portion of PVA non-operated PUD locations previously booked and pushed out the timing of the balance of booked PUD locations. As time passed, it became more apparent that PVA had redirected their investment strategy and what was viewed as a short-term drop in natural gas prices was, in effect, a more pronounced long term weakness causing companies to redirect drilling budgets to higher margin plays.
The performance revision from year-end 2008 to year end 2009 was 39 Bcfe, or 8.4% of GMXR’s total proved reserves.
| 3. | We note that on August 4, 2011 you announced that you were also suspending the further development of the Haynesville Shale due to low gas prices and high service costs until the economics become competitive with your oil development. Therefore, it would appear that you will need to remove the undeveloped Haynesville Shale reserves from the proved classification. Please confirm that you will be doing this in your next 10-K report. |
Response:
As stated in the excerpt below from GMXR’s Form 10-Q filed August 9, 2011, GMXR intends to resume drilling in the Haynesville/Bossier in July 2013 after establishing drilling programs in the Bakken and Niobrara. As a result of our intent to resume drilling in the Haynesville/Bossier during 2013, we do not currently anticipate removing our proved undeveloped Haynesville/Bossier reserves in our next 10-K report. Excerpt:
All of our Haynesville/Bossier acreage is held by production, which enables us to shift capital to higher economic return basins without risking the loss of core acreage. We have temporarily suspended drilling new Haynesville /Bossier horizontal wells as of July 2011 and are focusing our capital to accelerating the development of our oil acreage. We expect to continue to explore for additional oil opportunities within our core East Texas acreage.We anticipate reactivating our drilling program in July 2013 in the Haynesville/Bossier Shale in order to continue development of our natural gas reserves in our historic primary development area in East Texas.
September 1, 2011
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| 4. | All proved reserves must meet the standard of reasonable certainty. Therefore, please tell us the evidence that allowed you to determine that horizontal wells in the Haynesville Shale will produce in excess of 50 years. In that regard please tell us the estimated cumulative production of a horizontal well in the Haynesville Shale after 20 years of production. Please also tell us the initial and terminal decline rate you use for these fifty year forecasts. |
Response:
The initial decline of the PUD forecast is 99 percent tangential effective and the terminal decline used is 6 percent. Estimated cumulative production is 5.2 billion cubic feet (Bcf) after 20 years and 6.3 Bcf after 50 years. This represents 80 percent and 97 percent of gross projected volumes recovered after each of the respective time periods. This production profile extrapolates to a total life of about 55 years. These types of initial declines have been experienced in other shale plays, and terminal declines of even less than 6 percent have been recognized from old shale wells.
Oil and gas producing activities have been ongoing in the United States for over 120 years and in that time period drilling innovations, wellbore design, and advances in wellbore construction and tubular materials have allowed continuous production from thousands of wells exceeding 50 years of wellbore life.
In the region in which the GMXR properties are located, we noted that wells producing from the Smackover reservoir, which underlies the Haynesville and produces corrosive gas, have been on production since 1963. For example, the W A Moncrief (Smackover) field was discovered in 1963. Eight wells were drilled to the Smackover reservoir in this field between 1963 and 1974. Of those eight wells, seven are still producing commercial volumes of hydrocarbon with over 118 Bcf of gas and 2 million barrels (MMbbl) of condensate produced to date. This is a direct indication of reasonable certainty for wellbore lives of more than 50 years in the Haynesville, as the Smackover is located at a depth below the Haynesville and typically produces higher concentrations of corrosive gases (H2S and CO2) than found in the Haynesville wells. Specifically, the seven wells
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currently producing in the W A Moncrief (Smackover) field are drilled to depths ranging between 12,424 and 12,745 feet of sub-surface vertical depth and are currently producing in excess of 2,100 parts per million of hydrogen sulfide gas. Based on the declines expected, casing life history stated above the Haynesville Shale is expected to produce for more than 50 years.
| 5. | We note that your PDP wells in the Haynesville Shale have an average EUR of 4.3 BCF with a median EUR of 4.5 BCF per well. There are three wells (10%) that have an EUR greater than 6 BCF. However, your PUD wells in the Haynesville Shale average 6.2 BCF per well with 24 wells (69%) having an estimated EUR greater than 6 BCF with most of the other PUD wells just below an EUR of 6 BCF. As an actual Haynesville Shale well on your property that has an EUR greater than 6 BCF is the exception rather than the norm it appears that your PUD reserves in the Haynesville Shale have been too high. As all proved reserves have to meet the standard of reasonable certainty and the EUR should be much more likely to increase than decrease, it appears the PUD reserves should have a median estimate of no higher than 4.5 BCF per well or total Haynesville Shale PUD reserves of 99.9 BCF instead of the 158.9 BCF that you currently carry. Therefore, your total gas reserves as of December 31, 2010 should be reduced by 59 BCF to 252.9 BCF instead of the 311.9 that you currently carry. This does not include any adjustments in Haynesville Shale gas reserves due to the issue of well life as discussed in a previous comment. Please advise or revise accordingly. |
Response:
Since the completions in the Haynesville have varying lateral lengths, the proved undeveloped reserves were estimated by evaluating the recoverable reserves per foot of horizontal lateral for the producing properties and applying the resultant recovery per foot to the planned lateral lengths of undeveloped locations. This study included an analysis of the latest production data to estimate ultimate recovery for the 29 horizontal Haynesville Shale wells completed by GXMR and on production as of December 31, 2010. This sample was then reduced to the last 16 wells completed in the field, since they represented the latest completion techniques adopted by GXMR in 2010. Well spacing was estimated to be approximately 1,000 feet between laterals. Tables showing the previous wells that had been analyzed, recoveries per foot of lateral, and the proposed lateral lengths of undeveloped wells are included asExhibit A to this letter.
Proved undeveloped (PUD) reserves were estimated using the projected estimated ultimate recoveries from the proved producing properties. At the time the December 31, 2010, PUD estimates were made, GMXR had drilled and produced from 29 horizontal Haynesville Shale wells. These PDP wells were of varying lateral lengths ranging from 2,305 to 6,080 feet. GMXR’s stated development plan from that time forward was to drill horizontal Haynesville Shale wells with lateral lengths of about 6,500 feet. To account for the increased recovery of gas from the longer laterals due to the increase of
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contacted reservoir, the estimated recoveries of the PDP wells were normalized on a million cubic feet (MMcf) per lateral foot basis and a statistical analysis for a 35 well drilling program resulted in an estimated P90 recovery of 1.0 MMcf/lateral foot. Using this metric, PUD reserves were scaled up to account for the planned lateral lengths of the undeveloped locations, and this resulted in estimated ultimate recovery (EUR) estimates for 6,500-foot PUD locations of 6.5 Bcf of gross gas technically recoverable. After applying economic assumptions, the economic EUR for the 6,500 foot lateral PUD locations is 6.4 Bcf. The three developed wells with EUR estimates greater than 6 Bcf are 2010 wells completed with average to above-average recoveries on an EUR/foot basis. Since the 2010 year-end estimates were made, GMXR has drilled four 6,500-foot lateral wells and completed and produced from three of them. Initial production data from these three wells indicates that performance is on trend with our December 31, 2010 projections.
| 6. | In regards to your response to our prior comment number 6 from our letter to you dated July 25, 2011, with a view toward disclosure, please expand your response to state whether you typically run cement bond and temperature logs after your cementing operations to verify the integrity of the cement bond and to determine the top of cement (TOC). Also discuss if you run pressure tests on the casing prior to a frac job to check for any leak off of the pressure. |
Response:
Cement bond logs are not required to be run during drilling operations in Texas, and we have not run them on our casing strings since January 2009. When conditions of the well warrant the evaluation of the cement quality and/or top, we will run a cement bond log and any other evaluation tools, on an as needed basis. As an example, temperature logs are run if we don’t get cement returns to surface while cementing the surface casing. The log gives a good indication of where the cement top is located if the log is run within 24 hours of cementing.
It is an industry standard practice, and a practice that GMXR follows,to pressure test the production casing prior to any completion operations. If the pressure test warrants corrective action, that action will be performedprior to any completion operations, up to and including hydraulic fracturing operations.
| 7. | You discuss the steps you take to insure integrity of the casing and cement jobs. However successful isolation of an aquifer may be compromised if, for example: |
| • | an improper cement job or other imperfections in well construction creates conditions whereby the hydraulic fracturing fluid and naturally occurring substances mobilized by the fracturing treatment leaks into the surrounding geologic formation; |
September 1, 2011
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| • | a well, even if correctly constructed, fails over time due to downhole stresses and corrosion; and |
| • | during the fracturing process, “fluid-leakoff” occurs, whereby some of the hydraulic fracturing fluid flows through the artificially created fractures into the micropores or pore spaces within the formation, existing natural fractures in the formation, or small fractures opened into the formation by the pressure in the induced fracture. |
Please expand your response to discuss any conditions whereby isolation of the wellbore may not be successful, notwithstanding the existence of impermeable rock layers and your use of cement and steel casing pipe.
Response:
GMXR is not familiar with any of the hypothetical occurrences as set forth in your examples resulting in the contamination of an aquifer and cannot realistically discuss the conditions in which isolation is compromised as described. Corrosion may occur over a period of years long after any hydraulic fracturing takes place and the company operates in an area of relatively low tectonic activity. Surface water is protected by two or more casing strings so that if one of the deeper casing strings fail, the surface casing will still protect the ground water. Our cement slurries are lab tested for strength and setting times that are set forth by good drilling practices and by formation properties. All of our casing is inspected for integrity before it is shipped to the rig. The casing design is tailored to the specific geological and formation properties that we drill through. We monitor surface pressures during the frac jobs and those readings are consistent with injected fluids entering the desired interval. The dip of the target interval is low and the formation targeted does not outcrop at the surface in North America. The energy utilized to inject fracturing fluids, and the volumes of fluids injected into the formation, is not sufficient to activate a fracture exceeding the vertical distance from the injection interval up to the fresh water strata. That said, the fact that a small piece of the rock strata is removed from the earth during the drilling process does not preclude that such removal creates an opportunity for communication due to acombination of failures in well construction, however unlikely. Even in the case of such a failure, the presence of almost 2 miles of sedimentary rock with multiple layers of pressures and absorption capacity to capture any pressurized fluids is orders of magnitude greater than the volume of fluid involved in hydraulic fracturing operations. Accordingly, we believe direct or indirect injection of fluids into an aquifer from such an operation is effectively, if not absolutely, impossible under the circumstances in which the company conducts its operations.
| 8. | As to your response to our prior comment seven from our letter to you dated July 25, 2011, in order to protect groundwater as well as surface water, please tell us if you conduct baseline assessments of nearby water sources prior to any drilling or hydraulic fracturing operations. |
September 1, 2011
Page 8
Response:
We do not typically run a baseline groundwater assessment prior to commencing drilling or fracturing operations. However, in circumstances should we drill close to a residence, we would test the well water beforehand as a means of protecting GMXR from future liability or claims that the drilling or fracturing operations affected the quality of the water.
Current Report on Form 8-K, filed January 28, 2011
| 9. | It is not clear how DeGoyler and MacNaughton determined the proved undeveloped reserves for the Haynesville Shale wells. In their report they say they applied recovery factors to OGIP. Please tell us what these recovery factors were based on and the reliability of an original-oil-in-place calculation in the Haynesville Shale. In addition, you might consider having the reserve letter report revised to truly represent the work that was done on the GMX Resources’ reserves determined and to not contain boiler plate disclosure that discusses every reserve methodology whether it was actually used or not. If they did not use a recovery factor to calculate the reserves they should not be stating that they did or may have. |
Response:
DeGoyler and MacNaughton has provided a revised reserve letter report that addresses the above issues, which exhibit is filed as Exhibit 99.2 to the Form 10-K/A filed on September 1, 2011.
| 10. | The DeGoyler & MacNaughton reserve letter states, under economic assumptions, that estimated future gross revenue, future net revenue, and present worth of future net revenue are based on the continuation of prices in effect on December 31, 2010. This is not in compliance with the current SEC regulations on pricing. Please see the definition of Proved Reserves under Rule 210.4-10(a)(22)(v). Please revise the letter report and Standardized Measure as necessary. |
Response:
The reserve letter language was meant to convey “based on the continuation of SEC pricing guidelines in effect as of December 31, 2010.” The language has been revised in the revised reserve letter as noted above in the response to Comment 9, which exhibit is filed as Exhibit 99.2 to the Form 10-K/A filed on September 1,2011. The estimates were not changed, as the estimates had been correctly prepared in accordance with SEC guidelines, as described in the pricing discussion.
September 1, 2011
Page 9
| 11. | The DeGoyler & MacNaughton reserve letter should be revised to provide the geographic location of the reserves. Please see paragraph (a)(8)(iii) of Item 1202 of Regulation S-K. The letter should also be revised to include the purpose for which the report was prepared and the date on which the report was completed. In addition the report should be revised to include a discussion regarding the inherent uncertainties of reserve estimates. Please see paragraph (a)(8)(i), paragraph (a)(8)(ii) and paragraph (a)(8)(vii) of Item 1202 of Regulation S-K. |
Response:
All of the issues in Comment 11 are addressed in the revised letter report as noted in Comment 9, which exhibit is filed as Exhibit 99.2 to the Form 10-K/A filed on September 1, 2011. The discussion regarding the inherent uncertainties of reserves estimates was included on page 7 of our previous letter.
| 12. | The MHA reserve letter should be revised to include the purpose for which the report was prepared, the date of the completion of the report, the proportion of the registrant’s total reserves that were determined and a discussion on the possible effects of government regulation on the registrant’s ability to recover the estimated reserves. Please see paragraphs (a)(8)(i), (ii), (iii) and (vi) of Item 1202 of Regulation S-K. In addition, the report should be revised to remove the statement the report is for the exclusive use of GMX Resources and that should GMX Resources wish to release the report they must obtain a written release from MHA. It is not appropriate to attempt to limit the audience of an exhibit in an SEC filing. |
Response:
MHA has provided a revised reserve letter report that addresses the above issues, which revised reserve letter is filed as Exhibit 99.1 to the Form 10-K/A filed on September 1, 2011.
Closing Comments
We acknowledge that:
| • | should the Commission or the staff, acting pursuant to delegated authority, declare the filing effective, it does not foreclose the Commission from taking any action with respect to the filing; |
| • | the action of the Commission or the staff, acting pursuant to delegated authority, in declaring the filing effective, does not relieve the company from its full responsibility for the adequacy and accuracy of the disclosure in the filing; and |
September 1, 2011
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| • | the company may not assert staff comments and the declaration of effectiveness as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States. |
Please direct any questions you have with respect to the foregoing or with respect to the Registration Statement or Amendment No. 1 to the undersigned at (405) 600-0711 (ext 305).
| Sincerely, |
/s/ James A. Merrill |
| James A. Merrill |
| Chief Financial Officer |
| GMX Resources Inc. |
| cc: | David Buck, Esq. |
Andrews Kurth LLP
September 1, 2011
Page 11
EXHIBIT A
Table 1 - Proved Developed Producing (PDP)
Lease Name | Reserve Class | Reserve Category | Completed Lateral Length (ft) | Gross Wet Gas Technical EUR (MMcf) | EUR per Foot of Completed Lateral (MMcf/ft) | First Production (mm/dd/yyyy) | ||||||||||||
CALLISON 9H | Proved | Producing | 2,305 | 1,915 | 0.831 | 11/21/2008 | ||||||||||||
BOSH 11H | Proved | Producing | 2,985 | 2,117 | 0.709 | 1/29/2009 | ||||||||||||
BALDWIN 17H | Proved | Producing | 3,935 | 3,739 | 0.950 | 2/13/2009 | ||||||||||||
VERHALEN A 2H | Proved | Producing | 4,045 | 3,001 | 0.742 | 5/4/2009 | ||||||||||||
BLOCKER WARE 19H | Proved | Producing | 3,953 | 3,264 | 0.826 | 5/14/2009 | ||||||||||||
BLOCKER HEIRS 12H | Proved | Producing | 5,075 | 5,417 | 1.067 | 6/7/2009 | ||||||||||||
HOLT 1H | Proved | Producing | 4,481 | 4,188 | 0.935 | 8/1/2009 | ||||||||||||
VERHALEN B 1H | Proved | Producing | 5,025 | 3,783 | 0.753 | 9/2/2009 | ||||||||||||
VERHALEN C 1H | Proved | Producing | 5,175 | 2,898 | 0.560 | 10/24/2009 | ||||||||||||
VERHALEN D 1H | Proved | Producing | 4,542 | 2,491 | 0.548 | 12/6/2009 | ||||||||||||
BELL 5H | Proved | Producing | 4,170 | 2,200 | 0.528 | 12/23/2009 | ||||||||||||
MIA AUSTIN 1H | Proved | Producing | 4,468 | 6,162 | 1.379 | 2/6/2010 | ||||||||||||
VERHALEN E 1H | Proved | Producing | 4,387 | 3,716 | 0.847 | 2/14/2010 | ||||||||||||
BOSH 19H | Proved | Producing | 4,142 | 4,760 | 1.149 | 3/20/2010 | ||||||||||||
BLOCKER HEIRS 20H | Proved | Producing | 4,378 | 4,719 | 1.078 | 4/9/2010 | ||||||||||||
VERHALEN D 3H | Proved | Producing | 4,786 | 4,359 | 0.911 | 4/13/2010 | ||||||||||||
VERHALEN E 6H | Proved | Producing | 4,445 | 4,053 | 0.912 | 4/19/2010 | ||||||||||||
BLOCKER WARE 8H | Proved | Producing | 4,171 | 5,512 | 1.322 | 5/12/2010 | ||||||||||||
BLOCKER HEIRS 14H | Proved | Producing | 5,107 | 4,149 | 0.812 | 6/26/2010 | ||||||||||||
VERHALEN F 1H | Proved | Producing | 5,286 | 5,714 | 1.081 | 7/8/2010 | ||||||||||||
MERCER 11H | Proved | Producing | 4,851 | 6,277 | 1.294 | 7/30/2010 | ||||||||||||
HOLT 2H | Proved | Producing | 5,286 | 5,229 | 0.989 | 9/8/2010 | ||||||||||||
SHAW 1H | Proved | Producing | 5,107 | 4,918 | 0.963 | 10/1/2010 | ||||||||||||
BLOCKER HEIRS 21H | Proved | Producing | 5,452 | 5,182 | 0.951 | 10/18/2010 | ||||||||||||
BLOCKER WARE 23H | Proved | Producing | 4,837 | 4,021 | 0.831 | 10/19/2010 | ||||||||||||
MIA AUSTIN 6H | Proved | Producing | 6,080 | 6,471 | 1.064 | 11/7/2010 | ||||||||||||
VERHALEN B 7H | Proved | Producing | 5,017 | 5,127 | 1.022 | 11/25/2010 | ||||||||||||
BOSH HEISMAN 17H | Proved | Producing | N/A | 5,578 | N/A | 12/1/2010 | ||||||||||||
MIA AUSTIN 3H | Proved | Producing | N/A | 4,820 | N/A | 12/12/2010 | ||||||||||||
| | Median 2010 EUR per Foot (MMcf/ft) | | 1.006 | |||||||||||||||
| | Mean 2010 EUR per Foot (MMcf/ft) | | 1.038 | |||||||||||||||
September 1, 2011
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Table 2 - Proved Undeveloped (PUD)
Lease Name | Reserve Class | Reserve Category | Development Lateral Length (ft) | Gross Wet Gas Technical EUR (MMcf) | EUR per Foot of Completed Lateral (MMcf/ft) | First Production (mm/dd/yyyy) | ||||||||||||
VERHALEN A 5H | Proved | Undeveloped | 6,155 | 5,615 | 0.912 | 2/1/2011 | ||||||||||||
VERHALEN A 8H | Proved | Undeveloped | 6,500 | 5,865 | 0.902 | 2/1/2011 | ||||||||||||
MIA AUSTIN 10H | Proved | Undeveloped | 6,547 | 6,481 | 0.990 | 2/1/2011 | ||||||||||||
BELL 6H | Proved | Undeveloped | 5,851 | 5,865 | 1.002 | 3/1/2011 | ||||||||||||
BALDWIN-MIA AUSTIN 1H | Proved | Undeveloped | 6,499 | 6,501 | 1.000 | 3/1/2011 | ||||||||||||
HOLT-BOSH 5H | Proved | Undeveloped | 6,509 | 6,571 | 1.010 | 4/1/2011 | ||||||||||||
BALDWIN-MERCER 1H | Proved | Undeveloped | 6,500 | 6,501 | 1.000 | 5/1/2011 | ||||||||||||
SHAW-BENNETT 9H | Proved | Undeveloped | 7,089 | 6,501 | 0.917 | 5/1/2011 | ||||||||||||
HOLT-BLOCKER HRS-BLOCKER WARE 1H | Proved | Undeveloped | 6,500 | 6,501 | 1.000 | 8/1/2011 | ||||||||||||
BOSH-GERRY-CADENHEAD 12H | Proved | Undeveloped | 6,500 | 6,549 | 1.007 | 9/1/2011 | ||||||||||||
BLOCKER WARE-GILL 3H | Proved | Undeveloped | 6,000 | 6,058 | 1.010 | 10/1/2011 | ||||||||||||
CADENHEAD-CALLISON 1H | Proved | Undeveloped | 6,500 | 6,501 | 1.000 | 12/1/2011 | ||||||||||||
GILL-BLOCKER WARE 1H | Proved | Undeveloped | 6,500 | 6,500 | 1.000 | 2/1/2012 | ||||||||||||
BLOCKER WARE-GILL-CADENHEAD 2H | Proved | Undeveloped | 6,500 | 6,503 | 1.000 | 2/1/2012 | ||||||||||||
BARKER TRUSTS-MIA AUSTIN 2H | Proved | Undeveloped | 6,500 | 6,501 | 1.000 | 3/1/2012 | ||||||||||||
HEISMAN 16P | Proved | Undeveloped | 6,500 | 6,501 | 1.000 | 4/1/2012 | ||||||||||||
BENNETT-SHAW 2H | Proved | Undeveloped | 6,500 | 6,501 | 1.000 | 5/1/2012 | ||||||||||||
HEISMAN-BELL 13H | Proved | Undeveloped | 6,000 | 6,058 | 1.010 | 6/1/2012 | ||||||||||||
SHAW-BENNETT 5H | Proved | Undeveloped | 6,500 | 6,501 | 1.000 | 8/1/2012 | ||||||||||||
HEISMAN-BELL 10H | Proved | Undeveloped | 6,000 | 6,058 | 1.010 | 9/1/2012 | ||||||||||||
BENNETT-SHAW 3H | Proved | Undeveloped | 6,574 | 6,501 | 0.989 | 10/1/2012 | ||||||||||||
HEISMAN-BELL 9H | Proved | Undeveloped | 6,000 | 6,058 | 1.010 | 11/1/2012 | ||||||||||||
HOLT-BOSH 6H | Proved | Undeveloped | 6,500 | 6,506 | 1.001 | 12/1/2012 | ||||||||||||
BARKER TRUST 1H | Proved | Undeveloped | 5,529 | 5,646 | 1.021 | 1/1/2013 | ||||||||||||
CADENHEAD 28P | Proved | Undeveloped | 6,500 | 6,492 | 0.999 | 2/1/2013 | ||||||||||||
HAMILTON 3P | Proved | Undeveloped | 6,500 | 5,970 | 0.919 | 3/1/2013 | ||||||||||||
UNDERWOOD 12P | Proved | Undeveloped | 6,442 | 6,501 | 1.009 | 7/1/2013 | ||||||||||||
BOSH 24P | Proved | Undeveloped | 6,000 | 6,219 | 1.037 | 9/1/2013 | ||||||||||||
UNDERWOOD 14P | Proved | Undeveloped | 6,500 | 6,501 | 1.000 | 10/1/2013 | ||||||||||||
UNDERWOOD 16P | Proved | Undeveloped | 6,076 | 6,058 | 0.997 | 11/1/2013 | ||||||||||||
CADENHEAD 26P | Proved | Undeveloped | 6,485 | 6,497 | 1.002 | 1/1/2014 | ||||||||||||
BLOCKER WARE 29P | Proved | Undeveloped | 6,000 | 6,058 | 1.010 | 3/1/2014 | ||||||||||||
JOIE 5P | Proved | Undeveloped | 6,500 | 6,501 | 1.000 | 5/1/2014 | ||||||||||||
JOIE 3P | Proved | Undeveloped | 6,500 | 6,501 | 1.000 | 7/1/2014 | ||||||||||||
JOIE 1P | Proved | Undeveloped | 6,500 | 6,501 | 1.000 | 9/1/2014 | ||||||||||||
| | Median EUR per Foot (MMcf/ft) | | 1.000 | |||||||||||||||
| | Mean EUR per Foot (MMcf/ft) | | 0.993 | |||||||||||||||