| Chesapeake Granite Wash Trust | Chesapeake Energy Corporation | |
| c/o The Bank of New York Mellon | 6100 North Western Avenue | |
| Trust Company, N.A | Oklahoma City, Oklahoma 73118 | |
| 919 Congress Avenue, Suite 500 | ||
| Austin, Texas 78701 |
September 16, 2011
Division of Corporation Finance
Securities and Exchange Commission
100 F Street, NE
Washington, DC 20549-7010
Attention: Mr. H. Roger Schwall, Assistant Director
| Re: | Chesapeake Granite Wash Trust |
| Amendment No. 1 to Registration Statement on Form S-1 |
| Filed August 19, 2011 |
| File No. 333-175395 |
| Chesapeake Energy Corporation |
| Amendment No. 1 to Registration Statement on Form S-3 |
| Filed August 19, 2011 |
| File No. 333-175395-01 |
Ladies and Gentlemen:
Set forth below are the responses of Chesapeake Granite Wash Trust, a Delaware statutory trust (the “Trust”), and Chesapeake Energy Corporation, an Oklahoma corporation (“Chesapeake” or the “Company,” and, together with the Trust, “we,” “us” or “our”), to comments received from the Staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “Commission”) by letter dated September 6, 2011, with respect to Amendment No. 1 (“Amendment No. 1”) to the Registration Statement on Forms S-1 and S-3, respectively, (File Nos. 333-175395 and 333-175395-01) filed with the Commission on August 19, 2011 (as amended, the “Registration Statement”).
Concurrently with the submission of this letter, we are filing through EDGAR Amendment No. 2 to the Registration Statement (“Amendment No. 2”). For your convenience, we will hand deliver to the members of the Staff listed in the letter from the Staff dated September 6, 2011, seven copies of Amendment No. 2 that are marked to show all changes made since the filing of Amendment No. 1.
For the Staff’s convenience, each response is prefaced by the exact text of the Staff’s corresponding comment in bold, italicized text. Unless otherwise specified, all references to page
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numbers and captions in our responses correspond to the prospectus included as part of Amendment No. 2.
General
| 1. | We remind you of prior comments 1 through 6, and comment 10 from our letter dated August 4, 2011. In addition, we are reviewing your response to the staff’s letter dated August 2, 2011 with respect to Chesapeake Energy Corporation, and may have additional comments on your registration statement after the completion of such review. |
Response: We acknowledge the Staff’s comment and will continue to undertake to comply with prior comments 1 through 6 and 10 in the Staff’s letter dated August 4, 2011. Additionally, we acknowledge the Staff’s concurrent review of Chesapeake’s
Form 10-K for the year ended December 31, 2010.
| 2. | Please make relevant updates with each amendment. For example, and without limitation, please update your disclosure regarding the status of your application to list on The New York Stock Exchange. In that regard, we note the update provided in your response to comment 5 from our letter dated August 4, 2011. |
Response: We acknowledge the Staff’s comment and have updated the Registration Statement as appropriate, including revising the Registration Statement to reflect the status of our application to list on the New York Stock Exchange. Please see the prospectus cover page and page 112.
| 3. | We note your response to comment 5 from our letter dated August 4, 2011 with respect to the omitted information that relates to your hedging arrangements, and your statement that such information is market sensitive and dependent on the offering date. We also note your statement that you have accordingly omitted such information pursuant to Rule 430A. Please tell us whether you will be able to provide such information prior to effectiveness of the registration statement. If you will not be able to provide such information prior to effectiveness, please tell us why. For example, and without limitation, please tell us when the hedging arrangements will be finalized. We may have additional comment. |
Response: We acknowledge the Staff’s comment and advise the Staff that we anticipate that the hedge arrangements will be finalized prior to the printing and distribution of the preliminary prospectus for the offering. In order to allow the Staff time to review the omitted information regarding the hedging arrangements, we propose to include such information in an amendment filed shortly before the date we plan to commence printing the preliminary prospectus. We further undertake to keep the Staff apprised of the anticipated schedule for the offering in order to allow the Staff sufficient time to review the omitted information.
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Summary, page 1
| 4. | We note your response to comment 13 from our letter dated August 4, 2011. Please balance your disclosure regarding the relatively low risk nature of the reservoirs with a brief description of the relative development costs. |
Response: We acknowledge the Staff’s comment and have revised the summary accordingly. Please see pages 4 and 63.
Risk Factors, page 20
Oil and gas drilling and producing operations can be hazardous…, page 33
| 5. | We note your response to comment 17 from our letter dated August 4, 2011, and reissue such comment in part. In that regard, please tell us, with a view towards disclosure, the deductibles and the nature of the “customary exclusions and limitations” that you reference at page 34. |
Response: We acknowledge the Staff’s comment and have revised the risk factor (i) to disclose the dollar range of deductibles to which Chesapeake is subject under the insurance policies applicable to the Underlying Properties and (ii) to remove the reference to “customary exclusions and limitations,” as such exclusions and limitations function primarily to coordinate coverages under our separate policies and avoid duplicative coverage of similar risks by more than one policy. As a result, we have concluded that such exclusions and limitations are not material to trust unitholders. Please see page 34.
Sensitivity of Target Distributions to Changes in Oil, Natural Gas Prices and Volumes, page 59
| 6. | Please tells us, with a view toward disclosure, how much oil and natural gas prices would need to fall for the estimated distributable income of the trust to be zero (i.e., for the trust’s expenses to be equal to or in excess of the trust’s revenues) for the periods specified in the sensitivity tables on pages 60-61. |
Response: We acknowledge the Staff’s comment and we advise the Staff that, for the year ended December 31, 2010, the Trust’s pro forma revenues were approximately $154.0 million and the Trust’s pro forma expenses were only $1.0 million. Thus, based on the NYMEX strip prices we have used to calculate the target distributions in the Registration Statement, we believe that oil and natural gas prices would need to fall by approximately 90% (which would result in oil prices below $9.00 per barrel and natural gas prices below $0.40 per thousand cubic feet) for the Trust’s revenues to approximate the Trust’s expenses, many of which are of a fixed nature, for the periods specified. Stated another way, on a barrel of oil equivalent (“boe”) basis, Trust expenses are approximately $0.50 per boe, compared to revenue to the Trust of approximately $37.00 per boe based on such NYMEX strip prices. Because of the magnitude of the commodity price
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decreases that would have to occur for this situation to exist and because we anticipate that the commodity price hedges for the Trust will cover approximately 50% of the Trust’s production for the periods specified in the Registration Statement, we do not believe it is necessary to revise our disclosure to include this information.
| 7. | We note your response to comment 26 from our letter dated August 4, 2011. Please tell us why it is both necessary and appropriate for counsel to rely on your representation that the trust is organized in accordance with the Delaware Statutory Trust Act. |
Response: We acknowledge the Staff’s comment and have revised our disclosure to delete the reference noted in the Staff’s comment.
Engineering Comments
Hydraulic Fracturing, page 35
| 8. | Please tell us the average amount of fresh water used per well for hydraulically fracturing the Granite Wash; the source of that water and how you treat and dispose of this water. |
Response: We acknowledge the Staff’s comment and advise the Staff that each hydraulic fracturing treatment is uniquely designed and applied and, accordingly, the amount and sources of fresh water used by Chesapeake in the Colony Granite Wash varies with each well. For the 126 wells drilled by Chesapeake in the Colony Granite Wash to date, the average water usage in hydraulic fracturing activities per well has been approximately 2.5 million gallons. Chesapeake primarily uses fresh water, and in some cases a combination of fresh water and recycled produced water, in its fracturing treatments in the Colony Granite Wash. Chesapeake currently sources the fresh water it uses in the Colony Granite Wash primarily from water wells, and historically has also sourced fresh water from surface water sources such as ponds, lakes and rivers, in each case in accordance with applicable Oklahoma water management plans and laws. Chesapeake is actively engaged in the development of water recycling and re-use systems that may, in the future, decrease the amount of fresh water required for hydraulic fracturing activities in the Colony Granite Wash and elsewhere.
Produced, or formation, water exists naturally in oil and natural gas formations and is produced as a by-product of natural gas and oil extraction, even for wells on which no hydraulic fracturing activities have been performed. Chesapeake disposes of produced formation water and water used in hydraulic fracturing activities in the Colony Granite Wash, less any recycled water, in Class II underground injection control wells, which are designed and permitted to place the water into deep geologic formations that are isolated from fresh water
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sources. These Class II wells are overseen by the Environmental Protection Agency in its Underground Injection Control Program.
Additionally, we direct the Staff to the FracFocus website (www.fracfocus.org), a national publicly accessible web-based registry developed by the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission, with the support of the U.S. Department of Energy, in which Chesapeake participates. Chesapeake reports on the FracFocus registry the amount of water used, among other things, in the hydraulic fracturing process for each well that Chesapeake drills and hydraulically fractures, including its wells in the Colony Granite Wash.
Development Agreement and Drilling Support Lien, page 44
| 9. | You state that you will not drill or allow to be drilled any well that will have a perforated segment within 660 feet of a Development Well or Producing Well. Please tell us how this distance was determined and with a view towards disclosure please tell us the closest current distance between perforated segments of the wells that have already been drilled. |
Response: We acknowledge the Staff’s comment and advise the Staff that, after further consideration, we have determined that the drilling restriction will be 600 feet, instead of the 660 feet provided in Amendment No. 1, and we have made corresponding revisions in Amendment No. 2. Please see pages 4, 47 and 66.
Chesapeake’s drilling activities in the Colony Granite Wash to date have assumed well spacing of one well per 160-acre drilling unit and four drilling units per 640-acre (one square mile) section. Due to the horizontal orientation of the wells, each drilling unit is 1,320 feet wide and 5,280 feet (one mile) long; accordingly, if each well is drilled in the middle of a unit, each well would measure 660 feet from the unit boundaries paralleling such well and 1,320 feet from the wells in the two adjacent units. We determined the 600-foot drilling restriction to enable Chesapeake to downspace and utilize well spacing of one well per 80-acre drilling unit if drainage patterns justify such well spacing in the future. We selected 600 feet rather than 660 feet to retain Chesapeake’s flexibility to select well locations that are not precisely in the middle of a drilling unit. All wells that Chesapeake has drilled in the Colony Granite Wash have generally been drilled such that the perforated sections of adjacent wells are approximately 1,320 feet apart.
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| 10. | In regards to your response to our prior comment 33, we have reviewed the Ryder Scott reserve report and it does not appear that they limited the reserves for the Granite Wash Trust to the 20 year life of the trust. Please revise your proved reserves amount for the Granite Wash Trust so it includes no reserves that would be produced after the date of the termination of the trust which is given as June 30, 2031 on page 44. |
Response: We acknowledge the Staff’s comment and advise the Staff that one half of the Trust’s royalty interests will be conveyed to the Trust as term royalty interests with a 20 year term, which term royalty interests will automatically revert to Chesapeake at the end of the term. The other half of the Trust’s royalty interests will be conveyed to the Trust as perpetual royalty interests that will be retained by the Trust and then sold following the termination date of the Trust with the proceeds being distributed to Trust unitholders. We respectfully refer the Staff to the section titled “Description of the Royalty Interests” beginning on page 76 for a detailed description of the royalty interests that will be conveyed to the Trust. Because the Trust unitholders will ultimately receive value for the remaining reserves associated with the perpetual royalty interests, we believe those reserves should not be limited to the 20 year life of the Trust in the Ryder Scott reserve report.
| 11. | From the reserve report we note that the average EUR of NGLs of the proved producing reserves is approximately 200 thousand barrels per well but the average EUR of the proved developed shut-in and proved undeveloped reserves is closer to 300 thousand barrels per well. Please reconcile this for us. |
Response: We acknowledge the Staff’s comment and advise the Staff that the average EUR of natural gas liquids of the proved producing reserves set forth in the reserve report does not take into account the natural gas liquids produced from such wells prior to July 1, 2011, which is the effective date of the reserve report. We believe that an EUR analysis of the proved producing reserves that includes the historical cumulative production rates for natural gas liquids produced from the Underlying Properties prior to July 1, 2011 would effectively eliminate the disparity referenced in the Staff’s comment.
| 12. | In regards to your response to our prior comment 41, and with a view towards disclosure, please tell us who will be responsible for the cost of water production, handling, treatment and disposal. Also tell us if you currently use artificial lift on the wells on production and, if not, if you anticipate using it in the future. If so, please tell us who will be responsible for the costs to install this equipment. In addition, if the wells require re-fracking in the future, please tell us who will be responsible for those costs. |
Response: We acknowledge the Staff’s comment and advise the Staff that the operator of the Trust wells, which we anticipate initially will be
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Chesapeake for 93% of the wells, will be responsible for all of the costs mentioned in the Staff’s comment, including costs associated with water production, handling, treatment and disposal, the installation of artificial lift equipment and any further completion activities, such as re-fracturing a well. Certain of the existing producing wells require artificial lift, and we anticipate that many of the future wells will require artificial lift. We have not re-fractured any of the producing wells and we do not anticipate re-fracturing any of the wells in the future. We have revised our disclosure accordingly. Please see pages 76 and 77.
| 13. | In regards to your response number 46, please tell us where the annual administrative expenses that the Trust will be responsible for was included in the Ryder Scott evaluation. |
Response: We acknowledge the Staff’s comment and advise the Staff that Trust administrative expenses were not considered in the report of Ryder Scott Company, L.P. Instead, such costs are reflected as a reduction in the net proceeds available to the Trust in the Pro Forma Statement of Distributable Income of the Trust appearing on page F-16.
| 14. | All proved reserves must meet the standard of reasonable certainty. Therefore, please tell us the evidence that you have that horizontal wells in the Granite Wash for the Underlying Properties will produce in excess of fifty years with some estimated to produce as long as sixty five years. |
Response: We acknowledge the Staff’s comment and advise the Staff that Chesapeake took numerous factors into account to estimate the productive life of the horizontal wells in the Colony Granite Wash for the Underlying Properties. Because the horizontal wells in the Colony Granite Wash are relatively young, having produced for, at most, six years, we examined the long-term performance of wells in various tight gas and liquids formations across the continental United States, as reported in commercially available and public sources as well as Chesapeake’s internal database. Chesapeake owns interests in approximately 45,400 producing oil and natural gas wells and Chesapeake has access to data for an additional four million wells. As a result, we have vast amounts of data regarding the production history of wells in the continental U.S.
Chesapeake’s internal database on Chesapeake-owned wells contains information for 4,096 wells across the U.S. that have produced for more than 50 years, of which 3,594 wells are still producing. Additionally, industry-wide in the state of Oklahoma, there is a total of 7,117 wells that have produced for more than 50 years, of which 5,150 wells are still producing, with some wells producing for as long as 80 years. When comparing the production history of the horizontal wells in the Colony Granite Wash to the production history of wells in Oklahoma and
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beyond, we find strong correlation in the production rates and decline trends, supporting our conclusion that it is reasonably certain that the newer Colony Granite Wash horizontal wells will continue to exhibit production decline trends similar to those indicated by the older wells.
Chesapeake’s reserves are estimated using decline curve analysis and the resulting economic life of the royalty trust wells is cross checked and validated by several engineering standards. The estimated ultimate recovery of each well is substantiated by volumetric calculations of original hydrocarbons in place. Those original in-place calculations are supported by numerous open hole logs and several cores collected and analyzed by Chesapeake. Additionally, several reservoir fluids studies have been conducted (PVT analysis – Pressure, Volume, Temperature) to gain a better understanding of the reservoir drive mechanisms and the potential long-term performance of the wells. In addition to the volumetric calculations, Chesapeake has conducted several rate transient studies of the wells using commercially available software and matching the production and pressures seen to date. These “analytical” models also validate the projected reserve life. Lastly, Chesapeake has conducted reservoir simulation studies using software capable of accounting for all the physics and fluid properties. These detailed reservoir compositional models also show hyperbolic production profiles with long-life reserves at low decline rates.
In reaching our conclusion regarding the estimated productive life of the horizontal wells in the Colony Granite Wash, we also considered the fact that the mechanical integrity of well completions has greatly improved since the periods in which many of the longest producing wells referenced above were drilled. Lateral well bores, such as those drilled horizontally by Chesapeake in the Colony Granite Wash on the Underlying Properties, are now cased with new high grade pipe, and are designed with a vertical orientation to minimize liquid loading. The laterals are monitored regularly and treated when necessary to prevent chemical corrosion. We believe Chesapeake’s completion designs and operating methods will likely allow these new horizontal wells in the Colony Granite Wash to produce at least as long, if not longer, than the older vertical wells we reference above.
In sum, our access to and analysis of large amounts of data regarding the production history of wells in the continental U.S. allows us to predict with reasonable certainty that the estimated productive life of the horizontal wells in the Colony Granite Wash on the Underlying Properties will be in excess of 50 years, with some estimated to produce as long as 65 years.
Should any member of the Staff have a question regarding our responses to the comments set forth above, or need additional information, please do not hesitate to call Michael A. Johnson at (405) 935-9229, Michael J. Ulrich at (512) 236-6599, Jennifer M. Grigsby at (405) 835-9225 or our outside counsel Michael S. Telle at (713) 221-1327 at Bracewell & Giuliani LLP.
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As you requested in the comment letter, we acknowledge that:
| • | we are responsible for the adequacy and accuracy of the disclosure in the filing; |
| • | 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; and |
| • | 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. |
Very truly yours,
Chesapeake Granite Wash Trust
By: Chesapeake Energy Corporation | ||
| By: | ||
| Name: | Jennifer M. Grigsby | |
| Title: | Senior Vice President, Treasurer and Corporate Secretary | |
| Chesapeake Energy Corporation | ||
| By: | ||
| Name: | Jennifer M. Grigsby | |
| Title: | Senior Vice President, Treasurer and Corporate Secretary | |
