August 6, 2012
Securities and Exchange Commission
Division of Corporation Finance
Mail Stop 7010
100 F Street, N.E.
Washington, D.C. 20549
Attention: Mr. Brad Skinner, Senior Assistant Chief Accountant
Form 10-K for Fiscal Year Ended December 31, 2011
Filed February 28, 2012
Denbury Response Letter dated June 20, 2012
File No. 1-12935
Dear Mr. Skinner:
On behalf of Denbury Resources Inc. (the “Company” or “we”), set forth below are the Company’s responses to the comments of the Staff of the Securities and Exchange Commission regarding the above referenced filing as set forth in the Staff’s letter dated July 12, 2012. For the Staff’s convenience, we have repeated each of the comments set forth in the Staff’s letter (in bold text) and followed each comment with the Company’s response (in normal text).
Form 10-K for the Fiscal Year Ended December 31, 2011
Business and Properties - Oil and Natural Gas Operations, page 5
Rocky Mountain Region, page 13
Future Rocky Mountain Tertiary Properties without Proved Tertiary Reserves …, page 14
Grieve Field
1. | We note your response to prior comment one. Please confirm that you will provide all related disclosures required by Item 1202 of Regulation S-K and include the proposed disclosure in your response. |
Response:
The Company does not currently intend to disclose probable reserves in future periodic filings with the Commission. However, if we choose to disclose probable reserves in future filings, we confirm that we will include all related disclosures required by Item 1202 of Regulation S-K. For example, the disclosure in our Form 10-K for the year ended December 31, 2011 regarding Grieve Field probable reserves would have been modified to include the following:
“We estimate that the Grieve Field CO2 EOR project has probable reserves consisting of approximately 12 MMBbls of gross oil, or 6.1 MMBbls net to our revenue interest. The estimate of probable reserves at Grieve Field is based on current data available, is more speculative than estimates of proved reserves and is subject to greater uncertainties. Accordingly the likelihood of recovering these reserves is subject to substantially greater risk. The Company intends to recover the probable reserves with the implementation of a tertiary flood; therefore, uncertainties surrounding recovery of the reserves include the field’s response to CO2 injection in the tertiary flood, the associated recovery factors, and field development timing.”
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Estimated Net Quantities of Proved Oil and Natural Gas Reserves, page 21 – prior comment three
2. | Please reconcile the 26.4 MMBOE proved undeveloped reserves converted, and the $160 million of PUD development costs incurred in 2011, as disclosed on page 21, to the 34.6 MMBOE proved undeveloped reserves converted, and $516 million of development costs incurred in 2011, included in your response. Similarly, reconcile total estimated future PUD development costs at the beginning of the year for 2011 and 2010 per your response to the corresponding amounts appearing in the presentation of your Standardized Measure for 2010 and 2009 in the notes to your financial statements. |
Response:
The 34.6 million barrels of oil equivalent (“MMBOE”) of proved undeveloped reserves (“PUDs”) reported as converted to proved developed reserves during 2011 in our June 20, 2012 response to the Staff's June 6, 2012 comment number three reflects all PUD reserves which were in fact converted during the year. The difference of 8.2 MMBOE was an inadvertent exclusion in the prior disclosure that represents 4.1% of year-end 2011 PUDs and 1.8% of total proved reserves at December 31, 2011, which amounts we have concluded were not material to disclosures contained in our annual report on Form 10-K for the year ended December 31, 2011.
Costs incurred on PUDs generally include (1) direct costs such as well-work costs which are spent to drill new producing wells, and (2) indirect costs such as facility and field-level costs which include compressors, recycling facilities, injection wells, injection flow lines, and other costs required to deliver and process CO2 for our tertiary floods. Within a tertiary field, PUD reserves are often converted at different points in time primarily based on the timing of completion of well work, which completion of well work generally does not correlate with the date of completion of facilities. In its narrative description of investments and progress made during the year to convert PUD reserves to proved developed reserves, the Company disclosed the direct costs to convert PUDs which were incurred on wells that had PUD reserves at December 31, 2010 and which were classified as proved developed reserves at December 31, 2011.
We interpreted the Commission’s original June 6, 2012 comment letter as a request for additional supplemental information regarding actual development costs incurred during 2011 to include all costs spent on PUDs during the year, which encompasses a broader range of costs than those costs we disclosed in our Form 10-K to convert PUDs, including the following additional costs:
· | Development costs incurred on reserves which were not classified as PUDs in our December 31, 2010 reserve report, but were converted to PUDs during 2011, as well as development costs incurred during 2011 on PUDs which were not converted to proved developed reserves by year-end 2011. Approximately one-third of the $516 million total development costs incurred on PUDs in 2011 was spent either on PUDs that were not converted during 2011 and/or PUDs that did not exist as such at year-end 2010 and thus were not included in our December 31, 2010 reserve report. |
· | Facility and field-level costs described above, which made up approximately one-third of the $516 million development costs incurred on PUDs in 2011. |
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In response to the second sentence of the Staff's July 12, 2012 comment two above, the table below reconciles the difference between total estimated future PUD development costs at the beginning of the year for 2010 and 2011 presented in our June 20, 2012 response to the Staff to the corresponding amounts appearing in the presentation of the Standardized Measure in the notes to our financial statements. As you can see, the difference is comprised of future asset retirement costs associated with plugging and abandoning wells and facilities, and additional capital investment on proved developed producing and proved developed non-producing reserves. These latter capital investments primarily consisted of purchases of equipment, upgrading of tubulars, packers and other components of a wellbore in preparation for a CO2 flood, which components are upgraded to utilize materials that can better withstand higher levels of corrosion associated with CO2 injection, and minor costs incurred on tertiary proved developed non-producing well recompletions of existing wellbores to obtain access to other non-producing reservoirs.
The following table sets forth the reconciliation of estimated future development costs in our reserve reports for the years indicated:
December 31, | ||||||||
In millions | 2010 | 2009 | ||||||
Future development costs on proved developed producing reserves | $ | 63 | $ | 62 | ||||
Future development costs on proved developed non-producing reserves | 108 | 58 | ||||||
Future development costs on proved undeveloped reserves | 1,651 | 647 | ||||||
Future asset retirement costs | 90 | 69 | ||||||
Total future development costs of all categories of proved reserves as reported in our most recent 10-K Standardized Measure disclosure | $ | 1,912 | $ | 836 |
In connection with the foregoing responses, the undersigned, on behalf of the Company, acknowledges that:
· | The Company is responsible for the adequacy and accuracy of the disclosure in the filing; |
· | Staff comments or changes to disclosures in response to Staff comments do not foreclose the Commission from taking any action with respect to the filing; and |
· | The Company may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States. |
Thank you for your time and consideration of this matter. If you have any questions or concerns about this response, please contact the undersigned at 972-673-2007, or by fax at 972-673-2150.
Sincerely,
/s/ Mark C. Allen
Mark C. Allen
Sr. Vice President and Chief Financial Officer
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