corresp

July 20, 2007

Securities and Exchange Commission
Division of Corporation Finance
100 F Street, N.E., Mail Stop 7010
Washington, D.C. 20549

Attention: Jill S. Davis, Branch Chief


Re:		Denbury Resources Inc. Form 10-K for Fiscal Year Ended December 31, 2006 Filed February 28, 2007 File No. 1-12935

Dear Ms. Davis:

On behalf of Denbury Resources Inc. (the “Company”), set forth below is the Company’s supplemental submission following our July 12^th phone conversation regarding comment 4 in your letter dated June 28, 2007, pertaining to our most recently filed Form 10-K. For your convenience, we have repeated comment 4 as set forth in the Staff’s letter (in bold text) and followed it with the Company’s supplemental submission (in normal text).

Form 10-K for the Fiscal Year Ended December 31, 2006

Critical Accounting Policies

Accounting for Tertiary Injection Costs, page 50

	4.		We note your policy that indicates you expense at the time of injection, the costs associated with the CO₂ used in your tertiary recovery operations. Please explain why you believe it is appropriate under the Full Cost Method of accounting for oil and gas activities to expense these costs at the time of injection. It appears from your disclosures elsewhere in your document that such injections have led you to recognize proved tertiary reserves. Please refer to Rule 4-10(c) of Regulation S-X and contact us at your earliest convenience.

			Response: As discussed with you during our phone conversation on July 12, 2007, and as explained in more detail in our disclosures contained in our 2006 Form 10-K, we have been active in tertiary recovery operations through the injection of CO₂ since our acquisition of Little Creek Field in 1999. Subsequent to that acquisition, we acquired several fields that either had pilots or were in the same area and same reservoir with equal or better reservoir characteristics as our existing floods, and proved reserves were booked at the time we committed to initiate CO₂ injection. During 2006, we initiated floods in two fields that based on SEC reserve definitions

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			required a response before we could book proved reserves, even though we believed these formations had a very similar risk profile to our existing floods. In fact, we were so confident of the production response that we did not conduct a pilot project in these fields prior to installing the field-wide equipment and facilities. Based on our Company’s experience and general study of CO₂ floods, in reservoirs amenable to CO₂ flooding we are not aware of any situations in which a CO₂ flood was unsuccessful in recovering additional reserves. In summary, tertiary recovery operations are the primary focus for our Company and we utilize the injection of CO₂ to increase the production from fields that are late in their primary or secondary productive stage, and therefore we believe the cost of CO₂ used in these operations fit the definition of “production cost” as more fully discussed below.

			The process of using CO₂ in enhanced recovery operations is much different than typical oil and gas exploration and development, in which you identify potential reserves through geological and geophysical efforts, drill wells to verify the reserves exist and then initiate production activities to extract the reserves from the reservoir. The primary difference is that we already know that reserves exist in the reservoir that have been produced through primary and or secondary recovery efforts. In a typical oil reservoir, it would be reasonable to expect that on average primary production activities could recover 25 to 30 percent of the original oil in place. This means that roughly 70 to 75 percent of the identified oil remains in the reservoir and enhanced recovery methods, such as CO₂ injection, can be utilized to produce additional quantities of oil. We believe that it would be reasonable to expect that enhanced recovery efforts (including both secondary and tertiary recovery) could double the percent of reserves produced from a reservoir. This process is not without risk, but the risk is not whether the reserves exist, but what percentage of the reserves can be produced.

			The process of injecting CO₂ into a reservoir is widely accepted as one of the most efficient tertiary recovery methods for crude oil. When CO₂ is injected into a formation it acts somewhat like a solvent for the oil, removing the oil from the formations by reducing surface tension of the oil binding it to the rock as the CO₂ passes through the rock. In order to have production response to the CO₂, the reservoir must be pressured up with the CO₂ and additional CO₂ must be continuously injected over the life of the field. As the oil and CO₂ are produced, we separate the CO₂ from the oil and re-inject it into the reservoir. However, this reprocessing alone is not sufficient to maintain the reservoir pressure required to sustain production, therefore new CO₂ is required to be continuously injected into the reservoir to offset the decrease in reservoir pressure from the produced oil. The injection of new CO₂ is at higher levels in the earlier years of the flood and decreases over time, similar to the oil production response, which generally increases significantly in the early phases of the flood and then declines over the life of the field. We generally estimate that it will take from six to nine months to see response to the CO₂ injections, depending on several factors, including geological characteristics of the reservoir, pressure of the reservoir at the time of injection, the area encompassed by the flood pattern, rates of injection and number of injection wells, to name a few.

			As you noted in your comment, our policy is to expense all costs associated with the injection of CO₂, regardless of the timing of those injection costs relative to the life cycle of the flood or the booking of proved reserves. We also expense all costs to separate the CO₂ from the produced oil and re-inject the CO₂. We believe our accounting for this cost is appropriate under the Full Cost Method of accounting for the following reasons:

			First, we believe that our cost for CO₂ injection falls most appropriately under “Production Costs” as discussed under Rule 4-10(c)(5) of Regulation S-X, which refers to costs incurred to maintain

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			or increase levels of production from an existing completion interval. We believe that this particularly applies to tertiary activity, as all of our floods are in reservoirs that have previously produced significant amounts of oil and are in the later stages of primary or secondary production, and this injection of CO₂ maintains and increases the production from the reservoir, which is very similar to the concept of a water flood. Further, under the definitions of Rule 4-10(a)(17)(c), “production costs” include materials, supplies, and fuel consumed and supplies utilized in operating the wells and related facilities. In order to get tertiary production, we must inject CO₂ to pressure up the reservoir to achieve response, and then we must continue to inject CO₂ over the life of the field to maintain the pressure in the reservoir, a portion of which we are confident will never be recovered. We believe that this continuous process of injecting CO₂ represents a recurring expense over the life of the field rather than a one-time expenditure that you would normally associate with a capital cost. Similarly, we treat as an operating expense the significant costs for power and fuel that we expend in order to recycle the CO₂ that is produced with the oil.

			Since we own the source field for the CO₂, the cost of our CO₂ is essentially the cost to produce and transport the CO₂ to our injection fields and the payment to the royalty owners for their portion of the CO₂. During 2006, these costs averaged $.19 per Mcf. The cost to recycle the CO₂ is estimated to be more than our cost to inject new CO₂.

			Second, when considering costs to be capitalized under Rule 4-10 of Regulation S-X, we note that “development costs” include costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. Rule 4-10 of Regulation S-X also lists costs to provide improved recovery systems as development costs. As such, we capitalize the well conversion work, facility costs and infrastructure required to install the improved recovery system and we deplete these costs in our full cost pool once the reserves are recorded. We believe these costs appropriately reflect costs that have the characteristic of a “one-time” capital expenditure. We believe “systems” represent the actual facilities necessary to conduct improved recovery operations and do not speak to the actual injected material used in the improved recovery process for which we believe there are alternative treatments as discussed below.

			Third, we have considered the guidance in Petroleum Accounting Principles, Procedures & Issues, 5^th Edition, which we believe to be one of the primary sources of accounting guidance for the oil and gas industry. The guidance on pages 365 – 366 under caption “GAS ACQUIRED FROM OTHER SOURCES (EXTRANEOUS GAS)” discusses gas and products injected in a secondary and tertiary recovery system. The literature discusses three general ways to account for the cost of injected gas and products as follows:

	•		“Expense as incurred,

	•		Capitalize as cost of wells and development, or

	•		Capitalize as a deferred charge to be credited as the injected gas is reproduced.”

The literature goes on to say, “If the injectant costs are recurring over the property’s productive life and are not recoverable, they may simply be expensed as incurred. Reproduction and sale would be recorded as current revenue (or perhaps as a reduction of production expense).” .... “Still other companies may treat the cost of reinjected gas or products as a deferred charge (without amortization) until the material is recovered. The deferred charge account represents, in effect, an inventory account. It appears to be generally agreed that if gas or product purchases are to be treated as deferred charges, the amount recorded as an asset should represent only the

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			recoverable value of the gas or products, and the difference between the purchase price and amount recoverable should be charged to pressure maintenance expense of the injected reservoir at the time of injection.” Although our engineering estimates indicate that we may recover and extract up to 50% of the CO₂ remaining in a reservoir at the end of the flood (which may continue for 20 to 30 years or longer), we estimate the cost to produce it and transport it to another field is likely to exceed the cost of the original CO₂. Also, there may be other sources of CO₂ in the future that we could utilize, such as anthropogenic sources that may be more advantageous for us to use. Further, because the recycled CO₂ has too many impurities, we cannot sell it as commercial CO₂. For these reasons, we believe the market value for any future resale of the CO₂ is too uncertain at this point in time to record as inventory.

			Additionally, pages 778-779, under the caption “ACCOUNTING PROBLEMS RELATED TO ENHANCED RECOVERY” state that “Costs incurred to install enhanced recovery facilities, including the cost to drill injection wells, are properly capitalized as wells and related equipment and facilities and are amortized as the related reserves are produced.” In relation to materials injected into the reservoir, it revisits the three methods discussed above and concludes by saying that “another approach is to treat the cost of the recoverable material in the same way as that of the non-recoverable material.”

			We find it interesting to note that none of the discussions regarding the different accounting treatments for materials injected into the reservoir considered the booking of proved reserves as a determining factor in the treatment of costs, nor do we believe that the booking of reserves should be a determining factor. Instead, the discussion included on page 778 considers the booking of proved reserves as a separate accounting issue. We believe that the only plausible category for capitalizing these costs, if they were to be capitalized, would be to consider them development costs based on the Regulation S-X definitions. The definition of development costs presumes the existence of proved reserves, so it would seem inconsistent with the definition of development costs to monitor the timing of booking proved reserves and change the accounting treatment of “development costs” because of that timing.

			We believe that Regulation S-X and the above quoted accounting literature support the fact that there are different treatments that may be applied to the recording of injected CO₂, depending on a company’s particular circumstances and philosophies. While perhaps we could have been more aggressive on the cost side of our accounting and capitalized these costs, in summary, we believe that our CO₂ injection costs are more appropriately accounted for as a production cost because:

	(i)		these are “costs incurred to maintain or increase levels of production” as stated in the description of production costs under Rule 4-10 of Regulation S-X;

	(ii)		these costs are recurring over the life of the field, which aligns them more closely with a period expense than with one-time upfront capital costs;

	(iii)		we believe these costs are separate from the costs to construct facilities and infrastructure for an improved recovery system, and therefore we do not capitalize these costs as development costs; and

	(iv)		there is substantial doubt as to whether or not this CO₂ will ever be recovered, and whether there will be any market value for this CO₂, coupled with the likelihood that it will cost us more to recover this CO₂ than what it costs initially,

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			all further leading us to conclude that our CO₂ injection costs should be an expense and not an asset.

			Although we acknowledge that there are other acceptable approaches for treating this cost as noted in our discussion above, we believe that our accounting treatment is appropriate and conservative and our disclosures in our business and properties discussion, in our Management’s Discussion and Analysis of Financial Condition and Results of Operations and in our Notes to the Consolidated Financial Statements contained in our Form 10-K clearly discuss our treatment of tertiary injection costs. Based on our disclosures, there is no confusion as to our accounting treatment for the costs that we are incurring. Further, our disclosures in our Form 10-K discuss in detail the recognition of proved reserves associated with tertiary activities, the impact that these type of costs have on our financial statements, both currently and forward looking, and our current and planned activities regarding our tertiary operations.

*******

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 Allen
Mark Allen
Vice President and Chief Accounting Officer

cc: Mr. Kevin Stertzel