Denbury Resources Inc (DNR) SEC Annual Report (10-K) for 2011

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

2011 FORM 10-K

(Mark One)

☑   Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2011

OR

¨   Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from _________ to________

Commission file number   1-12935

DENBURY RESOURCES INC.

(Exact name of Registrant as specified in its charter)

Securities registered pursuant to Section 12(b) of the Act:

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes ☑  No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨  No ☑

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes ☑    No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☑     No¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a small reporting company.  See definition of "large accelerated filer", "accelerated filer", and "small reporting company" in Rule 12-b2 of the Exchange Act.

Large accelerated filer ☑    Accelerated filer ¨    Non-accelerated filer ¨   Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2).  Yes ¨   No ☑

The aggregate market value of the registrant's common stock held by non-affiliates, based on the closing price of the registrant's common stock as of the last business day of the registrant's most recently completed second fiscal quarter was $6,990,650,460.

The number of shares outstanding of the registrant's Common Stock as of January 31, 2012, was 390,282,768.

DOCUMENTS INCORPORATED BY REFERENCE

* This definition is an abbreviated version of the complete definition as defined by the SEC in Rule 4-10(a) of Regulation S-X. For the complete definition see http://ecfr.gpoaccess.gov/cgi/t/text/text-idx?c=ecfr&rgn=div5&view=text&node=17:2.0.1.1.8&idno=17#17:2.0.1.1.8.0.21.42 .

PART I

Item 1. Business and Properties

GENERAL

Denbury Resources Inc., a Delaware corporation, is a domestic independent oil and natural gas company with 461.9 million BOE of proved oil and natural gas reserves as of December 31, 2011, of which 77% is oil.  We are the largest combined oil and natural gas producer in Mississippi and Montana, own the largest reserves of CO 2 used for tertiary oil recovery east of the Mississippi River, and hold significant operating acreage in the Rocky Mountain and Gulf Coast regions.  Our goal is to increase the value of acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with our most significant emphasis relating to tertiary recovery operations.

As part of our corporate strategy, we believe in the following fundamental principles:

Denbury became a Canadian public company in 1992 through a reverse merger with a Canadian company that was originally incorporated in Canada in 1951.  In 1999, we moved our corporate domicile from Canada to the United States as a Delaware corporation and have been publicly traded in the United States since 1995 and on the New York Stock Exchange since May 1997.

Our corporate headquarters is located at 5320 Legacy Drive, Plano, Texas 75024, and our phone number is 972-673-2000. At December 31, 2011, we had 1,308 employees, 730 of whom were employed in field operations or at the field offices.  We make our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports, filed or furnished pursuant to section 13(a) or 15(d) of the Securities Exchange Act of 1934, available free of charge on or through our Internet website, www.denbury.com, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.  The SEC also maintains a website, www.sec.gov , which contains reports, proxy and information statements and other information filed by Denbury.  Throughout this Form 10-K we use the terms "Denbury," "Company," "we," "our," and "us" to refer to Denbury Resources Inc. and, as the context may require, its subsidiaries.

2010 ENCORE ACQUISITION AND RELATED DISPOSITIONS

OIL AND NATURAL GAS OPERATIONS

Enhanced Oil Recovery Overview. CO 2 used in EOR is one of the most efficient tertiary recovery mechanisms for producing crude oil.  The CO 2 acts somewhat like a solvent, mixing with the oil and ultimately freeing the oil from the formation as the CO 2 passes through reservoir rock.  CO 2 tertiary floods are unique in that they require large volumes of CO 2 .  To our knowledge, the location of large quantities of natural CO 2 in the United States is limited to a few geological basins.

While enhanced oil recovery projects utilizing CO 2 may not be considered a new technology, we apply several concepts we have learned over the years to fields to improve and increase sweep efficiency within the reservoirs, which include: (1) well evaluation methods, (2) CO 2 injection conformance, (3) new completion techniques, (4) varied operating equipment and operating conditions, and (5) application of intense reservoir management and production techniques.  We began our CO 2 operations in August 1999, when we acquired Little Creek Field, followed by our acquisition of Jackson Dome CO 2 reserves and the NEJD pipeline in 2001.  Based upon our success at Little Creek and the ownership of the CO 2 reserves, we began to transition our capital spending and acquisition efforts to focus a greater percentage on CO 2 EOR and, over time, transformed our strategy to focus almost exclusively on CO 2 EOR projects (with the exception of the Bakken properties since 2010).  Today, our asset base essentially consists of tertiary oil projects, future tertiary oil projects and the Bakken oil shale play.  We believe our investments and knowledge gained give us a strategic and competitive advantage in the areas in which we operate.

Our tertiary operations have grown so that approximately 32% of our proved reserves at December 31, 2011 are proved tertiary oil reserves; approximately 47% of our forecasted 2012 production is expected to come from tertiary oil operations (on a BOE basis); and approximately 62% of our 2012 planned capital expenditures are related to our tertiary oil operations.  At year-end 2011, the proved oil reserves in our tertiary recovery oil fields had an estimated PV-10 Value of approximately $5.7 billion, using 12-month first-day-of-the-month unweighted average NYMEX pricing of $96.19 per Bbl.  In addition, there are significant probable and possible reserves at several other fields for which tertiary operations are under way or planned.  Although the up-front cost of infrastructure is greater than in conventional oil recovery, we believe tertiary recovery has several favorable, offsetting and unique attributes including: (1) it has a lower risk, as we are operating oil fields that have significant historical production and reservoir and geological data, (2) our investments provide a reasonable rate of return at relatively low oil prices (we estimate our economic break-even point on a per-barrel basis before corporate-related overhead and expenses on these projects at current oil prices is in the $40 per barrel range, depending on the specific field and area), and (3) we have limited competition for this type of activity in our geographic regions.

Our Gulf Coast region is more fully developed than our Rocky Mountain region, as we have been expanding and conducting EOR operations in our Gulf Coast region for over 12 years.  In the Gulf Coast region, we own the only significant natural sources of CO 2 known to us, and these large volumes of CO 2 have allowed us to significantly grow our production in that region. In addition to the sources of CO 2 we currently have, we are pursuing anthropogenic (man-made) sources of CO 2 to use in our tertiary operations, which we believe will not only help us recover additional oil, but will provide an economical way to sequester CO 2 .  We refer to our Gulf Coast tertiary recovery operations by labeling our operating areas or groups of fields as Phases:

Through December 31, 2011, we have invested a total of $2.7 billion in tertiary fields in our Gulf Coast region (including allocated acquisition costs and amounts assigned to goodwill) and have recovered all of these costs, with excess net cash flow (revenue less operating expenses and capital expenditures, excluding pipeline-related capital expenditures) of $428 million.  Of this total invested amount, approximately $639.9 million (24%) was spent on fields that did not have appreciable proved reserves at December 31, 2011.  The proved oil reserves in our Gulf Coast tertiary oil fields have a year-end 2011 PV-10 Value of $5.7 billion, using the first-day-of-the-month 12-month unweighted average NYMEX pricing during calendar 2011 of $96.19 per Bbl.  These amounts do not include the capital costs or related depreciation and amortization of our CO 2 -producing properties or CO 2 pipelines, but do include CO 2 source field lease operating costs and transportation costs.  Excluding the Green Pipeline, which currently does not service any fields with proved tertiary oil reserves, we have invested a total of $892.2 million in CO 2 assets in the Gulf Coast region.

We acquired assets in the Rocky Mountain region as part of the Encore Merger, and as such, we have significantly fewer oil fields and CO 2 pipeline infrastructure in that region, although we are aggressively developing both.  We currently have three fields in the Rocky Mountain region that we plan to flood with CO 2 : Bell Creek Field, Grieve Field and Cedar Creek Anticline.  We have contracted to purchase CO 2 from the Lost Cabin gas plant in central Wyoming and are currently constructing the Greencore pipeline to deliver CO 2 from the gas plant to our Bell Creek Field.  We currently plan to begin injection of CO 2 at Bell Creek Field in late 2012 or early 2013.  Our Riley Ridge acquisition in 2010 and 2011 also provided us a large source of natural CO 2 for our currently planned and future potential projects in the area.

Gulf Coast Region

CO 2 Sources

Jackson Dome. Our Gulf Coast CO 2 source, Jackson Dome, located near Jackson, Mississippi, was discovered during the 1970s while being explored for hydrocarbons.  This significant and relatively pure source of CO 2 (98% CO 2 ) is the only significant deposit of CO 2 in the United States east of the Mississippi River known to us, and we believe that it provides us a significant strategic advantage in the acquisition of other properties in Mississippi, Louisiana and Texas that could be further exploited through tertiary recovery.

We acquired Jackson Dome in February 2001 for $42 million, a purchase that gave us ownership and control of the NEJD CO 2 pipeline.  This acquisition provided the platform to significantly expand our CO 2 tertiary recovery operations by assuring that CO 2 would be available to us on a reliable basis and at a reasonable and predictable cost.  Since February 2001, we have acquired two and drilled 26 CO 2 -producing wells, significantly increasing our estimated proved Gulf Coast CO 2 reserves from approximately 800 Bcf at the time of acquisition to approximately 6.7 Tcf as of December 31, 2011.  These proved reserves are nearly sufficient to provide all of the CO 2 for our existing and currently planned phases of operations in the Gulf Coast, including several fields we own and plan to flood that do not have proven tertiary reserves.  The CO 2 reserve estimates are based on a gross working interest of the CO 2 reserves, of which Denbury's net revenue interest is approximately 5.3 Tcf and is included in the evaluation of proved CO 2 reserves prepared by our outside reserve engineer, DeGolyer and MacNaughton.  In discussing our available CO 2 reserves, we make reference to the gross amount of proved and probable reserves, as this is the amount that is available both for Denbury's tertiary recovery programs and for industrial users who are customers of Denbury and others, as Denbury is responsible for distributing the entire CO 2 production stream.

In addition to the proved reserves, we estimate that we have an additional 2.5 Tcf of probable CO 2 reserves at Jackson Dome.  The majority of our probable reserves at Jackson Dome are located in structures that have been drilled and tested in the area but are not currently capable of producing because the original well is plugged; they are located in fault blocks that are immediately adjacent to fault blocks with proved reserves; they are in undrilled structures where we have sufficient subsurface data, and seismic and geophysical attributes that provide a high degree of certainty that CO 2 is present; or they are reserves associated with increasing the ultimate recovery factor from our existing reservoirs with proved reserves.  As of December 31, 2011, there have been 13 structures drilled within the Jackson Dome area and only one has not been productive.  This success rate, coupled with our seismic control across the undrilled structures, provides us with a high degree of certainty that additional CO 2 reserves will be developed.

Although our current proved and potential CO 2 reserves are quite large, in order to continue our tertiary development of oil fields in the Gulf Coast region, incremental deliverability of CO 2 is required.  In order to obtain additional CO 2 deliverability, we have continued our efforts by evaluating our 451 square miles of 3D seismic that we have recorded over the past several years.  We anticipate drilling four wells during 2012, three of which are planned development wells and are intended to increase productive capacity, and one of which is an exploratory step-out well that is targeting additional reserves as well as increased flow rate.  During 2011, we drilled three CO 2 wells and started the drilling of an exploration CO 2 well on a new structure identified by our seismic program.  Two wells were drilled at Gluckstadt Field and one well at the DRI Dock Field.  The well at DRI Dock field was determined to be non-commercial and was not completed.  In February 2012, we completed the drilling of the exploration well and determined that it was not successful.  In addition to our drilling at Jackson Dome, we continue to expand our processing and dehydration capacities, and we continue to install pipelines and/or pumping stations necessary to transport the CO 2 through our controlled pipeline network.

In addition to using CO 2 for our Gulf Coast tertiary operations, we sell CO 2 to third-party industrial users under long-term contracts and have three CO 2 volumetric production payment contracts ("VPPs").  Approximately 91% of our average daily CO 2 production in 2011, 87% in 2010 and 87% in 2009 was used in our tertiary recovery operations on our own behalf and on behalf of other working interest owners in our enhanced recovery fields, with the balance delivered to third-party industrial users.  During 2011, we sold an average of 89 MMcf/d of CO 2 to commercial users, and we used an average of 920 MMcf/d for our tertiary activities.  We are continuing to increase our CO 2 production, which averaged 1,024 MMcf/d during the fourth quarter of 2011, a 5% increase over the fourth quarter of 2010 CO 2 production levels.  We estimate that our planned 2012 tertiary operations will require additional CO 2 deliverability, and we currently plan to increase volumes through new drilling in the Gluckstadt Field, along with the addition or modification of certain facilities and pipelines required to deliver the CO 2 to the appropriate oil fields.

Gulf Coast Anthropogenic CO 2 Sources.   In addition to our natural source of CO 2 , we have entered into long-term contracts to purchase man-made CO 2 from six proposed plants or sources in the Gulf Coast region that will emit large volumes of CO 2 .  Two of these six projects are currently under construction with estimated completion dates in 2013 and 2014. We estimate these two sources will supply approximately 165 MMcf/d of CO 2 to our EOR operations, although under certain circumstances they could provide up to 270 MMcf/d of CO 2 .  If the remaining four plants were to also be built, we currently estimate these additional CO 2 sources could potentially provide us with aggregate CO 2 volumes of approximately 640 MMcf/d to 1,350 MMcf/d.  Construction of the remaining four plants is contingent on the satisfactory resolution of various matters, including financing.  While it is not likely that all four of these plants will be constructed, there are other plants currently being planned that could provide us additional anthropogenic CO 2 .  We are in ongoing discussions with several of these other potential sources.

In addition to the potential anthropogenic CO 2 sources located in the Gulf Coast, we have entered into long-term contracts to purchase man-made CO 2 from four proposed plants in the Midwest (Illinois, Indiana and Kentucky).  Any CO 2 obtained as a result of these projects would most likely be transported to and utilized by our tertiary oil fields in the Gulf Coast region.  Construction has not yet commenced on these four projects, which is conditioned, in each case, on Denbury's ability to justify the construction of the proposed Midwest CO 2 pipeline system.  Additionally, at December 31, 2011, two of the proposed Midwest facilities have been unable to meet a critical contractual obligation; thus, we are evaluating these projects to determine if we should extend the time for the facility to meet the contractual obligation.  The remaining two proposed plants are actively working to secure the necessary permits and financing to allow them to commence construction.  In one potential scenario, we are considering combining the CO 2 pipeline and plant in a joint venture, which would allow us to seek financing on a combined basis, and may include potential loan guarantees from the Department of Energy.  This would give us a minority interest in the total project and potentially reduce our required out-of-pocket capital expenditures.  See Off-Balance Sheet Agreements – Commitments and Obligations in Management's Discussion and Analysis of Financial Condition and Results of Operations for a discussion of CO 2 purchase commitments.

In addition to potential CO 2 sources discussed above, we continue to have ongoing discussions with owners of existing plants of various types that emit CO 2 that we may be able to purchase. In order to capture such volumes, we (or the plant owner) would need to install additional equipment, which includes, at a minimum, compression and dehydration facilities.  Most of these existing plants emit relatively small volumes of CO 2 , generally less than the proposed gasification plants, but such volumes may still be attractive if the source is located near our CO 2 pipelines.  The capture of CO 2 could also be influenced by potential federal legislation, which could impose economic penalties for the emission of CO 2 .  We believe that we are a likely purchaser of CO 2 produced in our areas of operation because of the scale of our tertiary operations, our CO 2 pipeline infrastructure and our large natural sources of CO 2 , which can act as a swing CO 2 source to balance CO 2 supply and demand.

Gulf Coast CO 2 Pipelines . We acquired the 183-mile NEJD CO 2 pipeline that runs from Jackson Dome to near Donaldsonville, Louisiana, as part of the 2001 acquisition of our Jackson Dome source.  Since 2001 we have constructed an additional 685 miles of CO 2 pipelines that give us the ability to deliver CO 2 to our fields throughout the Gulf Coast.  As of December 31, 2011, we either own, or control through long-term financing leases, approximately 864 miles of CO 2 pipelines in the Gulf Coast region. In addition to the NEJD CO 2 pipeline, the major pipelines are the Free State Pipeline (90 miles), the Delta Pipeline (110 miles) and the Green Pipeline (325 miles).

Gulf Coast Tertiary Properties

Phase 1. Phase 1 includes several fields along our NEJD CO 2 pipeline, which runs through southwest Mississippi and into Louisiana.  This phase includes some of our most mature CO 2 floods, including our initial CO 2 field, Little Creek, as well as five other areas (Mallalieu, McComb, Smithdale, Brookhaven and Lockhart Crossing).  These fields accounted for approximately 35% of our total 2011 CO 2 EOR production.  These fields have been producing for some time, and their production is generally on decline.

Since Phase 1 is our most mature phase, most of the development work is complete in this area; however, there are some additional areas at McComb, Brookhaven and Little Creek that we currently plan to develop, the timing of which is largely dictated by the current CO 2 recycle facility at each field.  As these fields have matured, we have experimented with a variety of techniques to maximize the recovery of oil from these reservoirs, gathering knowledge that we will utilize in all areas of our EOR operations.  All of the techniques we are employing are intended to improve the overall sweep efficiency in the formation and hence maximize production.  Due to the lower viscosity of CO 2 when compared to oil, CO 2 will tend to follow the path of least resistance.  This may result in high producing gas-oil ratios ("GORs") sooner than anticipated.  We have experimented with various techniques such as cement squeezes (injection and producing wells), chemical squeezes, perforation design and operating pressure controls.  Each one of these processes has had some success and will be utilized in the future as appropriate.  Our best results to date have been utilizing water-alternating gas ("WAG") injections, where water is substituted for the CO 2 for a given volume and then CO 2 is injected behind the water.  We have seen multiple patterns respond to the WAG cycles, and we continue to institute the WAG cycles in new patterns as the need arises.  The WAG process is currently being used to increase the recovery at fields like Little Creek, our most mature field, where we have already recovered a majority of the forecasted oil, and in fields like Brookhaven, where we have seen certain areas produce high GORs sooner than anticipated.  We intend to utilize the techniques that prove successful in Phase 1 in our other phases.

From inception through December 31, 2011, we have recovered all our costs in Phase 1 and the excess net cash flow (revenue less operating expenses and capital expenditures, including the acquisition costs) from this Phase was $1.1 billion.  As of December 31, 2011, the estimated PV-10 Value of our Phase 1 properties was $1.4 billion.

Phase 2.   Phase 2 includes Eucutta, Soso and Martinville fields, where there has been tertiary oil production for several years, and Heidelberg Field, where we started injecting CO 2 in December 2008.  Unlike the majority of fields in our other Phases, fields in Phase 2 typically contain multiple reservoirs that are amenable to CO 2 EOR.  Eucutta, Soso and Martinville fields are mostly developed in the reservoir(s) under flood at the present time.  All three fields were initiated in 2006 following completion of the Free State Pipeline.  Much like the initial Phase 1 fields, we continue to monitor and modify various patterns, operating conditions and CO 2 injections in an attempt to improve the oil recovery from these fields.  Based on the performance to date, we expect to recover at least 17% of the original oil in place at these three fields with EOR.

In 2008, we began CO 2 injections at Heidelberg Field, which consists of an East and West Unit.  Construction of the CO 2 facility, connecting pipeline and well work commenced on the West Unit during 2008, with our first CO 2 injections beginning in December 2008.  Our first tertiary oil production response occurred during May 2009.  During 2010, we added 19 new injection patterns and expanded the central processing facility.  After exceeding our anticipated production levels in 2010, production from the West Unit began to fall short of expectations in 2011.  We determined the shortfall was primarily the result of the CO 2 not reaching all the targeted zones, broadly described as "conformance issues."  In 2011, we drilled three new wells and modified the injection or production profile in 39 wells to address the conformance issues by redirecting CO 2 into previously un-swept intervals in the West Unit.  During the fourth quarter of 2011, EOR production at Heidelberg Field averaged 3,728 Bbls/d as compared to 3,422 Bbls/d in the year-ago period.  In 2011, we commenced development of our East Unit, which is larger and contains more oil-in-place than the West Unit.  During 2011, we added 9 new injection patterns and installed field facilities in the East Unit and expanded the central processing facility used by both the East and West Units.  We have budgeted $47 million in 2012 to continue developing the East Heidelberg Unit, including the addition of two injection patterns in the current development and expansion into a previously undeveloped reservoir.

Many of the fields in Phase 2 have multiple reservoirs.  We plan to develop these additional reservoirs in the future when well bores become available (the well bores are currently in use by another reservoir) or when the recycle facilities have available capacity.   From inception through December 31, 2011, we have recovered all our costs in Phase 2, and the excess net cash flow (revenue less operating expenses and capital expenditures, including the acquisition costs) from this Phase was $298 million.  As of December 31, 2011, the estimated PV-10 Value of our Phase 2 properties was $1.6 billion.

Phase 3 (Tinsley).   Phase 3, Tinsley Field, was acquired in January 2006 and is the largest oil field in the state of Mississippi and was first developed in the 1930s.  As is the case with the majority of fields in Mississippi, Tinsley produces from multiple reservoirs.  Our primary target in Tinsley for CO 2 enhanced oil recovery operations is the Woodruff formation, although there is additional potential in the Perry sandstone and other smaller reservoirs.  We initiated limited CO 2 injections in January 2007 through a previously existing 8-inch pipeline, but replaced the use of the 8-inch line in 2008 with the completion of the 24-inch Delta Pipeline to Tinsley.  We had our first tertiary oil production from Tinsley Field in April 2008.  As of December 31, 2011, we have completed the development of the West Fault Block and the majority of the East Fault Block.

In 2011, we focused on developing the southern half of the East Fault Block.  As we were expanding the CO 2 flood into this area, we found that multiple wells, many dating back to the 1940s and 1950s, had been improperly plugged and abandoned by prior operators and did not have sufficient cement in them.  Without proper cement plugs in place, we were unable to confine the CO 2 injection into the specific target zones. As a result, we had to stop injecting CO 2 into several patterns in Tinsley, reduce the reservoir pressure in those patterns and work over approximately 28 wells to properly plug them.  We are completing the needed well work and are restarting injections in impacted patterns during the fourth quarter of 2011 and first quarter of 2012. Reducing the CO 2 injections lowered our previously anticipated production growth from Tinsley in 2011 and pushed back our 2012 production growth in the area to the second half of the year. These events have not changed our overall expectations of recovery for Tinsley.

In 2012, 2013 and 2014, our expected development will focus on the Northern Fault Block at Tinsley, all in the Woodruff reservoir.  The Perry sandstone and the other smaller reservoirs will likely be developed after the Woodruff.  During the fourth quarter of 2011, the average tertiary oil production was 6,338 Bbls/d as compared to 6,614 Bbls/d in the year-ago period.  Tinsley Field produced an additional 269 Bbls/d from non-CO 2 operations during the fourth quarter of 2011 compared to 291 Bbls/d in the year-ago period.

From inception through December 31, 2011, we have recovered all our costs in this field, and our tertiary operations at Tinsley Field have generated excess net cash flow (revenue less operating expenses and capital expenditures, including the acquisition costs) of $4 million.  As of December 31, 2011, the estimated PV-10 Value of our Phase 3 property was $1.4 billion.

Phase 4 (Cranfield).   Phase 4 includes Cranfield, where we began CO 2 injection operations during July 2008 and had our first oil production response in the first quarter of 2009.  Phase 4 also includes Lake St. John Field, a project currently scheduled to commence within the next several years following a proposed crossing of the Mississippi River with our CO 2 pipeline.  Both Phase 4 fields are located near the Mississippi/Louisiana border, near Natchez, Mississippi.

We began development of Cranfield during 2008, commenced injections into the Lower Tuscaloosa reservoir in the third quarter of 2008, and had our first tertiary oil production in the first quarter of 2009.  Development of Cranfield will continue over the next several years with the addition of two to three patterns each year.  During 2012, we plan to spend approximately $9 million to develop three patterns in the field.  We are participating with the Bureau of Economic Geology at the University of Texas as it studies CO 2 injection and sequestration at Cranfield, to better define and understand the movement of CO 2 through the Lower Tuscaloosa reservoir.

From inception through December 31, 2011, we had not yet recovered our investment in this field and the remaining net investment to be recovered (revenue less operating expenses and capital expenditures, including the acquisition cost) from Cranfield was $83 million.  As of December 31, 2011, the estimated PV-10 Value of our Phase 4 property was $343.1 million.

Phase 5 (Delhi). Phase 5 is Delhi Field, a Louisiana field located southwest of Tinsley Field and east of Monroe, Louisiana.  During May 2006, we purchased Delhi for $50 million, plus a 25% reversionary interest to the seller after we achieve $200 million in net operating income.  We began well and facility development in 2008 and began delivering CO 2 to the field in the fourth quarter of 2009 via the Delta Pipeline which runs from Tinsley to Delhi.  First tertiary production occurred at Delhi Field in March 2010.  Early performance data is indicating that Delhi Field is acting as a miscible flood instead of a near-miscible flood as we originally modeled, which if true and if it continues, should positively affect our results.  Production from Delhi in the fourth quarter of 2011 averaged 3,778 Bbls/d, up from 703 Bbls/d in the year-ago period.  During 2012, we plan to spend approximately $64 million to develop three patterns and to construct additional facilities at Delhi Field.

From inception through December 31, 2011, we had not yet recovered our investment in this field, and the remaining investment to be recovered (revenue less operating expenses and capital expenditures, including the acquisition cost) from Delhi Field was $199 million.  As of December 31, 2011, the estimated PV-10 Value of our Phase 5 property was $1.0 billion.

Future Gulf Coast Tertiary Properties without Proved Tertiary Reserves or Tertiary Production at December 31, 2011

Phase 6 (Citronelle).   Phase 6 is Citronelle Field in Southwest Alabama, another field acquired in 2006.  Citronelle Field will require an extension to the Free State CO 2 Pipeline or a man-made source of CO 2 in order to commence this project, the timing of which is uncertain.

Phase 7 (Hastings).   Phase 7 is Hastings Field, a strategically significant property in southeast Texas.  We acquired a majority interest in this field in February 2009 for approximately $247 million.  Under the terms of the option agreement, Venoco, Inc. ("Venoco"), the seller, retained a 2% override and reversionary interest of approximately 25% following payout, as defined in the option agreement.  During 2010 we acquired the 2% override from Venoco for approximately $22.3 million.  During the fourth quarter of 2011, non-tertiary production from Hastings Field averaged 1,094 BOE/d as compared to 1,474 BOE/d in the year-ago period.  Conventional proved reserves at Hastings Field as of December 31, 2011 were approximately 7.1 MMBOE.

We believe the West Hastings Unit has the second-largest CO 2 EOR reserve potential in our Gulf Coast inventory.  Due to the vertical oil column that exists in the field, we are developing the Frio reservoir in multiple vertically segregated CO 2 EOR projects.  Each vertical interval will have dedicated CO 2 injection wells and dedicated producing wells.  We initiated CO 2 injection in the West Hastings Unit during December 2010 upon completion of the construction of the Green Pipeline.  We began producing EOR oil from the Hastings Field in late January 2012, and we expect to book initial proved tertiary

reserves for the field by the end of 2012.  In 2012, we expect to invest $66 million to continue developing the West Hastings Unit, including the development of additional patterns and expanding the processing facilities.  Significant additional capital expenditures will be required over several years to fully develop the field.

Phase 8 (Oyster Bayou).   Phase 8, which we acquired in 2007, consists of two fields located in southeast Texas on the east side of Galveston Bay.  The Oyster Bayou and Fig Ridge Fields are located in close proximity to each other.  We acquired a majority interest in Oyster Bayou Field and a relatively small interest in Fig Ridge Field.   Oyster Bayou Field was unitized in the spring of 2010 and we began CO 2 injections there in June 2010.  Oyster Bayou Field is somewhat unique when compared to our other CO 2 EOR projects because the field covers a relatively small area of 3,912 acres and will be developed in essentially one stage.  We commenced production from Oyster Bayou Field in December 2011, with the first oil sales occurring at the end of that month.  We expect to book initial proved tertiary reserves for the field by the end of 2012.  In 2012, we expect to invest $35 million to complete several patterns and expand facilities in Oyster Bayou Field.

The other field in Phase 8 is the Fig Ridge Field.  Due to our lack of majority interest in this field, it is uncertain if, or when, we will flood Fig Ridge Field.

Phase 9 (Conroe).   Phase 9 is Conroe Field, our largest potential tertiary flood in the Gulf Coast region, located north of Houston, Texas.  We acquired a majority interest in this field in 2009 for approximately $271 million in cash and 11,620,000 shares of Denbury common stock for a total aggregate value of $439 million.  The acquired Conroe Field interests had estimated proved conventional reserves of approximately 18.4 MMBOE on December 31, 2011, nearly all of which are proved developed.  During the fourth quarter of 2011, production at Conroe Field averaged 2,587 BOE/d net to our acquired interest.  Given the size of the Conroe Field of approximately 20,000 acres, the volume of CO 2 that could be injected is quite sizable, much larger than any field we have developed to date.  Therefore, the pace of development will partly be dictated by the amount of available CO 2 .

A pipeline must be constructed so that CO 2 can be delivered to Conroe.  This pipeline, which is planned as an extension of our Green Pipeline, is preliminarily estimated to cover 85 miles at a cost of between $165 million to $190 million .  Through 2013, we will determine the pipeline path, initiate the acquisition of rights-of-way, and engineer and design the pipeline while refining and finalizing our CO 2 EOR plan for Conroe.  Construction of the pipeline is expected to occur in 2014, with start-up and commissioning by the end of that year.

Non-Tertiary Oil and Natural Gas Properties in the Gulf Coast

We have been active in East Mississippi since Denbury was founded in 1990 and are by far the largest oil producer in the basin and the state.  Conventional or non-tertiary production during the fourth quarter of 2011, excluding non-core assets to be disposed, averaged approximately 4,746 BOE/d from this area (7% of our total continuing production), and we had proved reserves of 24.3 MMBOE as of December 31, 2011 (5% of our Company total).  Since we have generally owned these East Mississippi properties longer than properties in our other regions, they tend to be more fully developed.  Production from our conventional and secondary recovery operations in our East Mississippi fields, excluding non-core assets to be disposed, has been gradually declining, as expected, over the last three years, averaging 8,343 BOE/d during 2009, 6,505 BOE/d during 2010 and 5,486 BOE/d during 2011.  During 2011, we invested very little capital in these assets.  In January 2012, we entered into an agreement to sell certain non-core properties in this area for $155 million, before customary closing adjustments, and expect to close the sale in late February 2012.

The largest field in the region is the Heidelberg Field, which for the fourth quarter of 2011 produced an average of 3,129 BOE/d of conventional or non-tertiary production.  This compares to 4,206 BOE/d in the year-ago period, with most of the decline in production occurring in the Selma Chalk.  Heidelberg Field was acquired from Chevron in December 1997.  Most of the past and current production comes from the Eutaw, Selma Chalk and Christmas sands at depths from 3,500 feet to 5,000 feet.  The majority of the conventional oil production at Heidelberg Field is from waterflood units that produce from the Eutaw formation (at approximately 4,400 feet).  We have converted all of the waterflood units in West Heidelberg to CO 2 EOR and, as described previously above, are in the process of converting the East Heidelberg waterflood units to CO 2 EOR. Heidelberg also produces natural gas from the Selma Chalk, which was a fairly active area of development for us prior to 2009.  The Selma Chalk is a natural gas reservoir at around 3,700 feet that is developed with horizontal wells and hydraulic fracturing.  The Selma Chalk is estimated to contain 71.6 Bcf of proved natural gas reserves as of December 31, 2011.  Natural gas production from the Selma Chalk was 13.4 MMcf/d during the fourth quarter of 2011, as compared to 16.3 MMcf/d in the year-ago period.  The decline in production is due to a decrease in drilling activity over the past several years, combined with a rapid decline rate in the Selma Chalk wells.

Rocky Mountain Region

CO 2 Sources

Rocky Mountain Anthropogenic CO 2 Sources.   We have ongoing discussions with and are actively pursuing several sources for anthropogenic CO 2 supply in the Rocky Mountain region.  We have contracted to purchase CO 2 from the Lost Cabin gas plant in central Wyoming and from ExxonMobil's LaBarge facility in southwest Wyoming. The Lost Cabin agreement requires us to purchase as much as 50 MMcf/d of CO 2 from the Lost Cabin plant.  The purchase requirements also include the construction of the necessary pipeline tie-ins to the gas plant, and compression and metering equipment.  In 2011, we completed most of the interconnecting and tie-in work to the gas plant required to capture the CO 2 .  Final engineering design continues; compression, pumps and metering equipment have been ordered; and we expect to complete the plant tie-ins in the first half of 2012 and then install the required compression and metering equipment in the second half of 2012. All work is scheduled to be completed by the fourth quarter of 2012 to capture, compress and deliver the CO 2 into the Greencore Pipeline.  We estimate our 2012 capital investment in the Lost Cabin gas plant infrastructure will be $50 million.  The agreement with ExxonMobil requires us to purchase 30 MMcf/d of CO 2 , with an option to purchase up to 50 MMcf/d of CO 2 from ExxonMobil's LaBarge facility.  We intend to utilize the CO 2 to flood Grieve Field and expect to begin taking deliveries during the second half of 2012.

During the first quarter of 2011, we finalized and entered into a long-term supply contract to purchase anthropogenic CO 2 from a proposed plant in southeastern Wyoming.  We estimate the proposed plant will initially supply approximately 100 MMcf/d, and potentially up to 200 MMcf/d, of CO 2 for our enhanced oil recovery operations in Wyoming and Montana.  We expect to begin taking delivery of this CO 2 in approximately four years following commencement of construction.  The purchase price of CO 2 will fluctuate based on changes in the price of oil.  As is the case with all of our long-term supply contracts to purchase CO 2 , the agreement is subject to various contingencies, and completion of the plant is contingent upon securing debt financing and equity commitments, along with receipt of all necessary consents and approvals.

Greencore Pipeline.   The 20-inch Greencore Pipeline in Wyoming is the first CO 2 pipeline constructed by Denbury in the Rocky Mountain region.  As currently planned, the pipeline will eventually connect our Lost Cabin Plant CO 2 source to the Cedar Creek Anticline in eastern Montana, and ultimately connect our CO 2 source at Riley Ridge (see Rocky Mountain CO 2 Sources above).  The initial 232-mile section of the Greencore Pipeline will begin at the Lost Cabin gas plant and terminate at our Bell Creek oil field in Montana.  This portion of the pipeline will be constructed in two phases: the first 115-mile segment was completed in December 2011, and the second 117-mile segment will commence construction in August 2012 with currently scheduled completion in late 2012.  Pipeline completion is expected to coincide with the installation of capture equipment at the Lost Cabin gas plant.  We estimate our 2012 capital costs for the Greencore Pipeline will be $135 million.

Future Rocky Mountain Tertiary Properties without Proved Tertiary Reserves or Tertiary Production at December 31, 2011

Bell Creek Field.   Bell Creek Field is located in southeast Montana.  A majority interest was acquired as part of the Encore Merger.  Development of the CO 2 EOR project at Bell Creek Field was started by Encore.  As of December 31, 2011, the majority of the work has involved re-activating wells in the field and injecting additional water into the reservoir to raise reservoir pressure in anticipation of future CO 2 injections.  The original operator of the field temporarily abandoned wells in such a way as to preserve the mechanical integrity of the wellbore and to minimize the cost of re-entering the wells.  We expect to have first CO 2 injections in Bell Creek Field upon completion of the Greencore Pipeline in late 2012.  We anticipate first tertiary oil production by early 2014.  Because the producing reservoir in Bell Creek Field is a sandstone reservoir very similar to our Gulf Coast reservoirs, we expect the CO 2 EOR project to perform similarly.  Conventional production net to our interest during the fourth quarter of 2011 averaged 840 Bbls/d, as compared to 957 Bbls/d in the year-ago period.  Our 2012 capital expenditures to finish well work, install flowlines and shoot 3-D seismic over the first injection stage in Bell Creek Field is estimated to be $18 million.

Cedar Creek Anticline.   Cedar Creek Anticline ("CCA") is primarily located in Montana but covers such a large area (approximately 120 miles) that it also extends into North Dakota.  CCA is a series of 10 producing oil units, each of which could be considered a field by itself.  We acquired our interest in CCA as part of the Encore Merger, and it is currently the largest potential EOR field we own.  Production, net to our interest, during the fourth quarter of 2011 from all of the units in CCA averaged 8,858 BOE/d, compared to 9,328 BOE/d in the year-ago period.  The conventional proved reserves associated with CCA were 63.8 MMBbls of oil and 12.9 Bcf of gas as of December 31, 2011.

CCA is located approximately 110 miles north of Bell Creek Field, and we expect to ultimately connect this field to our proposed Greencore Pipeline.  CCA produces from numerous reservoirs, although the primary reservoir is the Red River formation, which is a series of dolomitic reservoirs that have produced significant amounts of oil.  A CO 2 pilot project conducted in the South Pine Unit in the mid-1980s demonstrated the potential to produce an additional 18% of the original oil-in-place from the Red River Zone U4 reservoir.  We currently forecast beginning tertiary oil production at CCA in 2017.  We expect the majority of the capital spending at CCA over the next several years will be invested to modify and expand the existing waterflood operations, upgrade and improve our production handling equipment, and upgrade and improve artificial lift equipment.

Non-Tertiary Oil and Natural Gas Properties in the Rocky Mountain Region

Bakken.   The Bakken play in North Dakota and Montana is one of the more active unconventional oil plays in North America.  We acquired a significant acreage position in the Bakken play as part of the Encore Merger.  At December 31, 2011, we had approximately 200,000 net prospective mineral acres under lease in the Bakken play, down from approximately 275,000 acres at year-end 2010.  The reduction was primarily related to our removing the Almond area from our acreage counts after drilling results indicated the area was uneconomic.  We conducted an active operated and non-operated drilling program on our Bakken acreage in 2011.  During 2011, we operated an average of five drilling rigs on our acreage, and we drilled and completed 30 operated Bakken wells.  Fourth quarter 2011 production averaged 11,743 BOE/d, up from 5,193 BOE/d in the fourth quarter of 2010.  In addition to the operated wells we drilled during 2011, we also participated in an additional 103 non-operated wells.  Our total investment in the Bakken play for 2011 was $435 million, excluding capitalized interest.

The typical Bakken well is horizontally drilled with a 10,000-foot horizontal section that traverses the majority of a two-section, 1,280-acre spacing unit.  Where previous smaller spacing units (640 acres or 320 acres) exist, the horizontal section is reduced to approximately 5,000 feet.  At the present time, we are seeking regulatory approval to drill seven wells per 1,280-acre spacing unit.

Completion technologies in the Bakken have been evolving and will continue to evolve as operators test new ideas.  At the present time, after a well is drilled, the horizontal section is typically hydraulically fractured utilizing 20 to 30 frac stages to complete the well, although other operators have experimented with up to 40 stages. Once all of the stages are pumped, the well is turned to production.  The Bakken shale includes two producing intervals over a large portion of the play.  The Middle Bakken is the shallower productive interval and is present throughout the entire play.  Three Forks is the lower productive interval of the Bakken, but does not cover the entire Bakken play.  Given the reservoir characteristics of the Bakken, which is a tight shale, production rates may initially exceed 2,000 BOE/d but thereafter decline rapidly for the first year or two, producing for many years thereafter at a more conventional or slow rate of decline.  Denbury is continually refining the completion and hydraulic fracturing designs on wells, as are all operators in the Bakken.  Early in the life of the play, many wells were stimulated with a relatively small number of stages, typically fewer than six or eight.  We have had success in re-fracturing these early wells and expect to continue to re-frac additional wells during 2012.

Our total estimated capital for our Bakken drilling program in 2012 is approximately $400 million.  Of this amount, we intend to spend $245 million to operate an average of four rigs to drill approximately 34 Bakken wells.  We currently intend to begin 2012 with six operated rigs and then gradually decline to three rigs by mid-2012.  We may eventually decide to retain four rigs in the Bakken if oil prices, and hence operating cash flow, exceed our expectations.  Typically, we own a 40% to 100% working interest in our operated wells.  Due to our large acreage position, we also participate in numerous non-operated wells in the Bakken.  In 2012, we expect to participate in more than 130 non-operated wells at a total net cost of approximately $155 million.  We expect working interests in these wells to generally range from 10% to 25%.

Hydraulic Fracturing

We use a hydraulic fracturing process to stimulate production in our Bakken shale and Selma Chalk properties.  During 2011, we fracture stimulated 31 operated wells in the Bakken and 4 wells in the Selma Chalk utilizing water-based fluids with no diesel component.  In these operations, we are cognizant of

environmental laws and continually monitor all of our operations for possible environmental impact.  In areas where there is known shallow water flow, Denbury underlines the location with a plastic barrier to prevent any fluids from seeping into the ground water.  We utilize metal sided containment walls with plastic underliners around our separation and storage facilities to serve as secondary containment, should a spill incident occur.  After the stimulation has been completed and the well is produced, it is common to recover 15% to 30% of the water used for the stimulation.  All of the return water is collected onsite in storage tanks, and delivered via water transports to a commercial salt water disposal facility.  During 2011, we derived in the range of 10% to 15% of our revenues from properties which have been fracture stimulated at some point in the useful life of the properties.

OIL AND GAS ACREAGE, PRODUCTIVE WELLS, AND DRILLING ACTIVITY

In the data below, "gross" represents the total acres or wells in which we own a working interest and "net" represents the gross acres or wells multiplied by our working interest percentage.  For the wells that produce both oil and gas, the well is typically classified as an oil or natural gas well based on the ratio of oil to natural gas production.

Oil and Gas Acreage

The following table sets forth our acreage position at December 31, 2011:

Our net undeveloped acreage that is subject to expiration over the next three years, if not renewed, is approximately 16% in 2012, 19% in 2013 and 4% in 2014.

Productive Wells

The following table sets forth our gross and net productive oil and natural gas wells as of December 31, 2011:

Drilling Activity

The following table sets forth the results of our drilling activities over the last three years.  As of December 31, 2011, we had 27 gross (5.5 net) wells in progress.

The following table summarizes sales volumes, sales prices, and production cost information for our net oil and natural gas production for the years ended December 31, 2011, 2010 and 2009:

PRODUCTION AND UNIT PRICES

Information regarding average production rates, unit sale prices and unit costs per BOE are set forth under Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations – Operating Results , included herein.

TITLE TO PROPERTIES

Customarily in the oil and natural gas industry, only a perfunctory title examination is conducted at the time properties believed to be suitable for drilling operations are first acquired.  Prior to commencement of drilling operations, a thorough drill site title examination is normally conducted, and curative work is performed with respect to significant defects.  Typically, in connection with acquisitions, title reviews are performed on selected higher-value properties.  We believe that we have good title to our oil and natural gas properties, some of which are subject to minor encumbrances, easements and restrictions.

SIGNIFICANT OIL AND GAS PURCHASERS AND PRODUCT MARKETING

Oil and gas sales are made on a day-to-day basis under short-term contracts at the current area market price. The loss of any single purchaser would not be expected to have a material adverse effect upon our operations; however, the loss of a large single purchaser could potentially reduce the competition for our oil and natural gas production, which in turn could negatively impact the prices we receive.  For the years ended December 31, 2011 and December 31, 2010, two purchasers accounted for 10% or more of our oil and natural gas revenues: Marathon Petroleum Company LLC (43% and 46% in 2011 and 2010, respectively) and Plains Marketing LP (16% and 14% in 2011 and 2010, respectively).  For the year ended December 31, 2009, we had two significant purchasers that each accounted for 10% or more of our oil and natural gas revenues:  Marathon Petroleum Company LLC (52%) and Hunt Crude Oil Supply Co. (21%).

Our ability to market oil and natural gas depends on many factors beyond our control, including the extent of domestic production and imports of oil and gas, the proximity of our oil and natural gas production to pipelines, the available capacity in such pipelines, the demand for oil and natural gas, the effects of weather, and the effects of state and federal regulation.  Our production in the Gulf Coast region is primarily from developed fields close to major pipelines or refineries and established infrastructure.  Our production in the Rocky Mountain region is dependent on limited transportation options caused by oversubscribed pipelines and market centers that are distant from producing properties.  As of December 31, 2011, we have not experienced significant difficulty in finding a market for all of our production as it becomes available or in transporting our production to those markets; however, there is no assurance that we will always be able to market all of our production or obtain favorable prices.

Oil Marketing

The quality of our crude oil varies by area, thereby impacting the corresponding price received.  As an example, in Heidelberg Field, one of our larger fields, and our other eastern Mississippi non-tertiary properties, our oil production is primarily light to medium sour crude and has historically sold at a significant discount to NYMEX prices.  However, during 2011, our light to medium sour crude sold at an average premium of $6.58 per barrel over NYMEX prices.  In western Mississippi, the location of our Phase 1 tertiary operations, our oil production is primarily light sweet crude, which historically sold near, or at a modest premium to, NYMEX prices.  However, during 2011, our oil production in this area sold for more than $15.00 per barrel over NYMEX prices.  The premiums above NYMEX were more pronounced in the second half of 2011 and are attributable to the depressed nature of the West Texas Intermediate ("WTI") market in Cushing, OK (where NYMEX is valued) relative to the other grades of waterborne crude oil (e.g., Louisiana Light Sweet ("LLS"), Poseidon, Mars, Mayan and Brent).

The marketing of our Rocky Mountain region oil production is dependent on transportation through local pipelines to market centers in Guernsey, Wyoming; Clearbrook, Minnesota; and Wood River, Illinois.  Shipments on some of the pipelines are oversubscribed and subject to apportionment.  We have currently been allocated sufficient pipeline capacity to move our oil production; however, there can be no assurance that we will be allocated sufficient pipeline capacity to move all of our oil production in the future.  Expansion of pipeline and newly-built rail infrastructure in the Rocky Mountain region is ongoing and, we believe, has somewhat greater stability in oil differentials in the area, although recent events resulting in wider than usual differentials in the current markets are expected to remain in place until incremental takeaway capacity comes on line.   For the year ended December 31, 2011 the discount for our oil production in the Rocky Mountain region averaged $5.15 per Bbl, compared to $8.35 per Bbl during 2010.

Overall, during 2011, we sold approximately 45% of our production based on the LLS index price, although due to contract provisions we may not realize the full differential; 28% of our production based on NYMEX or WTI Posting plus Argus P+ prices; and 27% based on various other indexes, most of which have also improved relative to WTI, but to a lesser degree.

Natural Gas Marketing

Virtually all of our natural gas production in the Gulf Coast region is close to existing pipelines; consequently, we generally have a variety of options to market our natural gas.  Our gas production in the Rocky Mountain region, like our oil production, is dependent on limited transportation options that can affect our ability to find markets for it.  We sell the majority of our natural gas on one-year contracts, with prices fluctuating month-to-month based on published pipeline indices and with slight premiums or discounts to the index.  We currently receive near NYMEX or Henry Hub prices for most of our natural gas sales in Mississippi.  For the year ended December 31, 2011, we averaged $0.15 per Mcf above NYMEX prices for our Mississippi natural gas production.  In the Texas Gulf Coast region, due primarily to its location, the price we received for the year ended December 31, 2011 averaged $0.66 per Mcf above NYMEX prices.  The Rocky Mountain region natural gas production is sold at the wellhead on a percent of proceeds basis.  We receive a percentage of proceeds on both the residue natural gas volumes and the natural gas liquids volumes.  Because there are a limited number of gas markets in this region, during 2011 we flared a significant portion of the natural gas produced in this region.  The natural gas has a significant component of propane, butanes and other higher-density hydrocarbons, resulting in a measurable natural gas liquids stream.  For the year ended December 31, 2011, we averaged $2.09 per Mcf over NYMEX prices for our Rocky Mountain region natural gas production due primarily to the natural gas liquids extracted from the gas stream, improving the net price we receive.  In late 2011, we amended the gas sales contracts for our Bakken production to sell the natural gas liquids separately from the dry gas.  As a result, sales of natural gas liquids will be included in our oil sales in 2012 and future periods.

Helium Marketing

We expect production to commence at Riley Ridge Field during the second quarter of 2012, at which time we will begin to supply helium to a third party purchaser under a 20-year helium supply arrangement.  Helium will be sold under the contract at a price that will fluctuate based on helium deliveries, CPI and other factors over the 20-year term.

COMPETITION AND MARKETS

We face competition from other oil and natural gas companies in all aspects of our business, including acquisition of producing properties, oil and gas leases, and CO 2 properties; marketing of oil and natural gas; and obtaining goods, services and labor.  Many of our competitors have substantially larger financial and other resources.  Factors that affect our ability to acquire producing properties include available liquidity, available information about prospective properties and our expectations for earning a minimum projected return on our investments.  Gathering systems are the only practical method for the intermediate transportation of natural gas. Therefore, competition for natural gas delivery is presented by other pipelines and gas gathering systems.  Competition is also presented to a lesser extent by alternative fuel sources, including heating oil and other fossil fuels.  Because of the nature of our core assets (our tertiary operations) and our ownership of relatively uncommon significant natural sources of CO 2 in the Gulf Coast and Rocky Mountain regions, we believe that we are effective in competing in the market.

The demand for qualified and experienced field personnel to drill wells and conduct field operations and for geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages.  There have also been shortages of drilling rigs and other equipment, as demand for rigs and equipment has increased along with the number of wells being drilled.  These factors also cause significant increases in costs for equipment, services and personnel.  Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services.  We cannot be certain when we will experience these issues, and these types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results or restrict our ability to drill those wells and conduct those operations that we currently have planned and budgeted.

FEDERAL AND STATE REGULATIONS

Numerous federal and state laws and regulations govern the oil and gas industry.  Additions or changes to these laws and regulations are often made in response to the current political or economic environment. Compliance with this evolving regulatory burden is often difficult and costly, and substantial penalties may be incurred for noncompliance.  The following sections describe some specific laws and regulations that may affect us.  We cannot predict the impact of these or future legislative or regulatory initiatives.

Management believes that we are in substantial compliance with all laws and regulations applicable to our operations and that continued compliance with existing requirements will not have a material adverse impact on us.  The future annual capital cost of complying with the regulations applicable to our operations is uncertain and will be governed by several factors, including future changes to regulatory requirements.  However, management does not currently anticipate that future compliance will have a materially adverse effect on our consolidated financial position, results of operations or cash flows.

Regulation of Natural Gas and Oil Exploration and Production

Our operations are subject to various types of regulation at the federal, state and local levels.  Such regulation includes requiring permits for drilling wells; maintaining bonding requirements in order to drill or operate wells and regulating the location of wells; the method of drilling and casing wells; the

surface use and restoration of properties upon which wells are drilled; the plugging and abandoning of wells; and the composition or disposal of chemicals and fluids used in connection with operations.  Our operations are also subject to various conservation laws and regulations.  These include regulation of the size of drilling, spacing or proration units and the density of wells that may be drilled in those units, and the unitization or pooling of oil and gas properties.  In addition, state conservation laws, which establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production.  The effect of these regulations may limit the amount of oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill.  The regulatory burden on the oil and gas industry increases our costs of doing business and, consequently, affects our profitability.

Federal Regulation of Sales Prices and Transportation

The transportation and certain sales of natural gas in interstate commerce are heavily regulated by agencies of the U.S. federal government and are affected by the availability, terms and cost of transportation.  In particular, the price and terms of access to pipeline transportation are subject to extensive U.S. federal and state regulation.  The Federal Energy Regulatory Commission ("FERC") is continually proposing and implementing new rules and regulations affecting the natural gas industry.  Some of FERC's proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines.  While our sales of crude oil, condensate and natural gas liquids are not currently subject to FERC regulation, our ability to transport and sell such products is dependent on certain pipelines whose rates, terms and conditions of service are subject to FERC regulation.  Additional proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, FERC, state regulatory bodies and the courts.  We cannot predict when or if any such proposals might become effective and their effect, if any, on our operations.

Federal Energy and Climate Change Legislation and Regulation

In October 2008, as part of the Emergency Economic Stabilization Act, Congress included a new tax credit for carbon capture and sequestration, including that achieved through enhanced oil recovery, as further modified by the American Recovery and Reinvestment Act of 2009, passed in February 2009.  In early 2012, the President signed the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, which updates federal pipeline safety standards, increases penalties for violations, gives the Transportation Department authority for new damage prevention and incident notification, and directs the Transportation Department to prescribe new minimum safety standards for CO 2 pipelines, which could affect our operations and the costs thereof.  In future periods, Congress may create new incentives for alternative energy sources and may also consider legislation to reduce emissions of CO 2 or other gases.  If enacted, such legislation could impose a tax or other economic penalty on the production of fossil fuels that, when used, ultimately release CO 2 , and could reduce the demand for and uses of oil, gas and other minerals and/or increase the costs incurred by the Company in its exploration and production activities.  The Environmental Protection Agency ("EPA") has promulgated regulations requiring permitting for release of certain greenhouse gases, along with requirements for wells used for geologic sequestration.  At the same time, legislation to reduce the emissions of CO 2 or other gases could also create economic incentives for technologies and practices that reduce or avoid such emissions, including processes that sequester CO 2 in geologic formations such as oil and gas reservoirs.

Natural Gas Gathering Regulations

State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory-take requirements.  Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Federal, State or Indian Leases

Our operations on federal, state or Indian oil and gas leases, especially those in the Rocky Mountains, are subject to numerous restrictions, including nondiscrimination statutes. Such operations must be conducted pursuant to certain on-site security regulations and other permits and authorizations issued by the Bureau of Land Management, the Bureau of Ocean Energy Management, the Bureau of Safety and Environmental Enforcement, the Bureau of Indian Affairs, and other federal and state stakeholder agencies.

Environmental Regulations

Public interest in the protection of the environment has increased dramatically in recent years.  Our oil and natural gas production, saltwater disposal operations, injection of CO 2 , and our processing, handling and disposal of materials such as hydrocarbons and naturally occurring radioactive materials ("NORM") are subject to stringent regulation.  We could incur significant costs, including cleanup costs resulting from a release of product, third-party claims for property damage and personal injuries, or fines and sanctions as a result of any violations or liabilities under environmental or other laws.  Changes in or more stringent enforcement of environmental laws could also result in additional operating costs and capital expenditures.

Various federal, state and local laws regulating the discharge of materials into the environment or otherwise relating to the protection of the environment, directly impact oil and gas exploration, development and production operations, and consequently may impact our operations and costs.  These regulations include, among others, (i) regulations by the EPA and various state agencies regarding approved methods of disposal for certain hazardous and nonhazardous wastes; (ii) the Comprehensive Environmental Response, Compensation, and Liability Act, Federal Resource Conservation and Recovery

Act and analogous state laws that regulate the removal or remediation of previously disposed wastes (including wastes disposed of or released by prior owners or operators), property contamination (including groundwater contamination), and remedial plugging operations to prevent future contamination; (iii) the Clean Air Act and comparable state and local requirements, which may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations or could result in the imposition of economic penalties on the production of fossil fuels that, when used, ultimately release CO 2 ; (iv) the Oil Pollution Act of 1990, which contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States; (v) the Resource Conservation and Recovery Act, which is the principal federal statute governing the treatment, storage and disposal of hazardous wastes; (vi) the Endangered Species Act and counterpart state legislation, which protects endangered and threatened species and could include certain species present on our leases, such as the sage grouse, as threatened or endangered; and (vii) state regulations and statutes governing the handling, treatment, storage and disposal of NORM.

Management believes that we are in substantial compliance with applicable environmental laws and regulations.  Management does not currently anticipate that future compliance will have a materially adverse effect on our consolidated financial position, results of operations or cash flows, although such compliance and regulations could cause significant delays, which may cause our expected production rates and cash flows to be less than anticipated.

ESTIMATED NET QUANTITIES OF PROVED OIL AND NATURAL GAS RESERVES AND PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES

Internal Controls Over Reserve Estimates

We engage DeGolyer and MacNaughton, an independent petroleum engineering consulting firm located in Dallas, Texas, to prepare our reserve estimates, and we rely on their expertise to ensure that our reserve estimates are prepared in compliance with SEC rules and regulations and that appropriate geologic, petroleum engineering, and evaluation principles and techniques are applied in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007)".  The person responsible for the preparation of the reserve report is a Senior Vice President at this consulting firm; he is a Registered Professional Engineer in the State of Texas; he received a Bachelor of Science degree in Petroleum Engineering at Texas A&M University in 1974; and he has in excess of 35 years of experience in oil and gas reservoir studies and evaluations.  Denbury's Vice President – Reserves and Technology is primarily responsible for overseeing the independent petroleum engineering firm during the process.  Our Vice President – Reserves and Technology has a Bachelor of Science degree in Petroleum Engineering and over 20 years of industry experience working with petroleum reserve estimates.  The Company's internal reserve engineering team consists of qualified petroleum engineers who both provide data to the independent petroleum engineer and prepare interim reserve estimates.  The internal reserve team reports directly to our Vice President – Reserves and Technology.  In addition, the Company's Board of Directors' Reserves Committee, on behalf of the Board of Directors, oversees the qualifications, independence, performance and hiring of the Company's independent petroleum engineering firm and reviews the final report and subsequent reporting of the Company's oil and natural gas reserves.  The Chairman of the Reserves Committee is a Chartered Engineer of Great Britain and received his Bachelor of Science degree in Chemical Engineering from the University of London in 1963.

Oil and Natural Gas Reserves Estimates

DeGolyer and MacNaughton prepared estimates of our net proved oil and natural gas reserves as of December 31, 2011, 2010 and 2009.  See the summary of DeGolyer and MacNaughton's report as of December 31, 2011, included as an exhibit to this Form 10-K. Estimates of reserves were prepared using an average price equal to the un-weighted arithmetic average of hydrocarbon prices on the first day of each month within the 12-month period in accordance with rules and regulations of the SEC.  Our oil and natural gas reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage.  The reserve estimates represent our net revenue interest in our properties.  During 2011, we provided oil and gas reserve estimates for 2010 to the United States Energy Information Agency, which were substantially the same as the reserve estimates included in our Form 10-K for the year ended December 31, 2010.

Our proved nonproducing reserves primarily relate to reserves that are to be recovered from productive zones that are currently behind pipe.  Since a majority of our properties are in areas with multiple pay zones, these properties typically have both proved producing and proved nonproducing reserves.

As of December 31, 2011, our estimated proved undeveloped reserves totaled approximately 201.2 MMBOE, or approximately 44% of our estimated total proved reserves.  Our proved undeveloped oil reserves primarily relate to our CO 2 tertiary operations (48.2 MMBOE) and Bakken fields (69.9 MMBOE).  Our proved undeveloped natural gas reserves are primarily located in our Riley Ridge Field (69.1 MMBOE).  We consider the CO 2 tertiary proved undeveloped reserves to be lower risk than other proved undeveloped reserves that require drilling at locations offsetting existing production, because all of these proved undeveloped reserves are associated with secondary recovery or tertiary recovery operations in fields and reservoirs that historically produced substantial volumes of oil under primary production.

During 2011, we spent approximately $160 million to convert 26.4 MMBOE of proved undeveloped reserves to proved developed reserves.  Proved undeveloped reserves were converted primarily through the expansion of our tertiary floods at Delhi and Tinsley fields (19.8 MMBOE) and through additional drilling in the Bakken (5.5 MMBOE).  The offsetting 67.2 MMBOE increase in our proved undeveloped reserves from December 31, 2010 to December 31, 2011 is primarily due to the acquisition of Riley Ridge Field (36.8 MMBOE) and new proved undeveloped reserves identified as a result of additional drilling in the Bakken (30.1 MMBOE).

As of December 31, 2011, less than 2% of our proved undeveloped reserves have been held as proved undeveloped for a period greater than five years, all of which are tertiary reserves.  It is expected that the tertiary reserves will become proved developed reserves during the next several years as the remaining tertiary development at these fields is completed.  It is expected that the remaining non-tertiary proved undeveloped reserves will be developed within the next five years.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and their values, including many factors beyond our control.  See Item 1A, Risk Factors – Estimating our reserves, production and future net cash flows is difficult to do with any certainty .  See also Note 15, Supplemental Oil and Natural Gas Disclosures (Unaudited) , to the Consolidated Financial Statements.

Item 1A.  Risk Factors

Oil and natural gas prices are volatile.  A substantial decrease in oil and natural gas prices could adversely affect our financial results.

Our future financial condition, results of operations, and cash flows, and the carrying value of our oil and natural gas properties, depend primarily upon the prices we receive for our oil and natural gas production.  Oil and natural gas prices historically have been volatile and may continue to be volatile in the future, especially given current world geopolitical conditions.  Oil and natural gas prices have continued their volatility, with NYMEX oil prices per Bbl increasing 8% between year-end 2010 and year-end 2011, and NYMEX natural gas prices per MMBtu decreasing by 32% during the year.  Natural gas prices declined an additional 12% between December 31, 2011 and February 23, 2012.  Future decreases in commodity prices could require us to record full cost ceiling test write-downs.  The amount of any future write-down is difficult to predict and will depend upon oil and natural gas prices, the incremental proved reserves that might be added during each period and additional capital spent.

Our cash flow from operations is highly dependent on the prices that we receive for oil and natural gas.  This price volatility also affects the amount of our cash flow available for capital expenditures and our ability to borrow money or raise additional capital.  Oil prices are likely to affect us more than natural gas prices because oil comprised approximately 93% of our 2011 production and 77% of our December 31, 2011 proved reserves, with oil being an even larger percentage of our current production and future potential reserves and projects due to our focus on tertiary operations.

The prices for oil and natural gas are subject to a variety of additional factors that are beyond our control.  These factors include the supply of and demand for these commodities, which fluctuate with changes in market and economic conditions and other factors, including:

These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and natural gas price movements.  Also, prices for oil and prices for natural gas do not necessarily move in tandem.  Declines in oil and natural gas prices would not only reduce revenue, but could reduce the amount of oil and natural gas that we can produce economically.  If the oil and natural gas industry experiences significant price declines, we may, among other things, be unable to meet our financial obligations or make planned expenditures.

Over the past 13 years, oil prices have gone from near historic low prices around $12.00 per Bbl to record highs of approximately $145.00 per Bbl in July 2008.  During the last half of 2008, oil prices declined precipitously, ending that year at a NYMEX price of $44.60 per Bbl.  Oil prices then reversed course, generally increasing through 2010 and 2011, ending 2010 at a NYMEX price of $91.38 per Bbl and ending 2011 at a NYMEX price of $98.83 per Bbl.  If this volatility repeats itself, oil prices could decline to a level that makes our tertiary or Bakken projects uneconomic.  If that were to happen, we may decide to suspend future expansion projects, and if prices were to drop below the cash break-even point for an extended period of time, we may decide to shut-in existing production, either of which would have a material adverse effect on our operations.  We have a practice of hedging approximately the next year and a half of production to mitigate the risks associated with price fluctuations (see Note 9, Derivative Instruments and Hedging Activities , to the Consolidated Financial Statements for details regarding our commodity derivative contracts).  As of February 23, 2012, we have oil commodity derivative contracts in place covering approximately 54,000 Bbls/d during 2012 and 50,000 Bbls/d during the first three quarters of 2013.  Since operating costs do not decrease as quickly as commodity prices, it is difficult to determine a precise break-even point for our tertiary projects.  Based on prior history, we estimate our economic break-even (before corporate overhead, and based on expenses on these projects at current oil prices) occurs at per barrel dollar costs in the $40-per-barrel range, depending on the specific field and area.

The prices we receive for our crude oil often do not correlate with NYMEX prices.  The prices we receive for our crude oil production can vary from NYMEX oil prices depending on the quality of the crude oil we sell, the location of our crude oil production and the related markets we sell to, variations in prices paid based upon different indices used, and the pricing contracts and indices at which we sell production.  Our NYMEX differentials on a field-by-field basis over the last few years have ranged from a positive $25.00 per Bbl to a negative $30.00 per Bbl.  On a corporate-wide basis, our NYMEX differentials over the last few years have ranged from approximately $9.00 per Bbl above NYMEX oil prices to over $5.00 per Bbl below NYMEX prices.  These variances have been due to various factors and are difficult to forecast or anticipate, but they have a direct impact on the net oil price we receive.

Natural gas price volatility has followed a different path during the last few years, with current prices depressed as a result of weak demand and significant natural gas storage in place, leading to excess gas supply.  NYMEX natural gas prices averaged $4.16 per MMBtu during 2009, $4.40 per MMBtu during 2010, $4.03 per MMBtu during 2011, and ended 2011 at $2.99 per MMBtu.  As of February 23, 2012, we have natural gas commodity derivative contracts in place covering approximately 20,000 MMBtu/d during 2012.

Our production will decline if our access to sufficient amounts of carbon dioxide is limited.

Our long-term growth strategy is focused on our CO 2 tertiary recovery operations. The crude oil production from our tertiary recovery projects depends on having access to sufficient amounts of CO 2 .  Our ability to produce this oil would be hindered if our supply of CO 2 were limited due to problems with our current CO 2 producing wells and facilities, including compression equipment, or catastrophic pipeline failure.  Our anticipated future crude oil production is also dependent on our ability to increase the production volumes of CO 2 and inject adequate amounts of CO 2 into the proper formation and area within each oil field. The production of crude oil from tertiary operations is highly dependent on the timing, volumes and location of the CO 2 injections.  If our crude oil production were to decline, it could have a material adverse effect on our financial condition, results of operations and cash flows.

Our planned tertiary operations and the related construction of necessary CO 2 pipelines could be delayed by difficulties in obtaining pipeline rights-of-way, other permits, or by the listing of certain species as threatened or endangered.

The production of crude oil from our planned tertiary operations is also dependent upon having access to pipelines to transport available CO 2 to our oil fields at a cost that is economically viable.  Our ongoing construction of CO 2 pipelines will require us to obtain rights-of-way not only from private landowners, but in certain areas, from the federal government if the proposed pipelines cross federal lands.  Certain states where we operate are considering the adoption of laws and regulations that would limit or eliminate a state's ability to exercise eminent domain over private property , in addition to possible judicially imposed constraints on, and additional requirements for, the exercise of eminent domain .  We also conduct operations on federal and other oil and gas natural leases that have species, such as the sage grouse, that could be listed as threatened or endangered under the Endangered Species Act, which could lead to material restrictions as to federal land use.  These sorts of laws, and regulations and court decisions , together with any other changes in law related to the use of eminent domain or the listing of certain species as threatened or endangered, could inhibit our ability to secure rights-of-way or access land for current or future pipeline construction projects.  As a result, obtaining rights-of-way may require additional regulatory and environmental compliance and additional expenditures, which could delay our CO 2 pipeline construction schedule and initiation of operations of these pipelines, and/or increase the costs of constructing those pipelines.

Our level of indebtedness may adversely affect operations and limit our growth.

If we are unable to generate sufficient cash flow or otherwise obtain funds necessary to make required payments on our indebtedness, or if we otherwise fail to comply with the various covenants related to such indebtedness, including covenants in our bank credit facility, we would be in default under our debt instruments. This default could permit the holders of such indebtedness to accelerate the maturity of such indebtedness and could cause defaults under other indebtedness, possibly resulting in our bankruptcy. Our ability to meet our obligations will depend upon our future performance, which will be subject to prevailing economic conditions, commodity prices, and financial, business and other factors, including factors beyond our control.

As of February 23, 2012, we had outstanding $2.1 billion (principal amount) of subordinated notes at interest rates ranging from 6.0% to 9.75% at a weighted average interest rate of 8.33% and $470 million of bank debt secured by most of our properties.  At February 23, 2012, we had $1.1 billion available on our bank credit facility.  We currently have a bank borrowing base of $1.6 billion.  The next regularly scheduled semiannual redetermination of the borrowing base for our bank credit facility will be in May 2012.  Our bank borrowing base is adjusted at the banks' discretion and is based in part upon external factors, such as commodity prices, over which we have no control.  If our then redetermined borrowing base is less than our outstanding borrowings under the facility, we will be required to repay the deficit over a period not to exceed four months.

We may incur additional indebtedness in the future under our bank credit facility in connection with our acquisition, development, exploitation and exploration of oil and natural gas producing properties.  Further, our cash flow from operations is highly dependent on the prices that we receive for oil and natural gas.  If oil and natural gas prices again decrease and remain at depressed levels for an extended period of time, our degree of leverage could increase substantially.  The level of our indebtedness could have important consequences, including but not limited to the following:

Product price derivative contracts may expose us to potential financial loss.

To reduce our exposure to fluctuations in the prices of oil and natural gas, we currently, and may in the future, enter into derivative contracts in order to economically hedge a portion of our oil and natural gas production.  Derivative contracts expose us to risk of financial loss in some circumstances, including when:

In addition, these derivative contracts may limit the benefit we would receive from increases in the prices for oil and natural gas.  Information as to these activities is set forth under Market Risk Management in Management's Discussion and Analysis of Financial Condition and Results of Operations, and in Note 9, Derivative Instruments and Hedging Activities , to the Consolidated Financial Statements.

A worldwide financial downturn, such as the 2008 – 2009 financial crisis, or negative credit market conditions may have lasting effects on our liquidity, business and financial condition that we cannot predict.

Liquidity is essential to our business.  Our liquidity could be substantially negatively affected by an inability to obtain capital in the long-term or short-term debt capital markets or equity capital markets or an inability to access bank financing.  A prolonged credit crisis, including the current sovereign debt crisis in Europe and related turmoil in the global financial system, could materially affect our liquidity, business and financial condition.  These conditions have adversely impacted financial markets and have created substantial volatility and uncertainty, and may continue to do so, with the related negative impact on global economic activity and the financial markets.  Negative credit market conditions could materially affect our liquidity and may inhibit our lenders from fully funding our bank credit facility or cause them to make the terms of our bank credit facility costlier and more restrictive.  We are subject to semiannual reviews, as well as unscheduled reviews, of our borrowing base under our bank credit facility, and we do not know the results of future redeterminations or the effect of then-current oil and natural gas prices on that process.  The economic situation could also adversely affect the collectability of our trade receivables or performance by our suppliers and cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection.  Additionally, negative economic conditions could lead to reduced demand for oil and natural gas, or lower prices for oil and natural gas, which could have a negative impact on our revenues.

Our future performance depends upon our ability to find or acquire additional oil and natural gas reserves that are economically recoverable.

Unless we can successfully replace the reserves that we produce, our reserves will decline, resulting eventually in a decrease in oil and natural gas production and lower revenues and cash flows from operations.  We have historically replaced reserves through both acquisitions and internal organic growth activities.  In the future, we may not be able to continue to replace reserves at acceptable costs.  The business of exploring for, developing or acquiring reserves is capital intensive.  We may not be able to make the necessary capital investment to maintain or expand our oil and natural gas reserves if our cash flows from operations are reduced, due to lower oil or natural gas prices or otherwise, or if external sources of capital become limited or unavailable.  Further, the process of using CO 2 for tertiary recovery and the related infrastructure requires significant capital investment, up to four or five years prior to any resulting production and cash flows from these projects, heightening potential capital constraints.  If we do not continue to make significant capital expenditures, or if outside capital resources become limited, we may not be able to maintain our growth rate or meet expectations.

During the last few years, we have acquired several fields at a significant cost because we believe that they have significant additional potential through tertiary flooding and we paid a premium price for these properties based on that assumption.  In addition, we plan to continue acquiring other oil fields that we believe are tertiary flood candidates.  We are investing significant amounts of capital as part of this strategy.  If we are unable to successfully develop the potential oil in these acquired fields, it would negatively affect the return on our investment on these acquisitions and could severely reduce our ability to obtain additional capital for the future, fund future acquisitions, and negatively affect our financial results to a significant degree.

Oil and natural gas drilling and producing operations involve various risks.

Drilling activities are subject to many risks, including the risk that new wells drilled by us will not discover commercially productive reservoirs or the risk that we will not recover all or any portion of our investment in such wells.  Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting drilling, operating and other costs.  The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Further, our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including:

Our operations are subject to all the risks normally incident to the operation and development of oil and natural gas properties and the drilling of oil and natural gas wells, including encountering well blowouts, cratering and explosions, pipe failure, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, release of contaminants into the environment and other environmental hazards and risks.

The nature of these risks is such that some liabilities could exceed our insurance policy limits, or, as in the case of environmental fines and penalties, cannot be insured.  We could incur significant costs related to these risks that could have a material adverse effect on our results of operations, financial condition and cash flows.

Our CO 2 tertiary recovery projects require a significant amount of electricity to operate the facilities.  If these costs were to increase significantly, it could have an adverse effect upon the profitability of these operations.  Additionally, a portion of our production activities involve CO 2 injections into fields with wells plugged and abandoned by prior operators.  It is often difficult to determine whether a well has been properly plugged prior to commencing injections and pressuring the oil reservoirs.  If wells have not been properly plugged, we will have to modify the wells, which can increase costs, delay our operations and reduce our production.

Certain of our operations may be limited during certain periods due to severe weather conditions and other regulations.

Certain of our operations in North Dakota, Montana and Wyoming are conducted in areas subject to extreme weather conditions and often in difficult terrain. As a result, our operations may be delayed because of cold, snow and wet conditions. During a harsh winter, certain operations may only be practical during non-winter months.  Unusually severe weather could delay certain of these operations, including the construction of CO 2 pipelines, the drilling of new wells and production from existing wells, and depending on the severity of the weather, could have a negative effect on our results of operations in this region. Further, certain of our operations are limited to certain time periods due to environmental regulations, which slow down our operations, cause delays and can have a negative effect on our results of operations.

Shortages of oil field equipment, services and qualified personnel could reduce our cash flow and adversely affect results of operations.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages.  During periods of high oil and natural gas prices, we have experienced shortages of equipment used in our tertiary facilities, drilling rigs and other equipment, as demand for rigs and equipment has increased along with higher commodity prices.  Higher oil and natural gas prices generally stimulate

increased demand and result in increased prices for drilling rigs, crews and associated supplies, oilfield equipment and services, and personnel in our exploration and production operations.  We have experienced such equipment shortages and price increases particularly in the Bakken play due to high demand for drilling rigs there.  These types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results and/or restrict or delay our ability to drill those wells and conduct those operations that we currently have planned and budgeted, causing us to miss our forecasts and projections.

Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is a practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations and is used in the Bakken formations we acquired as part of the Encore Merger.  The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.  The process is typically regulated by state oil and gas commissions.  The EPA, however, recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the federal Safe Drinking Water Act's ("SDWA") Underground Injection Control ("UIC") Program by posting a new requirement that requires facilities to obtain permits to use diesel fuel in hydraulic fracturing operations.  (The U.S. Energy Policy Act of 2005, which exempts hydraulic fracturing from regulation under the SDWA, prohibits the use of diesel fuel in the fracturing process without a UIC permit.)  Although the EPA has yet to take any action to enforce or implement this newly-asserted regulatory authority, industry groups have filed suit challenging the EPA's recent decisions.  At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with results of the study anticipated to be available by late 2012, and various committees have been investigating hydraulic fracturing practices.  In addition, legislation was proposed in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process.  In 2011, between 10% and 15% of our revenues were derived from operations related to hydraulic fracturing.

Although it is difficult to predict the ultimate outcome of these and future initiatives, these or any other new laws or regulations that significantly restrict hydraulic fracturing could make it more difficult or costly for us to drill and produce from conventional or tight formations, and fracturing activities could become subject to additional permitting and financial assurance requirements, increased monitoring, reporting and recordkeeping obligations, and also attendant permitting delays and potential increases in costs.  At this time, it is not possible to estimate the potential impact on our business that may arise if federal or state legislation governing hydraulic fracturing is enacted into law.

Enactment of legislative or regulatory proposals under consideration could negatively affect our business.

Numerous legislative and regulatory proposals affecting the oil and gas industry have been proposed or are under consideration by the current federal administration, Congress and various federal agencies.  Among these proposals are: (1) climate change/carbon tax legislation introduced in Congress and EPA greenhouse gas regulations, including decisions on the application of New Source Performance Standards (NSPS) for petroleum refineries due by November 2012; (2) proposals contained in the President's budget, along with legislation introduced in Congress, none of which have passed Congress, to impose new taxes on, or repeal various tax deductions available to, oil and gas producers, such as the current tax deduction for intangible drilling and development costs and the current deduction for qualified tertiary injectant expenses, which if eliminated could raise the cost of energy production, reduce energy investment and affect the economics of oil and gas exploration and production activities; (3) legislation being considered by Congress that would subject the process of hydraulic fracturing to federal regulation under the SDWA and new or anticipated Interior Department and EPA regulations to require disclosure of the chemicals used in the fracturing process; and (4) the Pipeline Safety, Regulatory Certainty, and Job Creation Act enacted in 2011, which increases penalties, grants new authority to impose damage prevention and incident notification requirements, and directs the Transportation Department to prescribe minimum safety standards for CO 2 pipelines, any of which could affect Company operations, their effectiveness and the costs thereof.  Generally, any such future laws and regulations could result in increased costs or additional operating restrictions and could have an effect on demand for oil and natural gas or prices at which it can be sold.  Until any such legislation or regulations are enacted or adopted, it is not possible to gauge their impact on our future operations or our results of operations and financial condition.

The loss of more than one of our large oil and natural gas purchasers could have a material adverse effect on our operations.

For the year ended December 31, 2011, two purchasers each accounted for more than 10% of our oil and natural gas revenues and in the aggregate, for 59% of these revenues.  However, the loss of a large single purchaser could potentially reduce the competition for our oil and natural gas production, which in turn could negatively impact the prices we receive.

Estimating our reserves, production and future net cash flows is difficult to do with any certainty.

Estimating quantities of proved oil and natural gas reserves is a complex process.  It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors such as future commodity prices, production costs, severance and excise taxes, capital expenditures and workover and remedial costs, and the assumed effect of governmental regulation.  There are numerous uncertainties about when a property may have proved reserves as compared to potential or probable reserves, particularly relating to our tertiary recovery operations.  Forecasting the amount of oil reserves recoverable from tertiary operations and the production rates anticipated therefrom requires estimates, one of the most significant being the oil recovery factor.  Actual results most likely will vary from our estimates.  Also, the use of a 10% discount factor for reporting purposes, as

prescribed by the SEC, may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.  Any significant inaccuracies in these interpretations or assumptions or changes of conditions could result in a reduction of the quantities and net present value of our reserves.

The reserve data included in documents incorporated by reference represent only estimates.  Quantities of proved reserves are estimated based on economic conditions, including oil and natural gas prices in existence at the date of assessment.  Our reserves and future cash flows may be subject to revisions based upon changes in economic conditions, including oil and natural gas prices, as well as due to production results, results of future development, operating and development costs, and other factors.  Downward revisions of our reserves could have an adverse effect on our financial condition, operating results and cash flows.  Actual future prices and costs may be materially higher or lower than the prices and cost as of the date of the estimate.

As of December 31, 2011, approximately 44% of our estimated proved reserves were undeveloped.  Recovery of undeveloped reserves requires significant capital expenditures and may require successful drilling operations.  The reserve data assumes that we can and will make these expenditures and conduct these operations successfully, but these assumptions may not be accurate, and this may not occur.

Substantial acquisitions or other transactions could require significant external capital and could change our risk and property profile.

To finance acquisitions, we may need to substantially alter or increase our capitalization through the use of our bank credit facility, the issuance of debt or equity securities, the sale of production payments, or by other means.  Such changes in capitalization could significantly affect our risk profile.  Additionally, significant acquisitions or other transactions can change the character of our operations and business.  The character of the new properties may be substantially different in operating or geological characteristics or geographic location than our existing properties.

We may experience an impairment of our goodwill.

We test goodwill for impairment annually during the fourth quarter, or more frequently if an event occurs or circumstances change that may indicate the fair value of a reporting unit is less than the carrying amount.  The need to test for impairment can be based on several indicators, such as a significant reduction in the price of oil or natural gas, a full cost ceiling write-down of oil and natural gas properties, or significant changes in the expected timing of production.

Fair value calculated for the purpose of testing for impairment of our goodwill is estimated using the expected present value of future cash flows method and comparative market prices when appropriate.  A significant amount of judgment is involved in performing these fair value estimates for goodwill since the results are based on estimated future cash flows and assumptions related thereto.  Significant assumptions include estimates of future oil and natural gas prices, projections of estimated quantities of oil and natural gas reserves, estimates of future rates of production, timing and amount of future development and operating costs, estimated availability and cost of CO 2 , projected recovery factors of reserves and risk-adjusted discount rates.  We base our fair value estimates on projected financial information that we believe to be reasonable; however, actual results may differ from those projections.

A cyber incident could occur and result in information theft, data corruption, operational disruption, and/or financial loss.

Our business has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain of our exploration, development and production activities.  We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information and in many other activities related to our business.  Our technologies, systems and networks may become the target of cyber-attacks or information security breaches that could result in the disruption of our business operations.  For example, unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our drilling or production operations.

To date we have not experienced any material losses relating to cyber-attacks, however there can be no assurance that we will not suffer such losses in the future.  As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any cyber-vulnerabilities.

Item 1B.  Unresolved Staff Comments

There are no unresolved written SEC staff comments regarding our periodic or current reports under the Securities Exchange Act of 1934 received 180 days or more before the end of the fiscal year to which this annual report on Form 10-K relates.

Item 2.  Properties

Information regarding the Company's properties called for by this item is included in Item 1 , Business and Properties – Oil and Natural Gas Operations .  We also have various operating leases for rental of office space, office and field equipment, and vehicles.  See Off-Balance Sheet Agreements – Commitments and Obligations in Management's Discussion and Analysis of Financial Condition and Results of Operations , and Note 11, Commitments and Contingencies , to the Consolidated Financial Statements for the future minimum rental payments.  Such information is incorporated herein by reference.

Item 3.  Legal Proceedings

We are involved in various other lawsuits, claims and regulatory proceedings incidental to our businesses.  While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position or overall trends in results of operations or cash flows, litigation is subject to inherent uncertainties.  If an unfavorable ruling in one of these lawsuits were to occur, there exists the possibility of a material adverse impact on our net income in the period in which the ruling occurs.  We provide accruals for litigation and claims if we determine that we may have a range of legal exposure that would require accrual.

Item 4.  Mine Safety Disclosures

Not applicable.

PART II

Item 5.  Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Common Stock Trading Summary

The following table summarizes the high and low reported sales prices on days in which there were trades of Denbury's common stock on the New York Stock Exchange ("NYSE") for each quarterly period for the last two fiscal years.  As of February 10, 2012, based on information from the Company's transfer agent, American Stock Transfer and Trust Company, the number of holders of record of Denbury's common stock was 1,550.  On February 24, 2012, the last reported sale price of Denbury's common stock, as reported on the NYSE, was $20.91 per share.

We have never paid any dividends on our common stock, and we currently do not anticipate paying dividends in the foreseeable future.  Also, our bank credit facility limits the amount of dividends we can pay on our common stock to $500 million, subject to other restrictions.  No unregistered securities were sold by the Company during 2011.

All other stock purchases during the fourth quarter of 2011 were made in connection with delivery by our employees of shares to us to satisfy their tax withholding requirements related to the vesting of restricted shares and the exercise of stock appreciation rights.

The following Performance Graph and related information shall not be deemed "soliciting material" or to be "filed" with the SEC, nor shall such information be incorporated by reference into any future filings under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filings.

The following graph illustrates changes over the five-year period ended December 31, 2011, in cumulative total stockholder return on our common stock as measured against the cumulative total return of the S&P 500 Index and the Dow Jones U.S. Exploration and Production Index.  The graph tracks the performance of a $100 investment in our common stock and in each index (with the reinvestment of all dividends) from December 31, 2006 to December 31, 2011.

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The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements and Notes thereto included in Item 8, Financial Statements and Supplementary Data .  Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Risk Factors under Item 1A of this report, along with Forward-Looking Information at the end of this section for information on the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

Overview

We are a growing independent oil and natural gas company.  We are the largest combined oil and natural gas producer in both Mississippi and Montana, own the largest CO 2 reserves used for tertiary oil recovery east of the Mississippi River, and hold significant operating acreage in the Rocky Mountain and Gulf Coast regions.  Our goal is to increase the value of acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis on our CO 2 tertiary recovery operations.

We completed the acquisition of Encore on March 9, 2010 (the "Encore Merger"), and during the remainder of 2010 executed on our plan to divest non-strategic Encore properties.  The magnitude of the Encore acquisition and subsequent 2010 asset divestitures impacts the comparability of our 2010 and 2011 financial results in many ways, including oil and natural gas production, revenues and operating expenses.  Our financial results for the year ended December 31, 2010 include the results of operations of Encore from the date of the acquisition through December 31, 2010, and were further impacted by our divestitures of non-strategic Encore properties and our ownership interests in Encore Energy Partners ("ENP") between May 2010 and December 31, 2010.

2011 Operating Highlights.   We achieved record net income and cash flows from operations in 2011.  We had net income of $573.3 million, or $1.45 per basic common share, during 2011, compared to net income of $271.7 million, or $0.73 per basic common share, during 2010.  The increase between the two periods is primarily attributable to a $475.9 million increase in oil and natural gas revenues due to higher oil prices, partially offset by lower production as a result of assets sold in late 2010, and to a lesser extent due to an $87.9 million decrease in costs related to the Encore Merger.  These increases to net income between 2010 and 2011 were offset by the absence in 2011 of a $101.5 million gain on the 2010 sale of Genesis Energy, LLC, and to a lesser extent were due to a $16.1 million loss on the early extinguishment of debt in 2011, certain asset impairment charges in 2011 related to our investment in Vanguard common units ($6.3 million), and the abandonment of our investment in certain CO 2 properties ($16.6 million).  Overall, our total expenses decreased by $57.4 million, from $1.44 billion in 2010 to $1.39 billion in 2011.  Our cash flow from operations was $1.2 billion in 2011, compared to $855.8 million in 2010, the increase also primarily due to the increase in oil revenues.

During 2011, our oil and natural gas production, which was 93% oil, averaged 65,660 BOE/d, compared to 72,927 BOE/d produced during 2010.  The decrease in production is primarily attributable to the 2010 sales of non-strategic legacy Encore assets and our ownership interests in ENP.  See Results of Operations - Operating Results - Production for more information.

Oil prices during 2011 were considerably higher than prices during 2010, with NYMEX oil prices averaging $95.08 per Bbl in 2011, compared to average NYMEX prices of $79.51 per Bbl in 2010.  Oil revenues made up approximately 98% of our oil and natural gas revenues in 2011 as compared to approximately 93% in 2010.  Our average price per barrel of oil, excluding the impact of derivative contracts, was $100.03 per barrel in 2011, as compared to $75.97 per barrel in 2010, a 32% increase between the two periods.  Oil prices received in 2011 were positively impacted by the favorable price differential for crude oil sold under Louisiana Light Sweet ("LLS") pricing.  See Results of Operations – Operating Results – Oil and Natural Gas Revenues below for more information.

August 2011 Acquisition of Remaining Working Interest in Riley Ridge.  On August 1, 2011, we acquired the remaining 57.5% working interest that we did not already own in the Riley Ridge Federal Unit ("Riley Ridge"), the remaining 57.5% interest in the associated Riley Ridge gas plant, along with interests in certain surrounding acreage.  The purchase price after closing adjustments was $214.8 million.  Riley Ridge not only contains significant natural gas and helium, but is strategic to our tertiary oil field development in the Rocky Mountain region as it provides a significant long-term source of CO 2 that we plan to use in our tertiary floods.  We currently expect the gas plant to be operational with the first production of natural gas and helium during the second quarter of 2012.  The CO 2 will be re-injected into the reservoir until we have completed an additional separation facility and a CO 2 pipeline to the field, which is expected to be completed in 2016.

As of December 31, 2011, Riley Ridge and minor surrounding acreage contained net proved reserves of 415 Bcf of natural gas and 2.2 Tcf of CO 2 reserves.  The CO 2 reserve estimates are based on the gross working interest of the CO 2 reserves, of which Denbury's net revenue interest is approximately 1.6 Tcf.  The helium reserves at Riley Ridge are owned by the U.S. government; however, we have the rights to produce and sell the helium reserves on behalf of the government in exchange for a fee.  As of December 31, 2011, we estimate that Riley Ridge contains proved helium reserves of 12.0 Bcf, net of fees to be remitted to the U.S. government.

Addition of Proved Oil and Natural Gas Reserves. We added 88.0 MMBOE of estimated proved reserves during 2011, including 48.2 MMBOE from the development of Bakken properties, 237 Bcf (39.5 MMBOE) of natural gas reserves from the Riley Ridge acquisition completed in August 2011, which is discussed above, and minor revisions to other properties.

Recent Common Share Repurchase Program.   In October 2011, we commenced a common share repurchase program approved by our Board of Directors for up to $500 million of Denbury common shares.  Between early October 2011 and December 31, 2011, we repurchased 14,112,610 shares of Denbury common stock (approximately 3.5% of our outstanding shares of common stock at September 30, 2011) for $195.2 million, or $13.83 per share.  The program has no pre-established ending date and may be suspended or discontinued at any time.  The Company is not obligated to repurchase any dollar amount or specific number of shares of its common stock under the program.

Pending 2012 Non-Core Gulf Coast Assets Divestiture.   In January 2012, we entered into a definitive agreement to sell certain non-core assets primarily located in central and southern Mississippi and in southern Louisiana for $155 million, subject to customary closing adjustments.  The sale is subject to customary closing conditions and is expected to close by late February 2012, with an effective date of December 1, 2011.  Production associated with the properties to be sold averaged 1,805 BOE/d during 2011.  See Note 14, Subsequent Events , to the Consolidated Financial Statements.

Capital Resources and Liquidity

We currently estimate our 2012 capital spending will be approximately $1.35 billion, net of estimated equipment leases ($75 million) and excluding capitalized interest and start-up costs associated with new tertiary floods.  Our current 2012 capital budget includes the following:

As discussed above, in October 2011 we commenced a common share repurchase program for up to $500 million of Denbury shares.  Our goal for 2012 is to limit any incremental debt incurred for such repurchases and for our 2012 capital budget to $250 million or less, and we estimate cumulative share repurchases of up to $250 million in determining our 2012 capital budget.  Of the $250 million in projected repurchases, thus far we have repurchased $195.2 million.  Based on our current anticipated levels of cash flows from operations and proceeds from asset sales, we currently expect to stay within our stated goal for incremental debt related to our share repurchase program and 2012 capital budget.  Our share repurchases will be determined based on various parameters; therefore, our share repurchases may be less or more than our estimated $250 million.

During 2011, we extended the maturity of our bank credit facility from March 2014 to May 2016.  As part of our semiannual bank review, on September 1, 2011, our borrowing base for our bank credit facility was reaffirmed at $1.6 billion.  Our next borrowing base redetermination is scheduled for May 1, 2012; we currently do not anticipate any reduction in our borrowing base as part of that redetermination, as we believe that we have more than enough collateral for the current borrowing base, based on current commodity prices and our proved asset base.  As of February 23, 2012, we had $470 million of bank debt outstanding on our $1.6 billion bank credit facility and estimated cash of $195 million, leaving us significant liquidity to fund any cash shortfall for capital expenditures.

To help protect our cash flows in case commodity prices were to decrease significantly from the levels of futures strip prices near the end of February 2012, we currently have oil and natural gas derivative commodity contracts in place through the third quarter of 2013.  Our oil derivative commodity contracts cover approximately 85–90% of our anticipated proved oil production in 2012 and 75–80% in the first three quarters of 2013.  Over 90% of our continuing production (excluding production from properties sold) is oil, and most of our oil contracts are costless collars with NYMEX floor prices between $70 and $80 per Bbl.  See Note 9, Derivative Instruments and Hedging Activities to the Consolidated Financial Statements for further details regarding the prices and volumes of our commodity derivative contracts.

We continually monitor our capital spending and anticipated cash flows and believe that we can adjust our capital spending up or down depending on cash flows; however, any such reduction in capital spending could reduce our anticipated production levels in future years.  For 2012 and some future years, we have contracted for certain capital expenditures; therefore, we cannot eliminate all of our capital commitments without penalties. (See Off-Balance Sheet Arrangements – Commitments and Obligations for further information regarding these commitments.)

In February 2011, we issued, at par, $400 million of 6⅜% Senior Subordinated Notes due 2021.  The net proceeds, together with cash on hand, were used to partially fund the repurchase of $525 million in principal amount of our outstanding 7½% Senior Subordinated Notes due 2013 and 7½% Senior Subordinated Notes due 2015.  During 2011, we recognized $16.1 million of loss associated with the debt repurchases included in our Consolidated Statements of Operations under the caption "Loss on early extinguishment of debt."  See Note 5, Long-Term Debt , to the Consolidated Financial Statements for more information related to the debt issuance and related tender offers.

Capital Expenditure Summary.   The following table summarizes our capital expenditures by project area.  Amounts include capitalized tertiary start-up costs and accrued capital expenditures: