UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

2011 FORM 10-K

(Mark One)

þ  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)

Delaware	20-0467835
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
5320 Legacy Drive, Plano, TX	75024
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (972) 673-2000

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

Title of Each Class:	Name of Each Exchange on Which Registered:
Common Stock $.001 Par Value	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ   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 þ

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 þ   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 þ    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 þ   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 þ

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

Document:	Incorporated as to:
1.Notice and Proxy Statement for the Annual Meeting of       Stockholders to be held May 15, 2012.	1.  Part III, Items 10, 11, 12, 13, 14

 Denbury Resources Inc.

2011 Annual Report on Form 10-K

 Table of Contents

		Page
	Glossary and Selected Abbreviations	3
	PART I
Item 1.	Business and Properties	5
Item 1A.	Risk Factors	23
Item 1B.	Unresolved Staff Comments	29
Item 2.	Properties	29
Item 3.	Legal Proceedings	29
Item 4.	Mine Safety Disclosures	29
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	30
Item 6.	Selected Financial Data	32
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	58
Item 8.	Financial Statements and Supplementary Data	58
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	98
Item 9A.	Controls and Procedures	98
Item 9B.	Other Information	98
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	99
Item 11.	Executive Compensation	99
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	99
Item 13.	Certain Relationships and Related Transactions, and Director Independence	99
Item 14.	Principal Accountant Fees and Services	99
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	100
	Signatures	106

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 Denbury Resources Inc.

Glossary and Selected Abbreviations

Bbl	One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
Bbls/d	Barrels of oil produced per day.
Bcf	One billion cubic feet of natural gas, CO2 or helium.
Bcfe	One billion cubic feet of natural gas equivalent, using the ratio of one barrel of crude oil, condensate or natural gas liquids to 6 Mcf of natural gas.
BOE	One barrel of oil equivalent, using the ratio of one barrel of crude oil, condensate or natural gas liquids to 6 Mcf of natural gas.
BOE/d	BOEs produced per day.
Btu	British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
CO2	Carbon dioxide.
EOR	Enhanced oil recovery.
Finding and Development Cost	The average cost per BOE to find and develop proved reserves during a given period. It is calculated by dividing costs, which includes the total acquisition, exploration and development costs incurred during the period plus future development and abandonment costs related to the specified property or group of properties, by the sum of (i) the change in total proved reserves during the period plus (ii) total production during that period.
MBbls	One thousand barrels of crude oil or other liquid hydrocarbons.
MBOE	One thousand BOEs.
Mbtu	One thousand Btus.
Mcf	One thousand cubic feet of natural gas, CO2 or helium at a temperature base of 60 degrees Fahrenheit (°F) and at the legal pressure base (14.65 to 15.025 pounds per square inch absolute) of the state or area in which the reserves are located or sales are made.
Mcf/d	One thousand cubic feet of natural gas, CO2 or helium produced per day.
MMBbls	One million barrels of crude oil or other liquid hydrocarbons.
MMBOE	One million BOEs.
MMBtu	One million Btus.
MMcf	One million cubic feet of natural gas, CO2 or helium.
MMcf/d	One million cubic feet of natural gas, CO2 or helium per day.
PV-10 Value	When used with respect to oil and natural gas reserves, PV-10 Value means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated future production, development and abandonment costs, and before income taxes, discounted to a present value using an annual discount rate of 10%. PV-10 Values were prepared using average hydrocarbon prices equal to the unweighted arithmetic average of hydrocarbon prices on the first day of each month within the 12-month period preceding the reporting date.  PV-10 Value is a non-GAAP measure and its use is further discussed in footnote 3 to the reserves table included in Item 1, Estimated Net Quantities of Proved Oil and Natural Gas Reserves and Present Value of Estimated Future Net Revenues.
Probable Reserves*	Are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

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 Denbury Resources Inc.

Proved Developed Reserves*	Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved Reserves*	The estimated quantities of reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved Undeveloped Reserves*	Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required.
Tcf	One trillion cubic feet of natural gas, CO2 or helium.

* 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.

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 Denbury Resources Inc.

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 CO2 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:

·      focus in specific regions where we either have, or believe we can create, a competitive advantage as a result of our ownership or use of CO2 reserves, oil fields and CO2 infrastructure;

·      acquire properties where we believe additional value can be created through tertiary recovery operations and a combination of other exploitation, development, exploration and marketing techniques;

·      acquire properties that give us a majority working interest and operational control or where we believe we can ultimately obtain it;

·      maximize the value of our properties by increasing production and reserves while controlling cost; and

·      maintain a highly competitive team of experienced and incentivized personnel.

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

On March 9, 2010, we acquired Encore Acquisition Company (“Encore”) pursuant to an Agreement and Plan of Merger (the "Encore Merger Agreement") in a stock and cash transaction valued at approximately $4.8 billion at the acquisition date, including the assumption of Encore debt and the value of the noncontrolling interest in Encore Energy Partners LP (“ENP”). Under the Encore Merger Agreement, Encore was merged with and into Denbury (the “Encore Merger”), with Denbury surviving the Encore Merger.  Pursuant to our stated intent, at the time of acquisition, to divest certain non-strategic legacy Encore properties, certain oil and gas properties in the Permian Basin, Mid-continent area and East Texas Basin were sold in May 2010.  We subsequently divested our production and acreage in the Cleveland Sand Play and Haynesville Play during 2010 as well.  In addition to the property sales, we sold our ownership interests in ENP on December 31, 2010.  Collectively, we received approximately $1.5 billion in total consideration from these divestitures in 2010, excluding the bank debt of ENP that was assumed by the purchaser in the sale.  See Note 2, Acquisitions and Divestitures, to the Consolidated Financial Statements for further discussion of these transactions and information as to other recent acquisitions and divestitures by Denbury.

OIL AND NATURAL GAS OPERATIONS

Summary. Our oil and natural gas properties are concentrated in the Gulf Coast and Rocky Mountain regions in the United States.  Currently our properties with proved and producing reserves in the Gulf Coast region are situated in Mississippi, Texas, Louisiana and Alabama, and in the Rocky Mountain region are primarily situated in Montana, North Dakota, Utah and Wyoming.  Our primary focus is using CO2 in enhanced oil recovery (“EOR”), which we have been doing actively for over 12 years in the Gulf Coast region.  EOR, which we also refer to as “tertiary recovery” (as opposed to primary and secondary recovery), is a term used to represent techniques for extracting incremental oil out of existing oil fields.  We acquired Encore during 2010 with the intent to employ our tertiary recovery strategy using CO2 throughout the Rocky Mountain region.  As part of the Encore Merger, we obtained a significant acreage position in the Bakken play in North Dakota, one of the more significant oil plays in North America.  Our current properties provide us significant growth potential through the remainder of this decade.

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 Denbury Resources Inc.

Our Gulf Coast EOR operations are driven by CO2 produced from our natural source at Jackson Dome, Mississippi, which is transported to our Gulf Coast tertiary fields through pipelines that we either own or control through long-term financing leases.  In the Rocky Mountain region, we made significant strides in executing our EOR strategy during 2011.  We were able to secure significant Rocky Mountain CO2reserves with the acquisition of the remaining interest in the Riley Ridge Federal Unit (“Riley Ridge”), and we completed the first 115 miles of the initial 232-mile segment of the 20-inch Greencore CO2pipeline, which will serve as part of our trunk-line in the region.  Although our development of tertiary fields, CO2 sources and pipelines in this new area is just beginning, we believe that Riley Ridge and other potential sources of CO2in the area will allow us to utilize CO2 injection to potentially recover significant amounts of incremental oil from old oil fields.  Each of our significant development areas and planned activities is discussed in more detail below.

The following table provides a summary by field and region of selected proved oil and natural gas reserve information, including total proved reserve quantities and the associated PV-10 Value of those reserves as of December 31, 2011, and average daily production and net revenue interest (“NRI”) for 2011.  The reserve estimates for all years presented were prepared by DeGolyer and MacNaughton, independent petroleum engineers located in Dallas, Texas.  We serve as operator of virtually all of our significant properties, in which we also own most of the interests, although typically less than a 100% working interest, and a lesser net revenue interest due to royalties and other burdens.  For additional reserve information, see Estimated Net Quantities of Proved Oil and Natural Gas Reserves and Present Value of Estimated Future Net Revenues below.

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 Denbury Resources Inc.

			Proved Reserves as of December 31, 2011(1)							2011 Average Daily Production
			Oil	Natural Gas			BOE	PV-10 Value(2)		Oil	Natural Gas	Average
			(MBbls)		(MMcf)	MBOEs	% of total	(000's)		(Bbls/d)	(Mcf/d)	2011 NRI
Gulf Coast region
Tertiary Oil Properties
	Phase 1
		Brookhaven	13,552		-	13,552	2.9%	$	561,962	3,255	-	81.2%
		McComb Area	6,540		-	6,540	1.4%		265,354	1,997	-	79.9%
		Mallalieu	8,033		-	8,033	1.7%		300,810	2,693	-	78.0%
		Other	6,667		-	6,667	1.4%		273,064	3,026	-	69.0%
	Phase 2
		Heidelberg	31,096		-	31,096	6.7%		930,408	3,448	-	84.7%
		Eucutta	8,720		-	8,720	1.9%		367,952	3,121	-	83.2%
		Soso	6,291		-	6,291	1.4%		234,858	2,347	-	77.2%
		Martinville	988		-	988	0.2%		24,465	462	-	77.2%
	Phase 3 (Tinsley)		31,325		-	31,325	6.8%		1,415,835	6,743	-	80.1%
	Phase 4 (Cranfield)		7,628		-	7,628	1.7%		343,077	1,123	-	77.9%
	Phase 5 (Delhi)		26,805		-	26,805	5.8%		1,020,302	2,739	-	76.3%
	Phase 8 (Oyster Bayou)(3)		-		-	-	0.0%		-	5	-	87.5%
		Total Tertiary Oil Properties	147,645		-	147,645	31.9%		5,738,087	30,959	-	78.8%
Non-Tertiary Properties
	Conroe		14,589		22,624	18,359	4.0%		338,168	2,336	2,765	81.2%
	Heidelberg		9,880		47,650	17,821	3.9%		373,661	2,239	8,343	76.8%
	Citronelle		7,490		-	7,490	1.6%		160,852	991	-	63.5%
	Hastings		7,100		-	7,100	1.5%		258,655	1,131	7	82.6%
	Other(4)		9,151		29,559	14,078	3.1%		334,453	2,440	10,622	15.7%
		Total Non-Tertiary Properties	48,210		99,833	64,848	14.1%		1,465,789	9,137	21,737	36.8%
		Total Gulf Coast region	195,855		99,833	212,493	46.0%		7,203,876	40,096	21,737	62.4%
Rocky Mountain region
Non-Tertiary Properties
	Cedar Creek Anticline		63,762		12,923	65,916	14.3%		1,342,444	8,736	1,393	66.7%
	Bakken		78,753		90,618	93,856	20.3%		1,511,622	7,957	4,984	26.3%
	Bell Creek		1,966		-	1,966	0.4%		53,092	889	-	85.2%
	Paradox		6,234		809	6,369	1.4%		100,311	655	59	11.0%
	Riley Ridge(5)		1		414,534	69,090	15.0%		16,889	-	60	43.9%
	Other		11,162		6,491	12,244	2.6%		330,905	2,403	1,309	30.8%
		Total Rocky Mountain region	161,878		525,375	249,441	54.0%		3,355,263	20,640	7,805	36.0%
Company Total			357,733		625,208	461,934	100.0%	$	10,559,139	60,736	29,542	51.0%
(1)		The reserves were prepared in accordance with Financial Accounting Standards Board Codification ("FASC") Topic 932, Extractive Industries - Oil and Gas, using the average first-day-of-the-month prices for each month during 2011, which for NYMEX oil was $96.19 per Bbl, adjusted to prices received by field, and for natural gas was a Henry Hub cash price of $4.16 per MMBtu, also adjusted to prices received by field.

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 Denbury Resources Inc.

(2)	PV-10 Value is a non-GAAP measure and is different from the Standardized Measure of Discounted Future Net Cash Flows ("Standardized Measure") in that PV-10 Value is a pre-tax number and the Standardized Measure is an after-tax number.  The information used to calculate PV-10 Value is derived directly from data determined in accordance with FASC Topic 932.  See the definition of PV-10 Value in the Glossary and Selected Abbreviations.  The Standardized Measure was $7.0 billion at December 31, 2011.  A comparison of PV-10 Value to the Standardized Measure is included in the reserves table in Estimated Net Quantities of Proved Oil and Natural Gas Reserves and Present Value of Estimated Future Net Revenues below.
(3)	We commenced production from Oyster Bayou 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 during 2012.  At December 31, 2011, we did not have any tertiary production from our fields in Phases 6 and 7.  Phase 6, Citronelle Field, will require an extension to the Free State CO2 Pipeline or another pipeline, depending on the ultimate CO2 source for this field, the timing of which is uncertain.  Phase 7, Hastings Field, is currently being injected with CO2, with first tertiary oil response in early 2012.
(4)	Includes certain non-core Gulf Coast properties scheduled to be sold during the first quarter of 2012.  See Note 14, Subsequent Events, to the Consolidated Financial Statements.  These assets had proved reserves of 6,369 MBOE at December 31, 2011.
(5)	The PV-10 Value of oil and natural gas properties associated with Riley Ridge does not include the discounted future net revenues associated with the Company's right to extract and sell the helium on behalf of the U.S. government, which we estimate to be $124.5 million at December 31, 2011.

Enhanced Oil Recovery Overview. CO2 used in EOR is one of the most efficient tertiary recovery mechanisms for producing crude oil.  The CO2 acts somewhat like a solvent, mixing with the oil and ultimately freeing the oil from the formation as the CO2 passes through reservoir rock.  CO2 tertiary floods are unique in that they require large volumes of CO2.  To our knowledge, the location of large quantities of natural CO2in the United States is limited to a few geological basins.

While enhanced oil recovery projects utilizing CO2 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) CO2injection 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 CO2 operations in August 1999, when we acquired Little Creek Field, followed by our acquisition of Jackson Dome CO2 reserves and the NEJD pipeline in 2001.  Based upon our success at Little Creek and the ownership of the CO2 reserves, we began to transition our capital spending and acquisition efforts to focus a greater percentage on CO2 EOR and, over time, transformed our strategy to focus almost exclusively on CO2 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 CO2knownto us, and these large volumes of CO2have allowed us to significantly grow our production in that region. In addition to the sources of CO2we currently have, we are pursuing anthropogenic (man-made) sources of CO2 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 CO2.  We refer to our Gulf Coast tertiary recovery operations by labeling our operating areas or groups of fields as Phases:

·      Phase 1 is in southwest Mississippi and includes several fields along our 183-mile NEJD CO2 Pipeline, including the current tertiary fields of Little Creek, Mallalieu, McComb, Brookhaven and Lockhart Crossing;

·      Phase 2, which began with the early 2006 completion of the Free State CO2 Pipeline to east Mississippi, currently includes Eucutta, Soso, Martinville and Heidelberg Fields;

·      Phase 3, which includes Tinsley Field located northwest of Jackson, Mississippi, was acquired in January 2006 and is serviced by the Delta CO2 Pipeline;

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 Denbury Resources Inc.

·      Phase 4 includes Cranfield and Lake St. John Fields, two fields near the Mississippi/Louisiana border located west of the Phase 1 fields, of which only Cranfield is currently an active tertiary flood;

·      Phase 5 is Delhi Field, a Louisiana field we acquired in 2006, located southwest of Tinsley Field, from which our first tertiary oil response occurred during early 2010;

·      Phase 6 is Citronelle Field in southwest Alabama, another field acquired in 2006, which will require an extension to the Free State CO2 Pipeline or another pipeline depending on the ultimate CO2 source for this field, the timing of which is uncertain at this time;

·      Phase 7 is Hastings Field in southeast Texas, a field we purchased in February 2009, where we commenced CO2 injections during December 2010 in conjunction with placing the final leg of the Green Pipeline into service and where we had first tertiary oil response in early 2012;

·      Phase 8 primarily includes Oyster Bayou Field in southeast Texas, acquired in 2007, where we initiated CO2 injections in June 2010 and where we had our first tertiary oil response during December 2011; and

·      Phase 9 is Conroe Field, a field we purchased in December 2009, which will require construction of an additional CO2 pipeline to connect the field to the Green Pipeline in southeast Texas.

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 oilfields 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 CO2-producing properties or CO2 pipelines, but do include CO2 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 CO2 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 CO2 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 CO2: Bell Creek Field, Grieve Field and Cedar Creek Anticline.  We have contracted to purchase CO2 from the Lost Cabin gas plant in central Wyoming and are currently constructing the Greencore pipeline to deliver CO2 from the gas plant to our Bell Creek Field.  We currently plan to begin injection of CO2 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 CO2for our currently planned and future potential projects in the area.

Gulf Coast Region

CO2Sources

Jackson Dome.Our Gulf Coast CO2source, Jackson Dome, located near Jackson, Mississippi, was discovered during the 1970s while being explored for hydrocarbons.  This significant and relatively pure source of CO2(98% CO2) is the only significant deposit of CO2in 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 CO2 pipeline.  This acquisition provided the platform to significantly expand our CO2 tertiary recovery operations by assuring that CO2 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 CO2-producing wells, significantly increasing our estimated proved Gulf Coast CO2 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 CO2 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 CO2 reserve estimates are based on a gross working interest of the CO2 reserves, of which Denbury’s net revenue interest is approximately 5.3 Tcf and is included in the evaluation of proved CO2 reserves prepared by our outside reserve engineer, DeGolyer and MacNaughton.  In discussing our available CO2 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 CO2 production stream.

In addition to the proved reserves, we estimate that we have an additional 2.5 Tcf of probable CO2 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 CO2 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 CO2 reserves will be developed.

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Although our current proved and potential CO2reserves are quite large, in order to continue our tertiary development of oil fields in the Gulf Coast region, incremental deliverability of CO2 is required.  In order to obtain additional CO2 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 CO2 wells and started the drilling of an exploration CO2 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 CO2 through our controlled pipeline network.

In addition to using CO2 for our Gulf Coast tertiary operations, we sell CO2 to third-party industrial users under long-term contracts and have three CO2 volumetric production payment contracts (“VPPs”).  Approximately 91% of our average daily CO2production 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 CO2 to commercial users, and we used an average of 920 MMcf/d for our tertiary activities.  We are continuing to increase our CO2 production, which averaged 1,024 MMcf/d during the fourth quarter of 2011, a 5% increase over the fourth quarter of 2010 CO2 production levels.  We estimate that our planned 2012 tertiary operations will require additional CO2 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 CO2to the appropriate oil fields.

Gulf Coast Anthropogenic CO2 Sources.  In addition to our natural source of CO2, we have entered into long-term contracts to purchase man-made CO2 from six proposed plants or sources in the Gulf Coast region that will emit large volumes of CO2.  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 CO2 to our EOR operations, although under certain circumstances they could provide up to 270 MMcf/d of CO2.  If the remaining four plants were to also be built, we currently estimate these additional CO2sources could potentially provide us with aggregate CO2volumes 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 CO2.  We are in ongoing discussions with several of these other potential sources.

In addition to the potential anthropogenic CO2 sources located in the Gulf Coast, we have entered into long-term contracts to purchase man-made CO2 from four proposed plants in the Midwest (Illinois, Indiana and Kentucky).  Any CO2 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 CO2 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 CO2 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 CO2 purchase commitments.

In addition to potential CO2 sources discussed above, we continue to have ongoing discussions with owners of existing plants of various types that emit CO2 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 CO2, generally less than the proposed gasification plants, but such volumes may still be attractive if the source is located near our CO2 pipelines.  The capture of CO2 could also be influenced by potential federal legislation, which could impose economic penalties for the emission of CO2.  We believe that we are a likely purchaser of CO2 produced in our areas of operation because of the scale of our tertiary operations, our CO2 pipeline infrastructure and our large natural sources of CO2, which can act as a swing CO2 source to balance CO2 supply and demand.

Gulf Coast CO2 Pipelines. We acquired the 183-mile NEJD CO2 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 CO2 pipelines that give us the ability to deliver CO2 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 CO2 pipelines in the Gulf Coast region. In addition to the NEJD CO2pipeline, the major pipelines are the Free State Pipeline (90 miles), the Delta Pipeline (110 miles) and the Green Pipeline (325 miles).

In December 2010 we completed the final construction of the Green Pipeline that allowed the first CO2 injection into the Hastings Field, located near Houston, Texas.  The completion of the Green Pipeline gives us the ability to deliver CO2 to oil fields all along the Gulf Coast from Baton Rouge, Louisiana to Alvin, Texas.  At the present time, all CO2 flowing in the Green Pipeline is delivered from the Jackson Dome area, but we expect to transport and deliver both natural and anthropogenic CO2 volumes in the future as the anthropogenic sources are built and begin deliveries to the system.

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Gulf Coast Tertiary Properties

Phase 1. Phase 1 includes several fields along our NEJD CO2 pipeline, which runs through southwest Mississippi and into Louisiana.  This phase includes some of our most mature CO2 floods, including our initial CO2 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 CO2 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 CO2 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 CO2when compared to oil, CO2 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 CO2 for a given volume and then CO2 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 CO2 in December 2008.  Unlike the majority of fields in our other Phases, fields in Phase 2 typically contain multiple reservoirs that are amenable to CO2 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 CO2 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 CO2injections at Heidelberg Field, which consists of an East and West Unit.  Construction of the CO2 facility, connecting pipeline and well work commenced on the West Unit during 2008, with our first CO2 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 CO2 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 CO2 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 CO2 enhanced oil recovery operations is the Woodruff formation, although there is additional potential in the Perry sandstone and other smaller reservoirs.  We initiated limited CO2 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.

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In 2011, we focused on developing the southern half of the East Fault Block.  As we were expanding the CO2 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 CO2 injection into the specific target zones. As a result, we had to stop injecting CO2 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 CO2 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-CO2 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 CO2 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 CO2pipeline.  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 CO2 injection and sequestration at Cranfield, to better define and understand the movement of CO2 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 CO2 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 CO2 Pipeline or a man-made source of CO2 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 CO2 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 CO2 EOR projects.  Each vertical interval will have dedicated CO2 injection wells and dedicated producing wells.  We initiated CO2 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

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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 CO2 injections there in June 2010.  Oyster Bayou Field is somewhat unique when compared to our other CO2 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 CO2 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 CO2.

A pipeline must be constructed so that CO2 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 CO2 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 CO2 EOR and, as described previously above, are in the process of converting the East Heidelberg waterflood units to CO2 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

CO2 Sources

Riley Ridge.  Our primary future Rocky Mountain CO2source, Riley Ridge, which is located in southwestern Wyoming, commenced natural gas production in the mid-1980s.  The gas composition from Riley Ridge is approximately 65% CO2, 19% natural gas, 5% hydrogen sulfide (H2S), 0.6% helium, and the remainder other gases.

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 We acquired Riley Ridge in two phases.  In October 2010, we acquired a 42.5% non-operated working interest for $132.3 million after closing adjustments.  This initial purchase included a 42.5% interest in a gas plant that was under construction and that will separate the helium and natural gas from the gas stream.  In August 2011, we acquired the remaining 57.5% working interest in Riley Ridge and the remaining interest in the gas plant.  As a result of the second phase of the transaction, we became the operator of the project.  The purchase price for the second phase was $214.8 million after closing adjustments, including a $15 million deferred payment to be made at the time the gas plant is operational and meets specific performance conditions.  We expect the gas plant to be operational during the second quarter of 2012.

As of December 31, 2011, our interest in Riley Ridge and minor surrounding acreage contained net proved reserves of 415 Bcf of natural gas and 2.2 Tcf of CO2 reserves.  The CO2 reserve estimates are based on the gross working interest of the CO2 reserves, in 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 right 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, presented net of amounts to be remitted the U.S. government.  In addition, we believe there is significant reserve potential in other acreage surrounding Riley Ridge in which we also own an interest.

The gas plant under construction at Riley Ridge will separate the natural gas and helium from the full well stream and the remaining gases, including CO2, will initially be reinjected into the producing formation until a planned CO2 capture facility and pipeline can be built.  We have initiated the engineering and design of the CO2 capture facility, which is estimated to initially capture up to 130 MMcf/d of CO2.  In addition to designing the CO2 capture facility, we are preparing development plans for the adjoining acreage, which when fully developed is expected to add 450 MMcf/d to 520 MMcf/d of CO2 (100% working interest), or an estimated total CO2 production from this asset of up to 650 MMcf/d (100% working interest).  The development plan to achieve these rates is expected to take up to 10 years.  We estimate 2012 capital costs for Riley Ridge at approximately $70 million in order to complete the initial phase of the facilities, drill one producer well and one injector well, build flow lines, and conduct engineering studies on CO2 capture and separation.

Rocky Mountain Anthropogenic CO2 Sources.  We have ongoing discussions with and are actively pursuing several sources for anthropogenic CO2 supply in the Rocky Mountain region.  We have contracted to purchase CO2 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 CO2 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 CO2.  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 CO2 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 CO2, with an option to purchase up to 50 MMcf/d of CO2 from ExxonMobil’s LaBarge facility.  We intend to utilize the CO2 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 CO2 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 CO2 for our enhanced oil recovery operations in Wyoming and Montana.  We expect to begin taking delivery of this CO2 in approximately four years following commencement of construction.  The purchase price of CO2 will fluctuate based on changes in the price of oil.  As is the case with all of our long-term supply contracts to purchase CO2, 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 CO2 pipeline constructed by Denbury in the Rocky Mountain region.  As currently planned, the pipeline will eventually connect our Lost Cabin Plant CO2 source to the Cedar Creek Anticline in eastern Montana, and ultimately connect our CO2 source at Riley Ridge (see Rocky Mountain CO2 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

Grieve Field. In May 2011, Denbury entered into a farm-in agreement, under which we have the right to acquire up to 65% of the working interest in the Grieve Field, located in Natrona County, Wyoming.  We estimate that the Grieve project has the potential for recovery of approximately 12 MMBbls of gross oil, or 6.1 MMBbls net to our revenue interest.  We are overseeing operations, design, construction and operations of the field.  We are contracting for the construction of the CO2 recycle facility and the required three-mile CO2 pipeline to deliver CO2 from an existing CO2 pipeline to the Grieve Field.  We estimate first CO2 injection at Grieve Field in the third quarter of 2012, with first EOR production estimated in 2014.  We plan to invest $39 million in Grieve Field in 2012, primarily to install a three-mile pipeline and to install injection and power infrastructure.

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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 CO2 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 CO2 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 CO2 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 CO2 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 CO2 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

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 Denbury Resources Inc.

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:

	Developed				Undeveloped				Total
	Gross		Net		Gross		Net		Gross		Net
Gulf Coast		259,926		215,886		425,691		108,162		685,617		324,048
Rocky Mountain		371,412		280,805		458,890		256,613		830,302		537,418
Total		631,338		496,691		884,581		364,775		1,515,919		861,466

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:

	Producing Natural
	Producing Oil Wells				Gas Wells				Total
	Gross		Net		Gross		Net		Gross		Net
Operated Wells:
Gulf Coast region		1,249		1,155.0		251		229.8		1,500		1,384.8
Rocky Mountain region		859		735.4		3		2.4		862		737.8
Total		2,108		1,890.4		254		232.2		2,362		2,122.6
Non-Operated Wells:
Gulf Coast region		66		3.0		221		1.4		287		4.4
Rocky Mountain region		504		65.1		2		0.1		506		65.2
Total		570		68.1		223		1.5		793		69.6
Total Wells:
Gulf Coast region		1,315		1,158.0		472		231.2		1,787		1,389.2
Rocky Mountain region		1,363		800.5		5		2.5		1,368		803.0
Total		2,678		1,958.5		477		233.7		3,155		2,192.2

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 Denbury Resources Inc.

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.

		Year Ended December 31,
		2011				2010				2009
		Gross		Net		Gross		Net		Gross		Net
Exploratory Wells:(1)
	Productive(2)		-		-		-		-		1		1.0
	Non-productive(3)		1		0.7		-		-		-		-
Development Wells:(1)
	Productive(2)		221		116.6		127		62.8		23		16.6
	Non-productive(3)(4)		-		-		-		-		-		-
	Total		222		117.3		127		62.8		24		17.6
(1)	An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well. A development well is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
(2)	A productive well is an exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
(3)	A non-productive well is an exploratory or development well that is not a productive well.
(4)	During 2011, 2010 and 2009, an additional 46, 41 and 20 wells, respectively, were drilled for water or CO2 injection purposes.

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:

		Year Ended December 31,
		2011		2010		2009
Net sales volume:
	Gulf Coast region
	Oil (MBbls)		14,635		14,657		13,487
	Natural gas (MMcf)		7,934		22,271		24,851
	Total Gulf Coast region (MBOE)		15,957		18,369		17,629
	Rocky Mountain region
	Oil (MBbls)		7,534		7,212		-
	Natural gas (MMcf)		2,849		6,220		-
	Total Rocky Mountain region (MBOE)		8,009		8,249		-
	Total Company (MBOE)		23,966		26,618		17,629
Average sales price:
	Gulf Coast region
	Oil (per Bbl)	$	105.23	$	78.35	$	57.75
	Natural gas (per Mcf)		4.31		4.56		3.54
	Rocky Mountain region
	Oil (per Bbl)	$	89.93	$	71.12	$	-
	Natural gas (per Mcf)		6.12		4.90		-
	Total Company
	Oil (per Bbl)	$	100.03	$	75.97	$	57.75
	Natural gas (per Mcf)		4.79		4.63		3.54

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 Denbury Resources Inc.

		Year Ended December 31,
		2011		2010		2009
Average production cost (per BOE sold):(1)
	Gulf Coast region	$	24.51	$	19.94	$	17.85
	Rocky Mountain region		14.52		12.61		-
	Total Company		21.17		17.67		17.85
(1)	Excludes oil and natural gas ad valorem and production taxes.

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.

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 Denbury Resources Inc.

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 CO2 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 CO2 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

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 Denbury Resources Inc.

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 CO2 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 CO2or 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 CO2, 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 CO2 or other gases could also create economic incentives for technologies and practices that reduce or avoid such emissions, including processes that sequester CO2 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 CO2, 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

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 Denbury Resources Inc.

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 CO2; (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 CO2 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 CO2 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).

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 Denbury Resources Inc.

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.

			December 31,
			2011		2010		2009
Estimated Proved Reserves
	Oil (MBbls)			357,733		338,276		192,879
	Natural gas (MMcf)			625,208		357,893		87,975
	Oil equivalent (MBOE)			461,934		397,925		207,542
Reserve Volumes Categories
	Proved developed producing:
		Oil (MBbls)		189,904		186,705		93,833
		Natural gas (MMcf)		116,562		104,050		67,952
		Oil equivalent (MBOE)		209,331		204,047		105,158
	Proved developed non-producing:
		Oil (MBbls)		49,837		32,372		22,359
		Natural gas (MMcf)		9,408		6,466		1,561
		Oil equivalent (MBOE)		51,405		33,450		22,619
	Proved undeveloped:
		Oil (MBbls)		117,992		119,199		76,687
		Natural gas (MMcf)		499,238		247,377		18,462
		Oil equivalent (MBOE)		201,198		160,428		79,765
Percentage of Total MBOE:
	Proved developed producing			45%		51%		51%
	Proved developed non-producing			11%		9%		11%
	Proved undeveloped			44%		40%		38%
Representative Oil and Natural Gas Prices:(1)
	Oil - NYMEX		$	96.19	$	79.43	$	61.18
	Natural gas - Henry Hub		$	4.16	$	4.40	$	3.87
Present Values (thousands):(2)
	Discounted estimated future net cash flow before income taxes (PV-10 Value)(3)		$	10,559,139	$	7,292,344	$	3,075,459
	Standardized measure of discounted estimated future net cash flow after income taxes ("Standardized Measure")		$	7,007,605	$	4,917,927	$	2,457,385
(1)	The reference prices were based on the average first day of the month prices for each month during the respective year, adjusted for differentials by field to arrive at the appropriate net price Denbury receives.  See Operating Results in Management’s Discussion and Analysis of Financial Condition and Results of Operations for details of oil and natural gas prices received, both including and excluding the impact of derivative settlements.
(2)	Determined based on the average first day of the month prices for each month, adjusted to prices received by field in accordance with standards set forth in the FASC.
(3)	PV-10 Value is a non-GAAP measure and is different from the Standardized Measure in that PV-10 Value is a pre-tax number and the Standardized Measure is an after-tax number.  The information used to calculate PV-10 Value is derived directly from data determined in accordance with FASC Topic 932.  The difference between these two amounts, the discounted estimated future income tax (in thousands) was $3,551,534 at December 31, 2011, $2,374,417 at December 31, 2010, and $618,074 at December 31, 2009.  We believe that PV-10 Value is a useful supplemental disclosure to the Standardized Measure because the Standardized Measure can be impacted by a company’s unique tax situation, and it is not practical to calculate the Standardized Measure on a property-by-property basis.  Because of this, PV-10 Value is a widely used measure within the industry and is commonly used by securities analysts, banks and credit rating agencies to evaluate the estimated future net cash flows from proved reserves on a comparative basis across companies or specific properties.  PV-10 Value is commonly used by us and others in our industry to evaluate properties that are bought and sold and to assess the potential return on investment in our oil and gas properties. PV-10 Value is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for the Standardized Measure.  Our PV-10 Value and the Standardized Measure do not purport to represent the fair value of our oil and natural gas reserves. See Glossary and Selected Abbreviations for the definition of "PV-10 Value" and see Note 15, Supplemental Oil and Natural Gas Disclosures (Unaudited), to the Consolidated Financial Statements for additional disclosures about the Standardized Measure.

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.

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 Denbury Resources Inc.

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:

·      the level of worldwide consumer demand for oil and natural gas;

·      the domestic and foreign supply of oil and natural gas;

·      the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

·      domestic governmental regulations and taxes;

·      the price and availability of alternative fuel sources;

·      weather conditions, including hurricanes and tropical storms in and around the Gulf of Mexico that can damage oil and natural gas facilities and delivery systems and disrupt operations, and winter conditions in the Rocky Mountains that can delay or impede operations;

·      market uncertainty;

·      worldwide political events and conditions, including actions taken by foreign oil and gas producing nations; and

·      worldwide economic conditions.

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.

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 Denbury Resources Inc.

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 CO2 tertiary recovery operations. The crude oil production from our tertiary recovery projects depends on having access to sufficient amounts of CO2.  Our ability to produce this oil would be hindered if our supply of CO2 were limited due to problems with our current CO2 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 CO2 and inject adequate amounts of CO2 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 CO2 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 CO2 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 CO2 to our oil fields at a cost that is economically viable.  Our ongoing construction of CO2 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 CO2 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:

·      a substantial portion of our cash flows from operations may be dedicated to servicing our indebtedness and would not be available for capital expenditures or other purposes;

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 Denbury Resources Inc.

·      our level of indebtedness may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or general corporate and other purposes;

·      our interest expense may increase in the event of increases in market interest rates, because bank borrowings are at variable rates of interest;

·      our vulnerability to general adverse economic and industry conditions may be greater as a result of our level of indebtedness, and increases in interest rates thereon, potentially restricting us from making acquisitions, introducing new technologies or exploiting business opportunities;

·      our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments may be limited by the covenants contained in the agreements governing our outstanding indebtedness limit; and

·      our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry.  Our failure to comply with such covenants could result in an event of default under such debt instruments which, if not cured or waived, could have a material adverse effect on us.

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:

·      production is less than expected;

·      the counter-party to the derivative contract defaults on its contract obligations; or

·      there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.

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 CO2 for tertiary recovery and the related infrastructure requires significant capital investment, up to four or five yearsprior 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.

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 Denbury Resources Inc.

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:

·      unexpected drilling conditions;

·      title problems;

·      pressure or irregularities in formations;

·      equipment failures or accidents;

·      adverse weather conditions, including hurricanes and tropical storms in and around the Gulf of Mexico that can damage oil and natural gas facilities and delivery systems and disrupt operations, and winter conditions in the Rocky Mountain region that can delay or impede operations;

·      compliance with environmental and other governmental requirements; and

·      cost of, or shortages or delays in the availability of, drilling rigs, equipment, pipelines and services.

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 CO2 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 CO2 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 CO2 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

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 Denbury Resources Inc.

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 CO2 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

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 Denbury Resources Inc.

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 CO2, 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.

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 Denbury Resources Inc.

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.

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 Denbury Resources Inc.

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.

	2011				2010
	High		Low		High		Low
First Quarter	$	24.56	$	18.45	$	16.87	$	13.55
Second Quarter		24.86		18.70		19.15		14.64
Third Quarter		20.85		11.50		17.02		14.18
Fourth Quarter		17.45		10.86		19.79		16.24

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.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Month	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
October 2011		11,017,712	$	13.59		10,990,939		-
November 2011		1,105,440		14.79		1,092,501		-
December 2011		2,036,070		14.76		2,029,170		-
Total		14,159,222		13.85		14,112,610		-

Between early October 2011, when we announced the commencement of a common share repurchase program for up to $500 million of Denbury common stock, and December 31, 2011, we have 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.

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.

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 Denbury Resources Inc.

Share Performance Graph

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.

[Missing Graphic Reference]

	December 31,
	2006		2007		2008		2009		2010		2011
Denbury Resources Inc.	$	100.00	$	214.11	$	78.59	$	106.51	$	137.39	$	108.67
S&P 500 (1)		100.00		105.49		66.46		84.05		96.71		98.75