DENBURY INC - Annual Report: 2012 (Form 10-K)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

2012 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, 2012

o 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 o

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 o 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 o

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 o

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. o

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 o Non-accelerated filer o Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes o 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 $5,050,462,439.

The number of shares outstanding of the registrant’s Common Stock as of January 31, 2013, was 373,462,597.

DOCUMENTS INCORPORATED BY REFERENCE



Document:		Incorporated as to:
1. Notice and Proxy Statement for the Annual Meeting of Stockholders to be held May 22, 2013.		1. Part III, Items 10, 11, 12, 13, 14

Table of Contents

Denbury Resources Inc.

2012 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	27
Item 1B.	Unresolved Staff Comments	34
Item 2.	Properties	34
Item 3.	Legal Proceedings	34
Item 4.	Mine Safety Disclosures	34

	PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	35
Item 6.	Selected Financial Data	37
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	65
Item 8.	Financial Statements and Supplementary Data	65
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	113
Item 9A.	Controls and Procedures	113
Item 9B.	Other Information	113

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance	114
Item 11.	Executive Compensation	114
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	114
Item 13.	Certain Relationships and Related Transactions, and Director Independence	114
Item 14.	Principal Accountant Fees and Services	114

	PART IV

Item 15.	Exhibits and Financial Statement Schedules	115
	Signatures	122

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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 Costs	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.

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.

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.

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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 4 to the table included in Item 1, Estimated Net Quantities of Proved Oil and Natural Gas Reserves and Present Value of Estimated Future Net Revenues - Oil and Natural Gas Reserve Estimates.

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://www.ecfr.gov/cgi-bin/text-idx?c=ecfr&rgn=div5&view=text&node=17:2.0.1.1.8&idno=17.

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PART I

Item 1. Business and Properties

GENERAL

Denbury Resources Inc., a Delaware corporation, is a domestic independent oil and natural gas company with 409.4 MMBOE of estimated proved oil and natural gas reserves as of December 31, 2012, of which 80% is oil. Our primary focus is on enhanced oil recovery utilizing CO₂, and our operations are focused in two key operating areas: the Gulf Coast region and Rocky Mountain region. We are the largest combined oil and natural gas producer in both Mississippi and Montana, and we own the largest reserves of CO₂ used for tertiary oil recovery east of the Mississippi River. Our goal is to increase the value of acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis 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. 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, 2012, we had 1,432 employees, 766 of whom were employed in field operations or at our 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 Annual Report on Form 10-K ("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.

2012 BUSINESS DEVELOPMENTS


•	Increased our average tertiary oil production to 35,206 Bbls/d in 2012, a 14% increase from average tertiary production in 2011 due to contributions from our newest CO₂ floods at Oyster Bayou and Hastings fields and expansion of our existing CO₂floods at Tinsley, Heidelberg and Delhi fields.


•	Added estimated proved tertiary reserves of 69.5 MMBbls, primarily including initial tertiary reserve bookings of 42.6 MMBbls at Hastings Field and 14.1 MMBbls at Oyster Bayou Field. The combined PV-10 value of the proved tertiary reserves at Hastings and Oyster Bayou fields at December 31, 2012 was $1.7 billion.


•	Completed construction of the first section of the Greencore pipeline, our first CO₂ pipeline in the Rocky Mountain region, which is on schedule to begin deliveries of CO₂ from the Lost Cabin gas plant to our Bell Creek Field in Montana in the first half of 2013.


•	Continued our share repurchase program, under which we repurchased a total of 17.0 million shares of Denbury common stock for $266.7 million during 2012, in addition to 14.1 million shares of Denbury common stock repurchased in 2011 for

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$195.2 million. As of February 21, 2013, we had spent a total of $521.0 million to repurchase an aggregate of 34.6 million shares, or approximately 8.6% of our outstanding shares as of September 30, 2011, at an average cost of $15.05 per share.

•

Completed or entered into agreements on several strategic and tax efficient property transactions which not only add value, but as importantly, make us a nearly pure CO₂ EOR company. These asset transactions, which included both acquisitions and dispositions, aggregated (or upon completion will aggregate) over $4 billion in value, and (1) resulted in an increase in our unproven potential reserves, which we believe provides us a better opportunity to achieve a higher return due to the nature of the acquired properties compared to the sold properties, (2) nearly replaced the production of the sold assets with that from the acquired or to-be-acquired assets, (3) exchanged proved reserves with a high proved undeveloped component for reserves that are nearly all proved developed, which significantly increases our current free cash flow, (4) increased our Rocky Mountain CO₂ reserves by 1.3 Tcf and up to 115 MMcf/d of deliverability, and (5) positioned us to execute on our long-term strategy which we expect will increase shareholder value for many years to come. A summary of these transactions follows, with more detail on each significant transaction discussed further below:


•	Bakken Exchange Transaction – Divested our Bakken area assets, which were all non-tertiary, at an estimated value of approximately $2.0 billion, in exchange for interests in two future potential tertiary oil fields, a new Rocky Mountain region CO₂ source and $1.3 billion of cash.

•

Pending Cedar Creek Anticline Acquisition – Entered into an agreement in early 2013 to purchase additional interests in the Cedar Creek Anticline ("CCA") in Montana and North Dakota (the "Pending CCA Acquisition"), an area with future potential tertiary oil upside, for $1.05 billion, which will be funded with a portion of the cash proceeds from the Bakken Exchange Transaction. We expect to complete the Pending CCA Acquisition near the end of the first quarter of 2013.

In two separate transactions earlier in 2012, which were also structured as like-kind exchanges for federal income tax purposes, we completed the following:


•	Acquisition of Thompson Field – Acquired a nearly 100% working interest and 84.7% net revenue interest in the Thompson Field in south Texas, a future potential tertiary oil field approximately 18 miles from our current EOR flood at Hastings Field, for $366.2 million.


•	Sale of Non-core Assets – Sold our interests in non-core oil and natural gas fields in the Paradox Basin of Utah and in the Gulf Coast region for $68.5 million and $141.8 million, respectively.

Bakken Exchange Transaction. In late 2012, we closed a sale and exchange transaction with Exxon Mobil Corporation and its wholly-owned subsidiary XTO Energy Inc. (collectively, “ExxonMobil”) under which we sold to ExxonMobil our Bakken area assets in North Dakota and Montana in exchange for $1.3 billion in cash (after preliminary closing adjustments) and EOR assets (the “Bakken Exchange Transaction”). By exchanging these non-tertiary Bakken area assets for EOR assets, we are able to more purely focus our attention on tertiary recovery operations.

The Bakken area assets we sold had proved reserves of approximately 109 MMBOE at the time of sale, of which 66% was undeveloped, and 2012 production through the third quarter of 15,850 BOE/d. The EOR assets acquired in the Bakken Exchange Transaction include: (1) Webster Field, a planned future tertiary field, located in southeastern Texas, with nearly 100% working interest and 80% net revenue interest, proved reserves of 3.7 MMBOE and production of approximately 1,000 BOE/d; (2) Hartzog Draw Field, a planned future tertiary field located in Wyoming, consisting of an 83% working interest and 71% net revenue interest in the oil-producing Shannon Sandstone zone and a 67% working interest and 53% net revenue interest in the natural gas-producing Big George Coal zone, with proved reserves of 5.2 MMBOE and production of approximately 2,600 BOE/d; and (3) approximately a one-third overriding royalty ownership interest in ExxonMobil's CO₂ reserves in LaBarge Field in Wyoming with proved reserves of 1.3 Tcf and estimated deliverability of up to 115 MMcf/d.

Pending CCA Acquisition. In January 2013, we entered into an agreement to acquire producing assets in the CCA of Montana and North Dakota from a wholly-owned subsidiary of ConocoPhillips for $1.05 billion in cash, before standard closing adjustments primarily for revenues and costs of the properties to be purchased from the January 1, 2013 effective date to the closing date. We plan to fund the acquisition with a portion of the cash proceeds from the Bakken Exchange Transaction in order to qualify the acquisition for like-kind-exchange treatment under federal income tax rules. We expect the Pending CCA Acquisition to close near the end of the first quarter of 2013.

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The assets we plan to purchase from ConocoPhillips include both additional interests in certain of our existing operated fields in CCA as well as operating interests in other CCA fields. We currently estimate on a preliminary basis that, as of December 31, 2012, the proved conventional (non-tertiary) reserves associated with the acquired assets, net to our acquired interests, were approximately 42 MMBOE, of which approximately 99% is oil and natural gas liquids, with average daily production of approximately 11,000 BOE/d during the fourth quarter of 2012. We plan to incorporate the newly acquired CCA assets into our CO₂development plan that is currently being designed and to extend the Greencore pipeline north and southwest in order to deliver the CO₂necessary to flood the CCA assets.

Acquisition of Thompson Field. In June 2012, we acquired a nearly 100% working interest and 84.7% net revenue interest in Thompson Field for $366.2 million after preliminary closing adjustments. The field is located approximately 18 miles west of our Hastings Field, which we are currently flooding with CO₂, and which is the current terminus of the Green Pipeline which transports CO₂ from natural sources in the Jackson Dome area of Mississippi. Thompson Field is similar to Hastings Field, producing oil from the Frio zone at similar depths, and is a planned future tertiary field.

Sale of Non-Core Assets. On April 9, 2012, we completed the sale of certain non-operated assets in the Paradox Basin of Utah for $68.5 million cash after final closing adjustments. On February 29, 2012, we completed the sale of certain non-core assets primarily located in central and southern Mississippi and in southern Louisiana for $141.8 million, after final closing adjustments. We structured the sale of our non-core assets and the purchase of Thompson Field as a like-kind-exchange transaction for federal income tax purposes and anticipate deferral of a majority of the taxable gain recognized on the sale of the non-core assets.

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 non-controlling 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. In 2012, we exchanged the Bakken area assets acquired in the Encore Merger for cash and other assets with an estimated value of approximately $2.0 billion (see 2012 Business Developments – Bakken Exchange Transaction above).

OIL AND NATURAL GAS OPERATIONS

Summary. Our oil and natural gas properties are concentrated in the Gulf Coast and Rocky Mountain regions of 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 in Montana, North Dakota and Wyoming. Our primary focus is using CO₂ in EOR, which we have been doing since we acquired Little Creek Field in the Gulf Coast region in 1999. 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 in the Rocky Mountain region. Our current portfolio of properties provides us significant growth potential for more than a decade.

Our Gulf Coast EOR operations are driven by CO₂ produced from natural sources in the Jackson Dome area of Mississippi, which is transported to our Gulf Coast tertiary fields. In late 2012, we received first deliveries of anthropogenic (man-made) CO₂into the Gulf Coast pipeline system from an industrial facility in Port Arthur, Texas. The CO₂ for our Rocky Mountain EOR operations will initially be supplied from the Lost Cabin gas plant in Wyoming and from an overriding royalty interest equivalent to an approximate one-third ownership interest in ExxonMobil's CO₂ reserves in LaBarge Field, which overriding royalty interest we acquired during 2012 in the Bakken Exchange Transaction. In the future, we intend to utilize CO₂ from our Riley Ridge CO₂ source. In 2012, we completed the initial 232-mile segment of the 20-inch Greencore Pipeline, which will serve as part of the planned CO₂trunk line in the region. Although our development of tertiary fields, CO₂ sources and pipelines in the Rocky Mountain

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region is just beginning, we believe that our significant CO₂ sources and planned pipeline infrastructure in the area will allow us to utilize CO₂ injection to potentially recover significant amounts of incremental oil from mature 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, 2012, and average daily production and net revenue interest (“NRI”) for 2012. 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.



	Proved Reserves as of December 31, 2012 ⁽¹⁾						2012 Average Daily Production
	Oil (MBbls)	Natural Gas (MMcf)	MBOEs	BOE % of total		PV-10 Value ⁽²⁾ (000's)	Oil (Bbls/d)	Natural Gas (Mcf/d)	Average 2012 NRI
Tertiary oil properties
Gulf Coast region
Mature properties:
Brookhaven	10,938	—	10,938	2.7	%	467,653	2,692	—	81.2	%
Eucutta	9,251	—	9,251	2.3	%	356,000	2,868	—	83.6	%
Mallalieu	6,450	—	6,450	1.6	%	222,586	2,338	—	78.0	%
Other mature properties ⁽³⁾	27,343	—	27,343	6.6	%	865,308	7,707	—	73.3	%
Delhi	25,038	—	25,038	6.1	%	989,608	4,315	—	76.1	%
Hastings	45,261	—	45,261	11.1	%	1,179,241	2,188	—	82.7	%
Heidelberg	34,599	—	34,599	8.5	%	1,156,508	3,763	—	82.9	%
Oyster Bayou	13,602	—	13,602	3.3	%	496,501	1,388	—	87.0	%
Tinsley	28,430	—	28,430	6.9	%	1,085,180	7,947	—	80.6	%
Total tertiary oil properties	200,912	—	200,912	49.1	%	6,818,585	35,206	—	78.9	%
Non-tertiary oil and gas properties
Gulf Coast region
Mississippi	6,408	28,165	11,102	2.7	%	260,235	1,985	11,662	40.4	%
Texas	33,694	17,861	36,671	9.0	%	1,035,953	4,157	3,477	80.0	%
Other	7,070	1,599	7,337	1.8	%	180,805	1,087	902	22.0	%
Total Gulf Coast region	47,172	47,625	55,110	13.5	%	1,476,993	7,229	16,041	47.3	%
Rocky Mountain region
Cedar Creek Anticline⁽⁴⁾	66,792	425	66,863	16.3	%	1,267,881	8,442	371	65.8	%
Riley Ridge ⁽⁵⁾	2	416,281	69,382	16.9	%	22	—	96	54.8	%
Other	14,246	17,310	17,131	4.2	%	346,111	2,990	1,335	34.9	%
Total Rocky Mountain region	81,040	434,016	153,376	37.4	%	1,614,014	11,432	1,802	53.9	%
Total continuing properties	329,124	481,641	409,398	100.0	%	9,909,592	53,867	17,843	67.0	%
Properties disposed in 2012
Bakken area assets	—	—	—	—	%	—	12,539	11,140
Gulf Coast assets	—	—	—	—	%	—	246	99
Paradox assets	—	—	—	—	%	—	185	27
Total	—	—	—	—	%	—	12,970	11,266
Company Total	329,124	481,641	409,398	100.0	%	9,909,592	66,837	29,109


(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 2012, which for

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NYMEX oil was $94.71 per Bbl, adjusted to prices received by field, and for natural gas was a Henry Hub cash price of $2.85 per MMBtu, also adjusted to prices received by field.

(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 Standardized Measure was $6.4 billion at December 31, 2012. 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. 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.


(3)	Other mature properties include Cranfield, Little Creek, Lockhart Crossing, Martinville, McComb and Soso fields.


(4)	The Cedar Creek Anticline consists of a series of 10 producing oil units, each of which could be considered a field by itself. CCA reserves at December 31, 2012 do not include 42 MMBOE of currently estimated proved reserves we plan to acquire during the first quarter of 2013 through the Pending CCA Acquisition discussed above. See 2012 Business Developments – Pending CCA Acquisition.


(5)	While the Riley Ridge Field reserves make up over 15% of the Company's total reserves, production from the field is currently negligible. We expect production to increase with the startup of the Riley Ridge gas plant in mid-2013.

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 naturally occurring CO₂ in 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 and monitoring methods, (2) CO₂ injection conformance, (3) new completion techniques, (4) varied operating equipment and operating conditions, and (5) application of intense reservoir management and production techniques. We began our 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 primarily, and then almost exclusively, on CO₂ EOR projects. With the sale of our Bakken area assets in late 2012, our asset base today almost entirely relates to current or planned tertiary oil operations. We believe our investments, experience and acquired knowledge give us a strategic and competitive advantage in the areas in which we operate.

Our tertiary operations have grown so that (1) 49% of our proved reserves at December 31, 2012 are proved tertiary oil reserves; (2) approximately 54% of our forecasted 2013 production is expected to come from tertiary oil operations (on a BOE basis); and (3) approximately 85% of our 2013 planned capital expenditures are related to our tertiary oil operations. At year-end 2012, the proved oil reserves in our tertiary recovery oil fields had an estimated PV-10 Value of approximately $6.8 billion, using 12-month first-day-of-the-month unweighted average NYMEX pricing during calendar 2012 of $94.71 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 and time to construct such 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 our Gulf Coast projects at current oil prices is in the $40-per-barrel range, depending on the specific field and area), (3) we have limited competition for this type of activity in our geographic regions, and (4) our EOR activities could be considered more eco-friendly than other current oil and gas development, as we develop existing oil fields thereby not disturbing new habitats, drill fewer new wellbores, do not utilize hydraulic fracturing in our oil and natural gas development operations, and have the ability to geologically store CO₂captured from industrial facilities.

We have been conducting and expanding EOR operations on our assets in the Gulf Coast region since 1999, and as a result, they are more developed from an EOR perspective than our assets in the Rocky Mountain region. In the Gulf Coast region, we

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own what is, to our knowledge, the only significant naturally occurring source of CO₂, and these large volumes of CO₂ have allowed us to significantly grow our production in that region. In addition to the sources of CO₂ we currently own, 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 also provide an economical and eco-friendly way to store CO₂. We started receiving our first anthropogenic CO₂ in the fourth quarter of 2012 from an industrial facility in Port Arthur, Texas and expect the amount of CO₂ we use in our operations coming from anthropogenic sources to grow in the future.

Through December 31, 2012, we have invested a total of $3.0 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 $1.1 billion. Of this total invested amount, approximately $185 million (6%) was spent on fields that did not yet have any appreciable proved reserves at December 31, 2012. The proved oil reserves in our Gulf Coast tertiary oil fields have a year-end 2012 PV-10 Value of $6.8 billion, using the 12-month first-day-of-the-month unweighted average NYMEX pricing during calendar 2012 of $94.71 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 and transportation costs. Including the Green Pipeline, which currently services our Hastings and Oyster Bayou fields, we have invested a total of $2.0 billion in CO₂-producing assets and pipelines in the Gulf Coast region.

We began operations in the Rocky Mountain region in March 2010 as part of the Encore Merger, and as such, we have significantly fewer oil fields and less CO₂ pipeline infrastructure in that region, although we are aggressively developing both. We currently have four properties in the Rocky Mountain region that we plan to flood with CO₂: Bell Creek Field, Grieve Field, Hartzog Draw Field, and Cedar Creek Anticline. The Cedar Creek Anticline is a geological structure over 126 miles in length consisting of 10 different operating units. We have contracted to purchase CO₂ from the Lost Cabin gas plant in central Wyoming and completed construction of the first section of the Greencore Pipeline in late 2012 to deliver CO₂ from such gas plant to our Bell Creek Field. We currently expect to begin purchasing CO₂ from the Lost Cabin plant during the first quarter of 2013 and start injections at Bell Creek Field during the second quarter of 2013. Our Riley Ridge acquisitions in 2010 and 2011 and ExxonMobil CO₂ acquisition in 2012 provide us additional sources of CO₂ for our currently planned and future potential projects in the area.

Tertiary Oil Properties

Gulf Coast Region

CO₂ Sources and Pipelines

Jackson Dome. Our primary Gulf Coast CO₂ source, 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, to our knowledge, the only significant deposit of CO₂ in the United States east of the Mississippi River, 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 also 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 and drilled numerous CO₂-producing wells, significantly increasing our estimated proved Gulf Coast CO₂ reserves from approximately 800 Bcf at the time of acquisition to approximately 6.1 Tcf as of December 31, 2012. The CO₂ reserve estimates are based on a gross working interest of the CO₂ reserves, of which our net revenue interest is approximately 4.8 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 our own tertiary recovery programs and for industrial users who are customers of Denbury and others, as we are responsible for distributing the entire CO₂ production stream.

In addition to the proved reserves, we estimate that we have 2.4 Tcf of probable CO₂ reserves at Jackson Dome, and significant other possible reserves. The majority of our probable reserves at Jackson Dome are located in structures that have been drilled

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and tested in the area but are not currently capable of producing because (1) the original well is plugged; (2) they are located in fault blocks that are immediately adjacent to fault blocks with proved reserves; (3) 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 (4) they are reserves associated with increasing the ultimate recovery factor from our existing reservoirs with proved reserves. Our historically high drilling success rate, coupled with our seismic data across the undrilled structures, provide us with a reasonably high degree of certainty that additional CO₂ reserves will be developed.

Although our current proved CO₂ reserves 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 conducted several 3D seismic surveys in the area over the past several years, and anticipate drilling five development wells in 2013 that are intended to increase productive capacity, three of which could potentially add incremental CO₂ reserves. 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. We expect our current proved reserves of CO₂, coupled with a risked drilling program at Jackson Dome and expected anthropogenic sources, to provide more than enough 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. Additionally, in the future, we believe that once a CO₂ flood reaches its productive economic limit, we could recycle a portion of the CO₂ that remains in that reservoir and utilize it in another tertiary flood.

In addition to using CO₂ for our Gulf Coast tertiary operations, we sell CO₂ to third-party industrial users under long-term contracts and currently have three CO₂ volumetric production payment contracts. Approximately 91% of our average daily CO₂ production in 2012 and 2011 and 87% in 2010 was used in our tertiary recovery operations on our own behalf and on behalf of other working interest owners and royalty owners in our enhanced recovery fields, with the balance delivered to third-party industrial users. During 2012, we sold an average of 92 MMcf/d of CO₂ to commercial users, and we used an average of 933 MMcf/d for our tertiary activities. We are continuing to increase our CO₂ production, which averaged 1,100 MMcf/d during the fourth quarter of 2012, a 7% increase over the fourth quarter of 2011.

Gulf Coast Anthropogenic CO₂ Sources. In addition to our natural source of CO₂, we are currently party to five long-term contracts to purchase man-made CO₂ from five plants that either exist, are currently under construction, or are planned, in the Gulf Coast region. In late 2012, we received first deliveries of anthropogenic CO₂ into the Gulf Coast pipeline system from an industrial facility in Port Arthur, Texas, and we anticipate taking deliveries from another existing plant in 2013 and a plant currently under construction in early 2014. We estimate these three sources will supply approximately 200 MMcf/d of CO₂ to our EOR operations, although under certain circumstances they could provide higher volumes. If the remaining two plants as to which we have long-term CO₂ purchase contracts also were to be built, we currently estimate our anthropogenic CO₂ sources could potentially provide us with aggregate CO₂ volumes of up to 600 MMcf/d. Construction of these two plants is considered probable, although is contingent on the satisfactory resolution of various matters, including financing. While both of these plants may not be constructed, other plants currently being planned could provide us additional anthropogenic CO₂. We are in ongoing discussions with, and/or have entered into contractual arrangements to purchase CO₂ from, several of these other potential sources.

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 and/or transport. 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 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 captured 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 acquired or constructed nearly 750 miles of CO₂ pipelines, which give us the ability to deliver CO₂ throughout the Gulf Coast. As of December 31, 2012, we have access to over 920 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).

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Completion of the Green Pipeline facilitated the first CO₂ injection into the Hastings Field, located near Houston, Texas, in late 2010. 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, most of the CO₂ flowing in the Green Pipeline is delivered from the Jackson Dome area, but we recently began receiving anthropogenic CO₂ from a plant in Port Arthur, Texas, and will transport a third party's CO₂ for a fee to the sales point at Hastings Field. We expect the volume of anthropogenic CO₂ flowing through the Green Pipeline to increase in future years.

Tertiary Properties with Tertiary Production and Tertiary Reserves at December 31, 2012

Mature properties. Mature properties include several fields along our NEJD CO₂ pipeline and the Free State pipeline, which run through east Mississippi, southwest Mississippi and into Louisiana. This grouping includes some of our most mature CO₂ floods, including our initial CO₂ field, Little Creek, as well as several other areas (Brookhaven, Cranfield, Eucutta, Lockhart Crossing, Mallalieu, Martinville, McComb and Soso fields). These fields accounted for approximately 44% of our total 2012 CO₂ EOR production and 27% of our proved tertiary reserves. These fields have been producing for some time, and their production is generally on decline. Many of these fields contain multiple reservoirs that are amenable to CO₂ EOR. In 2013, we plan to invest approximately $90 million in our mature properties.

Most of the development work is complete in this area; however, there are some additional areas at McComb, Cranfield, Brookhaven and Little Creek that we currently plan to develop. EOR operations in Eucutta and Martinville fields were initiated in 2006 following completion of the Free State Pipeline, and the fields are mostly developed in the reservoir(s) under flood at the present time. In addition to the developed reservoirs, these fields have potential development targets in other vertically segregated reservoirs. 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 to maximize production.

Due to the lower viscosity of CO₂ when compared to oil, CO₂ will tend to follow the path of least resistance. This may result in high producing gas-oil ratios sooner than anticipated. In order to address this issue, we have experimented with various techniques such as cement squeezes (injection and producing wells), chemical squeezes, perforation design, mechanical isolation assemblies and operating pressure controls. We have also utilized water-alternating gas injections, where water is substituted for the CO₂ for a given volume and then CO₂ is injected behind the water. Each one of these processes has had some success and we plan to continue to utilize them in the future as appropriate.

From inception through December 31, 2012, we have recovered all our costs relating to our mature properties, and the excess net cash flow (revenue less operating expenses and capital expenditures, including the acquisition costs) from the mature properties was $1.7 billion. As of December 31, 2012, the estimated PV-10 Value of our mature properties was $1.9 billion.

Delhi Field. Delhi Field is located southwest of Tinsley Field and east of Monroe, Louisiana. During May 2006, we purchased Delhi for $50 million, plus an approximate 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 Field to Delhi Field. First tertiary production occurred at Delhi Field in March 2010. Current trend and performance data indicate that Delhi Field is acting as predicted and continues to provide a positive outlook for this field. Production from Delhi in the fourth quarter of 2012 averaged 5,237 Bbls/d, up from 3,778 Bbls/d in the year-ago period. In 2013, we plan to invest approximately $40 million to drill 15 wells and optimize existing development patterns at Delhi Field. Based on our current estimates, we expect the reversionary interest to come into effect some time in the latter part of 2013, which will reduce our net revenue interest in the field at that time.

From inception through December 31, 2012, 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 costs) from Delhi Field was $122 million. As of December 31, 2012, the estimated PV-10 Value of Delhi Field was $989.6 million.

Hastings Field. Hastings Field is located just south of Houston, Texas. We acquired a majority interest in this field in February 2009 for approximately $247 million. Due to the large vertical oil column that exists in the field, we are developing the Frio reservoir using dedicated CO₂ injection and producing wells for each of the major sand intervals. We initiated CO₂ injection in the West Hastings Unit during December 2010 upon completion of the construction of the Green Pipeline. We began producing

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oil from our EOR operations at Hastings Field in January 2012, and we booked proved tertiary reserves of 42.6 MMBbl for the West Hastings Unit in 2012. During the fourth quarter of 2012, tertiary production from Hastings Field averaged 3,409 Bbls/d, compared to zero in the year-ago period. In 2013, we plan to invest approximately $90 million to continue developing the West Hastings Unit, including the development of additional patterns and expansion of the processing facilities. Significant additional capital expenditures will be required over several years to fully develop the field.

From inception through December 31, 2012, 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 Hastings Field was $331 million. As of December 31, 2012, the estimated PV-10 Value of Hastings Field was $1.2 billion.

Heidelberg Field. In 2008, we began CO₂ injections at Heidelberg Field, which is located in Mississippi and consists of an East and West Unit. Construction of the CO₂ facility, connecting pipeline and well work commenced on the West Heidelberg 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 injection patterns and expanded the central processing facility. Production from the West Unit began to decline in 2011 and we determined that CO₂ was not reaching all the targeted zones, broadly described as “conformance issues.” In 2011, we modified our development pattern to address the conformance issues by redirecting CO₂ into previously unswept intervals in the West Heidelberg Unit, and we believe this work has been successful. During the fourth quarter of 2012, tertiary production at Heidelberg Field averaged 3,930 Bbls/d, compared to 3,728 Bbls/d in the year-ago period. In 2012, we continued the development of our East Heidelberg Unit, which is larger and contains more oil in place than the West Heidelberg Unit, by initiating the second phase of the Eutaw development and the first phase of the Christmas development. In 2013, we plan to invest approximately $100 million to continue developing the East Heidelberg Unit, including an expansion of our development of the Eutaw and Christmas zones, and we plan to invest $20 million in the West Heidelberg Unit to optimize our development in the area.

From inception through December 31, 2012, we have recovered all our costs relating to the CO₂ flood at Heidelberg Field, and the excess net cash flow (revenue less operating expenses and capital expenditures, including the acquisition costs) from the field was $51 million. As of December 31, 2012, the estimated PV-10 Value of Heidelberg Field was $1.2 billion.

Oyster Bayou Field. Oyster Bayou Field, of which we acquired a majority interest in 2007, is located in southeast Texas on the east side of Galveston Bay. 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 was designed to be developed in essentially one stage. We commenced production from Oyster Bayou Field in December 2011 and booked initial proved tertiary reserves for the field of 14.1 MMBbl in 2012. During the fourth quarter of 2012, tertiary production at Oyster Bayou Field averaged 1,826 Bbls/d, compared to 18 Bbls/d in the year-ago period. In 2013, we plan to invest approximately $5 million to increase our CO₂ injection and water disposal capacity at Oyster Bayou Field.

From inception through December 31, 2012, 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 costs) from Oyster Bayou Field was $165 million. As of December 31, 2012, the estimated PV-10 Value of Oyster Bayou Field was $496.5 million.

Tinsley Field. Tinsley Field was acquired in January 2006, is located in 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 upon the completion of the 24-inch Delta Pipeline to Tinsley Field. We had our first tertiary oil production from Tinsley Field in April 2008. As of December 31, 2012, we have completed the development of the West and East Fault Blocks. In 2012, we installed and began injection into three patterns of the North Fault Block of Tinsley. We also installed trunklines and a test site to support future North Fault Block development. In 2013, we expect to invest approximately $40 million to continue our development of the North Fault Block at Tinsley Field. During the fourth quarter of 2012, the average tertiary oil production was 8,166 Bbls/d as compared to 6,338 Bbls/d in the year-ago period.

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From inception through December 31, 2012, 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 $151 million. As of December 31, 2012, the estimated PV-10 Value of Tinsley Field was $1.1 billion.

Future Tertiary Properties with No Tertiary Production or Tertiary Reserves at December 31, 2012

Webster Field. We acquired our interest in Webster Field in November 2012 as part of the Bakken Exchange Transaction. The field is located in Texas, approximately eight miles northeast of our Hastings Field, which we are currently flooding with CO₂. The acquired Webster Field interests had estimated proved conventional reserves of approximately 3.7 MMBOE at December 31, 2012. In December 2012, conventional production at Webster Field averaged 1,104 BOE/d net to our acquired interest. Webster Field is geologically similar to our Hastings and Thompson fields, producing oil from the Frio zone at similar depths, and is believed to be an ideal candidate for a CO₂ flood. In 2013 we plan to invest approximately $20 million on conventional infill drilling opportunities and recompletions along with preliminary CO₂ flood scoping at Webster Field. We currently plan to commence CO₂ injections at Webster Field in 2015, with first tertiary production expected that same year.

Conroe Field. Conroe Field, our largest potential tertiary flood in the Gulf Coast region, is located north of Houston, Texas. We acquired a majority interest in this field in 2009 for approximately $271 million in cash and 11.6 million 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 12.5 MMBOE at December 31, 2012, nearly all of which are proved developed. During the fourth quarter of 2012, production at Conroe Field averaged 2,745 BOE/d net to our acquired interest, compared to 2,587 BOE/d in the year-ago period. 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 Field. This pipeline, which is planned as an extension of our Green Pipeline, is preliminarily estimated to cover approximately 90 miles at a cost of $200 million to $240 million. With our acquisition of Webster Field in 2012, we deferred our construction plans for the Conroe pipeline by two years thus similarly deferring development plans for Conroe Field. We now plan to construct this pipeline in 2016 and to commence CO₂ injections at Conroe Field in 2017 with first tertiary production expected that same year. In 2013, we plan to determine the pipeline path, continue the acquisition of rights-of-way, and engineer and design the pipeline while refining and finalizing our CO₂ EOR plan for Conroe Field. In 2013 we also plan to invest $15 million on conventional infill drilling opportunities and recompletions at Conroe Field.

Thompson Field. We acquired our interest in Thompson Field in June 2012 for $366.2 million. The field is located in Texas, approximately 18 miles west of our Hastings Field. The acquired Thompson Field interests had estimated proved conventional reserves of approximately 16.7 MMBOE at December 31, 2012, of which approximately 55% are proved developed. In December 2012, conventional production at Thompson Field averaged 1,507 BOE/d net to our interest. Thompson Field is geologically similar to Hastings Field, producing oil from the Frio zone at similar depths; it is also expected to be an ideal candidate for a CO₂ flood. Under the terms of the Thompson Field acquisition agreement, after the initiation of CO₂ injection the seller will retain approximately a 5% gross revenue interest (less severance taxes) once average monthly oil production exceeds 3,000 Bbls/d. In 2013, we plan to invest $15 million on conventional infill drilling opportunities and recompletions at Thompson Field. We currently plan to commence CO₂ injections at Thompson Field in mid-2018, with first tertiary production expected in 2019.

Rocky Mountain Region

CO₂ Sources and Pipelines

LaBarge Field. LaBarge Field is located in southwestern Wyoming. The gas composition from LaBarge Field is approximately 65% CO₂, 20% natural gas, 5% hydrogen sulfide (H₂S), less than one percent helium, and the remainder other gases.

We acquired an overriding royalty interest equivalent to an approximate one-third ownership interest in ExxonMobil's CO₂ reserves in LaBarge Field in southwestern Wyoming in December 2012 as part of the Bakken Exchange Transaction. Based on the current capacity of ExxonMobil's Shute Creek gas processing plant at LaBarge Field and subject to availability, we expect to

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receive up to approximately 115 MMcf/d of CO₂ from such plant. We will pay ExxonMobil a fee to process and deliver the CO₂, which will initially be used to flood our Bell Creek, Grieve and Hartzog Draw fields. As of December 31, 2012, our interest in LaBarge Field consisted of approximately 1.3 Tcf of proved CO₂ reserves.

The Riley Ridge Federal Unit is also located in southwestern Wyoming and will produce gas from LaBarge Field. We acquired interests in Riley Ridge in two phases. In 2010, we acquired a 42.5% non-operated working interest for $132.3 million. This initial purchase included a 42.5% interest in a gas plant under construction that will separate the helium and natural gas from the gas stream. In 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 consummation 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. We currently expect the gas plant to be operational in mid-2013 once all engineering safety systems are in place. We plan to invest approximately $40 million at Riley Ridge in 2013 to complete the initial phase of the facilities and drill one producing well and complete one injection well.

As of December 31, 2012, our interest in Riley Ridge and minor surrounding acreage contained net proved reserves of 416 Bcf (69 MMBOE) 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 our 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, 2012, we estimate that Riley Ridge contains proved helium reserves of 12.7 Bcf, which volume estimate is reduced to reflect the related fee we will remit to 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 currently 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, and we currently plan to double this capacity within the next decade. We currently project that we will start to use CO₂ from Riley Ridge around 2017.

Other Rocky Mountain CO₂ Sources. We have ongoing discussions with, and are actively pursuing, several sources for CO₂ supply in the Rocky Mountain region. We have contracted to purchase CO₂ from the Lost Cabin plant in central Wyoming, which agreement will provide as much as 50 MMcf/d of CO₂ from the Lost Cabin plant. We have completed all necessary work to receive the CO₂ and expect first CO₂ deliveries from Lost Cabin in the first quarter of 2013.

In 2011, we entered into a long-term supply contract to purchase anthropogenic CO₂ from a proposed plant in southeastern Wyoming. We estimate the proposed plant could 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 would expect to begin taking delivery of CO₂ approximately four years following commencement of construction of this plant. 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 from proposed plants, 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 serve as our trunk-line in the Rocky Mountain region, eventually connecting our Lost Cabin, LaBarge and Riley Ridge CO₂ sources (see Rocky Mountain region CO₂ Sources and Pipelines above) to the Cedar Creek Anticline in eastern Montana, and may connect to other potential anthropogenic CO₂ sources in the region. The initial 232-mile section of the Greencore Pipeline begins at the Lost Cabin gas plant and terminates at our Bell Creek oil field in Montana. We completed construction of this section of the pipeline in late 2012 and expect to receive first CO₂ deliveries from the Lost Cabin gas plant in the first quarter of 2013. In 2013, we plan to build an interconnect between our Greencore Pipeline and an existing third-party CO₂ pipeline owned by another party in Wyoming. We plan to transport CO₂ from LaBarge Field to the Greencore Pipeline through this existing pipeline for use in planned CO₂ floods at Bell Creek and Hartzog Draw fields.

Future Tertiary Properties with No Tertiary Production or Tertiary Reserves at December 31, 2012

Bell Creek Field. Bell Creek Field is located in southeast Montana. We acquired our interest in Bell Creek through the Encore Merger. As of December 31, 2012, the majority of the work in this field has involved re-activating wells and injecting

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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 in the first half of 2013 and anticipate first tertiary oil production in the second half of 2013. The producing reservoir in Bell Creek Field is a sandstone reservoir very similar to our Gulf Coast reservoirs. Conventional production, net to our interest, during the fourth quarter of 2012 averaged 781 Bbls/d, as compared to 840 Bbls/d in the year-ago period. In 2013, we plan to invest approximately $100 million to install compression equipment and facilities and continue the development of injection patterns at Bell Creek Field.

Hartzog Draw Field. We acquired our interest in Hartzog Draw Field in November 2012 as part of the Bakken Exchange Transaction. The field is located in the Powder River Basin of northeastern Wyoming, approximately 12 miles from our Greencore Pipeline. The acquired Hartzog Draw interests had estimated proved reserves of approximately 5.2 MMBOE at December 31, 2012, 1.9 MMBOE of which relate to the natural gas producing Big George coal zone. In December 2012, conventional production at Hartzog Draw Field averaged 2,444 BOE/d net to our acquired interest. The oil reservoir characteristics of Hartzog Draw Field make the field an ideal candidate for a CO₂ flood. In 2013, we plan to invest approximately $13 million on conventional infill drilling opportunities and recompletions at Hartzog Draw Field. We must obtain regulatory approval and construct a 12-mile CO₂ pipeline from our existing Greencore Pipeline to Hartzog Draw Field before we can commence an EOR flood. We anticipate that we will be able to commence CO₂ injections at Hartzog Draw Field in 2016 with first tertiary production expected that same year.

Cedar Creek Anticline. CCA is primarily located in Montana but covers such a large area (approximately 126 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 initial 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 2012 from all of the units in CCA averaged 8,493 BOE/d, compared to 8,858 BOE/d in the year-ago period. The conventional proved reserves associated with CCA were 66.8 MMBbls of oil and 0.4 Bcf of gas as of December 31, 2012. In January 2013, we entered into a definitive agreement with a wholly-owned subsidiary of ConocoPhillips whereby we plan to add to our CCA assets through the purchase of ConocoPhillips' assets in the field. See 2012 Business Developments – Pending Cedar Creek Anticline Acquisition above and Note 2, Acquisitions and Divestitures, to the Consolidated Financial Statements for further discussion of this transaction and information as to other recent acquisitions and divestitures by Denbury. The Pending CCA Acquisition is expected to add approximately 42 MMBOE of incremental proved reserves at CCA; production associated with these assets averaged approximately 11,000 BOE/d during the fourth quarter of 2012.

CCA is located approximately 110 miles north of Bell Creek Field, and we expect to ultimately connect this field to our Greencore Pipeline. In 2013, we plan to invest approximately $115 million to improve waterfloods of CCA through well and facility work, recomplete existing wells, and develop plans for our planned future CO₂ flood of the field. We currently plan to commence first CO₂ injections into the field in 2017 with first tertiary production expected that same year.

Grieve Field. In May 2011, we 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 are overseeing design, construction and operations of the field. We completed the required three-mile CO₂ pipeline to deliver CO₂ from an existing CO₂ pipeline to the Grieve Field in December 2012, and are contracting for the construction of the CO₂ recycle facility. We estimate first CO₂ injection at Grieve Field in the first quarter of 2013 and first tertiary production late in 2014 or early in 2015.

Non-Tertiary Oil Properties

Our non-tertiary production in 2012 totaled 36,483 BOE/d, or 51% of total production. Excluding production from the non-core asset divestitures discussed above, our continuing non-tertiary production totaled 21,636 BOE/d or 38% of our continuing production in 2012. A substantial portion of this production is generated from fields we intend to flood with CO₂ in the future, and which are discussed above under Tertiary Oil Properties – Gulf Coast Region – Future Tertiary Properties with No Tertiary Production or Tertiary Reserves at December 31, 2012 and Tertiary Oil Properties – Rocky Mountain Region – Future Tertiary Properties with No Tertiary Production or Tertiary Reserves at December 31, 2012.

Gulf Coast Region

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Other Non-Tertiary Fields. We have been active in East Mississippi since Denbury was founded in 1990 and are the largest oil producer in the state. Conventional or non-tertiary production during the fourth quarter of 2012 averaged approximately 3,663 BOE/d from this area (6% of our total continuing production), and we had proved reserves of 11.1 MMBOE as of December 31, 2012 (3% of our Company total). Since we have generally owned these properties in East Mississippi longer than properties in our other regions, these East Mississippi properties tend to be more fully developed. In 2012, we completed the sale of certain non-core assets with proved reserves of 6.4 MMBOE primarily located in central and southern Mississippi and in southern Louisiana for $141.8 million.

Our largest field in the region is the Heidelberg Field located in Mississippi, which for the fourth quarter of 2012 produced an average of 1,947 BOE/d of conventional or non-tertiary production. This compares to 3,129 BOE/d in the year-ago period, with most of the decline in production due to the conversion of conventional areas of the field to a CO₂ flood and the decline in natural gas production in the Selma Chalk. 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 are in the process of converting the East Heidelberg waterflood units to CO₂ EOR. Heidelberg Field 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 approximately 3,700 feet that is developed with horizontal wells and, prior to 2012, hydraulic fracturing. The Selma Chalk is estimated to contain 28.2 Bcf of proved natural gas reserves as of December 31, 2012. Natural gas production from the Selma Chalk was 10.5 MMcf/d during the fourth quarter of 2012, compared to 13.4 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.

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, 2012:



	Developed		Undeveloped		Total
	Gross	Net	Gross	Net	Gross	Net
Gulf Coast	247,841	211,655	371,655	36,569	619,496	248,224
Rocky Mountain	275,449	225,863	345,567	133,000	621,016	358,863
Total	523,290	437,518	717,222	169,569	1,240,512	607,087

Our net undeveloped acreage that is subject to expiration over the next three years, if not renewed, is approximately 35% in 2013, 2% in 2014 and 4% in 2015.

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Productive Wells

The following table sets forth our gross and net productive oil and natural gas wells as of December 31, 2012:



	Producing Oil Wells		Producing Natural Gas Wells		Total
	Gross	Net	Gross	Net	Gross	Net
Operated Wells:
Gulf Coast region	1,315	1,231.6	190	174.1	1,505	1,405.7
Rocky Mountain region	880	750.0	3	2.4	883	752.4
Total	2,195	1,981.6	193	176.5	2,388	2,158.1
Non-Operated Wells:
Gulf Coast region	38	1.3	—	—	38	1.3
Rocky Mountain region	48	9.5	308	155.5	356	165.0
Total	86	10.8	308	155.5	394	166.3
Total Wells:
Gulf Coast region	1,353	1,232.9	190	174.1	1,543	1,407.0
Rocky Mountain region	928	759.5	311	157.9	1,239	917.4
Total	2,281	1,992.4	501	332.0	2,782	2,324.4

Drilling Activity

The following table sets forth the results of our drilling activities over the last three years. As of December 31, 2012, we had 19 gross (13.3 net) wells in progress.



	Year Ended December 31,
	2012		2011		2010
	Gross	Net	Gross	Net	Gross	Net
Exploratory Wells: ⁽¹⁾
Productive ⁽²⁾	1	—	—	—	—	—
Non-productive ⁽³⁾	1	—	1	0.7	—	—
Development Wells: ⁽¹⁾
Productive ⁽²⁾	205	90.4	221	116.6	127	62.8
Non-productive ⁽³⁾⁽⁴⁾	16	11.8	—	—	—	—
Total	223	102.2	222	117.3	127	62.8

(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 2012, 2011 and 2010, an additional 45, 46 and 41 wells, respectively, were drilled for water or CO₂ injection purposes.

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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, 2012, 2011 and 2010:



	Year Ended December 31,
	2012		2011		2010
Net sales volume:
Gulf Coast region
Oil (MBbls)	15,621		14,635		14,657
Natural gas (MMcf)	5,907		7,934		22,271
Total Gulf Coast region (MBOE)	16,606		15,957		18,369
Rocky Mountain region ⁽¹⁾
Oil (MBbls)	8,841		7,534		7,212
Natural gas (MMcf)	4,747		2,849		6,220
Total Rocky Mountain region (MBOE)	9,632		8,009		8,249
Total Company (MBOE)	26,238		23,966		26,618

Average sales price:
Gulf Coast region
Oil (per Bbl)	$	105.59	$	105.23	$	78.35
Natural gas (per Mcf)	2.79		4.31		4.56

Rocky Mountain region
Oil (per Bbl)	$	82.33	$	89.93	$	71.12
Natural gas (per Mcf)	3.38		6.12		4.90

Total Company
Oil (per Bbl)	$	97.18	$	100.03	$	75.97
Natural gas (per Mcf)	3.05		4.79		4.63

Average production cost (per BOE sold): ⁽²⁾
Gulf Coast region	$	24.96	$	24.51	$	19.94
Rocky Mountain region	12.23		14.52		12.61
Total Company	20.29		21.17		17.67


(1)	The year ended December 31, 2012 includes production of approximately 5.3 MMBOE from our Bakken area assets sold in the fourth quarter, and excludes production related to the Pending CCA Acquisition, which we currently expect to close near the end of the first quarter of 2013.


(2)	Excludes oil and natural gas ad valorem and production taxes.

PRODUCTION AND UNIT PRICES

Further 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.

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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 encumbrances, easements and restrictions which we do not believe are material to our operations.

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, 2012, 2011 and 2010, two purchasers accounted for 10% or more of our oil and natural gas revenues: Marathon Petroleum Company LLC (39%, 43% and 46% in 2012, 2011 and 2010, respectively) and Plains Marketing LP (17%, 16% and 14% in 2012, 2011 and 2010, respectively).

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, among other factors, limited transportation options caused by oversubscribed pipelines and market centers that are distant from producing properties. As of December 31, 2012, 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

Over the past couple of years, the oil produced in the Gulf Coast region has benefited from strong pricing differentials in relation to NYMEX and, where possible, we have attached our production to Louisiana Light Sweet ("LLS") pricing. During 2012 and 2011, our light sweet oil production in this area, on average, sold for more than $11.50 per Bbl over NYMEX. The light and medium sour crude production has also benefited from the continued strength of other Gulf Coast grades relative to NYMEX, with production in 2012 selling at a premium to NYMEX of $6.69 per Bbl. Historically, LLS pricing and NYMEX pricing have been much closer together than the spread we have experienced over the last two years. The market dynamics of the region suggest the possibility of divergence from the current premiums currently being realized due to the influx of light sweet crude and condensate from producing regions outside of the Gulf Coast region by rail and publicly announced major pipeline projects. Our current markets, at various sales points along the Gulf Coast, have sufficient demand to accommodate our production, but there can be no assurance of future demand, and we are therefore monitoring the marketplace for opportunities to strategically enter into long-term marketing arrangements.

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 increased stability of 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, 2012, the discount for our oil production in the Rocky Mountain region averaged $11.86 per Bbl, compared to $5.15 per Bbl during 2011. Excluding the Bakken area assets that we sold during the fourth quarter of 2012, our oil production in the Rocky Mountain region sold at a discount to NYMEX of $8.43 per Bbl during the year ended December 31, 2012.

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Overall, during 2012, we sold approximately 40% of our crude oil at prices based on the LLS index price, approximately 22% at prices partially tied to the LLS index price, and the balance at prices based on various other indexes tied to NYMEX prices, primarily in the Rocky Mountain region. On a pro forma basis excluding Bakken area assets sold in 2012, we sold approximately 49% of our crude oil at prices based on the LLS index price and approximately 27% at prices partially tied to the LLS index price.

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, among other factors, 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, 2012, the amount received per Mcf for our Mississippi natural gas production was consistent with NYMEX prices. In the Texas Gulf Coast region, due primarily to its location, the price we received for the year ended December 31, 2012 averaged $0.08 per Mcf below 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. 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, 2012, we averaged $0.55 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.

Helium Marketing

We expect production to commence at Riley Ridge Field in mid-2013, after which we expect to 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 primary 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 and have less competition than our peers in certain aspects of our business.

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 in such personnel. In recent years, the competition for qualified technical personnel has been extensive and our personnel costs have been escalating at a rate higher than general inflation. 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.

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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 other 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 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, although compliance and regulatory approval could cause delays or otherwise impede operations.

Regulation of Natural Gas and Oil Exploration and Production

Our operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for drilling wells; maintaining bonding requirements in order to drill or operate wells and regulating the location of wells; the method of drilling and casing wells; the surface use and restoration of properties upon which wells are drilled; the plugging and abandoning of wells; and the composition or disposal of chemicals and fluids used in connection with operations. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling, spacing or proration units and the density of wells that may be drilled in those units, and the unitization or pooling of oil and gas properties. In addition, state conservation laws, which establish maximum rates of production from oil and gas wells, generally prohibit or restrict 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 early 2012, the President signed the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011. This act, among other things, updates federal pipeline safety standards, increases penalties for violations of such standards, gives the Department of Transportation (the "DOT") authority for new damage prevention and incident notification, and directs the DOT to prescribe new minimum safety standards for CO₂ pipelines, which safety standards could affect our operations and the costs thereof. The DOT has not yet promulgated any such new minimum safety standards. In the future, Congress may create new incentives for alternative energy sources and may also consider legislation to reduce emissions of CO₂ or other greenhouse gases. If enacted, such legislation could (1) impose a tax or other economic penalty on the production of fossil fuels that, when used, ultimately release CO₂, (2) reduce the demand for, and uses of, oil, gas and other minerals, and/or (3) increase the costs incurred by us in our exploration and production activities. The Environmental Protection Agency (“EPA”) has promulgated regulations requiring permitting for certain sources of greenhouse gas emissions, along with requirements for wells used for geologic sequestration. At

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the same time, legislation to reduce the emissions of CO₂ or other greenhouse 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 depleted 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 the 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 penalties and other sanctions as a result of any violations or liabilities under environmental or other laws applicable to our operations. Changes in, or more stringent enforcement of, environmental laws and other laws applicable to our operations could also result in delays or additional operating costs and capital expenditures.

Various federal, state and local laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the environment directly impact our oil and gas exploration, development and production operations. These include, among others, (1) regulations adopted by the EPA and various state agencies regarding approved methods of disposal for certain hazardous and nonhazardous wastes; (2) the Comprehensive Environmental Response, Compensation, and Liability 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; (3) the Clean Air Act and comparable state and local requirements already applicable to our operations and new restrictions on air emissions from our operations, including those that could discourage the production of fossil fuels that, when used, ultimately release CO₂; (4) 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; (5) the Resource Conservation and Recovery Act, which is the principal federal statute governing the treatment, storage and disposal of hazardous wastes; (6) the Endangered Species Act and counterpart state legislation, which protects endangered and threatened species (and their related habitats) including certain species, which could be present on our leases, as threatened or endangered; and (7) state regulations and statutes governing the handling, treatment, storage and disposal of NORM.

Management believes that we are in material 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 laws and regulations, and compliance therewith, could cause significant delays or otherwise impede operations, which may cause our expected production rates and cash flows to be less than anticipated.

Hydraulic Fracturing

We previously used a hydraulic fracturing process to stimulate production in our Bakken area and Selma Chalk properties. We sold our Bakken area properties during the fourth quarter of 2012 and have no current plans to hydraulically fracture any of our remaining oil and gas wells, including our Selma Chalk properties, during 2013. During 2012, we fracture stimulated 41 operated wells in the Bakken utilizing water-based fluids with no diesel fuel component. In these operations, we are cognizant of environmental laws and continually monitor all of our operations for possible environmental impact. During 2012, we derived

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in the range of 15% to 20% of our revenues from properties that have been fracture stimulated at some point in the useful life of the properties.

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

Internal Controls Over Reserve Estimates

Reserve information in this report is based on estimates prepared by DeGolyer and MacNaughton ("D&M"), an independent petroleum engineering consulting firm located in Dallas, Texas, utilizing data provided by our internal reserve engineering team and is the responsibility of management. We rely on D&M's 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 D&M; 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 38 years of experience in oil and gas reservoir studies and evaluations. Our Senior Vice President – Planning, Technology and Business Development is primarily responsible for overseeing the independent petroleum engineering firm during the process. Our Senior Vice President – Planning, Technology and Business Development has a Bachelor of Science degree in Petroleum Engineering from Louisiana State University and over 31 years of industry experience working with petroleum reserve estimates. D&M relies on various data provided by our internal reserve engineering team in preparing their reserve estimates, including such items as oil and natural gas prices, ownership interests, production information, operating costs, planned capital expenditures and other technical data. Our internal reserve engineering team consists of qualified petroleum engineers who maintain the Company's internal evaluation of reserves and compare the Company's information to the reserves prepared by D&M. Management is responsible for designing the internal control procedures used in the preparation of our oil and gas reserves, which include verification of data input into reserve forecasting and economics evaluation software, as well as multi-discipline management reviews. The internal reserve team reports directly to our Senior Vice President – Planning, Technology and Business Development. In addition, our Board of Directors’ Reserves and Health, Safety and Environment ("HSE") Committee, on behalf of the Board of Directors, oversees the qualifications, independence, performance and hiring of our independent petroleum engineering firm and reviews the final report and subsequent reporting of our oil and natural gas reserve estimates. The Chairman of the Reserves and HSE Committee holds a Ph.D. in Chemical Engineering from the Massachusetts Institute of Technology and bachelor's degrees in Chemistry and Mathematics from Capital University in Ohio. He has 33 years of industry experience, with responsibilities including reserves preparation and approval.

Oil and Natural Gas Reserves Estimates

D&M prepared estimates of our net proved oil and natural gas reserves as of December 31, 2012, 2011 and 2010. See the summary of D&M’s report as of December 31, 2012, included as an exhibit to this Form 10-K. These estimates of reserves were prepared using an average price equal to the unweighted 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. These 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 2012, we provided oil and gas reserve estimates for 2011 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, 2011.

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, 2012, our estimated proved undeveloped reserves totaled approximately 162.7 MMBOE, or approximately 40% of our estimated total proved reserves, a decline of 38.5 MMBOE from December 31, 2011 levels. Our proved undeveloped oil reserves primarily relate to our CO₂ tertiary operations (72.8 MMBOE) and our proved undeveloped natural gas reserves are primarily located in our Riley Ridge Field (69.4 MMBOE) acquired in 2010 and 2011. Our December 31, 2012 proved undeveloped reserves also include 10.5 MMBOE of proved undeveloped reserves at our CCA fields acquired in 2010 and 7.4 MMBOE of

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proved undeveloped reserves we acquired at Thompson Field during 2012. 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 tertiary recovery operations in fields and reservoirs that historically produced substantial volumes of oil under primary production.

During 2012, we spent approximately $875 million to convert 40.5 MMBOE of proved undeveloped reserves to proved developed reserves. Proved undeveloped reserves were converted primarily through the expansion of our tertiary floods (25.0 MMBOE) and through additional drilling in the Bakken. During 2012, proved undeveloped reserve additions of 89.1 MMBOE, primarily related to the initial recognition of reserves associated with new tertiary floods (62.6 MMBOE) and the acquisition of Thompson Field (7.4 MMBOE), were partially offset by the decrease in proved undeveloped reserves resulting from the sale of our Bakken area assets (73.5 MMBOE).

As of December 31, 2012, 16.6 MMBOE of our total proved undeveloped reserves are not scheduled to be developed within five years of initial booking, all of which are part of CO₂ EOR projects. We believe these reserves satisfy the conditions to be included as proved reserves because (1) we have established and continue to follow the previously adopted development plan for each of these projects; (2) we have significant ongoing development activities in each of these CO₂ EOR projects and (3) we have an historical record of completing the development of comparable long-term projects.

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	December 31,
	2012			2011			2010
Estimated Proved Reserves ⁽¹⁾
Oil (MBbls)	329,124			357,733			338,276
Natural gas (MMcf)	481,641			625,208			357,893
Oil equivalent (MBOE)	409,398			461,934			397,925
Reserve Volumes Categories
Proved developed producing:
Oil (MBbls)	208,745			189,904			186,705
Natural gas (MMcf)	60,832			116,562			104,050
Oil equivalent (MBOE)	218,884			209,331			204,047
Proved developed non-producing:
Oil (MBbls)	27,264			49,837			32,372
Natural gas (MMcf)	3,359			9,408			6,466
Oil equivalent (MBOE)	27,824			51,405			33,450
Proved undeveloped:
Oil (MBbls)	93,115			117,992			119,199
Natural gas (MMcf)	417,450			499,238			247,377
Oil equivalent (MBOE)	162,690			201,198			160,428
Percentage of Total MBOE:
Proved developed producing	53		%	45		%	51		%
Proved developed non-producing	7		%	11		%	9		%
Proved undeveloped	40		%	44		%	40		%
Representative Oil and Natural Gas Prices: ⁽²⁾
Oil – NYMEX	$	94.71		$	96.19		$	79.43
Natural gas – Henry Hub	2.85			4.16			4.40
Present Values (thousands): ⁽³⁾
Discounted estimated future net cash flow before income taxes (PV-10 Value) ⁽⁴⁾	$	9,909,592		$	10,559,139		$	7,292,344
Standardized measure of discounted estimated future net cash flow after income taxes ("Standardized Measure")	$	6,414,380		$	7,007,605		$	4,917,927

(1)

Estimated proved reserves as of December 31, 2012 reflect the sale of reserves associated with our Bakken area assets sold in 2012 (approximately 109 MMBOE). Year-end 2012 reserves reflect CCA reserves acquired in 2010 as part of the Encore Merger, but do not include reserves of approximately 42 MMBOE related to the Pending CCA Acquisition, which we currently expect to close near the end of first quarter of 2013.

(2)

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 we receive. 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.


(3)	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.


(4)	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

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data determined in accordance with FASC Topic 932. The difference between these two amounts, the discounted estimated future income tax (in thousands) was $3,495,212 at December 31, 2012, $3,551,534 at December 31, 2011, and $2,374,417 at December 31, 2010. 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 14, 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 14, Supplemental Oil and Natural Gas Disclosures (Unaudited), to the Consolidated Financial Statements.

Item 1A. Risk Factors

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

Our future financial condition, results of operations, 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 between year-end 2011 and year-end 2012, with NYMEX oil prices per Bbl decreasing 7%, and NYMEX natural gas prices per MMBtu increasing by 12%. 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 2012 production and 80% of our December 31, 2012 proved reserves, with oil being an even larger percentage of our current production and future potential reserves and projects due to our primary 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;


•	storage levels of oil and natural gas;


•	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 and forest fires 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

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•	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 five years oil prices have fluctuated significantly, reaching record highs of approximately $145 per Bbl in July 2008, declining precipitously during the last half of 2008, and ending that year at a NYMEX price of $44.60 per Bbl. Oil prices then reversed course, generally increasing through the past several years, ending 2011 at a NYMEX price of $98.83 per Bbl and ending 2012 at a NYMEX price of $91.82 per Bbl. Due to the volatility of oil prices, oil prices could decline to a level that makes our tertiary projects uneconomical. 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, both of which could have a material adverse effect on our operations. We may also be required to reduce our capital expenditures in the event of reduced commodity prices to reflect the reduced cash flow, which could reduce or eliminate our growth. We have a practice of hedging approximately 15 to 24 months (from the current quarter) of forecasted 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 21, 2013, we have oil commodity derivative contracts in place covering approximately 55,000 Bbls/d during 2013 and 50,000 Bbls/d during 2014. 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 point (before corporate overhead, and based on expenses on these projects at current oil prices) occurs at per barrel dollar costs in the $40-per-barrel range, depending on the specific field and area.

The prices we receive for our crude oil often do not correlate with NYMEX prices. The prices we receive for our crude oil production can vary from NYMEX oil prices depending on, among other factors, the quality of the crude oil we sell, the location of our crude oil production and the related markets to which we sell, 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 approximately $25 per Bbl above NYMEX to approximately $25 per Bbl below NYMEX. On a corporate-wide basis, our NYMEX differentials over the last few years have ranged from approximately $9 per Bbl above NYMEX oil prices to approximately $4 per Bbl below NYMEX oil 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 $4.40 per MMBtu during 2010, $4.03 per MMBtu during 2011, and $2.82 per MMBtu during 2012, and ended 2012 at $3.35 per MMBtu. As of February 21, 2013, we do not have any natural gas commodity derivative contracts in place.

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, 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

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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 natural gas 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 laws, 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 our pipelines, and/or increase the costs of constructing our 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 21, 2013, we had outstanding $2.9 billion (principal amount) of subordinated notes at interest rates ranging from 4.625% to 9.75% at a weighted average interest rate of 6.61% and no amounts outstanding under our bank credit facility. We currently have a borrowing base of $1.6 billion under our bank credit facility, and at February 21, 2013, nearly all of this amount was available on such facility. The next regularly scheduled semiannual redetermination of the borrowing base for our bank credit facility will be in May 2013. 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;


•	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, among other things, 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; 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.

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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 counterparty 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 Item 7. 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 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 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 more costly 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 years prior to any resulting production and cash flows from these projects, heightening potential capital constraints. If we do not continue to make significant capital expenditures, or if outside capital resources become limited, we may not be able to maintain our growth rate or meet expectations.

During the last few years, we have acquired several fields at a significant cost because we believe that they have significant additional potential through tertiary flooding; 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.

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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 and forest fires 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, and certain operations may be practical only 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 can slow down our operations, cause delays and 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 in such personnel. In recent years, the competition for qualified technical personnel has been extensive and our personnel costs have been escalating at a rate higher than general inflation. 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

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generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, oilfield equipment and services, and personnel in our exploration and production operations. 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.

Governmental laws and regulations relating to environmental protection are costly and stringent.

Our exploration, production, and marketing operations are subject to complex and stringent federal, state, and local laws and regulations governing, among other things, the discharge of substances into the environment or otherwise relating to environmental protection. These laws and regulations affect the costs, manner, and feasibility of our operations and require us to make significant expenditures in our efforts to comply. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial obligations, and the issuance of injunctions that could limit or prohibit our operations. In addition, some of these laws and regulations may impose joint and several, strict liability for contamination resulting from spills, discharges, and releases of substances, including petroleum hydrocarbons and other wastes, without regard to fault or the legality of the original conduct. Under such laws and regulations, we could be required to remove or remediate previously disposed substances and property contamination, including wastes disposed or released by prior owners or operators. Changes in or additions to environmental laws and regulations occur frequently, and any changes or additions that result in more stringent and costly waste handling, storage, transport, disposal, or cleanup or other environmental protection requirements could have a material adverse effect on our operations and financial position.

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 introduced, are anticipated to be introduced or are otherwise under consideration by Congress and various federal agencies. Among these proposals are: (1) climate change/carbon tax legislation introduced in Congress and EPA regulations to reduce greenhouse gas emissions, including an EPA proposal to apply New Source Performance Standards for petroleum refineries expected in 2013; (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 deductions for intangible drilling and development costs and 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 previously considered by Congress (but not adopted) that would subject the process of hydraulic fracturing to federal regulation under the Safe Drinking Water Act and new or anticipated Department of Interior 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 Department of Transportation to prescribe minimum safety standards for CO₂ pipelines, any of which could affect our operations, and the costs thereof. Generally, any 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. However, until such legislation or regulations are enacted or adopted into law and implemented, it is not possible to gauge their impact on our future operations or our results of operations and financial condition.

Certain federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated, and additional state taxes on natural gas extraction may be imposed, as a result of future legislation.

In recent years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain U.S. federal income tax benefits and deductions currently available to oil and gas companies. Such changes include, but are not limited to, (1) the repeal of the percentage depletion allowance for oil and gas properties, (2) the increase of the amortization period of geological and geophysical expenses, (3) the elimination of current deductions for intangible drilling and development costs and qualified tertiary injectant expenses, and (4) the elimination of the deduction for certain U.S. production activities. It is unclear whether any such proposals will be enacted into law and, if so, what form such laws might possibly take. The passage of such legislation or any other similar change in U.S. federal income tax law could eliminate, reduce or postpone certain tax deductions that are currently available to us, and any such change could negatively affect our financial condition and results of operations.

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The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to hedge risks associated with our business.

The Dodd-Frank Act requires the Commodities Futures Trading Commission, and the SEC to promulgate rules and regulations establishing federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. These new rules and regulations could significantly increase the cost or decrease the liquidity of energy-related derivatives we use to hedge against commodity price fluctuations. Although we believe the derivative contracts that we enter into should not be materially impacted by these new statutory and regulatory requirements, because derivatives regulations have not been finalized, final regulations could negatively affect to our detriment the economics and terms of derivative instruments available from counterparties in the marketplace.

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, 2012, two purchasers individually accounted for 10% or more of our oil and natural gas revenues and, in the aggregate, for 56% of such revenues. The loss of a large single purchaser could potentially reduce the competition for our oil and natural gas production, which in turn could negatively impact the prices we receive.

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

Estimating quantities of proved oil and natural gas reserves is a complex process. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors such as future commodity prices, production costs, severance and excise taxes, capital expenditures and workover and remedial costs, and the assumed effect of governmental regulation. There are numerous uncertainties about when a property may have proved reserves as compared to potential or probable reserves, particularly relating to our tertiary recovery operations. Forecasting the amount of oil reserves recoverable from tertiary operations and the production rates anticipated therefrom requires estimates, one of the most significant being the oil recovery factor. Actual results most likely will vary from our estimates. Also, the use of a 10% discount factor for reporting purposes, as prescribed by the SEC, may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject. Any significant inaccuracies in these interpretations or assumptions or changes of conditions could result in a reduction of the quantities and net present value of our reserves.

The reserve data included in documents incorporated by reference represent only estimates. Quantities of proved reserves are estimated based on economic conditions, including first-day-of-the-month average oil and natural gas prices for the 12-month period preceding the date of the 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 used in the estimate.

As of December 31, 2012, approximately 40% 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 these expenditures and operations may not occur.

Significant acquisitions or other transactions could require substantial 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 from that of our existing properties.

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Our results of operations could be negatively affected as a result of goodwill impairments.

Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. At December 31, 2012, the Company's goodwill balance totaled $1.3 billion and represented approximately 11.5% of our total assets. Goodwill is not amortized; rather it is tested for impairment annually during the fourth quarter and when facts or circumstances indicate that the carrying value of the Company's goodwill may be impaired, requiring an estimate of the fair values of the reporting unit's assets and liabilities. An impairment of goodwill could significantly reduce earnings during the period in which the impairment occurs and would result in a corresponding reduction to goodwill and equity. See Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates – Impairment Assessment of Goodwill.

We may lose executive officers or other key management personnel, which could endanger the future success of our operations.

Our success depends to a significant degree upon the continued contributions of our executive officers and other key management personnel. Our employees, including our executive officers, are employed at will and do not have employment agreements. If one or more members of our management team dies, becomes disabled or voluntarily terminates employment with us, there is no assurance that we will find a suitable or comparable substitute. We believe that our future success depends, in large part, upon our ability to hire and retain highly skilled managerial personnel. Competition for persons with these skills is intense, and we cannot assure that we will be successful in attracting and retaining such skilled personnel. The loss of any of our management personnel could adversely affect our operations.

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

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

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

Item 1B. Unresolved Staff Comments

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

Item 2. Properties

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

Item 3. Legal Proceedings

We are involved in various 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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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 January 31, 2013, 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 1,643. On February 27, 2013, the last reported sale price of Denbury’s common stock, as reported on the NYSE, was $17.99 per share.



	2012				2011
	High		Low		High		Low
First Quarter	$	20.91	$	16.29	$	24.56	$	18.45
Second Quarter	19.50		13.46		24.86		18.70
Third Quarter	17.65		13.74		20.85		11.50
Fourth Quarter	16.76		14.32		17.45		10.86

We have never paid any dividends on our common stock. Also, our bank credit facility limits the aggregate amount of (i) dividends we can pay on our common stock and (ii) our common stock we can repurchase. Under our bank credit facility, we had $679.0 million available as of February 21, 2013 that can be used to pay dividends or repurchase shares of Denbury's common stock. No unregistered securities were sold by the Company during 2012.

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	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (in millions) ⁽¹⁾
October 2012	2,138,550	$	16.35	2,133,910	$	228.8
November 2012	6,052,120	15.03		6,018,276	409.5
December 2012	6,340,742	15.83		6,332,387	309.3 ⁽²⁾
Total	14,531,412	15.57		14,484,573	$	309.3


(1)	In October 2011, the Company's Board of Directors approved a common stock repurchase program for up to $500 million of Denbury's common stock, which was increased by an additional $271.2 million in early November 2012.


(2)	Amounts shown do not give effect to the repurchase of an additional 3.5 million shares of Denbury common stock from January 1, 2013 through February 21, 2013 under the share repurchase program for $59.1 million, or $16.73 per share.

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, 2012, we repurchased 31,090,618 shares of Denbury common stock (approximately 7.7% of our outstanding shares of common stock at September 30, 2011) for $461.9 million, or $14.86 per share. The program was increased to $771.2 million in 2012, has no pre-established ending date and may be suspended or discontinued at any time. We are not obligated to repurchase any dollar amount or specific number of shares of our common stock under the program.

All other repurchases of our common stock during the fourth quarter of 2012 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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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, 2012, 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, 2007 to December 31, 2012.

COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURN



	December 31,
	2007		2008		2009		2010		2011		2012
Denbury Resources Inc.	$	100.00	$	36.71	$	49.75	$	64.17	$	50.76	$	54.45
S&P 500 ⁽¹⁾	100.00		63.00		79.67		91.67		93.61		108.59
Dow Jones US Exploration & Production ⁽²⁾	100.00		59.88		84.17		98.26		94.14		99.62

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Denbury Resources Inc.

Item 6. Selected Financial Data



	Year Ended December 31,
In thousands, except per share data or otherwise noted	2012			2011			2010 ⁽¹⁾			2009			2008
Consolidated Statements of Operations Data:
Revenues and other income:
Oil, natural gas, and related product sales	$	2,409,867		$	2,269,151		$	1,793,292		$	866,709		$	1,347,010
Other	46,605			40,173			128,499			22,441			24,046
Total revenues and other income	$	2,456,472		$	2,309,324		$	1,921,791		$	889,150		$	1,371,056
Net income (loss) attributable to Denbury stockholders ⁽²⁾	525,360			573,333			271,723			(75,156		)	388,396
Net income (loss) per common share:
Basic	1.36			1.45			0.73			(0.30		)	1.59
Diluted	1.35			1.43			0.72			(0.30		)	1.54
Weighted average number of common shares outstanding:
Basic	385,205			396,023			370,876			246,917			243,935
Diluted	388,938			400,958			376,255			246,917			252,530
Consolidated Statements of Cash Flow Data:
Cash provided by (used by):
Operating activities	$	1,410,891		$	1,204,814		$	855,811		$	530,599		$	774,519
Investing activities	(1,376,841		)	(1,605,958		)	(354,780		)	(969,714		)	(994,659		)
Financing activities	45,768			37,968			(139,753		)	442,637			177,102
Production (average daily):
Oil (Bbls)	66,837			60,736			59,918			36,951			31,436
Natural gas (Mcf)	29,109			29,542			78,057			68,086			89,442
BOE (6:1)	71,689			65,660			72,927			48,299			46,343
Unit sales prices – excluding impact of derivative settlements:
Oil (per Bbl)	$	97.18		$	100.03		$	75.97		$	57.75		$	92.73
Natural gas (per Mcf)	3.05			4.79			4.63			3.54			8.56
Unit sales prices – including impact of derivative settlements:
Oil (per Bbl)	$	96.77		$	98.90		$	71.69		$	68.63		$	90.04
Natural gas (per Mcf)	5.67			7.34			6.45			3.54			7.74
Costs per BOE:
Lease operating expenses	$	20.29		$	21.17		$	17.67		$	17.85		$	17.71
Taxes other than income	6.10			6.16			4.53			2.45			3.06
General and administrative expenses	5.49			5.24			5.04			5.77			3.36
Depletion, depreciation and amortization	19.34			17.07			16.32			13.52			13.08
Proved Oil and Natural Gas Reserves: ⁽³⁾
Oil (MBbls)	329,124			357,733			338,276			192,879			179,126
Natural gas (MMcf)	481,641			625,208			357,893			87,975			427,955
MBOE (6:1)	409,398			461,934			397,925			207,542			250,452
Proved Carbon Dioxide Reserves:
Gulf Coast region (MMcf) ⁽⁴⁾	6,073,175			6,685,412			7,085,131			6,302,836			5,612,167
Rocky Mountain region (MMcf) ⁽⁵⁾	3,495,534			2,195,534			2,189,756			—			—
Proved Helium Reserves Associated with Denbury's Production Rights: ⁽⁶⁾
Rocky Mountain region (MMcf)	12,712			12,004			7,159			—			—
Consolidated Balance Sheet Data:
Total assets	$	11,139,342		$	10,184,424		$	9,065,063		$	4,269,978		$	3,589,674
Total long-term liabilities	5,408,032			4,716,659			4,105,011			1,903,951			1,363,539
Stockholders’ equity	5,114,889			4,806,498			4,380,707			1,972,237			1,840,068

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Denbury Resources Inc.


(1)	On March 9, 2010, we acquired Encore Acquisition Company ("Encore"). We consolidated Encore's results of operations beginning March 9, 2010. See Note 2, Acquisitions and Divestitures, to the Consolidated Financial Statements for further discussion of this transaction.


(2)	During 2009, we had a pretax charge of $236.2 million associated with our commodity derivative contracts.

(3)

Estimated proved reserves as of December 31, 2012 reflect the disposition of reserves associated with our Bakken area assets sold in late 2012 (approximately 109 MMBOE). Year-end 2012 reserves reflect CCA reserves acquired in 2010 as part of the Encore Merger, but do not include estimated reserves of approximately 42 MMBOE related to the Pending CCA Acquisition, which we currently expect to close near the end of first quarter of 2013.

(4)

Proved CO₂ reserves in the Gulf Coast region consist of reserves from our reservoirs at Jackson Dome and are presented on a gross or 8/8ths working interest basis, of which our net revenue interest was approximately 4.8 Tcf, 5.3 Tcf, 5.6 Tcf, 5.0 Tcf and 4.5 Tcf at December 31, 2012, 2011, 2010, 2009 and 2008, respectively, and include reserves dedicated to volumetric production payments of 57.1 Bcf, 84.7 Bcf, 100.2 Bcf, 127.1 Bcf and 153.8 Bcf at December 31, 2012, 2011, 2010, 2009 and 2008, respectively. (See Note 15, Supplemental CO₂ and Helium Disclosures (Unaudited), to the Consolidated Financial Statements.)


(5)	Proved CO₂ reserves in the Rocky Mountain region consist of our reserves at Riley Ridge (presented on a gross working interest basis) and our overriding royalty interest in LaBarge Field, of which our net revenue interest was approximately 2.9 Tcf, 1.6 Tcf and 0.9 Tcf at December 31, 2012, 2011, and 2010 respectively.

(6)

Reserves associated with helium production rights include helium reserves located in the acreage in the Rocky Mountain region for which we have the right to extract the helium. The U.S. government retains title to the helium reserves and we retain the right to extract and sell the helium on behalf of the government in exchange for a fee. The estimate of helium reserves is reduced to reflect the related fee we will remit to the U.S. government.

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Denbury Resources Inc.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements and Notes thereto included in Item 8, Financial Statements and Supplementary Data. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Risk Factors under Item 1A of this Form 10-K, along with Forward-Looking Information at the end of this section for information on the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

OVERVIEW

Our primary focus is on enhanced oil recovery utilizing CO₂and our operations are focused in two key operating areas: the Gulf Coast region and Rocky Mountain region. We are the largest combined oil and natural gas producer in both Mississippi and Montana, and we own the largest reserves of CO₂ used for tertiary oil recovery east of the Mississippi River. Our goal is to increase the value of acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to tertiary recovery operations.

Strategic and Value-Driven Transactions

Over the last year, we completed or entered into agreements on several strategic and tax efficient property transactions which not only add value, but as importantly, make us a nearly pure CO₂ EOR company. These asset transactions, which included both acquisitions and dispositions, aggregated (or upon completion will aggregate) over $4 billion in value, and (1) resulted in an increase in our unproven potential reserves, which we believe provides us a better opportunity to achieve a higher return due to the nature of the acquired properties compared to the sold properties, (2) nearly replaced the production of the sold assets with that from the acquired or to-be-acquired assets, (3) exchanged proved reserves with a high proved undeveloped component for reserves that are nearly all proved developed, which significantly increases our current free cash flow, (4) increased our Rocky Mountain CO₂ reserves by 1.3 Tcf and up to 115 MMcf/d of deliverability, and (5) positioned us to execute on our long-term strategy which we expect will increase shareholder value for many years to come. A summary of these transactions follows, with more detail on each significant transaction discussed below in this overview section.


•	Bakken Exchange Transaction – Divested our Bakken area assets, which were all non-tertiary, at an estimated value of approximately $2.0 billion, in exchange for interests in two future potential tertiary oil fields, a new Rocky Mountain region CO₂ source and $1.3 billion of cash.

•

Pending Cedar Creek Anticline Acquisition – Entered into an agreement in early 2013 to purchase additional interests in the Cedar Creek Anticline ("CCA") in Montana and North Dakota, an area with future potential tertiary oil upside, for $1.05 billion, which will be funded with a portion of the cash proceeds from the Bakken Exchange Transaction. We expect to complete the Pending CCA Acquisition near the end of the first quarter of 2013.

In two separate transactions earlier in 2012, which were also structured as like-kind exchanges for federal income tax purposes, we completed the following:


•	Acquisition of Thompson Field – Acquired a nearly 100% working interest and 84.7% net revenue interest in the Thompson Field in south Texas, a future potential tertiary oil field approximately 18 miles from our current EOR flood at Hastings Field, for $366.2 million.


•	Sale of Non-core Assets – Sold our interests in non-core oil and natural gas fields in the Paradox Basin of Utah and in the Gulf Coast region for $68.5 million and $141.8 million, respectively.

Bakken Exchange Transaction. In late 2012, we closed a sale and exchange transaction with Exxon Mobil Corporation and its wholly-owned subsidiary XTO Energy Inc. (collectively, “ExxonMobil”) under which we sold to ExxonMobil our Bakken area assets in North Dakota and Montana in exchange for $1.3 billion in cash (after preliminary closing adjustments) and EOR-related assets (the “Bakken Exchange Transaction”). By exchanging these non-tertiary Bakken area assets for EOR fields and CO₂assets, we are able to more purely focus our attention on tertiary recovery operations. These acquired assets include:

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

•

operating interests in the Webster Field, a planned future tertiary field located in southeastern Texas, made up of a nearly 100% working interest and nearly 80% net revenue interest. The field is located approximately eight miles from Denbury's Hastings Field which is currently being flooded with CO₂, and which is the current terminus of the Green Pipeline which transports CO₂ from natural sources in the Jackson Dome area of Mississippi. Webster Field is similar to Hastings Field, producing oil from the Frio zone at similar depths, and is also expected to be an ideal candidate for a CO₂ flood;

•

operating interests in the Hartzog Draw Field, a planned future tertiary field, located in Wyoming, consisting of an 83% working interest and 71% net revenue interest in the oil producing Shannon Sandstone zone, and a 67% working interest and 53% net revenue interest in the natural gas producing Big George Coal zone. Hartzog Draw Field is located approximately 12 miles from the recently completed initial segment of our Greencore Pipeline and is expected to be an ideal candidate for a CO₂ flood; and


•	an overriding royalty interest equivalent to an approximate one-third ownership interest in ExxonMobil's CO₂ reserves in LaBarge Field in Wyoming with an estimated 1.3 Tcf of proved reserves and up to 115 MMcf/d of deliverability.

The proved reserves acquired at Webster and Hartzog Draw fields total approximately 9 MMBOE at December 31, 2012. We did not record a gain or loss on the Bakken Exchange Transaction in accordance with the full cost method of accounting. The Bakken area assets had approximately 109 MMBOE of proved reserves at the time of sale, of which approximately 66% were undeveloped with an estimated future development cost of more than $1.7 billion. A total of $1.05 billion of the cash proceeds from the Bakken Exchange Transaction were placed into a qualifying trust account with a third party and will be used to fund the pending CCA acquisition discussed below, as a like-kind exchange for federal income tax purposes.

Pending Cedar Creek Anticline Acquisition. On January 14, 2013, we entered into an agreement to acquire producing assets in the CCA of Montana and North Dakota from a wholly-owned subsidiary of ConocoPhillips for $1.05 billion in cash (the "Pending CCA Acquisition"), before standard closing adjustments primarily for revenues and costs of the properties to be purchased from the January 1, 2013 effective date to the closing date. The assets we plan to purchase from ConocoPhillips include both additional interests in certain of our existing operated fields in CCA as well as operating interests in other CCA fields. We currently estimate on a preliminary basis that, as of December 31, 2012, the proved conventional (non-tertiary) reserves associated with the acquired assets, net to our acquired interests, were approximately 42 MMBOE. We expect the Pending CCA Acquisition to close near the end of the first quarter of 2013, and we plan to fund this acquisition with a portion of the cash proceeds from the Bakken Exchange Transaction (see discussion above), of which $1.05 billion was placed in qualifying trust accounts in order to qualify this acquisition for like-kind-exchange treatment for federal income tax purposes.

Acquisition of Thompson Field. In June 2012, we acquired operating interests in Thompson Field for $366.2 million after preliminary closing adjustments, which added approximately 900 BOE/d to our production in 2012. The field is located approximately 18 miles west of Denbury's Hastings Field which is currently being flooded with CO₂, and which is the current terminus of the Green Pipeline which transports CO₂ from natural sources in the Jackson Dome area of Mississippi. Thompson Field is similar to Hastings Field, producing oil from the Frio zone at similar depths, and is a planned future tertiary field. We funded the purchase principally with cash proceeds from property sales earlier in 2012 and the remainder from borrowings under our bank credit facility.

Sale of Non-Core Assets. On January 19, 2012, we sold our investment in Vanguard Natural Resources LLC common units for cash consideration of $83.5 million, net of related transaction fees. On February 29, 2012, we completed the sale of certain Gulf Coast assets primarily located in central and southern Mississippi and in southern Louisiana for $155.0 million, realizing net proceeds of $141.8 million after final closing adjustments. On April 9, 2012, we completed the sale of certain non-operated assets in the Paradox Basin of Utah for $75.0 million, realizing net proceeds of $68.5 million after final closing adjustments.

2012 Highlights

2012 Operating Highlights. Our net income was $525.4 million, or $1.35 per diluted common share, during 2012, compared to net income of $573.3 million, or $1.43 per diluted common share, during 2011. Although we had a $140.7 million increase in oil and natural gas revenues in 2012 compared to 2011, which was primarily driven by higher production, this increase in revenues was more than offset by increases in other expenses, such as a $63.2 million non-cash change in the fair value of our commodity derivative contracts in 2012 compared to 2011, and an increase of $98.3 million in depletion, depreciation and amortization and $25.0 million in lease operating expenses, largely driven by increased production. Our cash flow from operations was $1.4 billion

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

in 2012, compared to $1.2 billion in 2011, with the increase primarily due to the increase in oil revenues and changes in working capital items.

During 2012, our oil and natural gas production, which was 93% oil (as was the case in 2011), averaged 71,689 BOE/d, compared to 65,660 BOE/d produced during 2011. The increase in production is primarily attributable to record production from our tertiary oil properties (an increase of 4,247 BOE/d, or 14% from 2011) and production from our recently disposed Bakken area assets (an increase of 5,055 BOE/d, or 54% from 2011 levels). See Results of Operations – Operating Results – Production for more information.

The average oil price we realized during 2012, excluding the impact of derivative contracts, was $97.18 per barrel, or about 3% lower than prices realized during 2011. This decrease was due primarily to a decrease in the prices we receive relative to NYMEX oil prices, which we refer to as our NYMEX price differential. Our Gulf Coast region oil prices received in 2012 continued to be favorably impacted by a positive NYMEX price differential, as a large portion of that crude oil is sold under Louisiana Light Sweet (“LLS”) pricing, which has maintained a price higher than NYMEX throughout the last two years; however, some of that benefit was offset by wider negative NYMEX price differentials in the Rocky Mountain region during 2012. See Results of Operations – Operating Results – Oil and Natural Gas Revenues below for more information.

Proved Oil and Natural Gas Reserves. Our estimated proved oil and gas reserves were 409.4 MMBOE as of December 31, 2012, as compared to 461.9 MMBOE at December 31, 2011. We added 114.2 MMBOE of estimated proved reserves during 2012, including tertiary reserves of 69.5 MMBbls, primarily at Hastings and Oyster Bayou fields based on these fields' responses to CO₂injections, 25.9 MMBOE from the acquisition of interests in the Thompson, Webster and Hartzog Draw fields, and 11.5 MMBOE from our Bakken area assets prior to their sale in the fourth quarter of 2012. These increases were offset by the disposition of 123.9 MMBOE of reserves as a result of sales of our Bakken area assets, non-core assets in the Gulf Coast region and the Paradox Basin of Utah.

2013 Debt Issuance and Tender Offers

On February 5, 2013, we issued $1.2 billion of 4 5/8% Senior Subordinated Notes due July 2023 (the "2023 Notes"). The net proceeds from this transaction of $1.18 billion were used to retire a portion of our senior subordinated notes and to pay down amounts outstanding on the Company's bank credit facility. As part of this refinancing, we (1) completed cash tender offers for our 9¾% Senior Subordinated Notes due 2016 (the "9¾% Notes") and our 9½% Senior Subordinated Notes due 2016 (the "9½% Notes"), (2) purchased a total of $378.4 million principal amount of outstanding notes in February 2013, and (3) subsequently called the 9¾% Notes for redemption effective on March 7, 2013. Beginning May 1, 2013, the remaining $38.2 million of 9½% Notes become redeemable at 104.75% of par.

CAPITAL RESOURCES AND LIQUIDITY

Overview. During the last year, we have completed or entered into agreements for several significant transactions (discussed above), with the purchase transactions funded with a portion of the cash proceeds from asset sales, resulting in a slight net increase in our cash or capital resources. We also purchased $461.9 million of our common stock between early October 2011 and December 31, 2012, funded by planned reduced capital expenditures in 2012 (i.e. cash flow), net cash from the transactions and bank debt (see stock purchase detail below). In early 2013, we refinanced two of our high-rate subordinated notes with ten-year notes carrying an interest rate of 4 5/8%, lowering our interest expense and reducing, with a portion of the proceeds of our newest notes offering, our outstanding bank borrowings. As a result of these transactions, our current debt to cash flow is slightly higher than normal. Even so, we are comfortable that we will have more than adequate capital resources and liquidity for the foreseeable future because (i) we have refinanced our bank debt with low-cost subordinated debt, leaving significant borrowing capacity on our bank line; (ii) we have extended our oil hedges by about six months, hedging a substantial portion of our forecasted proven oil production for two years with a floor price of $80, (see Note 9, Derivative Instruments and Hedging Activities to the Consolidated Financial Statements for further details regarding the prices and volumes of our commodity derivative contracts); (iii) we expect to fund our projected capital expenditures for the next few years with cash flow from operations, which means that our expected growth in production and cash flow will gradually reduce our leverage (assuming oil prices are relatively consistent with current levels); and (iv) we can significantly reduce our capital expenditures for extended periods of time if necessary and still maintain current production levels as a result of our unique EOR operations.

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

We plan to fund the Pending CCA Acquisition with a portion of the cash proceeds from the Bakken Exchange Transaction, of which $1.05 billion was placed in qualifying trust accounts in order to qualify the acquisition for like-kind-exchange treatment for federal income tax purposes. This $1.05 billion cash was classified as Restricted Cash in our December 31, 2012 Balance Sheet. We expect the Pending CCA Acquisition to close near the end of the first quarter of 2013.

2013 Capital Spending. We currently estimate our 2013 capital spending will be approximately $1.0 billion, excluding acquisitions and $125 million of estimated capitalized costs including geological and geophysical, overhead, interest and pre-production start-up costs associated with new tertiary floods. Our current 2013 capital budget includes the following:


•	$540 million allocated for tertiary oil field expenditures;


•	$110 million for pipeline construction;


•	$200 million to be spent on CO₂ sources; and


•	$150 million to be spent in all other areas.

Based on oil and natural gas commodity futures prices in early February 2013 and our current production forecast (including production from the Pending CCA Acquisition), we estimate that our anticipated 2013 cash flow from operations should be adequate to cover our 2013 capital budget (including capitalized costs consisting of geological and geophysical, overhead, interest and pre-production start-up costs associated with new tertiary floods). If prices were to decrease or changes in operating results were to cause us to have a significant reduction in anticipated 2013 cash flows, we have ample availability on our bank credit facility to cover any potential shortfall, and we also have the ability to reduce our capital expenditures if desired.

We continually monitor our capital spending and anticipated cash flows and believe that we can adjust our capital spending up or down depending on cash flows; however, any such reduction in capital spending could reduce our anticipated production levels in future years. For 2013 and some future years, we have contracted for certain capital expenditures; therefore, we cannot eliminate all of our capital commitments without penalties (see Commitments and Obligations for further information regarding these commitments).

Stock Repurchase Program. Our Board of Directors has approved a common share repurchase program for up to $771.2 million of Denbury common shares. As of February 21, 2013, we had repurchased approximately $521.0 million of our common stock under this program, with an additional $250.2 million of purchases authorized. See Note 7, Stockholders' Equity to the Consolidated Financial Statements for further discussion. Our share repurchases will be determined based on various parameters; therefore, our share repurchases may be less than the remaining approved balance under the program and there is no set expiration date for our program. We anticipate that repurchases during 2013 will be primarily funded with excess cash flow from operations or with borrowings under our bank credit facility.

Bank Credit Facility. Our primary sources of capital are our cash flow from operations and borrowings under our bank credit facility. As part of our semiannual bank review in November 2012, the borrowing base for our bank credit facility was reaffirmed at $1.6 billion. Our next borrowing base redetermination is scheduled on or around May 1, 2013. We currently do not anticipate any reduction in our borrowing base as part of that redetermination, and we believe, based on current commodity prices and our proved asset base, that we could obtain lender approval to significantly increase the borrowing base under our bank credit facility above the current $1.6 billion level if we desired to do so. As of February 21, 2013, we had no amounts outstanding under our $1.6 billion bank credit facility and estimated cash of approximately $90 million, leaving us significant liquidity to fund any cash shortfall for capital expenditures. On a pro forma basis as of February 21, 2013, assuming redemption of all remaining outstanding 9¾% Notes and 9½% Notes, we anticipate that our bank debt, net of cash, would be approximately $200 million, leaving significant availability on our bank credit facility.

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Denbury Resources Inc.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

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



	Year Ended December 31,
In thousands	2012			2011			2010
Capital expenditures by project:
Tertiary oil fields	$	468,328		$	522,007		$	371,274
Bakken	428,313			435,159			108,363
CO₂ pipelines	181,873			134,377			171,511
CO₂ sources ⁽¹⁾	238,613			103,541			73,316
Other areas	159,606			244,055			156,076
Capital expenditures before acquisitions and capitalized interest	1,476,733			1,439,139			880,540
Less: recoveries from sale/leaseback transactions	(35,102		)	(70,332		)	(40,490		)
Net capital expenditures excluding acquisitions and capitalized interest	1,441,631			1,368,807			840,050
Acquisitions:
Property acquisitions ⁽²⁾	942,359			250,084			157,929
Consideration for Encore Merger ⁽³⁾	—			—			2,952,515
Capitalized interest	77,432			61,586			66,815
Capital expenditures, net of sale/leaseback transactions	$	2,461,422		$	1,680,477		$	4,017,309


(1)	Includes capital expenditures related to the Riley Ridge gas plant.

(2)

In 2012, includes capital expenditures of $212.5 million related to Thompson Field that are not reflected as an Investing Activity on our Consolidated Statement of Cash Flows due to the movement of proceeds through a qualified intermediary in a like-kind exchange transaction, and $571.6 million representing the aggregate fair value of net assets acquired, excluding cash, in the Bakken Exchange Transaction. See Note 2, Acquisitions and Divestitures to the Consolidated Financial Statements.


(3)	Consideration given in the Encore Merger includes $2.09 billion for the fair value of Denbury common stock issued.

Our 2012 capital expenditures were funded primarily with $1.4 billion of cash flow from operations, and our property acquisitions were funded with proceeds from asset sales as discussed above.

Our 2011 capital expenditures, excluding the Riley Ridge acquisition, were funded with $1.2 billion of cash flow from operations and cash on hand at the beginning of the period. The Riley Ridge acquisition was funded with incremental bank debt.

Our 2010 capital expenditures, excluding the Encore acquisition, were funded with $855.8 million of cash flow from operations and incremental cash generated from the sale of non-strategic assets. Net cash used to acquire Encore was approximately $815 million, which was funded with incremental debt drawn under our bank credit facility.

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Denbury Resources Inc.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Commitments and Obligations

A summary of our obligations at December 31, 2012, is presented in the following table:



	Payments Due by Period
In thousands	2013		2014 and 2015		2016 and 2017		Thereafter		Total
Contractual Obligations:
Bank Credit Agreement ⁽¹⁾	$	—	$	—	$	700,000	$	—	$	700,000
Estimated interest payments on bank credit facility and subordinated debt⁽¹⁾	188,011		375,895		235,459		267,097		1,066,462
Subordinated debt ⁽¹⁾	—		1,557		653,520		1,396,273		2,051,350
Pipeline lease obligations ⁽²⁾	30,817		64,583		61,911		296,226		453,537
Operating lease obligations	10,656		23,752		25,104		80,562		140,074
Capital lease obligations	35,429		61,768		50,090		31,806		179,093
Other obligations ⁽³⁾	118,166		159,262		158,343		864,260		1,300,031
Derivative liabilities ⁽⁴⁾	2,842		23,781		—		—		26,623
Asset retirement obligations ⁽⁵⁾	7,042		3,745		14,285		293,798		318,870
Total contractual obligations	$	392,963	$	714,343	$	1,898,712	$	3,230,022	$	6,236,040

(1)

These long-term borrowings and related interest payments are further discussed in Note 5, Long-Term Debt, to the Consolidated Financial Statements. This table assumes that our long-term debt is held until maturity. During February 2013 we issued $1.2 billion in additional senior subordinated notes and refinanced a portion of our outstanding notes and paid down borrowings under our bank credit facility, which 2013 events are not reflected above. See Note 13, Subsequent Events, to the Consolidated Financial Statements.

(2)

Represents estimated future cash payments under a long-term transportation service agreement for the Free State Pipeline and future minimum cash payments in a 20-year financing lease for the NEJD pipeline system. Both transactions were entered into during 2008 and are being accounted for as financing leases. The payment required for the Free State Pipeline is variable based upon the amount of the CO₂ we ship through the pipeline, and the commitment amounts disclosed above for that financing lease are computed based upon our internal forecasts. Approximately $217.3 million of these payments, in the aggregate, represent interest. See Note 5, Long-Term Debt, to the Consolidated Financial Statements.

(3)

Represents future cash commitments under contracts in place as of December 31, 2012, primarily for pipe, anthropogenic CO₂ purchase contracts, drilling rig services and well-related costs. As is common in our industry, we commit to make certain expenditures on a regular basis as part of our ongoing development and exploration program. These commitments generally relate to projects that occur during the subsequent several months and are usually part of our normal operating expenses or part of our capital budget, which for 2013 is currently set at $1.0 billion (see 2013 Capital Spending above). In certain cases we have the ability to terminate contracts for equipment, in which case we would be liable only for the cost incurred by the vendor up to that point; however, as we currently do not anticipate canceling those contracts, these amounts include our estimated payments under those contracts. We also have recurring expenditures for such things as accounting, engineering and legal fees; software maintenance; subscriptions; and other overhead-type items. Normally these expenditures do not change materially on an aggregate basis from year to year and are part of our general and administrative expenses. We have not attempted to estimate the amounts of these types of recurring expenditures in this table, as most could be quickly canceled with regard to any specific vendor, even though the expense itself may be required for our ongoing normal operations. Other obligations exclude approximately $1.3 billion of potential costs to be incurred after 2017 for anthropogenic CO₂ purchase contracts for which plant construction has not yet begun and therefore it is uncertain that we will be obligated to incur these costs.


(4)	Derivative liabilities represent the fair value of our derivatives presented as liabilities in our Consolidated Balance Sheet as of December 31, 2012. The ultimate settlement amounts of our derivative obligations are unknown because they are subject to continuing market risk. See further discussion of our derivative contracts and their market price sensitivities in Market

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Risk Management below in this 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.


(5)	Represents the estimated future asset retirement obligations on an undiscounted basis. The present value of the discounted asset retirement obligation is $106.4 million, as determined under the Asset Retirement and Environmental Obligations topic of the FASC, and is further discussed in Note 3, Asset Retirement Obligations, to the Consolidated Financial Statements.

Off Balance-Sheet Arrangements. We have several operating leases relating to office space and other minor equipment leases. At December 31, 2012, we had a total of $16.0 million of letters of credit outstanding under our bank credit facility. Additionally, we have obligations that are not currently recorded on our balance sheet relating to various obligations for development and exploratory expenditures that arise from our normal capital expenditure program or from other transactions common to our industry. In addition, in order to recover our undeveloped proved reserves, we must also fund the associated future development costs estimated in our proved reserve reports. For a further discussion of our future development costs, see Note 14, Supplemental Oil and Natural Gas Disclosures (Unaudited), to the Consolidated Financial Statements.

RESULTS OF OPERATIONS

As discussed in Item 1, Business and Properties – Oil and Natural Gas Operations – Enhanced Oil Recovery Overview above, our tertiary operations represent a significant portion of our overall operations and have become our primary strategic focus. The economics of a tertiary field and the related impact on our financial statements differ from a conventional oil and gas play and are explained further below.

Financial Overview of Tertiary Operations

While it is difficult to accurately forecast future production, we believe our tertiary recovery operations provide significant long-term production growth potential at reasonable rates of return, with relatively low risk. Our rate of return from our tertiary operations has generally been higher than our rate of return on traditional oil and gas operations. Generally, finding and development costs are lower and operating costs are higher than traditional oil and gas operations. We have been developing tertiary oil properties for over 13 years, and the financial impact of such operations is reflected in our historical financial statements. The summary below highlights our observations regarding how tertiary operations have impacted our financial statements.

Finding and Development Costs. We currently expect Finding and Development Costs (including future development and abandonment costs but excluding CO₂ pipeline infrastructure capital expenditures and expenditures on fields without proven reserves) over the life of each field to be lower than the industry average costs for other oil properties. See the definition of Finding and Development Costs in the Glossary and Selected Abbreviations.

Timing of Capital Costs. There is a significant delay between the initial capital expenditures on these fields and the resulting production increases. We must build facilities, and often a CO₂ pipeline to the field, before CO₂ flooding can commence, and it usually takes six to twelve months before the field responds to the injection of CO₂ (i.e., oil production commences). Further, we may spend significant amounts of capital before we can recognize any proven reserves from fields we flood and, even after a field has proven reserves, there will usually be significant amounts of additional capital required to fully develop the field.

Recognition of Proved Reserves. In order to recognize proved tertiary oil reserves, we must either demonstrate production resulting from the tertiary process or the field must be analogous to an existing tertiary flood. The magnitude of proven reserves that we can book in any given year will depend on our progress with new floods, the timing of the production response from new floods and the performance of our existing floods.

Production Rates. The production growth rate at a tertiary flood can vary from quarter to quarter as a tertiary field’s production may increase rapidly when wells respond to the CO₂, plateau temporarily, and then resume its growth as additional areas of the field are developed. During a tertiary flood life cycle, facility capacity is increased from time to time, which occasionally requires temporary shutdowns during installation, thereby causing temporary declines in production. We also find it difficult to precisely predict when any given well will respond to the injected CO₂, as the CO₂ seldom travels through the rock consistently due to

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

heterogeneity in the oil-bearing formations. We find all of these fluctuations to be normal, and generally expect oil production at a tertiary field to increase over time until the entire field is developed, albeit sometimes in inconsistent patterns.

Operating Costs. Tertiary projects may be more expensive to operate than traditional industry operations because of the cost of injecting and recycling the CO₂ (primarily due to the cost of the CO₂ and the significant energy requirements to re-compress the CO₂ back into a near-liquid state for re-injection purposes). The costs of our CO₂ and the electricity required to recycle and inject this CO₂ comprise almost half of our typical tertiary operating expenses. Since these costs vary along with commodity and electrical prices, they are highly variable and will increase in a high-commodity-price environment and decrease in a low-price environment. Most of our CO₂ operating costs are allocated to our tertiary oil fields and recorded as lease operating expenses (following the commencement of tertiary oil production) at the time the CO₂ is injected, and these costs have historically represented approximately 20% to 25% of the total operating costs for our tertiary operations. Since we expense all of the operating costs to produce and inject our CO₂ (following the commencement of tertiary oil production), the operating costs per barrel will be higher at the inception of CO₂ injection projects because of minimal related oil production at that time.

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

Operating Results

Certain of our operating results and statistics for each of the last three years are included in the following table.



	Year Ended December 31,
In thousands, except per share and unit data	2012			2011			2010 ⁽¹⁾
Operating results
Net income attributable to Denbury stockholders	$	525,360		$	573,333		$	271,723
Net income per common share – basic	1.36			1.45			0.73
Net income per common share – diluted	1.35			1.43			0.72
Net cash provided by operating activities	1,410,891			1,204,814			855,811
Average daily production volumes
Bbls/d	66,837			60,736			59,918
Mcf/d	29,109			29,542			78,057
BOE/d	71,689			65,660			72,927
Operating revenues
Oil sales	$	2,377,337		$	2,217,529		$	1,661,380
Natural gas sales	32,530			51,622			131,912
Total oil and natural gas sales	$	2,409,867		$	2,269,151		$	1,793,292
Commodity derivative contracts ⁽²⁾
Cash receipt (payment) on settlement of commodity derivative contracts	$	17,880		$	2,377		$	(31,612	)
Non-cash fair value adjustment income (expense)	(13,046		)	50,120			53,026
Total income from commodity derivative contracts	$	4,834		$	52,497		$	21,414
Unit prices – excluding impact of derivative settlements
Oil price per Bbl	$	97.18		$	100.03		$	75.97
Natural gas price per Mcf	3.05			4.79			4.63
Unit prices – including impact of derivative settlements ⁽²⁾
Oil price per Bbl	$	96.77		$	98.90		$	71.69
Natural gas price per Mcf	5.67			7.34			6.45
Oil and natural gas operating expenses
Lease operating expenses	$	532,359		$	507,397		$	470,364
Marketing expenses	52,836			26,047			31,036
Production and ad valorem taxes	149,919			139,170			114,980
Oil and natural gas operating revenues and expenses per BOE
Oil and natural gas revenues	$	91.85		$	94.68		$	67.37
Lease operating expenses	20.29			21.17			17.67
Marketing expenses, net of third-party purchases	1.60			1.09			1.17
Production and ad valorem taxes	5.71			5.81			4.32
CO₂ Sources - revenues and expenses
CO₂ sales and transportation fees	$	26,453		$	22,711		$	19,204
CO₂ discovery and operating expenses ⁽³⁾	(14,694		)	(14,258		)	(7,801		)
CO₂ revenue and expenses, net	$	11,759		$	8,453		$	11,403


(1)	Includes the results of operations of Encore and ENP from March 9, 2010, through December 31, 2010.


(2)	See also Market Risk Management below for information concerning our derivative transactions.


(3)	Includes $9.5 million and $7.5 million of exploratory costs in 2012 and 2011, respectively. We incurred no exploratory costs during 2010.

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Production

Average daily production by area for 2012, 2011 and 2010, and for each of the quarters of 2012, is shown below:



	Average Daily Production (BOE/d)
	2012 Quarters				Year Ended December 31,
Operating Area	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	2012	2011	2010 ⁽¹⁾
Tertiary oil production
Gulf Coast region
Mature properties:
Brookhaven	3,014	2,779	2,460	2,520	2,692	3,255	3,429
Eucutta	3,090	2,870	2,782	2,730	2,868	3,121	3,495
Mallalieu	2,585	2,461	2,181	2,127	2,338	2,693	3,377
Other mature properties ⁽²⁾	8,012	7,867	7,347	7,605	7,707	8,955	10,240
Delhi	4,181	4,023	3,813	5,237	4,315	2,739	483
Hastings	618	1,913	2,794	3,409	2,188	—	—
Heidelberg	3,583	3,823	3,716	3,930	3,763	3,448	2,454
Oyster Bayou	877	1,304	1,540	1,826	1,388	5	—
Tinsley	7,297	8,168	8,153	8,166	7,947	6,743	5,584
Total tertiary oil production	33,257	35,208	34,786	37,550	35,206	30,959	29,062
Non-tertiary oil and gas production
Gulf Coast region
Mississippi	4,573	4,095	3,401	3,663	3,930	5,486	6,505
Texas	3,674	4,573	5,173	5,513	4,737	4,133	4,941
Other	1,281	1,306	1,137	1,217	1,235	1,336	1,559
Total Gulf Coast region	9,528	9,974	9,711	10,393	9,902	10,955	13,005
Rocky Mountain region
Cedar Creek Anticline	8,496	8,535	8,490	8,493	8,503	8,968	7,930
Other	3,204	3,060	3,037	3,616	3,231	2,968	2,673
Total Rocky Mountain region	11,700	11,595	11,527	12,109	11,734	11,936	10,603
Total continuing production	54,485	56,777	56,024	60,052	56,842	53,850	52,670
Properties disposed:
Bakken area assets ⁽³⁾	15,285	15,503	16,752	10,064	14,395	9,340	4,315
Non-core asset divestitures ⁽⁴⁾	1,762	57	—	—	452	2,470	2,288
Legacy Encore properties	—	—	—	—	—	—	6,556
ENP	—	—	—	—	—	—	7,098
Total production	71,532	72,337	72,776	70,116	71,689	65,660	72,927


(1)	Includes production of Encore and ENP from the March 9, 2010 acquisition date through December 31, 2010, or in the case of non-strategic assets disposed, through the date the asset was sold.


(2)	Other mature properties include Cranfield, Little Creek, Lockhart Crossing, Martinville, McComb and Soso fields.


(3)	Includes production from certain Bakken area assets sold in the fourth quarter of 2012.


(4)	Includes production from certain non-core Gulf Coast assets sold in late February 2012 and certain non-operated assets in the Greater Aneth Field in the Paradox Basin of Utah sold in April 2012.

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Total Production

As outlined in the above table, continuing production increased 2,992 BOE/d (6%) between 2011 and 2012. The increases were primarily due to production increases from our tertiary oil fields, which reached record aggregate production levels in 2012, offset by normal declines in most of our other non-tertiary properties. The year-over-year 9% increase in total production was further impacted by increases in production from our Bakken area assets, which were sold late in the fourth quarter of 2012.

Continuing production increased 1,180 BOE/d (2%) between 2010 and 2011. Increases in tertiary production and Cedar Creek Anticline production due to a full year of operations were offset by normal declines at our non-tertiary fields. Total production decreased 10% due to the sale of non-strategic legacy Encore and ENP properties during 2010, offset by a 116% increase in Bakken area production.

Our production during 2012 and 2011 was 93% oil compared to 82% during 2010. The increase in oil production percentage in 2011 is due to the sales of the non-strategic Encore and ENP properties during 2010, which had a higher percentage of natural gas production, and increases in our tertiary and Bakken production, which are primarily oil.

Tertiary Production

Oil production from our tertiary operations increased to record levels during 2012 averaging 35,206 Bbls/d, a 14% increase over our 2011 tertiary production level of 30,959 Bbls/d, primarily due to production growth in response to continued expansion of the tertiary floods at Tinsley and Delhi fields and production at our Oyster Bayou and Hastings fields, which experienced their initial tertiary production response in late December 2011 and early January 2012, respectively. Offsetting 2012 production gains were production declines in our more mature tertiary fields. Tertiary production during the fourth quarter of 2012 increased 8% over third quarter of 2012 levels, largely due to production increases at Delhi and Hastings fields resulting from the expansion of the tertiary floods at these fields. Although all of our tertiary production is currently in the Gulf Coast region, during 2013 we plan to initiate our first tertiary operations in the Rocky Mountain region at Bell Creek Field and estimate initial production from this field to begin in the second half of 2013.

Oil production from our tertiary operations averaged 30,959 Bbls/d during 2011, a 7% increase over our 2010 tertiary production level of 29,062 Bbls/d, primarily due to production growth in response to continued expansion of the tertiary floods in Delhi, Tinsley, Cranfield and Heidelberg fields. Offsetting 2011 tertiary production gains were declines in our more mature fields.

Non-Tertiary Production

With the exception of production from our recently sold Bakken area assets and acquisitions during 2012, which have increased our production in Texas, production from our other non-tertiary properties generally declined during 2012 and 2011. Most of these conventional oil production declines are impacted by the expansion of our tertiary floods in those areas.

Our production from CCA has generally declined pending further development. During 2013, we plan to improve our waterflood at CCA through well and facility work and recompletion of existing wells, as a result of which we expect a slight increase in production. Additionally, we expect CCA volumes to increase upon the close of our Pending CCA Acquisition (see Overview – Strategic and Value-Driven Transactions), which to-be-acquired properties we estimate will add approximately 7,700 BOE/d to our 2013 annual production.

Production from our Bakken area assets averaged 14,395 BOE/d during 2012, compared to 9,340 BOE/d during 2011 and 4,315 BOE/d during 2010. Since we acquired the Bakken area properties in the Encore Merger, we have grown Bakken area production through an acceleration of drilling activities in that area, as we increased our operated drilling rigs from two at the time of the acquisition in March 2010, to five at the beginning of 2011 and as many as seven during the latter half of 2011. During 2012, we reduced the rig count to four, and late in the fourth quarter of 2012, we sold our Bakken area assets in the Bakken Exchange Transaction.

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

Oil and Natural Gas Revenues

Oil and natural gas revenues increased between 2010 and 2011 and again between 2011 and 2012. The increase in oil and natural gas revenues in 2011 was attributable to higher realized oil prices, whereas the increase in oil and natural gas revenues in 2012 was the result of increases in production volumes. The changes in revenues due to these factors, excluding any impact of our derivative contracts, are reflected in the following table:



	Year Ended December 31, 2012 vs. 2011					Year Ended December 31, 2011 vs. 2010
In thousands	Increase (Decrease) in Revenues			Percentage Increase (Decrease) in Revenues		Increase (Decrease) in Revenues			Percentage Increase (Decrease) in Revenues
Change in revenues due to:
Increase (decrease) in production	$	215,150		9	%	$	(178,709	)	(10	)%
Increase (decrease) in commodity prices	(74,434		)	(3	)%	654,568			37	%
Total increase in oil and natural gas revenues	$	140,716		6	%	$	475,859		27	%

Excluding any impact of our derivative contracts, our net realized commodity prices and NYMEX differentials were as follows during 2012, 2011 and 2010:



	Year Ended December 31,
	2012		2011		2010
Net Realized Prices:
Oil price per Bbl	$	97.18	$	100.03	$	75.97
Natural gas price per Mcf	3.05		4.79		4.63
Price per BOE	91.85		94.68		67.37
NYMEX Differentials:
Oil per Bbl	$	2.99	$	4.95	$	(3.54	)
Natural gas per Mcf	0.23		0.76		0.23

As reflected in the table above, our net realized oil price declined 3% during 2012, compared to prices received during 2011, largely due to a decline in our oil price differentials between the two periods, from $4.95 per Bbl above NYMEX in 2011 to $2.99 above NYMEX in 2012. The net differential we received was primarily impacted by positive differentials in the Gulf Coast region, offset by unfavorable differentials in the Rocky Mountain region, each of which is discussed in further detail below.

We received favorable NYMEX differentials in the Gulf Coast region during 2012 and 2011, primarily due to the favorable differential for crude oil sold under LLS index prices. The quarterly average LLS-to-NYMEX differential (on a trade-month basis) ranged from a positive $12.55 per Bbl to $20.08 per Bbl for 2012, compared to a positive $9.28 per Bbl to $23.36 per Bbl during 2011. During 2012, we sold approximately 40% of our crude oil at prices based on the LLS index price and approximately 22% at prices partially tied to the LLS index price. On a pro forma basis excluding Bakken area assets sold in 2012, we sold approximately 49% of our crude oil at prices based on the LLS index price and approximately 27% at prices partially tied to the LLS index price. Prices received in a regional market can differ from NYMEX pricing due to a variety of reasons, including supply and/or demand factors and location differentials. While this differential is significant in the pricing for our oil production, other market and contractual factors may prevent us from realizing the full differential. As indicated by the above variations, the LLS-to-NYMEX differential is volatile and has been at historically high levels in recent periods, which may not continue as infrastructure is added to move barrels of oil from the U.S. Mid-continent market to the Gulf Coast.

Our production in the Rocky Mountain region has generally sold at a discount to NYMEX oil prices. Unfavorable NYMEX differentials in the Rocky Mountain region are largely impacted by oil production from our Bakken area assets, which were sold late in the fourth quarter of 2012. The realized oil prices for these sold properties averaged $15.05 per Bbl below NYMEX during

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2012, compared to an average differential of $8.86 per Bbl below NYMEX during 2011. Our oil production in the Rocky Mountain region, excluding the Bakken area assets we sold in the fourth quarter of 2012, also sells at a discount to NYMEX oil prices.

Excluding oil prices received on the Bakken area assets that were sold late in the fourth quarter of 2012, our Company-wide fourth quarter average differential was $11.65 above NYMEX. Our Company-wide oil NYMEX differential improved during 2011 over our differential in 2010 primarily due to the favorable price differential for crude oil sold under LLS index pricing.

Our natural gas NYMEX differentials are generally caused by movement in the NYMEX natural gas prices during the month, as most of our natural gas is sold on an index price that is set near the first of each month. While the percentage change in NYMEX natural gas differentials can be quite large, these differentials are very seldom more than a dollar above or below NYMEX prices.

Oil and Natural Gas Derivative Contracts

The following table summarizes the impact our oil and natural gas derivative contracts had on our operating results for 2012, 2011 and 2010:



	Non-Cash Fair Value Gain/(Loss)									Cash Settlements Receipt/(Payment)
In thousands	2012			2011			2010			2012			2011			2010
Crude oil derivative contracts:
First quarter	$	(42,445	)	$	(167,064	)	$	61,821		$	(8,230	)	$	(5,028	)	$	(63,550	)
Second quarter	140,923			187,194			145,099			(709		)	(16,972		)	(13,829		)
Third quarter	(60,726		)	205,355			(62,450		)	(641		)	(1,857		)	(3,590		)
Fourth quarter	(26,848		)	(166,505		)	(100,029		)	(411		)	(1,271		)	(12,448		)
Full Year	$	10,904		$	58,980		$	44,441		$	(9,991	)	$	(25,128	)	$	(93,417	)

Natural gas derivative contracts:
First quarter	$	(1,640	)	$	(5,274	)	$	39,018		$	7,040		$	6,616		$	3,749
Second quarter	(9,096		)	(3,348		)	(19,909		)	7,991			6,030			16,630
Third quarter	(7,174		)	229			19,933			6,910			6,427			13,626
Fourth quarter ⁽¹⁾	(6,040		)	(467		)	(30,457		)	5,930			8,432			27,800
Full Year	$	(23,950	)	$	(8,860	)	$	8,585		$	27,871		$	27,505		$	61,805

Total commodity derivative contracts:
First quarter	$	(44,085	)	$	(172,338	)	$	100,839		$	(1,190	)	$	1,588		$	(59,801	)
Second quarter	131,827			183,846			125,190			7,282			(10,942		)	2,801
Third quarter	(67,900		)	205,584			(42,517		)	6,269			4,570			10,036
Fourth quarter	(32,888		)	(166,972		)	(130,486		)	5,519			7,161			15,352
Full Year	$	(13,046	)	$	50,120		$	53,026		$	17,880		$	2,377		$	(31,612	)


(1)	Natural gas derivative settlements for the fourth quarter of 2010 include receipts of $10.0 million related to the monetization of natural gas swaps that were unwound due to the sale of our Haynesville and East Texas assets.

Changes in commodity prices and the expiration of contracts cause fluctuations in the estimated fair value of our oil and natural gas derivative contracts. Because we do not utilize hedge accounting for our commodity derivative contracts, the period-to-period changes in the fair value of these contracts, as outlined above, are recognized in our statements of operations.

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Our current derivative contracts for 2013 or beyond are all NYMEX oil contracts given that our current and forecasted production is primarily oil (93% of BOE volumes in 2012), leading us to use oil derivative contracts in our commodity market risk management program. The detail of our outstanding commodity derivative contracts at December 31, 2012 is included in Note 9, Derivative Instruments and Hedging Activities, to the Consolidated Financial Statements.

Production Expenses

Lease operating expense



	Year Ended December 31,
In thousands, except per BOE data	2012		2011		2010
Lease operating expense
Tertiary	$	307,686	$	272,066	$	229,940
Non-tertiary	224,673		235,331		240,424
Total lease operating expense	$	532,359	$	507,397	$	470,364

Lease operating expense per BOE
Tertiary	$	23.88	$	24.08	$	21.68
Non-tertiary	16.83		18.58		15.02
Total lease operating expense per BOE	$	20.29	$	21.17	$	17.67

The 5% increase in lease operating expense during 2012, compared to 2011, is due to the expansion of our tertiary operations and the resultant higher production volumes. On a per-BOE basis, lease operating expense declined 4% between the two periods due primarily to lower non-tertiary operating cost per barrel. Lease operating expense increased 8% between 2010 and 2011 on an absolute-dollar basis and 20% on a per-BOE basis.

During 2012, tertiary lease operating expense increased 13% on an absolute-dollar basis compared to 2011 levels, but decreased slightly on a per-BOE basis, from an average of $24.08 per Bbl during 2011 to an average of $23.88 per Bbl during 2012. The decrease in tertiary operating costs per barrel is due to the 14% increase in tertiary production, which more than offset the higher total tertiary operating expenses resulting from the increase in the number of our active tertiary floods due to our new tertiary floods at Hastings and Oyster Bayou fields. For any specific field, we expect our tertiary lease operating expense per barrel to be high initially, as we experienced early in 2012 with our Oyster Bayou and Hastings floods, and then decrease as production increases, ultimately leveling off until production begins to decline in the later life of the field, when lease operating expense per barrel will again increase.

Our higher per-barrel tertiary lease operating expense in 2011, compared to 2010, was due primarily to higher workover, power, and facility and compressor repair expenses, plus higher CO₂ expense, which is primarily due to higher oil prices. Our single highest cost for our tertiary operations is our cost for fuel and utilities, averaging $6.51 per Bbl in 2012, $6.31 per Bbl in 2011 and $5.93 per Bbl in 2010, which has increased on a per-barrel basis due to the higher cost of these items, and the continued expansion of our tertiary floods.

Currently, our CO₂ expense comprises approximately one-fourth of our typical Gulf Coast tertiary operating expenses and consists of our CO₂ production expenses, payment to CO₂ royalty owners and taxes for the CO₂ we utilize in our tertiary floods. This cost for produced CO₂, which excludes depreciation and amortization of capital expended at our Jackson Dome source and CO₂ pipelines, was approximately $0.26 per Mcf in 2012 and 2011, compared to an average cost of $0.22 per Mcf in 2010. The change in our cost of CO₂ is primarily directly attributable to changes in oil prices, as the royalty we pay to CO₂ royalty owners is directly tied to oil prices. Including the cost of depreciation and amortization expense related to the Jackson Dome CO₂ production but excluding depreciation of our CO₂ pipelines, our cost of CO₂ was $0.33 per Mcf in 2012, $0.31 per Mcf in 2011 and $0.30 per Mcf in 2010.

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Non-tertiary lease operating expense decreased 5% on an absolute-dollar basis and decreased 9% on a per-BOE basis during 2012 compared to 2011. The lower operating expense per BOE was largely driven by increased production related to our Bakken area assets which had lower operating costs than our other properties, and the sale of certain non-core assets during the first half of 2012, which had a higher operating cost per BOE compared to the average of our other properties. We sold our Bakken area assets late in the fourth quarter of 2012, and thus expect our non-tertiary operating expense per BOE to increase during 2013. Excluding the Bakken area assets, our pro forma lease operating expense would have been $24.11 per BOE in 2012.

Non-tertiary lease operating costs declined between 2010 and 2011 on an absolute-dollar basis primarily due to the sale of non-strategic Encore assets during 2010, which reduced our lease operating costs by $44.1 million, partially offset by higher operating costs in our Rocky Mountain region. Increases in our Rocky Mountain region operating expenses are primarily attributable to: (1) the 2010 period being approximately ten months, as the properties were acquired in early March 2010; (2) the Cedar Creek Anticline, where we experienced higher workover costs in 2011 compared to 2010; and (3) the Bakken, where production increased significantly since 2010 due to new wells. Non-tertiary lease operating expense per BOE increased $3.56 (20%) between 2010 and 2011, primarily due to the sale of non-strategic Encore and ENP properties from May 2010 through December 2010, which were primarily natural gas properties that generally had a lower operating cost per BOE than Denbury's legacy properties.

Taxes other than income

Taxes other than income includes ad valorem, production and franchise taxes. On a per-BOE basis, taxes remained relatively steady between 2012 and 2011 and increased by 36% between 2010 and 2011. The change in each period is generally aligned with fluctuations in oil and natural gas revenues.

General and Administrative Expenses (“G&A”)



	Year Ended December 31,
In thousands, except per BOE data and employees	2012			2011			2010
Gross administrative costs	$	296,696		$	246,112		$	231,280
Gross stock-based compensation	37,897			39,875			35,075
Operator labor and overhead recovery charges	(141,358		)	(125,466		)	(112,160		)
Capitalized exploration and development costs	(49,216		)	(34,996		)	(20,074		)
Net G&A expense	$	144,019		$	125,525		$	134,121

G&A per BOE:
Net administrative costs	$	4.48		$	3.98		$	3.95
Net stock-based compensation	1.01			1.26			1.09
Net G&A expense	$	5.49		$	5.24		$	5.04
Employees as of December 31	1,432			1,308			1,195

Net G&A expense increased 15% between 2011 and 2012 and decreased 6% between 2010 and 2011 on an absolute-dollar basis and increased 5% between 2011 and 2012 and 4% between 2010 and 2011 on a per-BOE basis.

Gross administrative costs increased $50.6 million, or 21%, between 2011 and 2012, and increased $14.8 million, or 6%, between 2010 and 2011. The increase in 2012 compared to 2011 is due to higher compensation-related costs both from an increase in headcount from year-end 2011 levels (9%), as well as higher salaries and employee bonus expense in 2012, plus an increase in other employee-related costs such as health insurance. The annual employee bonus was paid at 105% of target in 2012 as compared to 67% of target in 2011. The increased gross administrative cost in 2011 compared to 2010 is primarily due to increased expense resulting from the Encore Merger, as the 2010 period included the effect of the Encore Merger beginning on the acquisition date, March 9, 2010.

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Stock-based compensation costs decreased in 2012 as compared to 2011 due to a shift in the mix of compensation awarded to employees during 2012 to include more cash-based compensation. Stock-based compensation costs increased during 2011 over 2010 levels primarily due to the increased number of employees during 2011 compared to 2010. Stock-based compensation, net of amounts reclassified to field operations or capitalized, were approximately $26.5 million in 2012, $30.3 million in 2011 and $27.9 million in 2010.

Our well operating agreements allow us, when we are the operator, to charge a well with a specified overhead rate during the drilling phase and also to charge a monthly fixed overhead rate for each producing well. In addition, salaries associated with field personnel are initially recorded as gross administrative costs and subsequently reclassified to lease operating expenses or capitalized to field development costs to the extent those individuals are dedicated to oil and gas production and development activities. As a result of additional operated wells and drilling activities, additional tertiary operations and increased compensation expense, the amount we recovered as operator labor and overhead charges increased by 13% between 2011 and 2012 and 12% between 2010 and 2011. Capitalized exploration and development costs also increased between the periods, primarily due to increased compensation costs subject to capitalization.

Interest and Financing Expenses



	Year Ended December 31,
In thousands, except per BOE data and interest rates	2012			2011			2010
Cash interest expense	$	216,205		$	207,727		$	221,759
Noncash interest expense	14,808			18,219			21,169
Less: Capitalized interest	(77,432		)	(61,586		)	(66,815		)
Interest expense, net	$	153,581		$	164,360		$	176,113
Interest expense, net per BOE	$	5.85		$	6.86		$	6.62
Average debt outstanding	$	2,935,485		$	2,470,682		$	2,736,634
Average interest rate ⁽¹⁾	7.4		%	8.4		%	8.1		%


(1)	Includes commitment fees but excludes debt issue costs and amortization of discount or premium.

Interest expense, net decreased $10.8 million, or 7%, between 2012 and 2011, and decreased $11.8 million, or 7%, between 2010 and 2011. The decline in interest expense between 2011 and 2012 is largely due to higher capitalized interest, offset in part by higher cash interest expense resulting from an increase in average debt outstanding during the period. Capitalized interest increased 26% during 2012 primarily due to incremental capitalized interest on the Riley Ridge plant and Greencore Pipeline construction projects. We expect capitalized interest to decline in 2013 primarily due to (1) a lower capitalization rate resulting from the issuance of our 2023 Notes and (2) the anticipated completion of a number of projects during 2013, including the Riley Ridge gas plant and Bell Creek Field, both of which are expected to be placed into service during the first half or mid-2013.

Interest expense, net decreased between 2010 and 2011 primarily due to a decrease in average debt outstanding. Our debt level increased in early 2010 as a result of the Encore Merger and decreased throughout 2010 and in early 2011, as we repaid debt with proceeds from the sale of non-strategic legacy Encore assets and our ENP ownership interests. Also, in early 2011 we refinanced $525 million of our 7½% senior subordinated debt with $400 million of our 6 3/8% senior subordinated debt, decreasing our debt outstanding and interest rate. Capitalized interest decreased 8% between 2010 and 2011 due to a reduction in capitalized interest on the Green Pipeline, which was placed in service during 2010, offset by incremental capitalized interest on CO₂ floods, Riley Ridge and the Greencore Pipeline.

See Note 5, Long-Term Debt, to the Consolidated Financial Statements for information regarding our February 2013 debt issuance and tender offer to refinance certain of our outstanding debt at a lower interest rate and for a longer term.

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

Depletion, Depreciation and Amortization ("DD&A")



	Year Ended December 31,
In thousands, except per BOE data	2012		2011		2010
Depletion and depreciation of oil and natural gas properties	$	420,094	$	362,788	$	394,957
Depletion and depreciation of CO₂ properties	23,843		18,220		20,665
Asset retirement obligations	7,228		6,287		6,443
Depreciation of other fixed assets	56,373		21,901		21,860
Cumulative change due to revision in policy for CO₂ properties	—		—		(9,618		)
Total DD&A	$	507,538	$	409,196	$	434,307

DD&A per BOE:
Oil and natural gas properties	$	16.28	$	15.40	$	15.08
CO₂ and other fixed assets	3.06		1.67		1.60
Cumulative change due to revision in policy for CO₂ properties	—		—		(0.36		)
Total DD&A cost per BOE	$	19.34	$	17.07	$	16.32

We adjust our DD&A rate each quarter for significant changes in our estimates of oil and natural gas reserves and costs. In addition, under full cost accounting rules, the divestiture of oil and gas properties generally does not result in gain or loss recognition; instead, the proceeds of the disposition reduce the full cost pool. As such, our DD&A rate has changed significantly over time, and it may continue to change in the future. Depletion and depreciation of oil and natural gas properties increased between 2011 and 2012 on both an absolute-dollar basis and a per-BOE basis. During the first nine months of 2012, our DD&A rate for our oil and natural gas properties was $16.90 per BOE, which was higher than 2011 levels due to higher finding and development costs related to our Bakken capital program. However, in the fourth quarter of 2012, our DD&A rate for our oil and natural gas properties decreased to $14.39 per BOE due to the Bakken Exchange Transaction. As a result of this transaction, there was a decrease in capitalized costs relating to the sales proceeds credited to the full cost pool and a significant reduction in future development costs relating to the sold proved reserves, partially offset by the reduction in total proved reserves. Upon the completion of the Pending CCA Acquisition late in the first quarter of 2013, we expect our DD&A rate to increase from the fourth quarter of 2012 rate due to our expectation that the CCA acquisition will be recorded at a rate higher than our current DD&A rate. However, since the value at which CCA is recorded is partially dependent upon the value of the to-be-acquired assets as of the closing date of the transaction in accordance with generally accepted accounting principles, we are not able to precisely predict the DD&A impact.

Depletion and depreciation of oil and natural gas properties decreased on an absolute-dollar basis during 2011 compared to 2010, primarily due to the sale of non-strategic legacy Encore assets and our ownership interests in ENP during 2010. Depletion and depreciation of oil and gas properties increased on a per-BOE basis during 2011 compared to 2010, primarily due to higher costs per barrel associated with our larger 2011 Bakken capital program and upward revisions in estimated future development costs, also primarily relating to the Bakken assets, offset in part by natural gas reserves added from the Riley Ridge acquisition, which were purchased at a low cost per Mcf.

During 2012, we added 114.2 MMBOE of estimated proved reserves, including tertiary reserves of 69.5 MMBbls, primarily at Hastings and Oyster Bayou fields based on these fields' responses to CO₂injections, 25.9 MMBOE from the acquisition of interests in the Thompson, Webster and Hartzog Draw fields, and 11.5 MMBOE from our Bakken area assets prior to their sale in the fourth quarter of 2012. These increases were offset by the disposition of 123.9 MMBOE of reserves associated with the disposed properties including our Bakken area assets, non-core assets in the Gulf Coast region and the Paradox Basin of Utah. We reclassified approximately $430 million from unevaluated properties to the full cost pool relating to Hastings and Oyster Bayou fields, representing the acquisition costs and development expenditures incurred on these fields prior to recognizing proved reserves.

Depletion and depreciation of our CO₂ properties increased on an absolute-dollar and BOE basis during 2012 from 2011 levels primarily due to increased drilling activity at Jackson Dome, and depreciation of other fixed assets increased during the same

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period due to incremental pipeline depreciation and the change in classification of our equipment leases from operating to capital during the second quarter of 2012. See Note 5, Long-Term Debt, to the Consolidated Financial Statements for further discussion. Our DD&A expense for our CO₂ assets decreased in 2011 compared to 2010 due to CO₂ reserve increases at Jackson Dome at the end of 2010. On a per BOE basis, DD&A expense for our CO₂ assets and other fixed assets increased in 2011 compared to that in the prior year period due to decreased oil and natural gas production volumes as a result of the sale of non-strategic Encore properties and our interests in ENP during 2010.

During the third quarter of 2010, we changed our method of accounting for CO₂ properties and recorded a one-time, non-cash net reduction of $9.6 million ($6.0 million after tax) to DD&A expense for the period, which reflects the cumulative impact of the revised accounting policy on our historical financials. See Note 1, Significant Accounting Policies, to the Consolidated Financial Statements for additional information regarding this change.

Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation. Under these rules, the full cost ceiling value is calculated using a 12-month average price based on the first-day price of every month during the period. We did not have a ceiling test write-down during 2012, 2011 or 2010. However, if oil prices were to decrease significantly in subsequent periods, we may be required to record write-downs under the full cost pool ceiling test in the future. The possibility and amount of any future write-down is difficult to predict and will depend upon oil and natural gas prices, the incremental proved reserves that may be added each period, revisions to previous estimates of reserves and future capital expenditures, and additional capital spent.

Encore Transaction and Other Costs and Impairment of Assets

The FASC Business Combinations topic requires that all transaction costs (advisory, legal, accounting, due diligence, integration, third-party fees, etc.) be expensed as incurred. We recognized a total of $4.4 million and $92.3 million of transaction and other costs during 2011 and 2010, respectively, associated with the Encore Merger, including $3.6 million and $43.8 million during 2011 and 2010, respectively, related to severance costs.

During 2012, we recognized $17.5 million of impairment charges primarily related to our investment in Faustina Hydrogen Products LLC, an entity created to develop a proposed plant from which we could offtake CO₂, as a result of the project not moving forward.

Income Taxes



	Year Ended December 31,
Amounts in thousands, except per BOE amounts and tax rates	2012			2011			2010
Current income tax expense	$	75,754		$	8,249		$	33,194
Deferred income tax expense	255,743			342,463			160,349
Total income tax expense	$	331,497		$	350,712		$	193,543
Average income tax expense per BOE	$	12.63		$	14.63		$	7.27
Effective tax rate	38.7		%	38.0		%	40.4		%
Total net deferred tax liability	$	2,124,296		$	1,868,420		$	1,520,538

Our income tax provision for 2012 was based on an estimated statutory rate of approximately 38.5%, while 2011 and 2010 tax provisions were based on an estimated statutory rate of approximately 38%. The increase in our statutory rate is partly driven by a shift in the amount of revenues we earn in each state due to recent acquisitions and divestitures. Our effective tax rate was consistent with our estimated statutory rates in 2012 and 2011; however, our 2010 effective tax rate was higher than the estimated statutory rate in that year primarily due to the recognition of additional net tax expense on the revaluation of our deferred taxes at the date of the Encore Merger.

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

The increase in current income tax expense during 2012 includes $42 million of current taxes resulting from the taxable gain recognized in the Bakken Exchange Transaction that we were unable to defer through a like-kind-exchange transaction. Current income tax expense during 2012, 2011 and 2010 also includes our anticipated alternative minimum cash taxes that we cannot offset with enhanced oil recovery credits, as well as state income taxes. Our current income tax expense during 2011 was offset by a net benefit due to the change in treatment for certain items between our 2010 tax provision and our 2010 filed tax return. This change in treatment resulted in a reclassification of approximately $16.9 million from current to deferred taxes.

As of December 31, 2012, we had an estimated $17.3 million of enhanced oil recovery credits to carry forward that can be utilized to reduce our current income taxes during 2013 or future years, down from $53.4 million in 2011 due to current year utilization. These enhanced oil recovery credits do not begin to expire until 2025. Since the ability to earn additional enhanced oil recovery credits is based upon the level of oil prices, we would not currently expect to earn additional enhanced oil recovery credits unless oil prices were to decrease significantly from current levels.

Per BOE Data

The following table summarizes our cash flow, DD&A and results of operations on a per BOE basis for the comparative periods. Each of the individual components is discussed above.



	Year Ended December 31,
Per BOE data	2012			2011			2010
Oil and natural gas revenues	$	91.85		$	94.68		$	67.37
Gain (loss) on settlements of derivative contracts	0.68			0.10			(1.19		)
Lease operating expenses	(20.29		)	(21.17		)	(17.67		)
Production and ad valorem taxes	(5.71		)	(5.81		)	(4.32		)
Marketing expenses, net of third party purchases	(1.60		)	(1.09		)	(1.17		)
Production netback	64.93			66.71			43.02
CO₂ sales, net of operating expenses	0.45			0.36			0.43
General and administrative expenses	(5.49		)	(5.24		)	(5.04		)
Transaction costs and other costs related to the Encore Merger	—			(0.18		)	(3.47		)
Interest expense, net	(5.85		)	(6.86		)	(6.62		)
Other	(1.44		)	1.95			0.77
Changes in assets and liabilities relating to operations	1.17			(6.47		)	3.06
Cash flow from operations	53.77			50.27			32.15
DD&A	(19.34		)	(17.07		)	(16.32		)
Deferred income taxes	(9.75		)	(14.29		)	(6.02		)
Gain on sale of interests in Genesis	—			—			3.81
Loss on early extinguishment of debt	—			(0.67		)	—
Non-cash commodity derivative adjustments	(0.50		)	2.09			1.99
Net income attributable to noncontrolling interest	—			—			(0.52		)
Impairment of assets	(0.67		)	(0.96		)	—
Other non-cash items	(3.49		)	4.55			(4.88		)
Net income	$	20.02		$	23.92		$	10.21

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

MARKET RISK MANAGEMENT

Restricted Cash

Restricted cash on our Consolidated Balance Sheet as of December 31, 2012 consists of proceeds from the Bakken Exchange Transaction (see Note 2, Acquisitions and Divestitures, to the Consolidated Financial Statements) being held by a qualified intermediary through three separate financial institutions and which are restricted for application towards future acquisitions to facilitate an anticipated like-kind-exchange transaction for federal income tax purposes. We manage and control counterparty credit risk related to this restricted cash using a trust agreement, whereby the assets held in trust must be segregated from the financial institution's assets, and in the event of its bankruptcy, the funds would not be subject to payments to the creditors of the financial institution.

Debt

We finance some of our acquisitions and other expenditures with fixed and variable rate debt. These debt agreements expose us to market risk related to changes in interest rates. At December 31, 2012, we had $700 million in outstanding borrowings on our bank credit facility. None of our existing debt has any triggers or covenants regarding our debt ratings with rating agencies, although under the NEJD financing lease, in the event of significant downgrades of our corporate credit rating by the rating agencies, certain credit enhancements can be required from us, and possibly other remedies made available under the lease. The fair value of our senior subordinated debt is based on quoted market prices. The following table presents the principal cash flows and fair values of our outstanding debt at December 31, 2012.



In thousands	2014		2015		2016		2017		2020		2021		Total		Fair Value
Variable rate debt:
Bank credit facility (weighted average interest rate of 1.96% at December 31, 2012)	$	—	$	—	$	700,000	$	—	$	—	$	—	$	700,000	$	700,000
Fixed rate debt:
9½% Senior Subordinated Notes due 2016	—		—		224,920		—		—		—		224,920		240,372
9¾% Senior Subordinated Notes due 2016	—		—		426,350		—		—		—		426,350		451,931
8¼% Senior Subordinated Notes due 2020	—		—		—		—		996,273		—		996,273		1,120,807
6 3/8% Senior Subordinated Notes due 2021	—		—		—		—		—		400,000		400,000		440,000
Other Subordinated Notes	1,072		485		—		2,250		—		—		3,807		3,807

See Note 5, Long-Term Debt, to the Consolidated Financial Statements for details regarding our long-term debt, including information regarding our February 2013 debt issuance and tender offers to refinance certain of our outstanding debt at a lower interest rate and for a longer term.

Oil and Natural Gas Derivative Contracts

From time to time, we enter into oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production. These contracts have consisted of price floors, collars and fixed price swaps. We do not hold or issue derivative financial instruments for trading purposes. The production that we hedge has varied from year to year, depending on our levels of debt and financial strength and expectation of future commodity prices. We currently employ a strategy to hedge a portion of our forecasted production for approximately two years in the future from the current quarter, as we believe it is important to protect our future cash flow for a short period of time in order to give us time to adjust to commodity price fluctuations, particularly since many of our expenditures have long lead times (see Capital Resources and Liquidity above). We recently extended this from a period closer to a year and a half into the future, due in part to slightly higher leverage. We do not have any natural gas derivative contracts for 2013 or beyond. Because our current and forecasted production is primarily oil (93% of BOE volumes in 2012), we use oil derivative contracts in our commodity market risk management program. See Note 9, Derivative Instruments and Hedging Activities, to the Consolidated Financial Statements for additional information regarding our commodity derivative contracts.

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All of the mark-to-market valuations used for our oil and natural gas derivatives are provided by external sources. We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification. All of our commodity derivative contracts are with parties that are lenders under our bank credit facility. We have included an estimate of nonperformance risk in the fair value measurement of our oil and natural gas derivative contracts, which we have measured for nonperformance risk based upon credit default swaps or credit spreads.

For accounting purposes, we do not apply hedge accounting to our oil and natural gas derivative contracts. This means that any changes in the fair value of these derivative contracts will be charged to earnings on a quarterly basis instead of charging the effective portion to other comprehensive income and the ineffective portion to earnings.

At December 31, 2012, our derivative contracts were recorded at their fair value, which was a net liability of approximately $6.9 million, a $13.0 million decrease from the $6.1 million net asset recorded at December 31, 2011. This change is primarily related to the expiration of oil and natural gas derivative contracts during 2012 and to the oil futures prices as of December 31, 2012, in relation to the new commodity derivative contracts we entered into during 2012 for future periods.

Commodity Derivative Sensitivity Analysis

Based on NYMEX crude oil and natural gas futures prices as of December 31, 2012, and assuming both a 10% increase and decrease thereon, we would expect to make or receive payments on our crude oil derivative contracts as shown in the following table:



	Crude Oil Derivative Contracts
In thousands	Receipt/ (Payment)
Based on:
NYMEX futures prices as of December 31, 2012	$	—
10% increase in prices	(35,849		)
10% decrease in prices	—

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in accordance with generally accepted accounting principles requires that we select certain accounting policies and make certain estimates and judgments regarding the application of those policies. Our significant accounting policies are included in Note 1, Significant Accounting Policies, to the Consolidated Financial Statements. These policies, along with the underlying assumptions and judgments by our management in their application, have a significant impact on our consolidated financial statements. Following is a discussion of our most critical accounting estimates, judgments and uncertainties that are inherent in the preparation of our financial statements.

Full Cost Method of Accounting, Depletion and Depreciation and Oil and Natural Gas Properties

Businesses involved in the production of oil and natural gas are required to follow accounting rules that are unique to the oil and gas industry. We apply the full cost method of accounting for our oil and natural gas properties. Another acceptable method of accounting for oil and natural gas production activities is the successful efforts method of accounting. In general, the primary differences between the two methods are related to the capitalization of costs and the evaluation for asset impairment. Under the full cost method, all geological and geophysical costs, exploratory dry holes and delay rentals are capitalized to the full cost pool, whereas under the successful efforts method such costs are expensed as incurred. In the assessment of impairment of oil and natural gas properties, the successful efforts method follows the FASB guidance under the Accounting for the Impairment or Disposal of Long-Lived Assets topic of the FASC, under which the net book value of assets is measured for impairment against the undiscounted future cash flows using commodity prices consistent with management expectations. Under the full cost method, the full cost pool (net book value of oil and natural gas properties) is measured against future cash flows discounted at 10% using

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the average first-day-of-the-month oil and natural gas price for each month during the 12-month period ended as of each quarterly reporting period. The financial results for a given period could be substantially different depending on the method of accounting that an oil and gas entity applies. Further, we do not designate our oil and natural gas derivative contracts as hedge instruments for accounting purposes under the Derivatives and Hedging topic of the FASC (see below), and as a result, these contracts are not considered in the full cost ceiling test.

We make significant estimates at the end of each period related to accruals for oil and natural gas revenues, production, capitalized costs and operating expenses. We calculate these estimates with our best available data, which includes, among other things, production reports, price posting, information compiled from daily drilling reports and other internal tracking devices, and analysis of historical results and trends. While management is not aware of any required revisions to its estimates, there will likely be future adjustments resulting from such things as changes in ownership interests, payouts, joint venture audits, re-allocations by the purchaser/pipeline, or other corrections and adjustments common in the oil and gas industry, many of which will require retroactive application. These types of adjustments cannot be currently estimated or determined and will be recorded in the period during which the adjustment occurs.

Under full cost accounting, the estimated quantities of proved oil and natural gas reserves used to compute depletion and the related present value of estimated future net cash flows therefrom used to perform the full cost ceiling test have a significant impact on the underlying financial statements. The process of estimating oil and natural gas reserves is very complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continued reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that the reported reserve estimates represent the most accurate assessments possible, including the hiring of independent engineers to prepare reported estimates, the subjective decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in our financial statement disclosures. Over the last four years, annual revisions to our reserve estimates have averaged approximately 1.7% of the previous year’s estimates and have been both positive and negative.

Changes in commodity prices also affect our reserve quantities. Between 2010 and 2011, oil prices used to calculate reserve quantities in our year-end proved reserve report increased, resulting in an additional increase in our proved reserves of 2.6 MMBOE. Between 2011 and 2012, oil and natural gas prices used to calculate year-end proved reserves decreased, resulting in a decrease in our proved reserves of 6.7 MMBOE. These changes in quantities affect our DD&A rate, and the combined effect of changes in quantities and commodity prices impacts our full cost ceiling test calculation. For example, we estimate that a 5% increase in our estimate of proved reserves quantities would have lowered our fourth quarter 2012 DD&A rate from $18.20 per BOE to approximately $17.54 per BOE, and a 5% decrease in our proved reserve quantities would have increased our DD&A rate to approximately $18.93 per BOE. Also, reserve quantities and their ultimate values, determined solely by our lenders, are the primary factors in determining the maximum borrowing base under our bank credit facility.

Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation. The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as: (1) the present value of our future net revenues from proved reserves before future abandonment costs calculated using the average first-day-of-the-month oil and natural gas price for each month during the 12-month period then ended, discounted at 10%; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects. Our future net revenues from proved reserves are not reduced for development costs related to the cost of drilling for and developing CO₂ reserves nor for those related to the cost of constructing CO₂ pipelines, as those costs have already been incurred by the Company. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO₂ costs related to CO₂ reserves and CO₂ pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes.

We did not have a full cost pool ceiling test write-down in 2012, 2011 or 2010. Crude oil prices increased between 2010 and 2011, but decreased slightly during 2012, with first-day-of-the-month NYMEX oil prices during 2012 averaging $94.71 per Bbl

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Denbury Resources Inc.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

during the year. First-day-of-the-month unweighted average NYMEX natural gas prices during 2012 of $2.85 per Mcf were lower than 2011 levels due to declining prices early in 2012. Natural gas prices began to rise later in 2012, ending the year at $3.35 per Mcf at December 31, 2012. Commodity prices have historically been volatile and are expected to continue to be so in the future. If oil and natural gas prices should decrease, we may be required to record write-downs due to the full cost ceiling test. The amount of any future write-down is difficult to predict and will depend upon the oil and natural gas prices utilized in the ceiling test, the incremental proved reserves that might be added during each period and additional capital spent.

Tertiary Injection Costs

Our tertiary operations are conducted in reservoirs that have already produced significant amounts of oil over many years; however, in accordance with the rules for recording proved reserves, we cannot recognize proved reserves associated with enhanced recovery techniques such as CO₂ injection until we can demonstrate production resulting from the tertiary process or unless the field is analogous to an existing flood. Our costs associated with the CO₂ we produce (or acquire) and inject are principally our cash out-of-pocket costs of production, transportation and acquisition, and to pay royalties.

We capitalize, as a development cost, injection costs in fields that are in their development stage, which means we have not yet seen incremental oil production due to the CO₂ injections (i.e., a production response). These capitalized development costs will be included in our unevaluated property costs if there are not already proved tertiary reserves in that field. After we see a production response to the CO₂ injections (i.e., the production stage), injection costs will be expensed as incurred, and any previously deferred unevaluated development costs will become subject to depletion upon recognition of proved tertiary reserves. During 2012, 2011 and 2010, we capitalized $36.8 million, $65.3 million and $20.5 million, respectively, of tertiary injection costs associated with our tertiary projects.

Income Taxes

We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Our federal and state income tax returns are generally not prepared or filed before the consolidated financial statements are prepared; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits and net operating loss carryforwards. Adjustments related to these estimates are recorded in our tax provision in the period in which we finalize our income tax returns. Further, we must assess the likelihood that we will be able to recover or utilize our deferred tax assets (primarily our enhanced oil recovery credits and state loss carryforwards). If recovery is not likely, we must record a valuation allowance against such deferred tax assets for the amount we would not expect to recover, which would result in an increase to our income tax expense. As of December 31, 2012, we believe that all of our deferred tax assets recorded on our Consolidated Balance Sheet will ultimately be recovered. If our estimates and judgments change regarding our ability to utilize our deferred tax assets, our tax provision would increase in the period it is determined that recovery is not likely. A 1% increase in our effective tax rate would have increased our calculated income tax expense by approximately $8.6 million, $9.2 million and $4.8 million for the years ended December 31, 2012, 2011 and 2010, respectively. See Note 6, Income Taxes, to the Consolidated Financial Statements and see Income Taxes above for further information concerning our income taxes.

Fair Value Estimates

The FASC defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. It does not require us to make any new fair value measurements, but rather establishes a fair value hierarchy that prioritizes the inputs to the valuation techniques used to measure fair value. Level 1 inputs are given the highest priority in the fair value hierarchy, as they represent observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date, while Level 3 inputs are given the lowest priority, as they represent unobservable inputs that are not corroborated by market data. Valuation techniques that maximize the use of observable inputs are favored. See Note 10, Fair Value Measurements, to the Consolidated Financial Statements for disclosures regarding our recurring fair value measurements.

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Denbury Resources Inc.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Significant uses of fair value measurements include:


•	allocation of the purchase price paid to acquire businesses to the assets acquired and liabilities assumed in those acquisitions;


•	assessment of impairment of long-lived assets;


•	assessment of impairment of goodwill; and


•	recorded value of derivative instruments.

Acquisitions

Under the acquisition method of accounting for business combinations, the purchase price paid to acquire a business is allocated to its assets and liabilities based on the estimated fair values of the assets acquired and liabilities assumed as of the date of acquisition. The FASC Fair Value Measurements and Disclosures topic defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (often referred to as the “exit price”). A fair value measurement is based on the assumptions of market participants and not those of the reporting entity. Therefore, entity-specific intentions do not impact the measurement of fair value unless those assumptions are consistent with market participant views.

The excess of the purchase price over the fair value of the net tangible and identifiable intangible assets acquired is recorded as goodwill. A significant amount of judgment is involved in estimating the individual fair values involving long-term tangible assets, identifiable intangible assets and long-term asset retirement obligations. We use all available information to estimate the fair values of assets acquired and liabilities assumed in an acquisition and engage a third-party consultant to review certain assumptions utilized in our valuations.

Specifically, the valuation of oil properties recoverable through enhanced oil recovery requires us to estimate the cost a third party market participant would pay for CO₂. A third party's economics and access to CO₂ is substantially different in our operating regions than our own, as CO₂ is limited and there may be no known CO₂ available in a given area except through our own sources. These factors generally result in our estimation of the cost of CO₂ to a market participant being higher than our cost. Because of our strategic advantage relating to CO₂ supply and associated infrastructure, a third party's economics (the required basis for allocating values) for a potential EOR flood will be less than ours. Therefore, we cannot attribute much, if any, of our purchase price relating to the future EOR flood to unevaluated properties, even though we may have attributed value to the future flood when we made the purchase decision. As such, we must attribute the unallocated purchase price to goodwill, which has resulted in our recognition of more goodwill than most of our industry peers.

The fair values used to allocate the purchase price of an acquisition are often estimated using the expected present value of future cash flows method, which requires us to project related future cash inflows and outflows and apply an appropriate discount rate. The estimates used in determining fair values are based on assumptions believed to be reasonable but that are inherently uncertain. Accordingly, actual results may differ from the projected results used to determine fair value.

Impairment Assessment of Goodwill

We test goodwill for impairment annually during the fourth quarter, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. The need to test for impairment can be based on several indicators, including a significant reduction in prices of oil or natural gas, a full-cost ceiling write-down of oil and natural gas properties, unfavorable adjustments to reserves, significant changes in the expected timing of production, other changes to contracts or changes in the regulatory environment.

Goodwill is tested for impairment at the reporting unit level. Denbury applies SEC full cost accounting rules, under which the acquisition cost of oil and gas properties is recognized on a cost center basis (country), of which Denbury has only one cost center (United States). Goodwill is assigned to this single reporting unit.

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Denbury Resources Inc.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

In each period that a goodwill impairment test is performed, we have the option to assess qualitative factors to determine if it is more likely than not that our reporting unit’s fair value is less than its carrying amount. The following events and circumstances are certain of the qualitative factors we consider in evaluating whether it is more likely than not the fair value of our reporting unit is less than its carrying amount:


•	Macroeconomic conditions, such as deterioration in general economic conditions, limitations on accessing capital, or other developments in equity and credit markets;


•	Industry and market conditions, such as deterioration in the environment in which we operate, including significant declines in oil prices, inability to access oil field equipment and/or qualified personnel and regulations impacting the oil and natural gas industry, among others;


•	Cost factors, such as increases in power and labor costs;


•	Overall financial performance, such as negative or declining cash flows or a decline in actual or forecasted revenues or earnings;


•	Other relevant Company-specific events, such as material changes in management or key personnel, a change in strategy or litigation;


•	Material events, such as a change in the composition or carrying amount of our reporting unit’s net assets, including acquisitions and dispositions; and


•	Consideration of the relationship of our market capitalization to our book value, as well as a sustained decrease in our share price.

If we determine that it is more likely than not that our reporting unit’s fair value is less than its carrying amount, we will proceed to step 1 of the 2-step quantitative goodwill assessment, in which we perform a calculation to compare the fair value of our reporting unit to its carrying cost. In any given period, we have the option to bypass the qualitative assessment and proceed directly to step 1 of the 2-step quantitative goodwill impairment test.

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 and net asset value when appropriate. The Company also takes into consideration the Company's market capitalization, including a control premium. A significant amount of judgment is involved in performing these fair value estimates for goodwill, since the results are based on forecasted assumptions. Significant assumptions include projections of future oil and natural gas prices, projections of estimated quantities of oil and natural gas reserves, projections of future rates of production, timing and amount of future development and operating costs, projected availability and cost of CO₂, projected recovery factors of tertiary 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.

We completed our goodwill impairment assessment during the fourth quarter of 2012 and did not record any goodwill impairment during 2012, nor have we recorded a goodwill impairment historically.

Oil and Natural Gas Derivative Contracts

We enter into oil and natural gas derivative contracts to mitigate our exposure to commodity price risk associated with future oil and natural gas production. These contracts have historically consisted of options, in the form of price floors or collars, and fixed price swaps. We do not designate these derivative commodity contracts as hedge instruments for accounting purposes under the FASC Derivatives and Hedging topic. This means that any changes in the fair value of these derivative contracts will be charged to earnings on a quarterly basis instead of charging the effective portion to other comprehensive income and the balance to earnings. While we may experience more volatility in our net income than if we were to apply hedge accounting treatment as permitted by the FASC Derivatives and Hedging topic, we believe that for us the benefits associated with applying hedge accounting do not outweigh the cost, time and effort to comply with hedge accounting. During 2012, 2011 and 2010, we recognized expense (income) of $13.0 million, $(50.1) million and $(53.0) million, respectively, related to non-cash changes in the fair market value of our derivative contracts.

Use of Estimates

See Note 1, Significant Accounting Policies, to the Consolidated Financial Statements for a discussion of our use of estimates.

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Denbury Resources Inc.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Recent Accounting Pronouncements

See Note 1, Significant Accounting Policies, to the Consolidated Financial Statements for a discussion of the effects of recently issued and recently adopted accounting pronouncements.

FORWARD-LOOKING INFORMATION

The statements contained in this Annual Report on Form 10-K that are not historical facts, including, but not limited to, statements found in the sections entitled “Business” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” are forward-looking statements, as that term is defined in Section 21E of the Securities and Exchange Act of 1934, as amended, that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, forecasted capital expenditures, drilling activity or methods including the timing and location thereof, completion of pending acquisitions and the hydrocarbon reserves and production attributable to them, timing of CO₂ injections and initial production responses in tertiary flooding projects, acquisition plans and proposals and dispositions, development activities, finding costs, cost savings, capital budgets, production rates and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO₂ reserves, helium reserves, potential reserves, percentages of recoverable original oil in place, hydrocarbon prices, pricing or cost assumptions based on current and projected oil and gas prices, liquidity, cash flows, availability of capital, borrowing capacity, regulatory matters, prospective legislation affecting the oil and gas industry, mark-to-market values, competition, long-term forecasts of production, finding costs, rates of return, estimated costs, or changes in costs, future capital expenditures and overall economics and other variables surrounding our operations and future plans. Such forward-looking statements generally are accompanied by words such as “plan,” “estimate,” “expect,” “predict,” “anticipate,” “projected,” “should,” “assume,” “believe,” “target” or other words that convey the uncertainty of future events or outcomes. Such forward-looking information is based upon management’s current plans, expectations, estimates and assumptions and is subject to a number of risks and uncertainties that could significantly affect current plans, anticipated actions, the timing of such actions and our financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by us or on our behalf. Among the factors that could cause actual results to differ materially are fluctuations of the prices received or demand for our oil and natural gas; effects of our indebtedness; success of our risk management techniques; inaccurate cost estimates; availability of and fluctuations in the prices of goods and services; the uncertainty of drilling results and reserve estimates; operating hazards; disruption of operations and damages from hurricanes or tropical storms; acquisition risks; requirements for capital or its availability; conditions in the financial and credit markets; general economic conditions; competition and government regulations; and unexpected delays, as well as the risks and uncertainties inherent in oil and gas drilling and production activities or that are otherwise discussed in this annual report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in our other public reports, filings and public statements.

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Denbury Resources Inc.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The information required by Item 7A is set forth under Market Risk Management in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Item 8. Financial Statements and Supplementary Data



		Page

Report of Independent Registered Public Accounting Firm		66
Consolidated Balance Sheets		67
Consolidated Statements of Operations		68
Consolidated Statements of Comprehensive Operations		69
Consolidated Statements of Cash Flows		70
Consolidated Statements of Changes in Stockholders’ Equity		71
Notes to Consolidated Financial Statements
1.	Significant Accounting Policies	74
2.	Acquisitions and Divestitures	81
3.	Asset Retirement Obligations	86
4.	Property and Equipment	87
5.	Long-Term Debt	88
6.	Income Taxes	92
7.	Stockholders' Equity	94
8.	Stock Compensation Plans	94
9.	Derivative Instruments and Hedging Activities	99
10.	Fair Value Measurements	100
11.	Commitments and Contingencies	103
12.	Supplemental Information	104
13.	Subsequent Events	106
14.	Supplemental Oil and Natural Gas Disclosures (Unaudited)	107
15.	Supplemental CO₂ and Helium Disclosures (Unaudited)	111
16.	Unaudited Quarterly Information	112

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Denbury Resources Inc.:

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Denbury Resources Inc. and its subsidiaries at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Dallas, Texas

February 28, 2013

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Denbury Resources Inc.

Consolidated Balance Sheets

(In thousands, except par value and share data)



	December 31,
	2012			2011
Assets
Current assets
Cash and cash equivalents	$	98,511		$	18,693
Restricted cash	1,050,015			—
Accrued production receivable	253,131			294,689
Trade and other receivables, net	81,971			164,446
Short-term investments	—			86,682
Derivative assets	19,477			47,402
Deferred tax assets	29,156			50,156
Other current assets	10,493			22,045
Total current assets	1,542,754			684,113
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved	6,963,211			7,026,579
Unevaluated	809,154			1,157,106
CO₂ properties	1,032,653			596,003
Pipelines and plants	2,035,126			1,701,756
Other property and equipment	417,207			157,674
Less accumulated depletion, depreciation, amortization and impairment	(3,180,241		)	(2,627,493		)
Net property and equipment	8,077,110			8,011,625
Derivative assets	36			29
Goodwill	1,283,590			1,236,318
Other assets	235,852			252,339
Total assets	$	11,139,342		$	10,184,424
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	414,668		$	429,336
Oil and gas production payable	161,945			197,092
Derivative liabilities	2,842			26,523
Current maturities of long-term debt	36,966			8,316
Total current liabilities	616,421			661,267
Long-term liabilities
Long-term debt, net of current portion	3,104,462			2,669,729
Asset retirement obligations	102,730			88,726
Derivative liabilities	23,781			18,872
Deferred taxes	2,153,452			1,918,576
Other liabilities	23,607			20,756
Total long-term liabilities	5,408,032			4,716,659
Commitments and contingencies (Note 11)
Stockholders’ equity
Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding	—			—
Common stock, $.001 par value, 600,000,000 shares authorized; 406,163,194 and 402,946,070 shares issued, respectively	406			403
Paid-in capital in excess of par	3,136,461			3,090,374
Retained earnings	2,434,835			1,909,475
Accumulated other comprehensive loss	(348		)	(418		)
Treasury stock, at cost, 30,601,262 and 13,965,673 shares, respectively	(456,465		)	(193,336		)
Total stockholders’ equity	5,114,889			4,806,498
Total liabilities and stockholders’ equity	$	11,139,342		$	10,184,424

See accompanying Notes to Consolidated Financial Statements.

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Denbury Resources Inc.

Consolidated Statements of Operations

(In thousands, except per share data)



	Year Ended December 31,
	2012			2011			2010
Revenues and other income
Oil, natural gas, and related product sales	$	2,409,867		$	2,269,151		$	1,793,292
CO₂ sales and transportation fees	26,453			22,711			19,204
Gain on sale of interests in Genesis	—			—			101,537
Interest income and other income	20,152			17,462			7,758
Total revenues and other income	2,456,472			2,309,324			1,921,791
Expenses
Lease operating expenses	532,359			507,397			470,364
Marketing expenses	52,836			26,047			31,036
CO₂ discovery and operating expenses	14,694			14,258			7,801
Taxes other than income	160,016			147,534			120,541
General and administrative expenses	144,019			125,525			134,121
Interest, net of amounts capitalized of $77,432, $61,586 and $66,815, respectively	153,581			164,360			176,113
Depletion, depreciation and amortization	507,538			409,196			434,307
Derivatives expense (income)	(4,834		)	(52,497		)	(23,833		)
Loss on early extinguishment of debt	—			16,131			—
Transaction and other costs related to the Encore Merger	—			4,377			92,271
Impairment of assets	17,515			22,951			—
Other expenses	21,891			—			—
Total expenses	1,599,615			1,385,279			1,442,721
Income before income taxes	856,857			924,045			479,070
Income tax provision	331,497			350,712			193,543
Consolidated net income	525,360			573,333			285,527
Less: net income attributable to noncontrolling interest	—			—			(13,804		)
Net income attributable to Denbury stockholders	$	525,360		$	573,333		$	271,723

Net income per common share – basic	$	1.36		$	1.45		$	0.73
Net income per common share – diluted	1.35			1.43			0.72

Weighted average common shares outstanding
Basic	385,205			396,023			370,876
Diluted	388,938			400,958			376,255

See accompanying Notes to Consolidated Financial Statements.

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Denbury Resources Inc.

Consolidated Statements of Comprehensive Operations

(In thousands)



	Year Ended December 31,
	2012		2011		2010
Consolidated net income	$	525,360	$	573,333	$	285,527
Other comprehensive income (loss), net of income tax:
Interest rate lock derivative contracts reclassified to income, net of tax of $43, $43 and $43, respectively	70		70		69
Change in deferred hedge loss on interest rate swaps, net of tax benefit of $62	—		—		(83		)
Total other comprehensive income (loss)	70		70		(14		)
Comprehensive income	525,430		573,403		285,513
Less: comprehensive income attributable to noncontrolling interest	—		—		(13,727		)
Comprehensive income attributable to Denbury stockholders	$	525,430	$	573,403	$	271,786

See accompanying Notes to Consolidated Financial Statements.

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Denbury Resources Inc.

Consolidated Statements of Cash Flows

(In thousands)



	Year Ended December 31,
	2012			2011			2010
Cash flow from operating activities:
Consolidated net income	$	525,360		$	573,333		$	285,527
Adjustments to reconcile consolidated net income to cash flow from operating activities:
Depletion, depreciation and amortization	507,538			409,196			434,307
Deferred income taxes	255,743			342,463			160,349
Gain on sale of interests in Genesis	—			—			(101,537		)
Stock-based compensation	29,310			33,190			35,366
Noncash fair value derivative adjustments	13,159			(50,008		)	(55,445		)
Loss on early extinguishment of debt	—			16,131			—
Amortization of debt issuance costs and discounts	14,695			16,954			17,876
Impairment of assets	17,515			22,951			—
Other, net	16,804			(4,302		)	(2,144		)
Changes in assets and liabilities, net of effects from acquisitions:
Accrued production receivable	36,234			(74,781		)	2,426
Trade and other receivables	45,836			(55,470		)	24,977
Other current and long-term assets	7,688			(15,817		)	(4,119		)
Accounts payable and accrued liabilities	5,828			(35,462		)	48,549
Oil and natural gas production payable	(23,460		)	54,391			15,565
Other liabilities	(41,359		)	(27,955		)	(5,886		)
Net cash provided by operating activities	1,410,891			1,204,814			855,811

Cash flow used for investing activities:
Oil and natural gas capital expenditures	(1,122,615		)	(1,082,853		)	(671,574		)
Acquisitions of oil and natural gas properties	(156,082		)	(35,305		)	(25,672		)
Cash paid in Encore Merger and Riley Ridge acquisitions	—			(199,263		)	(947,241		)
Cash received in Bakken Exchange Transaction	281,669			—			—
CO₂ capital expenditures	(131,043		)	(84,789		)	(93,556		)
Pipelines and plants capital expenditures	(330,417		)	(236,133		)	(207,536		)
Purchases of other assets	(25,765		)	(28,838		)	(28,684		)
Net proceeds from sale of interests in Genesis	—			—			162,619
Net proceeds from sales of oil and natural gas properties and equipment	34,750			69,370			1,458,029
Net proceeds from sale of short-term investments	83,545			—			—
Other	(10,883		)	(8,147		)	(1,165		)
Net cash used for investing activities	(1,376,841		)	(1,605,958		)	(354,780		)

Cash flow provided by (used for) financing activities:
Bank repayments	(1,555,000		)	(330,000		)	(1,530,000		)
Bank borrowings	1,870,000			715,000			1,114,000
Repayment of senior subordinated notes	—			(525,000		)	(609,424		)
Premium paid on repayment of senior subordinated notes	—			(13,137		)	(7,213		)
Net proceeds from issuance of senior subordinated notes	—			400,000			1,000,000
Costs of debt financing	(34		)	(13,123		)	(76,251		)
ENP distributions to noncontrolling interest	—			—			(36,738		)
Common stock repurchase program	(251,480		)	(195,227		)	—
Other	(17,718		)	(545		)	5,873
Net cash provided by (used for) financing activities	45,768			37,968			(139,753		)
Net increase (decrease) in cash and cash equivalents	79,818			(363,176		)	361,278
Cash and cash equivalents at beginning of year	18,693			381,869			20,591
Cash and cash equivalents at end of year	$	98,511		$	18,693		$	381,869

See accompanying Notes to Consolidated Financial Statements.

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Denbury Resources Inc.

Consolidated Statements of Changes in Stockholders’ Equity

(Dollar amounts in thousands)



	Common Stock ($.001 Par Value)				Paid-In Capital in Excess of Par			Retained Earnings		Accumulated Other Comprehensive Income (Loss)			Treasury Stock (at cost)					Denbury Stockholders' Equity			Non-controlling Interest		Total Equity
	Shares		Amount		Paid-In Capital in Excess of Par			Retained Earnings		Accumulated Other Comprehensive Income (Loss)			Shares		Amount			Denbury Stockholders' Equity			Non-controlling Interest		Total Equity
Balance – December 31, 2011	402,946,070		$	403	$	3,090,374		$	1,909,475	$	(418	)	13,965,673		$	(193,336	)	$	4,806,498		$	—	$	4,806,498
Repurchase of common stock	—		—		—			—		—			472,966		(8,125		)	(8,125		)	—		(8,125		)
Issued pursuant to employee stock purchase plan	—		—		1,607			—		—			(815,385	)	11,653			13,260			—		13,260
Stock Repurchase Program	—		—		—			—		—			16,978,008		(266,657		)	(266,657		)	—		(266,657		)
Issued pursuant to employee stock option plan	1,429,309		1		6,022			—		—			—		—			6,023			—		6,023
Issued pursuant to directors' compensation plan	19,648		—		321			—		—			—		—			321			—		321
Restricted stock grants	1,909,739		2		(1		)	—		—			—		—			1			—		1
Restricted stock grants – forfeited	(261,762	)	—		—			—		—			—		—			—			—		—
Performance-based shares issued	120,190		—		—			—		—			—		—			—			—		—
Stock-based compensation	—		—		37,897			—		—			—		—			37,897			—		37,897
Income tax benefit from equity awards	—		—		241			—		—			—		—			241			—		241
Derivative contracts, net	—		—		—			—		70			—		—			70			—		70
Net income	—		—		—			525,360		—			—		—			525,360			—		525,360
Balance – December 31, 2012	406,163,194		$	406	$	3,136,461		$	2,434,835	$	(348	)	30,601,262		$	(456,465	)	$	5,114,889		$	—	$	5,114,889

See accompanying Notes to Consolidated Financial Statements.

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Denbury Resources Inc.

Consolidated Statements of Changes in Stockholders’ Equity

(Dollar amounts in thousands)



	Common Stock ($.001 Par Value)				Paid-In Capital in Excess of Par			Retained Earnings		Accumulated Other Comprehensive Income (Loss)			Treasury Stock (at cost)					Denbury Stockholders' Equity			Non-controlling Interest		Total Equity
	Shares		Amount		Paid-In Capital in Excess of Par			Retained Earnings		Accumulated Other Comprehensive Income (Loss)			Shares		Amount			Denbury Stockholders' Equity			Non-controlling Interest		Total Equity
Balance – December 31, 2010	400,291,033		$	400	$	3,045,937		$	1,336,142	$	(488	)	78,524		$	(1,284	)	$	4,380,707		$	—	$	4,380,707
Repurchase of common stock	—		—		—			—		—			441,406		(9,683		)	(9,683		)	—		(9,683		)
Issued pursuant to employee stock purchase plan	11,330		—		(1,623		)	—		—			(666,867	)	12,858			11,235			—		11,235
Stock Repurchase Program	—		—		—			—		—			14,112,610		(195,227		)	(195,227		)	—		(195,227		)
Issued pursuant to employee stock option plan	1,200,759		1		4,685			—		—			—		—			4,686			—		4,686
Issued pursuant to directors' compensation plan	19,745		—		309			—		—			—		—			309			—		309
Restricted stock grants	1,134,627		1		—			—		—			—		—			1			—		1
Restricted stock grants – forfeited	(157,811	)	—		—			—		—			—		—			—			—		—
Performance-based shares issued	446,387		1		—			—		—			—		—			1			—		1
Stock-based compensation	—		—		40,187			—		—			—		—			40,187			—		40,187
Income tax benefit from equity awards	—		—		879			—		—			—		—			879			—		879
Derivative contracts, net	—		—		—			—		70			—		—			70			—		70
Net income	—		—		—			573,333		—			—		—			573,333			—		573,333
Balance – December 31, 2011	402,946,070		$	403	$	3,090,374		$	1,909,475	$	(418	)	13,965,673		$	(193,336	)	$	4,806,498		$	—	$	4,806,498

See accompanying Notes to Consolidated Financial Statements.

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Denbury Resources Inc.

Consolidated Statements of Changes in Stockholders’ Equity

(Dollar amounts in thousands)



	Common Stock ($.001 Par Value)				Paid-In Capital in Excess of Par			Retained Earnings		Accumulated Other Comprehensive Income (Loss)			Treasury Stock (at cost)					Denbury Stockholders' Equity			Non-controlling Interest			Total Equity
	Shares		Amount		Paid-In Capital in Excess of Par			Retained Earnings		Accumulated Other Comprehensive Income (Loss)			Shares		Amount			Denbury Stockholders' Equity			Non-controlling Interest			Total Equity
Balance – December 31, 2009	261,929,292		$	262	$	910,540		$	1,064,419	$	(557	)	156,284		$	(2,427	)	$	1,972,237		$	—		$	1,972,237
Repurchase of common stock	—		—		—			—		—			413,869		(6,729		)	(6,729		)	—			(6,729		)
Issued pursuant to employee stock purchase plan	—		—		325			—		—			(491,629	)	7,872			8,197			—			8,197
Issued pursuant to employee stock option plan	999,077		1		4,867			—		—			—		—			4,868			—			4,868
Issued pursuant to directors' compensation plan	16,118		—		266			—		—			—		—			266			—			266
Issued pursuant to Encore Merger	135,170,505		135		2,085,546			—		—			—		—			2,085,681			—			2,085,681
Encore restricted stock grants	1,070,686		1		(1		)	—		—			—		—			—			—			—
Restricted stock grants	960,597		1		—			—		—			—		—			1			—			1
Restricted stock grants – forfeited	(301,735	)	—		—			—		—			—		—			—			—			—
Performance-based shares issued	446,493		—		—			—		—			—		—			—			—			—
Stock-based compensation	—		—		39,791			—		—			—		—			39,791			—			39,791
Income tax benefit from equity awards	—		—		4,603			—		—			—		—			4,603			—			4,603
ENP revaluation at Encore Merger	—		—		—			—		—			—		—			—			515,210			515,210
ENP cash distributions to noncontrolling interest	—		—		—			—		—			—		—			—			(36,738		)	(36,738		)
Sale of ENP	—		—		—			—		—			—		—			—			(492,193		)	(492,193		)
Derivative contracts, net	—		—		—			—		69			—		—			69			(83		)	(14		)
Consolidated net income	—		—		—			271,723		—			—		—			271,723			13,804			285,527
Balance – December 31, 2010	400,291,033		$	400	$	3,045,937		$	1,336,142	$	(488	)	78,524		$	(1,284	)	$	4,380,707		$	—		$	4,380,707

See accompanying Notes to Consolidated Financial Statements.

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Denbury Resources Inc.

Notes to Consolidated Financial Statements

Note 1. Significant Accounting Policies

Organization and Nature of Operations

Denbury Resources Inc., a Delaware corporation, is a growing independent oil and natural gas company. We are the largest combined oil and natural gas producer in both Mississippi and Montana, own the largest 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 our acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO₂ tertiary recovery operations.

Encore Merger. On March 9, 2010, we acquired Encore Acquisition Company (“Encore”), pursuant to an Agreement and Plan of Merger (the “Encore Merger Agreement”), under which Encore was merged with and into Denbury (the “Encore Merger”), with Denbury surviving the Encore Merger following approval by the stockholders of both Denbury and Encore, closing of a new revolving credit facility as part of the financing for the Encore Merger, and satisfaction of other conditions precedent. The Encore Merger provided Encore stockholders stock and/or cash and included the assumption of Encore’s debt by Denbury. Denbury has consolidated Encore’s results of operations since the March 9, 2010 acquisition date. See Note 2, Acquisitions and Divestitures, for more information.

Principles of Reporting and Consolidation

The consolidated financial statements herein have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) and include the accounts of Denbury and entities in which we hold a controlling financial interest. Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis. Investments in non-controlled entities over which we exercise significant influence are accounted for under the equity method. Other investments are carried at cost. All intercompany balances and transactions have been eliminated.

From March 9, 2010 through December 31, 2010, we owned approximately 46% of Encore Energy Partners LP (“ENP”) outstanding common units and 100% of Encore Energy Partners GP LLC (“ENP GP LLC”) membership interests, which was ENP’s general partner. Considering the presumption of control of ENP GP LLC in accordance with the Consolidation topic of the Financial Accounting Standards Board Codification (“FASC”), the results of operations and cash flows of ENP were consolidated with those of Denbury for this period. On December 31, 2010, we sold all of our ownership interests in ENP and ENP GP LLC; therefore, we did not consolidate ENP in our Consolidated Balance Sheet as of December 31, 2010. As presented in the accompanying Consolidated Statement of Operations for the year ended December 31, 2010, “Net income attributable to noncontrolling interest” of $13.8 million represents ENP’s results of operations attributable to limited partners other than Denbury for the portion of the year for which we consolidated ENP.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amount of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during each reporting period. Management believes its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates underlying these financial statements include: (1) the fair value of financial derivative instruments; (2) the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom and the ceiling test; (3) the estimated quantities of proved and probable CO₂ reserves used to compute depletion of CO₂ properties; (4) accruals related to oil and natural gas sales volumes and revenues, capital expenditures and lease operating expenses; (5) the estimated costs and timing of future asset retirement obligations; (6) estimates made in the calculation of income taxes; and (7) estimates made in determining the fair values for purchase price allocations, including goodwill. While management is not aware of any significant revisions to any of its estimates, there will likely be future revisions to its estimates resulting from matters such as revisions in estimated oil and natural gas volumes, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and natural gas industry, many

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Denbury Resources Inc.

Notes to Consolidated Financial Statements

of which require retroactive application. These types of adjustments cannot be currently estimated and will be recorded in the period in which the adjustment occurs.

Reclassifications

Certain prior period amounts have been reclassified to conform with the current year presentation. Such reclassifications had no impact on our reported net income, current assets, total assets, current liabilities, total liabilities or stockholders' equity.

Cash Equivalents

We consider all highly liquid investments to be cash equivalents if they have maturities of three months or less at the date of purchase.

Restricted Cash

Restricted cash at December 31, 2012 consists of proceeds from the exchange of oil and gas properties with Exxon Mobil Corporation and its wholly-owned subsidiary XTO Energy Inc. (see Note 2, Acquisitions and Divestitures) being held by a qualified intermediary through three separate financial institutions and which are restricted for application towards future potential acquisitions to facilitate an anticipated like-kind-exchange transaction for federal income tax purposes. We manage and control counterparty credit risk related to this restricted cash using a trust agreement, whereby the assets held in trust must be segregated from the financial institution's assets, and in the event of a bankruptcy, the funds would not be subject to payments to the creditors of the financial institution.

Short-term Investments

Short-term investments represent available-for-sale securities recorded at fair value with any unrealized gains or losses included in accumulated other comprehensive income. At December 31, 2011, short-term investments consisted entirely of our investment in Vanguard Natural Resources LLC (“Vanguard”) common units obtained as partial consideration for the sale of our interests in ENP to a subsidiary of Vanguard on December 31, 2010 (see Note 2, Acquisitions and Divestitures). Our original cost basis of this investment was $93.0 million. We received distributions of $7.2 million on the Vanguard common units we owned for the year ended December 31, 2011, which are included in “Interest income and other income” on our Consolidated Statements of Operations. Due to the decline in the market value of this investment and the expectation that the investment would not recover its cost basis prior to the time of sale, we recorded a $6.3 million “other-than-temporary” impairment loss on this investment for the year ended December 31, 2011, which is included in “Impairment of assets” on our Consolidated Statements of Operations. During January 2012, we sold our investment in Vanguard for cash consideration of $83.5 million, net of related transaction fees. The Company recognized a pretax loss on the sale of $3.1 million, which is included in “Other expenses” on our Consolidated Statements of Operations for the year ended December 31, 2012.

Oil and Natural Gas Properties

Capitalized Costs. We follow the full cost method of accounting for oil and natural gas properties. Under this method, all costs related to acquisitions, exploration and development of oil and natural gas reserves are capitalized and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and nonproductive wells, capitalized interest on qualifying projects, and general and administrative expenses directly related to exploration and development activities, and do not include any costs related to production, general corporate overhead or similar activities. We assign the purchase price of oil and natural gas properties we acquire to proved and unevaluated properties based on the estimated fair values as defined in the FASC Fair Value Measurements and Disclosures topic. Proceeds received from disposals are credited against accumulated costs except when the sale represents a significant disposal of reserves, in which case a gain or loss would be recognized. A disposal of twenty-five percent or more of our proved reserves would be considered significant.

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Denbury Resources Inc.

Notes to Consolidated Financial Statements

Depletion and Depreciation. The costs capitalized, including production equipment and future development costs, are depleted or depreciated using the unit-of-production method, based on proved oil and natural gas reserves as determined by independent petroleum engineers. Oil and natural gas reserves are converted to equivalent units on a basis of 6,000 cubic feet of natural gas to one barrel of crude oil. The depletion and depreciation rate per BOE associated with our oil and gas producing activities was $18.69 in 2012, $16.42 in 2011 and $15.82 in 2010.

Under full cost accounting, we may exclude certain unevaluated costs from the amortization base pending determination of whether proved reserves can be assigned to such properties. The costs classified as unevaluated are transferred to the full cost amortization base as the properties are developed, tested and evaluated.

Ceiling Test. The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as: (1) the present value of estimated future net revenues from proved reserves before future abandonment costs (discounted at 10%), based on the average first-day-of-the-month oil and natural gas price for each month during the 12-month period prior to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects. Our future net revenues from proved reserves are not reduced for development costs related to the cost of drilling for and developing CO₂ reserves nor those related to the cost of constructing CO₂ pipelines, as those costs have previously been incurred by the Company. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO₂ costs related to CO₂ reserves and CO₂ pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes. The cost center ceiling test is prepared quarterly. We did not have a ceiling test write-down during the years ended December 31, 2012, 2011 or 2010.

Joint Interest Operations. Substantially all of our oil and natural gas exploration and production activities are conducted jointly with others. These financial statements reflect only our proportionate interest in such activities, and any amounts due from other partners are included in trade receivables.

Tertiary Injection Costs. Our tertiary operations are conducted in reservoirs that have already produced significant amounts of oil over many years; however, in accordance with the SEC rules and regulations for recording proved reserves, we cannot recognize proved reserves associated with enhanced recovery techniques, such as CO₂ injection, until there is a production response to the injected CO₂, or unless the field is analogous to an existing flood.

We capitalize, as a development cost, injection costs in fields that are in their development stage, which means we have not yet seen incremental oil production due to the CO₂ injections (i.e., a production response). These capitalized development costs are included in our unevaluated property costs if there are not already proved tertiary reserves in that field. After we see a production response to the CO₂ injections (i.e., the production stage), injection costs are expensed as incurred, and once proved reserves are recognized, previously deferred unevaluated development costs become subject to depletion.

CO₂ Properties

We own and produce CO₂ reserves, a non-hydrocarbon resource, that are used in our tertiary oil recovery operations on our own behalf and on behalf of other interest owners in enhanced recovery fields, with a portion sold to third-party industrial users. We record revenue from our sales of CO₂ to third parties when it is produced and sold. Expenses related to the production of CO₂ are allocated between volumes sold to third parties and volumes consumed internally that are directly related to our tertiary production. The expenses related to third-party sales are recorded in “CO₂ discovery and operating expenses,” and the expenses related to internal use are recorded in “Lease operating expenses” in the Consolidated Statements of Operations, or are capitalized as oil and gas properties in our Consolidated Balance Sheets, depending on the status of floods that receive the CO₂ (see Tertiary Injection Costs above for further discussion).

During 2010 and 2011, we acquired interests in the Riley Ridge Federal Unit (“Riley Ridge”), in which helium and CO₂ (non-hydrocarbon resources) as well as natural gas (a hydrocarbon resource) are present. It is not possible to separately identify the capitalized costs related to the development of each product in the commingled gas stream; thus, these costs are allocated to each

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Denbury Resources Inc.

Notes to Consolidated Financial Statements

product based on the relative future revenue value of each product line and classified accordingly on the Consolidated Balance Sheets.

During 2010, we revised our capitalization policies for CO₂ properties. Previously, we accounted for our CO₂ source properties in a manner similar to our method of accounting for oil and natural gas properties, as the process and activities to identify, develop and produce CO₂ reserves are virtually identical to those used to identify, develop and produce oil and natural gas reserves. However, because CO₂ is not a hydrocarbon, it is excluded from the scope of FASC Topic 932, Extractive Industries – Oil and Gas; therefore, we are precluded from accounting for our CO₂ operations in accordance with FASC Topic 932. Accordingly, commencing in July 2010, costs incurred to search for CO₂ are expensed as incurred until proved or probable reserves are established. Once proved or probable reserves are established, costs incurred to obtain those reserves are capitalized and classified as “CO₂ properties” on our Consolidated Balance Sheets. Capitalized CO₂ is aggregated by geologic formation and depleted on a unit-of-production basis over proved and probable reserves. The impact of the revised accounting policy on our financial statements was not material to any individual year. We recognized the cumulative impact of the revised accounting policy as a noncash net reduction to depletion, depreciation and amortization during the year ended December 31, 2010, resulting in a pretax credit of $9.6 million ($6.0 million after tax), which reflected a reduction to “CO₂ properties” of $26.1 million offset by a decrease in “Accumulated depletion, depreciation and amortization” of $35.7 million. The cumulative adjustment did not have an impact on our net cash flows.

The portion of our capitalized CO₂ costs related to CO₂ reserves and CO₂ pipelines that we estimate will be consumed in the process of producing our proved oil reserves is included in the ceiling test as a reduction to future net revenues. The remaining net capitalized CO₂ properties, equipment and pipelines balance is evaluated for impairment by comparing the net carrying costs to the expected future net revenues from (1) the production of our probable and possible tertiary oil reserves and (2) the sale of CO₂ to third-party industrial users.

Pipelines and Plants

CO₂ used in our tertiary floods is transported to our fields through CO₂ pipelines. Costs of CO₂ pipelines under construction are not depreciated until the pipelines are placed into service. Pipelines are depreciated on a straight-line basis over their estimated useful lives, which range from 15 to 50 years.

Pipelines and plants include the Riley Ridge gas plant in southwestern Wyoming, which is currently under construction. The plant is being withheld from depreciation until it is placed in service, which we currently expect to occur during mid-2013.

Property and Equipment – Other

Other property and equipment, which includes furniture and fixtures, vehicles, computer equipment and software, and capitalized leases, is depreciated principally on a straight-line basis over estimated useful lives. Vehicles and furniture and fixtures are generally depreciated over a useful life of five to ten years, and computer equipment and software are generally depreciated over a useful life of three to five years. Leasehold improvements are amortized over the shorter of the estimated useful life or the remaining lease term.

Leased property meeting certain capital lease criteria is capitalized, and the present value of the related lease payments is recorded as a liability. Amortization of capitalized leased assets is computed using the straight-line method over the shorter of the estimated useful life or the initial lease term.

Maintenance and repair costs that do not extend the useful lives of property and equipment are charged to expense as incurred.

Asset Retirement Obligations

In general, our future asset retirement obligations relate to future costs associated with plugging and abandoning our oil, natural gas and CO₂ wells, removing equipment and facilities from leased acreage, and returning land to its original condition. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using our credit-adjusted-risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount

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Denbury Resources Inc.

Notes to Consolidated Financial Statements

of the related long-lived asset. The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset. Revisions to estimated retirement obligations will result in an adjustment to the related capitalized asset and corresponding liability. If the liability is settled for an amount other than the recorded amount, the difference is recorded to the full cost pool, unless significant.

Asset retirement obligations are estimated at the present value of expected future net cash flows and are discounted using our credit-adjusted-risk-free rate. We utilize unobservable inputs in the estimation of asset retirement obligations that include, but are not limited to, costs of labor, costs of materials, profits on costs of labor and materials, the effect of inflation on estimated costs, and the discount rate. Accordingly, asset retirement obligations are considered a Level 3 measurement under the FASC Fair Value Measurements and Disclosures topic.

Derivative Instruments and Hedging Activities

We utilize oil and natural gas derivative contracts to mitigate our exposure to commodity price risk associated with our future oil and natural gas production. These derivative contracts have historically consisted of options, in the form of price floors or collars, and fixed price swaps. From time to time, we have also used interest rate lock contracts to mitigate our exposure to interest rate fluctuations related to sale-leaseback financing of certain equipment used at our oilfield facilities. Our derivative financial instruments are recorded on the balance sheet as either an asset or a liability measured at fair value. We do not apply hedge accounting to our oil and natural gas derivative contracts; accordingly, the changes in the fair value of these instruments are recognized in our Consolidated Statements of Operations in the period of change.

Financial Instruments with Off-Balance-Sheet Risk and Concentrations of Credit Risk

Our financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents, trade and accrued production receivables, and the derivative instruments discussed above. Our cash equivalents represent high-quality securities placed with various investment-grade institutions. This investment practice limits our exposure to concentrations of credit risk. Our trade and accrued production receivables are dispersed among various customers and purchasers; therefore, concentrations of credit risk are limited. We evaluate the credit ratings of our purchasers, and if customers are considered a credit risk, letters of credit are the primary security obtained to support lines of credit. We attempt to minimize our credit risk exposure to the counterparties of our oil and natural gas derivative contracts through formal credit policies, monitoring procedures and diversification. All of our derivative contracts are with banks, which are part of the syndicate of banks in our bank credit facility, or with their affiliates. There are no margin requirements with the counterparties of our derivative contracts.

Goodwill

Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Goodwill is not amortized; rather, it is tested for impairment annually during the fourth quarter and when events or changes in circumstances indicate that it is more likely than not the fair value of a reporting unit with goodwill has been reduced below its carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. However, we have only one reporting unit. To assess impairment, we have the option to qualitatively assess if it is more likely than not that the fair value of the reporting unit is less than the carrying value. Absent a qualitative assessment, or, through the qualitative assessment, if we determine it is more likely than not that the fair value of the reporting unit is less than the carrying value, a quantitative assessment is prepared to calculate the fair market value of the reporting unit. If it is determined that the fair value of the reporting unit is less than the carrying value, the recorded goodwill is impaired to its implied fair value with a charge to operating expense. We completed our annual goodwill impairment assessment during the fourth quarter of 2012 and did not record any goodwill impairment during 2012, nor have we recorded a goodwill impairment historically.

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Denbury Resources Inc.

Notes to Consolidated Financial Statements

The following table summarizes the changes in goodwill for the years ended December 31, 2012 and 2011:



	Year Ended December 31,
In thousands	2012		2011
Beginning of year balance	$	1,236,318	$	1,232,418
Goodwill related to the Riley Ridge acquisition	—		3,900
Goodwill related to the Thompson Field acquisition	47,272		—
End of year balance	$	1,283,590	$	1,236,318

Revenue Recognition

Revenue is recognized at the time oil and natural gas is produced and sold. Any amounts due from purchasers of oil and natural gas are included in accrued production receivable.

We follow the sales method of accounting for our oil and natural gas revenue, whereby we recognize revenue on all oil or natural gas sold to our purchasers regardless of whether the sales are proportionate to our ownership in the property. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves. As of December 31, 2012 and 2011, our aggregate oil and natural gas imbalances were not material to our consolidated financial statements.

We recognize revenue and expenses of purchased producing properties at the time we assume effective control, commencing from either the closing or purchase agreement date, depending on the underlying terms and agreements. We follow the same methodology in reverse when we sell properties by recognizing revenue and expenses of the sold properties until the closing date.

Income Taxes

Income taxes are accounted for using the asset and liability method, under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.

We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement.

Net Income Per Common Share

Basic net income per common share is computed by dividing the net income attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income per common share is calculated in the same manner, but includes the impact of potentially dilutive securities. Potentially dilutive securities consist of stock options, stock appreciation rights (“SARs”), nonvested restricted stock and nonvested performance equity awards. For each of the three years in the period ended December 31, 2012, there were no adjustments to net income for purposes of calculating basic and diluted net income per common share.

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Notes to Consolidated Financial Statements

The following is a reconciliation of the weighted average shares used in the basic and diluted net income per common share calculations for the periods indicated:



	Year Ended December 31,
In thousands	2012	2011	2010
Basic weighted average common shares	385,205	396,023	370,876
Potentially dilutive securities:
Stock options and SARs	2,584	3,539	3,844
Performance equity awards	86	38	319
Restricted stock	1,063	1,358	1,216
Diluted weighted average common shares	388,938	400,958	376,255

Basic weighted average common shares excludes 3.7 million, 3.4 million and 3.2 million shares of nonvested restricted stock during the year ended December 31, 2012, 2011 and 2010, respectively. As these restricted shares vest or become retirement eligible, they will be included in the shares outstanding used to calculate basic net income per common share (although all restricted stock is issued and outstanding upon grant). For purposes of calculating diluted weighted average common shares, the nonvested restricted stock is included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, adjusted for any estimated future tax consequences recognized directly in equity.

The following securities could potentially dilute earnings per share in the future but were not included in the computation of diluted net income per share, as their effect would have been antidilutive:



	Year Ended December 31,
In thousands	2012	2011	2010
Stock options and SARs	4,068	5,017	3,671
Restricted stock	47	104	17

Recent Accounting Pronouncements

Presentation of Comprehensive Income. In June 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update ("ASU") 2011-05, Presentation of Comprehensive Income (“ASU 2011-05”). ASU 2011-05 requires the presentation of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. ASU 2011-05 was effective for Denbury beginning January 1, 2012. Since ASU 2011-05 only amended presentation requirements, it did not have a material effect on our consolidated financial statements.

Accumulated Other Comprehensive Income Reclassifications. In February 2013, the FASB issued ASU 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income ("ASU 2013-02"). ASU 2013-02 requires disclosure of amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required to be reclassified to net income in its entirety in the same reporting period. For amounts not reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures that provide additional detail about those amounts. ASU 2013-02 is effective prospectively for our fiscal year beginning January 1, 2013. The adoption of ASU 2013-02 will not have a material effect on our consolidated financial statements.

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Notes to Consolidated Financial Statements

Fair Value. In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-04”). ASU 2011-04 amends the FASC Fair Value Measurements topic by providing a consistent definition and measurement of fair value, as well as similar disclosure requirements between U.S. GAAP and International Financial Reporting Standards. ASU 2011-04 changes certain fair value measurement principles, clarifies the application of existing fair value measurements and expands the fair value disclosure requirements, particularly for Level 3 fair value measurements. ASU 2011-04 was effective for Denbury beginning January 1, 2012. The adoption of ASU 2011-04 did not have a material effect on our consolidated financial statements, but did require additional disclosures. See Note 10, Fair Value Measurements.

Balance Sheet Offsetting. In December 2011, the FASB issued ASU 2011-11, Disclosure about Offsetting Assets and Liabilities (“ASU 2011-11”). ASU 2011-11 requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. In January 2013, the FASB issued ASU 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities ("ASU 2013-01"). The update clarifies that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with the Derivatives and Hedging topic of the FASC, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset or subject to an enforceable master netting arrangement or similar agreement. ASU 2011-11 and ASU 2013-01 are effective for our fiscal year beginning January 1, 2013 and will be applied retrospectively for all comparative periods presented. The adoption of ASU 2011-11 and ASU 2013-01 will not have a material effect on our consolidated financial statements, but may require additional disclosures.

Note 2. Acquisitions and Divestitures

Acquisitions and Exchange Transaction

Fair Value. The FASC Fair Value Measurements and Disclosures topic defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (often referred to as the “exit price”). The fair value measurement is based on the assumptions of market participants and not those of the reporting entity. Therefore, entity-specific intentions do not impact the measurement of fair value unless those assumptions are consistent with market participant views.

The fair value of oil and natural gas properties is based on significant inputs not observable in the market, which the FASC Fair Value Measurements and Disclosures topic defines as Level 3 inputs. Key assumptions may include: (1) NYMEX oil and natural gas futures (this input is observable); (2) dollar-per-acre values of recent sale transactions (this input is observable); (3) projections of the estimated quantities of oil and natural gas reserves, including those classified as proved, probable and possible; (4) estimated oil and natural gas pricing differentials; (5) projections of future rates of production; (6) timing and amount of future development and operating costs; (7) projected costs of CO₂ (to a market participant); (8) projected reserve recovery factors; and (9) risk-adjusted discount rates.


•	operating interests in the Webster Field, a planned future tertiary field, located in southeastern Texas, made up of a nearly 100% working interest and nearly 80% revenue interest;


•	operating interests in the Hartzog Draw Field, a planned future tertiary field, located in Wyoming, consisting of an 83% working interest and 71% net revenue interest in the oil-producing Shannon Sandstone zone and a 67% working interest and 53% net revenue interest in the natural gas producing Big George Coal zone; and


•	approximately a one-third overriding royalty ownership interest in ExxonMobil's CO₂ reserves in LaBarge Field in Wyoming.

The exchange of properties closed in two phases on November 30, 2012 and December 21, 2012, and is collectively referred to as the "Bakken Exchange Transaction".

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Notes to Consolidated Financial Statements

Our acquisition of property interests constitutes a business combination under the FASC Business Combinations topic. Accordingly, the purchase price of the acquisition is measured as the fair value of consideration transferred, which consists of our Bakken area assets. The fair value of Bakken area net assets transferred to ExxonMobil in the Bakken Exchange Transaction was measured using a discounted future net cash flow model for developed properties and a market dollar-per-acre value for undeveloped properties. The fair value of assets transferred in the Bakken Exchange Transaction was measured at the dates control was transferred to ExxonMobil, which were November 30, 2012 and December 21, 2012 for 82.5% and 17.5%, respectively, of our interest in our Bakken area assets. The fair value of oil and gas properties received from ExxonMobil in such transaction was measured using a discounted future net cash flow model, and the fair value of CO₂interests received was measured using a market-based approach, at the date control was transferred to Denbury, which was November 30, 2012, for the acquisition of interests in Webster and Hartzog Draw fields and December 21, 2012, for the acquisition of interests in LaBarge Field. We did not record a gain or loss on the exchange in accordance with the full cost method of accounting.

The following table presents a summary of the preliminary fair value of assets acquired and liabilities assumed in the Bakken Exchange Transaction:



In thousands
Consideration:
Fair value of net assets transferred	$	1,903,280

Less: Fair value of assets acquired and liabilities assumed: ⁽¹⁾
Cash ⁽²⁾	1,331,684
Oil and natural gas properties
Proved	201,301
Unevaluated	98,635
CO₂ properties	314,505
Other assets	477
Other liabilities	(29,531		)
Asset retirement obligations	(13,791		)
Fair value of net assets acquired	$	1,903,280


(1)	Fair value of the assets acquired and liabilities assumed is preliminary, pending final closing adjustments and further evaluation of reserves and asset retirement obligations.

(2)

Cash proceeds include preliminary closing adjustments of $41.7 million primarily representing adjustments for net revenues and capital expenditures of the transferred oil and natural gas property assets from the Bakken Exchange Transaction effective date to the closing dates. Also see Note 12, Supplemental Information and Note 13, Subsequent Events, for additional information regarding the placement of $1.05 billion of the proceeds in a qualified trust to facilitate an anticipated like-kind-exchange transaction for federal income tax purposes.

June 2012 Acquisition of Reserves in the Gulf Coast region at Thompson Field. In June 2012, we acquired a nearly 100% working interest and 84.7% net revenue interest in Thompson Field for $366.2 million after preliminary closing adjustments. The field is located approximately 18 miles west of Hastings Field, which is an enhanced oil recovery field that we are currently flooding with CO₂, and is the current terminus of the Green Pipeline which transports CO₂ from the Jackson Dome, located near Jackson, Mississippi. Thompson Field is similar to Hastings Field, producing oil from the Frio zone at similar depths, and is also a planned future tertiary field. Under the terms of the Thompson Field acquisition agreement, the seller will retain approximately a 5% gross revenue interest (less severance taxes) once average monthly oil production exceeds 3,000 Bbls/d after the initiation of CO₂ injection.

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Notes to Consolidated Financial Statements

This acquisition meets the definition of a business under the FASC Business Combinations topic. As such, we estimated the fair value of assets acquired and liabilities assumed as of June 1, 2012, the closing date of the acquisition using a discounted future net cash flow model. In applying these accounting principles, we estimated the fair value of the assets acquired less liabilities assumed on the acquisition date to be approximately $318.9 million. This measurement resulted in the recognition of goodwill of approximately $47.3 million, which represents the excess of the cash paid to acquire the field over the acquisition date estimated fair value. This resultant goodwill is due primarily to two factors. The first factor is the decrease in average NYMEX oil futures prices between the date of signing the purchase agreement on April 24, 2012 and closing the purchase on June 1, 2012. The second factor is the fair value assigned to the estimated oil reserves recoverable through a CO₂ EOR project. By building an 18-mile extension of the Green Pipeline, we will have access to CO₂ reserves at Jackson Dome, one of the few known significant natural sources of CO₂ in the United States, and the largest known source east of the Mississippi River, allowing us to carry out CO₂ EOR activities in this field at a lower cost than other market participants. However, the FASC Fair Value Measurements and Disclosures topic does not allow entity-specific assumptions in the measurement of fair value. Therefore, we estimated the fair value of the oil reserves recoverable through CO₂ EOR using a higher estimated cost of CO₂ to other market participants, which lowers the discounted net revenue stream used in making the fair value estimate related to this field. All of the goodwill associated with the acquisition is deductible for tax purposes as property cost.

The fair value of the assets acquired and liabilities assumed was finalized during the fourth quarter of 2012, after consideration of final closing adjustments and evaluation of reserves and asset retirement obligations. The following table presents a summary of the fair value of assets acquired and liabilities assumed in the Thompson Field acquisition:



In thousands
Consideration:
Cash payment ⁽¹⁾	$	366,179

Less: Fair value of assets acquired and liabilities assumed:
Oil and natural gas properties
Proved	305,233
Unevaluated	12,023
Pipelines and plants	2,000
Other assets	2,957
Asset retirement obligations	(3,306		)
	318,907
Goodwill	$	47,272


(1)	See Note 6, Income Taxes, for additional information regarding the like-kind-exchange transaction utilized to fund this purchase and Note 12, Supplemental Information, for supplemental cash flow information regarding the cash payment.

October 2010 and August 2011 Riley Ridge Acquisitions. In October 2010, we acquired a 42.5% non-operated working interest in Riley Ridge, located in southwestern Wyoming, for $132.3 million after closing adjustments. Riley Ridge contains natural gas resources, as well as helium and CO₂ resources. The purchase included a 42.5% interest in a gas plant, currently under construction, which will separate the helium and natural gas from the commingled gas stream, and interests in certain surrounding properties. On August 1, 2011, we acquired the remaining 57.5% working interest in Riley Ridge that we did not already own, the remaining 57.5% interest in the gas plant, and interests in certain surrounding properties for $214.8 million after closing adjustments. As a result of the transaction, we became the operator of both projects. The purchase price includes a $15 million deferred payment to be made, subject to the terms of the purchase agreement, at the time the property's gas plant is operational and meets specific performance conditions. This deferred payment is measured at fair value on a quarterly basis using management's expectation of future cash flows. Because the Riley Ridge plant remains under construction, current production at the field is negligible. As a result, pro forma information has not been disclosed due to the immateriality of revenues and expenses during 2011 and 2010.

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Notes to Consolidated Financial Statements

Each of the acquisitions of Riley Ridge meets the definition of a business under the FASC Business Combinations topic. As such, we estimated the fair value of assets acquired and liabilities assumed using a discounted net cash flow model. Goodwill associated with the acquisitions is deductible for income tax purposes. The fair values assigned to assets acquired and liabilities assumed in the August 2011 acquisition have been finalized, and no adjustments have been made to fair value amounts previously disclosed in our Form 10-K for the period ended December 31, 2011. The following table presents a summary of the fair value of assets acquired and liabilities assumed in the August 2011 Riley Ridge acquisition:



In thousands
Consideration:
Cash payment	$	199,779
Deferred payment	15,000
Total consideration	214,779

Less: Fair value of assets acquired and liabilities assumed:
Oil and natural gas properties
Proved	48,731
Unproved	12,542
CO₂ properties	9,741
Pipelines and plants	91,594
Other assets ⁽¹⁾	48,660
Asset retirement obligations	(389		)
	210,879
Goodwill	$	3,900

(1)

Other assets includes helium extraction rights of $36.7 million. Helium reserves at Riley Ridge are owned by the U.S. government. The fair value assigned to helium extraction rights was calculated using the income approach and represents the discounted future net revenues associated with our right to extract and sell the helium on behalf of the helium resource owners. Upon commencement of helium production, helium extraction rights will be amortized on a unit-of-production basis.

2010 Merger with Encore Acquisition Company. On March 9, 2010, we acquired Encore pursuant to the Encore Merger Agreement entered into with Encore on October 31, 2009. The Encore Merger Agreement provided for a stock and cash transaction valued at approximately $4.8 billion at the acquisition date, including the assumption of debt and the value of the noncontrolling interest in ENP. Under the Encore Merger Agreement, Encore was merged with and into Denbury, with Denbury surviving the Encore Merger.

In the Encore Merger, we issued approximately 135.2 million shares of common stock and paid approximately $833.9 million in cash to Encore stockholders. The Denbury shares issued to Encore stockholders represented approximately 34% of Denbury’s common stock issued and outstanding immediately after the Encore Merger. The total fair value of our common stock issued to Encore stockholders in the Encore Merger was approximately $2.1 billion based upon our closing price of $15.43 per share on March 9, 2010. The Encore Merger was financed through a combination of issuing $1.0 billion of 8¼% Senior Subordinated Notes due 2020, which we issued in February 2010, borrowings under a new $1.6 billion revolving credit agreement entered into in March 2010, and the assumption of Encore's remaining outstanding senior subordinated notes.

The Encore Merger met the definition of a business combination under the FASC Business Combinations topic. As such, we estimated the fair value of Encore as of March 9, 2010, the acquisition date, which was the date on which we obtained control of Encore.

For the period from March 9, 2010 to December 31, 2010, we recognized $623.4 million of oil, natural gas and related product sales related to properties acquired in the Encore Merger. For the period from March 9, 2010 to December 31, 2010, we recognized

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Notes to Consolidated Financial Statements

$426.0 million net field operating income (oil, natural gas and related product sales less lease operating expenses and production taxes and marketing expenses) related to properties acquired in the Encore Merger. Transaction and other costs related to the Encore Merger included in the Consolidated Statement of Operations for the year ended December 31, 2010 include $48.5 million of third-party, legal and accounting fees, which have been expensed as incurred, and $43.8 million of employee-related severance and termination costs, which were accrued over the employees’ service period. Accrued employee-related severance costs totaled $19.8 million at December 31, 2010, of which $16.5 million was classified as accounts payable and accrued liabilities and $3.3 million was classified as long-term other liabilities on our balance sheet. Transaction and other costs related to the Encore Merger included in the Consolidated Statement of Operations for the year ended December 31, 2011, include $0.8 million of third-party, legal and accounting fees, which have been expensed as incurred, and $3.6 million of employee-related severance and termination costs.

Unaudited Pro Forma Acquisition Information. The following combined pro forma total revenues and other income and net income are presented as if the Bakken Exchange Transaction and Thompson Field acquisition had occurred on January 1, 2011:



	Year Ended December 31,
In thousands, except per share data	2012		2011
Pro forma total revenues and other income	$	2,203,703	$	2,184,507
Pro forma net income	454,549		523,227
Pro forma net income per common share
Basic	$	1.18	$	1.32
Diluted	1.17		1.30

The following combined pro forma total revenues and other income and net income attributable to Denbury stockholders are presented as if the acquisition of Encore occurred on January 1, 2010:



In thousands, except per share data	Year Ended December 31, 2010
Pro forma total revenues and other income	$	2,098,241
Pro forma net income attributable to Denbury stockholders	286,891
Pro forma net income per common share
Basic	$	0.73
Diluted	0.72

Divestitures

2012 Divestitures. In April 2012, we completed the sale of certain non-operated assets in the Paradox Basin of Utah for $75.0 million. The sale had an effective date of January 1, 2012, and proceeds received after consideration of final closing adjustments totaled $68.5 million. Closing adjustments included operating net revenues after January 1, 2012, net of capital and lease operating expenditures, along with other purchase price adjustments. We did not record a gain or loss on the sale in accordance with the full cost method of accounting.

In February 2012, we completed the sale of certain non-core assets primarily located in central and southern Mississippi and in southern Louisiana for $155.0 million to a privately held entity in which a member of our Board of Directors served as chairman of the board, in a sale for which there was a competing bid contained in a multi-property purchase proposal. We realized net proceeds of $141.8 million, after final closing adjustments. The sale had an effective date of December 1, 2011, and consequently, operating revenues of $13.5 million after the effective date, net of capital and lease operating expenditures, along with any other purchase price adjustments, were adjustments to the selling price. We did not record a gain or loss on the sale in accordance with the full cost method of accounting.

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Notes to Consolidated Financial Statements

Certain of our 2012 divestitures were structured as like-kind-exchange transactions for federal income tax purposes. See Note 6, Income Taxes for further details.

2010 Divestitures. In December 2010, we sold our ownership interests in ENP, which consisted of our 100% ownership in ENP GP LLC, ENP’s general partner, and 20.9 million ENP common units, to a subsidiary of Vanguard for consideration consisting of $300.0 million cash and 3,137,255 Vanguard common units valued at $93.0 million at the time of closing. In addition, Vanguard assumed all of ENP’s long-term bank debt of $234.0 million. We did not record a gain or loss on the sale of oil and gas properties in accordance with the full cost method of accounting, nor did we record a gain or loss on the remainder of the net assets sold as the book value approximated fair value.

Pursuant to our plan of divesting 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 for consideration of $892.1 million after final closing adjustments. We subsequently divested our production and acreage in the Cleveland Sand Play of western Oklahoma for consideration of $32.1 million after closing adjustments and the Haynesville and East Texas natural gas properties for consideration of $213.8 million after closing adjustments. Together with the sale of our ownership interest in ENP and ENP GP LLC discussed above, we received $1.5 billion in total consideration from these divestitures in 2010. For all Encore legacy property dispositions during 2010, we reduced our full cost pool by the amount of the net proceeds and did not record a gain or loss on the sale in accordance with the full cost method of accounting.

In February 2010, we sold our interest in Genesis Energy, LLC, the general partner of Genesis Energy, L.P. ("Genesis"), for net proceeds of approximately $84 million, after giving effect to the change of control provision of the incentive compensation agreement with Genesis’ management, which was triggered and under which we paid a total of $14.9 million. In March 2010, we sold all of our Genesis common units in a secondary public offering for net proceeds of approximately $79 million. We accounted for our investment in Genesis under the equity method, and we recognized a pre-tax gain of approximately $101.5 million ($63.0 million after tax) on these dispositions.

Note 3. Asset Retirement Obligations

The following table summarizes the changes in our asset retirement obligations for the years ended December 31, 2012 and 2011:



	Year Ended December 31,
In thousands	2012			2011
Beginning asset retirement obligation	$	93,468		$	85,744
Liabilities incurred and assumed during period	50,956			12,477
Revisions in estimated retirement obligations	5,334			12,217
Liabilities settled and sold during period	(50,556		)	(23,257		)
Accretion expense	7,228			6,287
Ending asset retirement obligation	106,430			93,468
Less: current asset retirement obligation ⁽¹⁾	(3,700		)	(4,742		)
Long-term asset retirement obligation	$	102,730		$	88,726


(1)	Included in "Accounts payable and accrued liabilities" in our Consolidated Balance Sheets.

Liabilities incurred and assumed generally relate to the drilling of incremental wells and liabilities assumed upon the acquisition of Thompson, Webster and Hartzog Draw fields during 2012. Liabilities settled include the plugging of old wells in the Tinsley Field during 2012 and 2011. Sales of properties in 2012 primarily represent the sale of non-core assets located in the Paradox Basin of Utah, Gulf Coast region and Bakken area assets in North Dakota and Montana.

We have escrow accounts that are legally restricted for certain of our asset retirement obligations. The balances of these escrow accounts were $35.2 million and $34.1 million at December 31, 2012 and 2011, respectively. These balances are recorded

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Notes to Consolidated Financial Statements

at amortized cost and are included in “Other assets” in our Consolidated Balance Sheets. The estimated fair market value of these investments approximate cost at December 31, 2012 and 2011.

Note 4. Property and Equipment

The following table presents a summary of our net property and equipment balances as of December 31, 2012 and 2011:



	December 31,
In thousands	2012			2011
Oil and natural gas properties
Proved properties	$	6,963,211		$	7,026,579
Unevaluated properties	809,154			1,157,106
Total	7,772,365			8,183,685
Accumulated depletion and depreciation	(2,827,256		)	(2,407,520		)
Net oil and natural gas properties	4,945,109			5,776,165
CO₂ properties
CO₂ properties	1,032,653			596,003
Accumulated depletion and depreciation	(119,784		)	(91,666		)
Net CO₂ properties	912,869			504,337
Pipelines and plants
CO₂ pipelines ⁽¹⁾	1,632,255			1,432,646
Plants under construction ⁽²⁾	402,871			269,110
Total	2,035,126			1,701,756
Accumulated depletion and depreciation	(99,185		)	(65,392		)
Net plants and pipelines	1,935,941			1,636,364
Other property and equipment
Other property and equipment	417,207			157,674
Accumulated depletion and depreciation	(134,016		)	(62,915		)
Net other property and equipment	283,191			94,759
Net property and equipment	$	8,077,110		$	8,011,625


(1)	Amounts include $346.5 million of CO₂ pipelines at December 31, 2012 that were not subject to depreciation during 2012.


(2)	Plants under construction are not subject to depreciation.

A summary of the unevaluated properties excluded from oil and natural gas properties being amortized at December 31, 2012, and the year in which they were incurred follows:



	December 31, 2012
	Costs Incurred During:
In thousands	2012		2011		2010		2009 and prior		Total
Property acquisition costs	$	110,658	$	12,543	$	351,712	$	115,075	$	589,988
Exploration and development	106,075		40,152		3,155		8,390		157,772
Capitalized interest	29,249		30,430		333		1,382		61,394
Total	$	245,982	$	83,125	$	355,200	$	124,847	$	809,154

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Notes to Consolidated Financial Statements

Our 2012 property acquisition costs were primarily related to the fair value allocated to our Hartzog Draw and Thompson fields. Our 2010 property acquisition costs were primarily related to the fair value allocated to CO₂ tertiary potential at our Bell Creek and Cedar Creek Anticline properties, acquired as part of the Encore Merger. Property acquisition costs for 2009 and prior were primarily related to CO₂ tertiary potential at Conroe Field. Exploration and development costs shown as unevaluated properties are primarily associated with our tertiary oil fields that are under development but did not have proved reserves at December 31, 2012. The most significant development costs incurred during 2012 and 2011 relate to development in preparation for upcoming CO₂ floods at Bell Creek and Grieve fields. We have not yet recognized proved reserves in these fields.

During 2012, we established proved reserves at Hastings and Oyster Bayou fields and, as a result, transferred $431.1 million of costs incurred on these projects into the amortization base. Costs are transferred into the amortization base on an ongoing basis as projects are evaluated and proved reserves established or impairment determined. We review the excluded properties for impairment at least annually. We currently estimate that evaluation of most of these properties and the inclusion of their costs in the amortization base is expected to be completed within five years. Until we are able to determine whether there are any proved reserves attributable to the above costs, we are not able to assess the future impact on the amortization rate of the full cost pool.

Note 5. Long-Term Debt

The following long-term debt and capital lease obligations were outstanding as of December 31, 2012 and 2011:



	December 31,
In thousands	2012			2011
Bank Credit Agreement	$	700,000		$	385,000
9½% Senior Subordinated Notes due 2016, including premium of $9,118 and $11,854, respectively	234,038			236,774
9¾% Senior Subordinated Notes due 2016, including discount of $13,569 and $17,854, respectively	412,781			408,496
8¼% Senior Subordinated Notes due 2020	996,273			996,273
6 3/8% Senior Subordinated Notes due 2021	400,000			400,000
Other Subordinated Notes, including premium of $25 and $33, respectively	3,832			3,840
Pipeline financings	236,244			243,274
Capital lease obligations	158,260			4,388
Total	3,141,428			2,678,045
Less: current obligations	(36,966		)	(8,316		)
Long-term debt and capital lease obligations	$	3,104,462		$	2,669,729

The parent company, Denbury Resources Inc. (“DRI”), is the sole issuer of all of our outstanding senior subordinated notes. DRI has no independent assets or operations. Each of the subsidiary guarantors of such notes is 100% owned, directly or indirectly, by DRI; any subsidiaries of DRI other than the subsidiary guarantors are minor subsidiaries, and the guarantees of the notes are full and unconditional and joint and several.

February 2013 Issuance of 4 5/8% Senior Subordinated Notes due 2023

On February 5, 2013, we issued $1.2 billion of 4 5/8% Senior Subordinated Notes due 2023 (the “2023 Notes”). The 2023 Notes, which carry a coupon rate of 4.625%, were sold at par. We intend to use the net proceeds of $1.18 billion from the issuance of the 2023 Notes to repurchase or redeem our 9½% Senior Subordinated Notes due 2016 (the “9½% Notes”) and our 9¾% Senior Subordinated Notes due 2016 (the “9¾% Notes”) and to pay down a portion of outstanding borrowings on our Bank Credit Agreement. See Note 13, Subsequent Events, for more information.

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Notes to Consolidated Financial Statements

$1.6 Billion Revolving Credit Agreement

In March 2010, we entered into a $1.6 billion revolving credit agreement with JPMorgan Chase Bank, N.A. (“JPMorgan”), as administrative agent, and other lenders party thereto (as amended, the “Bank Credit Agreement”). Availability under the Bank Credit Agreement is subject to a borrowing base, which is redetermined semi-annually on or prior to May 1 and November 1 and upon requested special redeterminations. The borrowing base is adjusted at the banks’ discretion and is based in part upon external factors over which we have no control. If the borrowing base were to be less than outstanding borrowings under the Bank Credit Agreement, we would be required to repay the deficit over a period not to exceed four months. As part of the semi-annual review completed in September 2012 pursuant to the terms of the Bank Credit Agreement, our borrowing base was reaffirmed at $1.6 billion. Loans under the Bank Credit Agreement mature in May 2016.

The Bank Credit Agreement is secured by substantially all of the proved oil and natural gas properties of our restricted subsidiaries and by the equity interests of our restricted subsidiaries. In addition, our obligations under the Bank Credit Agreement are guaranteed jointly and severally by all of our subsidiaries, other than minor subsidiaries.

The Bank Credit Agreement contains several restrictive covenants including, among others:


•	a limitation on the ability to repurchase Denbury common stock and to pay dividends on Denbury common stock, in an aggregate amount not to exceed $1.2 billion during the term of the Bank Credit Agreement, subject to certain restrictions;


•	a requirement to maintain a current ratio, as determined under the Bank Credit Agreement, of not less than 1.0 to 1.0;


•	a maximum permitted ratio of debt to adjusted EBITDA (as defined in the Bank Credit Agreement) of us and our restricted subsidiaries of not more than 4.25 to 1.0; and


•	a prohibition against incurring debt, subject to permitted exceptions.

The Bank Credit Agreement also includes a limitation on the aggregate amount of forecasted oil and natural gas production that can be economically hedged with oil or natural gas derivative contracts. During 2012, we received a limited waiver of any oil hedging noncompliance that may occur as a result of the Bakken Exchange Transaction during the period commencing on the closing date continuing through and including December 31, 2013 (see Note 2, Acquisitions and Divestitures).

Under the Bank Credit Agreement, we are permitted to incur capital lease obligations in an aggregate amount outstanding at any time not to exceed $300 million, and are also permitted to incur up to $40 million of other unsecured debt (which include capital leases). The Bank Credit Agreement was amended during 2012 concurrent with our change in classification of equipment leases from operating to capital (see Capital Leases below), and we received a waiver of any applicable violations of the provisions of the Bank Credit Agreement resulting from such correction and the recording of our equipment leases as debt.

Loans under the Bank Credit Agreement are subject to varying rates of interest based on (1) the total outstanding borrowings in relation to the borrowing base and (2) whether the loan is a Eurodollar loan or a base rate loan. Eurodollar loans bear interest at the Adjusted Eurodollar Rate (as defined in the Bank Credit Agreement) plus the applicable margin in a range from 1.5% to 2.5% based on the ratio of outstanding borrowings to the borrowing base, and base rate loans bear interest at the Base Rate (as defined in the Bank Credit Agreement) plus the applicable margin in a range from 0.5% to 1.5% based on the ratio of outstanding borrowings to the borrowing base. The “Eurodollar rate” for any interest period (either one, two, three, six, nine or twelve months, as selected by us) is the rate per year equal to LIBOR, as published by Reuters or another source designated by JPMorgan, for deposits in dollars for a similar interest period. The “base rate” is calculated as the highest of (1) the annual rate of interest announced by JPMorgan as its “prime rate,” (2) the federal funds effective rate plus 0.5%, and (3) the Adjusted Eurodollar Rate (as defined in the Bank Credit Agreement) for a one-month interest period plus 1.0%. We incur a commitment fee of either 0.375% or 0.5%, based on the ratio of outstanding borrowings to the borrowing base, on the unused availability under the Bank Credit Agreement.

2011 Redemption of our 2013 and 2015 Notes

Pursuant to cash tender offers, during March 2011, we repurchased $169.6 million in principal of our 7½% Senior Subordinated Notes due 2013 (the “2013 Notes”) at 100.625% of par, and $220.9 million in principal of our 7½% Senior Subordinated Notes due 2015 (the “2015 Notes”) at 104.125% of par. We called the remaining 2013 and 2015 Notes, repurchasing all of the remaining

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outstanding 2015 Notes ($79.1 million) at 103.75% of par on March 21, 2011, and all of the remaining outstanding 2013 Notes ($55.4 million) at par on April 1, 2011. We recognized a $16.1 million loss during the year ended December 31, 2011 associated with the debt repurchases, which is included in our Consolidated Statements of Operations under the caption “Loss on early extinguishment of debt”.

9½% Senior Subordinated Notes due 2016

As a result of the Encore Merger, we became successor in interest to Encore under the Encore indenture with respect to the 9½% Notes in the original principal amount of $225 million. Interest on the 9½% Notes is due semi-annually, on May 1 and November 1, at a rate of 9½%. The 9½% Notes mature on May 1, 2016. We may redeem the 9½% Notes, in whole or in part at our option beginning May 1, 2013, at the following redemption prices: 104.75% after May 1, 2013; 102.375% after May 1, 2014; and 100% after May 1, 2015. At any time prior to May 1, 2013, we may redeem 100% of the principal amount of the 9½% Notes at a price equal to 100% of the principal amount plus a “make-whole” premium and accrued and unpaid interest. The indenture governing the 9½% Notes includes various covenants and restrictions, including providing a put right by holders upon a change of control. All of our subsidiaries, other than minor subsidiaries, guarantee this debt jointly and severally. Pursuant to a cash tender offer commenced during January 2013, during February 2013 we repurchased $186.7 million principal amount of our 9½% Notes at 106.87% of par, and the indenture governing the 9½% Notes was amended to eliminate most of its restrictive covenants and certain events of default. We intend to use a portion of the net proceeds from the recent issuance of our 2023 Notes to fund the redemption of the remaining outstanding principal amount of our 9½% Notes. See Note 13, Subsequent Events, for more information.

9¾% Senior Subordinated Notes due 2016

In February 2009, we issued $420.0 million of 9¾% Notes, which carry a coupon rate of 9.75%. The 9¾% Notes were sold at a discount (92.816% of par), which equates to an effective yield to maturity of approximately 11.25%. In June 2009, we issued an additional $6.4 million of 9¾% Notes.

The 9¾% Notes mature on March 1, 2016, and interest on the 9¾% Notes is payable March 1 and September 1 of each year. The indenture governing the 9¾% Notes contains certain restrictions on our ability to incur additional debt, pay dividends on our common stock, make investments, create liens on our assets, engage in transactions with our affiliates, transfer or sell assets, consolidate or merge, or sell substantially all of our assets. The 9¾% Notes are not subject to any sinking fund requirements. All of our subsidiaries, other than minor subsidiaries, guarantee this debt jointly and severally. Pursuant to a cash tender offer commenced during January 2013, during February 2013 we repurchased $191.7 million principal amount of our 9¾% Notes at 105.425% of par. On February 5, 2013, we called the remaining 9¾% Notes for redemption on March 7, 2013, at 104.875% of par. See Note 13, Subsequent Events, for more information.

8¼% Senior Subordinated Notes due 2020

In February 2010, we issued $1.0 billion of 8¼% Senior Subordinated Notes due 2020 (the “2020 Notes”), for net proceeds after underwriting discounts and commissions of $980 million. The 2020 Notes, which carry a coupon rate of 8.25%, were sold at par. We subsequently redeemed $3.7 million principal amount of the 2020 Notes, as required under the indenture governing the 2020 Notes.

The 2020 Notes mature on February 15, 2020, and interest is payable on February 15 and August 15 of each year. We may redeem the 2020 Notes in whole or in part at our option beginning February 15, 2015, at the following redemption prices: 104.125% after February 15, 2015; 102.75% after February 15, 2016; 101.375% after February 15, 2017; and 100% after February 15, 2018. Prior to February 15, 2013, we may, at our option, redeem up to an aggregate of 35% of the principal amount of the 2020 Notes at a price of 108.25% with the proceeds of certain equity offerings. At any time prior to February 15, 2015, we may redeem 100% of the principal amount of the 2020 Notes at a price equal to 100% of the principal amount plus a “make-whole” premium and accrued and unpaid interest. The indenture governing the 2020 Notes contains certain restrictions on our ability to incur additional debt, pay dividends on our common stock, make investments, create liens on our assets, engage in transactions with our affiliates, transfer or sell assets, consolidate or merge, or sell substantially all of our assets. The 2020 Notes are not subject to any sinking fund requirements. All of our subsidiaries, other than minor subsidiaries, guarantee this debt jointly and severally.

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Notes to Consolidated Financial Statements

6 3/8% Senior Subordinated Notes due 2021

In February 2011, we issued $400 million of 6 3/8% Senior Subordinated Notes due 2021 (“2021 Notes”). The 2021 Notes, which carry a coupon rate of 6.375%, were sold at par. The net proceeds of $393 million were used to repurchase a portion of our 2013 Notes and 2015 Notes (see Redemption of our 2013 and 2015 Notes above). The 2021 Notes mature on August 15, 2021, and interest is payable on February 15 and August 15 of each year. We may redeem the 2021 Notes in whole or in part at our option beginning August 15, 2016 at the following redemption prices: 103.188% on or after August 15, 2016; 102.125% on or after August 15, 2017; 101.062% on or after August 15, 2018; and 100% on or after August 15, 2019. Prior to August 15, 2014, we may at our option redeem up to an aggregate of 35% of the principal amount of the 2021 Notes at a price of 106.375% with the proceeds of certain equity offerings. In addition, at any time prior to August 15, 2016, we may redeem 100% of the principal amount of the 2021 Notes at a price equal to 100% of the principal amount plus a “make-whole” premium and accrued and unpaid interest. The indenture governing the 2021 Notes contains certain restrictions on our ability to incur additional debt, pay dividends on our common stock, make investments, create liens on our assets, engage in transactions with our affiliates, transfer or sell assets, consolidate or merge, or sell substantially all of our assets. The 2021 Notes are not subject to any sinking fund requirements. All of our subsidiaries, other than minor subsidiaries, guarantee this debt jointly and severally.

Pipeline Financings

In May 2008, we closed two transactions with Genesis involving two of our pipelines. The NEJD Pipeline system included a 20-year financing lease, and the Free State Pipeline included a long-term transportation service agreement. We recorded both of these transactions as financing leases.

Debt Issuance Costs

In connection with the issuance of our outstanding long-term debt, we have incurred debt issuance costs, which are being amortized to interest expense using the effective interest method over the term of each related facility. Remaining unamortized debt issuance costs were $56.5 million and $69.6 million at December 31, 2012 and 2011, respectively. These balances are included in “Other assets” in our Consolidated Balance Sheets.

Indebtedness Repayment Schedule

At December 31, 2012, our indebtedness, including our capital and financing lease obligations but excluding the discount and premium on our senior subordinated debt, is payable over the next five years and thereafter as follows:



In thousands
2013	$	36,966
2014	38,481
2015	39,113
2016	1,388,592
2017	34,965
Thereafter	1,607,737
Total indebtedness	$	3,145,854

Capital Lease Obligations

During the second quarter of 2012, we corrected the accounting for our equipment leases from operating leases to capital leases to comply with the FASC Leases topic, as a result of the consideration of nonperformance-related default covenants included in our equipment lease agreements. We recorded a cumulative adjustment to establish the capital lease assets as “Other property and equipment” ($155.6 million) and the capital lease obligations as “Long-term debt” ($138.9 million) and “Current maturities of long-term debt” ($25.1 million) on the accompanying Consolidated Balance Sheets for the year ended December 31, 2012. We

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also recognized the cumulative pre-tax impact of $8.4 million ($5.2 million after tax) as “Other expenses” on the accompanying Consolidated Statements of Operations for the year ended December 31, 2012. Because the amounts involved were not material to our financial statements in any individual prior period and the cumulative impact is not material to the results of operations for the year ended December 31, 2012, we recorded the cumulative effect of correcting these items during 2012.

Note 6. Income Taxes

Our income tax provision (benefit) is as follows:



	Year Ended December 31,
In thousands	2012		2011			2010
Current income tax expense (benefit)
Federal	$	57,720	$	(12,552	)	$	15,683
State	18,034		20,801			17,511
Total current income tax expense	75,754		8,249			33,194

Deferred income tax expense
Federal	239,862		329,715			143,381
State	15,881		12,748			16,968
Total deferred income tax expense	255,743		342,463			160,349
Total income tax expense	$	331,497	$	350,712		$	193,543

During 2012, for federal income tax purposes, we structured the divestitures of our Bakken area assets and certain non-core assets as like-kind-exchange transactions for interests acquired in Thompson, Webster, Hartzog Draw and LaBarge fields and assets to be acquired in the Pending CCA Acquisition (See Note 13, Subsequent Events), thereby deferring the majority of the taxable gain on those divestitures. The increase in current taxes during 2012 is primarily due to the taxable gain recognized in the Bakken Exchange Transaction that we were unable to defer through a like-kind-exchange transaction.

At December 31, 2012, we had tax-effected state net operating loss carryforwards (“NOLs”) totaling $35.0 million, an estimated $17.3 million of enhanced oil recovery credits to carry forward related to our tertiary operations, and $34.8 million of alternative minimum tax credits. Our state NOLs expire in various years, starting in 2015, although most do not begin to expire until 2024. Our enhanced oil recovery credits will begin to expire in 2025.

Deferred income taxes reflect the available tax carryforwards and the temporary differences based on tax laws and statutory rates in effect at the December 31, 2012 and 2011 balance sheet dates. We believe that we will be able to realize all of our deferred tax assets at December 31, 2012, and therefore, have provided no valuation allowance against our deferred tax assets.

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Notes to Consolidated Financial Statements

Significant components of our deferred tax assets and liabilities as of December 31, 2012 and 2011 are as follows:



	December 31,
In thousands	2012			2011
Deferred tax assets:
Loss carryforwards – federal	$	—		$	13,970
Loss carryforwards – state	35,007			41,960
Tax credit carryover	34,837			34,829
Derivative contracts	7,252			3,551
Enhanced oil recovery credit carryforwards	17,346			53,381
Stock based compensation	28,387			32,566
Other	37,226			35,279
Total deferred tax assets	160,055			215,536

Deferred tax liabilities:
Property and equipment	(2,277,388		)	(2,078,143		)
Other	(6,963		)	(5,813		)
Total deferred tax liabilities	(2,284,351		)	(2,083,956		)
Total net deferred tax liability	$	(2,124,296	)	$	(1,868,420	)

Our reconciliation of income tax expense computed by applying the U.S. federal statutory rate and the reported effective tax rate on income from continuing operations is as follows:



	Year Ended December 31,
In thousands	2012			2011			2010
Income tax provision calculated using the federal statutory income tax rate	$	299,900		$	323,416		$	167,674
State income taxes, net of federal income tax benefit	30,955			29,555			13,087
Effect of statutory rate change	(429		)	(578		)	11,502
Other	1,071			(1,681		)	1,280
Total income tax expense	$	331,497		$	350,712		$	193,543

In the third quarter of 2008, we obtained approval from the National Office of the Internal Revenue Service (“IRS”) to change our method of tax accounting for certain assets used in our tertiary oilfield recovery operations. As a result of the approved change in method of tax accounting, beginning with the 2007 tax year we began to deduct, rather than capitalize, such costs for tax purposes and applied for tax refunds associated with such change for our 2004 and 2006 tax years. Notwithstanding its consent to our change in tax accounting in 2008, the IRS exercised its prerogative to challenge the tax accounting method we used. In late January 2011, we received a Technical Advice Memorandum (“TAM”) issued by the IRS National Office disapproving our method of accounting and revoking its consent to our change, on a prospective basis only, commencing January 1, 2011. Beginning with the 2011 tax year, we returned to capitalizing and depreciating the costs of these assets for tax purposes. In December 2011, we received notification from the IRS that the review process was completed and that all issues related to the TAM were settled without further adjustments. As a result of the prospective nature of the IRS’s determination, there was no change in our position with respect to the deductibility of these costs for 2007, 2008, 2009 and 2010. Refund claims of $10.6 million for tax years through 2006 were received, plus accrued interest, in 2012.

We file consolidated and separate income tax returns in the U.S. federal jurisdiction and in many state jurisdictions. The IRS concluded its examination of our 2006, 2007 and 2008 tax years during the fourth quarter of 2011 with no adjustments. During the third quarter of 2012, the IRS concluded its audit of Encore Acquisition Company for the tax years 2008, 2009 and 2010 and Encore Operating LP for the tax years 2008 and 2009, with no significant adjustments. During the fourth quarter of 2012, the

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state of Mississippi concluded its audit of Denbury for the tax years 2004, 2005, 2006, and 2007, with no significant adjustments. Our income tax returns for tax years ending 2009 through 2011 currently remain subject to examination by the appropriate taxing authorities. We have not paid any significant interest or penalties associated with our income taxes.

Note 7. Stockholders' Equity

Stock Repurchase Program

In October 2011, we commenced a common share repurchase program for up to $500 million of Denbury common shares, as approved by the Company's Board of Directors. During 2012, the Board of Directors increased the dollar amount of Denbury common shares that can be purchased under the program to an aggregate of $771.2 million. The program has no pre-established ending date and may be suspended or discontinued at any time. We are not obligated to repurchase any dollar amount or specific number of shares of our common stock under the program. During 2012, we repurchased 17.0 million shares of Denbury common stock for $266.7 million, or $15.71 per share, and during 2011, we repurchased 14.1 million shares of Denbury common stock for $195.2 million, or $13.83 per share under this share repurchase program. From the time the share repurchase program commenced in October 2011 through December 31, 2012, we have purchased 31.1 million shares of Denbury common stock (approximately 7.7% of our outstanding shares of common stock at September 30, 2011) at a cost of $461.9 million, and at that date, we were authorized to spend an additional $309.3 million under this repurchase program. We account for treasury stock using the cost method and include treasury stock as a component of stockholders’ equity. See Note 13, Subsequent Events, for additional information.

Other share repurchases during 2012 and 2011, and all of our share repurchases during 2010 were from our employees who surrendered shares to the Company to satisfy their minimum tax withholding requirements as provided for under our stock compensation plans and were not part of a formal stock repurchase plan.

Employee Stock Purchase Plan

We have an Employee Stock Purchase Plan that is authorized to issue up to 9,900,000 shares of common stock. As of December 31, 2012, there were 462,131 authorized shares remaining to be issued under the plan. In accordance with the plan, eligible employees may contribute up to 10% of their base salary, and we match 75% of their contribution. The combined funds are used to purchase previously unissued Denbury common stock or treasury stock that we purchased in the open market for that purpose, in either case, based on the market value of our common stock at the end of each quarter. We recognize compensation expense for the 75% Company match portion, which totaled $5.7 million, $4.8 million and $3.5 million for the years ended December 31, 2012, 2011 and 2010, respectively. This plan is administered by the Compensation Committee of our Board of Directors.

401(k) Plan

We offer a 401(k) plan to which employees may contribute tax-deferred earnings subject to IRS limitations. We match 100% of an employee’s contribution, up to 6% of compensation, as defined by the plan, which is vested immediately. During 2012, 2011 and 2010, our matching contributions to the 401(k) Plan were approximately $8.0 million, $7.1 million and $5.7 million, respectively.

Note 8. Stock Compensation Plans

Stock Incentive Plans

We have two stock compensation plans. The first plan (providing only for the issuance of stock options) has been in existence since 1995 (the “1995 Plan”) and expired in August 2005 (although options granted under the 1995 Plan prior to that time can remain outstanding for up to 10 years). The second plan, the 2004 Omnibus Stock and Incentive Plan (the “2004 Plan”), has a 10-year term and was approved by the stockholders in May 2004. The 2004 Plan provides for the issuance of incentive and non-qualified stock options, restricted stock awards, restricted stock units, SARs settled in stock, and performance awards that may be issued to officers, employees, directors and consultants. Awards covering a total of 29.5 million shares of common stock have

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been authorized for issuance pursuant to the 2004 Plan. At December 31, 2012, 11.3 million shares were available under the 2004 Plan for future issuance of awards, all of which could be issued in the form of restricted stock or performance vesting awards. Our incentive compensation program is administered by the Compensation Committee of our Board of Directors.

Prior to January 1, 2006, we granted incentive and non-qualified stock options to our employees. Effective January 1, 2006, we completely replaced the use of stock options for employees with SARs settled in stock, as SARs are less dilutive to our stockholders while providing an employee with essentially the same economic benefits as stock options. The stock options and SARs generally become exercisable over a three- or four-year vesting period, with the specific terms of vesting determined at the time of grant based on guidelines established by the Compensation Committee of the Board of Directors. The stock options and SARs expire over terms not to exceed 10 years from the date of grant, 90 days after termination of employment, 90 days or one year after permanent disability, depending on the plan, or one year after the death of the optionee. The stock options and SARs are granted at the fair market value at the time of grant, which is defined in the 2004 Plan as the closing price on the NYSE on the date of grant.

Holders of restricted stock awards have the rights and privileges of owning the shares (including voting rights) except that the holders are not entitled to delivery of a portion thereof until certain requirements are met. Restricted stock awards vest over three-to-four-year vesting periods, with the specific terms of vesting determined at the time of grant.

Annually, the Board of Directors grants performance-based equity awards to officers of Denbury. These performance-based awards vest over 1.25 to 3.25 years and the number of performance-based shares earned (and eligible to vest) during the performance period will depend upon two sets of factors: (1) our level of success in achieving four specifically identified performance targets ("Performance-based Operational Awards") and (2) relative performance of our stock to that of a designated peer group ("Performance-based TSR Awards"). Generally, one-half of the maximum number of shares that could be earned under the performance-based awards will be earned for performance at the designated target levels (100% target vesting levels) or upon any earlier change of control, and twice the number of shares will be earned if the higher maximum target levels are met. If performance is below the designated minimum levels for all performance targets, no performance-based shares will be earned. Performance-based Operational Awards are valued using the fair market value of Denbury stock on the grant date and Performance-based TSR Awards are valued using a Monte Carlo simulation.

Stock-based compensation expense associated with our field employees is included in “Lease operating expense,” while such expense associated with non-field employees is included in “General and administrative expenses” in the Consolidated Statements of Operations. Stock-based compensation associated with Encore Merger transition employees is included in “Transaction and other costs related to the Encore Merger” in the Consolidated Statements of Operations. Stock-based compensation associated with our employees involved in exploration and drilling activities is capitalized as part of “Oil and natural gas properties” in the Consolidated Balance Sheets.

Stock-based compensation costs for the years ended December 31, 2012, 2011 and 2010, are as follows:



	Year Ended December 31,
In thousands	2012		2011		2010
Stock-based compensation expensed:
General and administrative expenses	$	26,463	$	30,256	$	28,169
Lease operating expenses	2,847		2,621		2,056
Transaction and other costs related to the Encore Merger	—		313		5,866
Total stock-based compensation expensed	29,310		33,190		36,091
Stock-based compensation capitalized	8,587		6,998		3,702
Total cost of stock-based compensation arrangements	$	37,897	$	40,188	$	39,793

Income tax benefit realized for stock-based compensation arrangements	$	15,131	$	18,383	$	8,462

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Notes to Consolidated Financial Statements

Stock Options and SARs

The fair value of each SARs award is estimated on the date of grant using the Black-Scholes option pricing model with the assumptions noted in the following table. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant. The expected life of stock options and SARs granted was derived from examination of our historical option grants and subsequent exercises. The contractual terms (cliff vesting and graded vesting) are evaluated separately for the expected life, as the exercise behavior for each is different. Expected volatilities are based on the historical volatility of our common stock. Implied volatility was not used in this analysis, as our tradable call option terms are short and the trading volume is low. Our dividend yield is zero, as we have historically not paid dividends.



	2012			2011			2010
Weighted average fair value of SARs granted	$	8.90		$	9.68		$	8.45
Risk-free interest rate	0.79		%	1.74		%	2.19		%
Expected life	4.0 to 5.0 years			4.0 to 5.0 years			4.0 to 4.3 years
Expected volatility	64.9		%	63.3		%	65.0		%
Dividend yield	—		%	—		%	—		%

The following is a summary of our stock option and SARs activity:



	Number of Awards		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (in years)	Aggregate Intrinsic Value (in thousands)
Outstanding at December 31, 2011	11,949,610		$	13.56
Granted	1,066,294		17.14
Exercised	(2,029,570	)	8.03
Forfeited or expired	(541,199	)	18.34
Outstanding at December 31, 2012	10,445,135		14.75		3.7	$	31,861

Exercisable at end of period	7,115,744		$	13.81	3.2	$	30,031

The following is a summary of the total intrinsic value of stock options and SARs exercised and grant-date fair value of stock options and SARs vested:



	Year Ended December 31,
In thousands	2012		2011		2010
Intrinsic value of stock options exercised	$	17,315	$	20,463	$	12,670
Grant-date fair value of stock options and SARs vested	26,391		11,416		8,689

As of December 31, 2012, there was $13.8 million of total compensation cost to be recognized in future periods related to nonvested stock option and SARs share-based compensation arrangements. The cost is expected to be recognized over a weighted-average period of 2.0 years. The following is a summary of cash received from stock option exercises under share-based payment arrangements and tax benefits realized from the exercises of stock options and SARs:



	Year Ended December 31,
In thousands	2012		2011		2010
Cash received from stock option exercises	$	6,022	$	4,685	$	4,867
Tax benefit realized for the exercises of stock options and SARs	241		879		4,603

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Notes to Consolidated Financial Statements

Restricted Stock – 2004 Plan

As of December 31, 2012, there was $29.0 million of unrecognized compensation expense related to nonvested restricted stock grants. This unrecognized compensation cost is expected to be recognized over a weighted-average period of 2.61 years. The following is a summary of the total vesting date fair value of restricted stock under the 2004 Plan:



	Year Ended December 31,
In thousands	2012		2011		2010
Fair value of restricted stock vested	$	22,332	$	12,355	$	12,731

A summary of the status of our nonvested restricted stock grants issued under our 2004 Plan and the changes during the year ended December 31, 2012 is presented below:



	Number of Shares		Weighted Average Grant-Date Fair Value
Nonvested at December 31, 2011	3,131,435		$	14.82
Granted	1,909,739		16.94
Vested	(1,378,496	)	15.38
Forfeited	(256,471	)	17.08
Nonvested at December 31, 2012	3,406,207		15.60

Restricted Stock – Legacy Encore Plan

In February 2010, prior to the consummation of the Encore Merger, Encore issued a restricted stock grant to its employees under the Encore Acquisition Company 2008 Incentive Stock Plan (“Encore Plan”). At the time of the Encore Merger, the shares were converted to shares of Denbury restricted stock. The shares vest ratably over a four-year graded vesting period; however, legacy Encore employees who terminate their employment for Good Reason, as defined by Encore’s legacy Employee Severance Protection Plan, will automatically vest in their awards upon termination. Encore employees who did not accept permanent positions with Denbury but who continued their employment through a predefined transition period were considered to have terminated for Good Reason and, accordingly, vested in their awards upon termination. As of December 31, 2012, there was $0.5 million of unrecognized compensation expense related to non-vested restricted stock issued under the Encore Plan, which is expected to be recognized over a weighted-average period of 1.1 years. The following is a summary of the total vesting date fair value of restricted stock under the Encore Plan:



	Year Ended December 31,
In thousands	2012		2011		2010
Fair value of restricted stock vested	$	584	$	2,259	$	6,571

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Notes to Consolidated Financial Statements

A summary of the status of the non-vested restricted stock grants under the Encore Plan and the changes during the year ended December 31, 2012 is presented below:



	Number of Shares		Weighted Average Grant-Date Fair Value
Nonvested at December 31, 2011	103,043		$	15.43
Vested	(36,049	)	15.43
Forfeited	(10,736	)	15.43
Nonvested at December 31, 2012	56,258		15.43

Performance-Based Equity Awards

During 2012, we granted Performance-based Operational Awards and Performance-based TSR Awards to our officers. The range of assumptions used in the Monte Carlo simulation valuation approach for Performance-based TSR Awards, which were granted for the first time during 2012, are as follows:



	2012
Weighted average fair value of Performance-based TSR Award granted	$	24.68
Risk-free interest rate	0.42		%
Expected life	2.81 years
Expected volatility	45.2		%
Dividend yield	—		%

A summary of the status of the nonvested performance-based equity awards (presented at the target level) during the year ended December 31, 2012 is as follows:



	Performance-based Operational Awards				Performance-based TSR Awards
	Number of Awards		Weighted Average Grant-Date Fair Value		Number of Awards		Weighted Average Grant-Date Fair Value
Nonvested at December 31, 2011	214,627		$	18.71	—		$	—
Granted	110,615		17.27		96,325		24.68
Vested⁽¹⁾	(214,627	)	18.71		—		—
Forfeited	(10,422	)	17.27		(9,408	)	24.68
Nonvested at December 31, 2012	100,193		17.27		86,917		$	24.68


(1)	During 2012, the 2011 annual Performance-based Operational Awards vested, and award holders received shares equivalent to 56% of the number of target-level shares.

The following is a summary of the total vesting date fair value of performance-based equity awards:



	Year Ended December 31,
In thousands	2012		2011		2010
Vesting date fair value of Performance-based Operational Awards	$	2,191	$	10,892	$	7,532

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Notes to Consolidated Financial Statements

Note 9. Derivative Instruments and Hedging Activities

Oil and Natural Gas Derivative Contracts

We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the fair values of these instruments are recognized in income in the period of change. These fair value changes, along with the cash settlements of expired contracts, are shown under “Derivatives expense (income)” in our Consolidated Statements of Operations.

From time to time, we enter into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production. We do not hold or issue derivative financial instruments for trading purposes. These contracts have consisted of price floors, collars and fixed price swaps. The production that we hedge has varied from year to year depending on our levels of debt and financial strength and expectation of future commodity prices. We currently employ a strategy to hedge a portion of our forecasted production approximately two years in the future from the current quarter, as we believe it is important to protect our future cash flow to provide a level of assurance for our capital spending in those future periods in light of current worldwide economic uncertainties and commodity price volatility. We do not have any natural gas derivative contracts for 2013 or beyond. Because our current and forecasted production is primarily oil, we currently use only oil derivative contracts in our commodity market risk management program.

The following is a summary of “Derivatives expense (income)” included in our Consolidated Statements of Operations:



	Year Ended December 31,
In thousands	2012			2011			2010
Oil
Payment on settlements of derivative contracts	$	9,991		$	25,128		$	93,417
Fair value adjustments to derivative contracts – income	(10,904		)	(58,980		)	(44,441		)
Total derivatives expense (income) – oil	(913		)	(33,852		)	48,976
Natural gas
Receipt on settlements of derivative contracts	(27,871		)	(27,505		)	(61,805		)
Fair value adjustments to derivative contracts – expense (income)	23,950			8,860			(8,585		)
Total derivatives expense (income) – natural gas	(3,921		)	(18,645		)	(70,390		)
Ineffectiveness on interest rate swaps	—			—			(2,419		)
Derivatives expense (income)	$	(4,834	)	$	(52,497	)	$	(23,833	)

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Notes to Consolidated Financial Statements

Commodity Derivative Contracts Not Classified as Hedging Instruments



					Contract Prices per Barrel
		Type of	Volume			Weighted Average Price
Year	Months	Contract	(Barrels per day)		Range	Floor		Ceiling

Oil Contracts:
2013	Jan – Mar	Collar	55,000	$	70.00 – 113.00	$	78.91	$	108.01
	Apr – June	Collar	56,000		75.00 – 121.50	79.64		108.61
	July – Sept	Collar	56,000		75.00 – 133.10	79.64		109.15
	Oct – Dec	Collar	54,000		80.00 – 127.50	80.00		117.53


2014	Jan – Mar	Collar	52,000	$	80.00 – 104.50	$	80.00	$	102.44
	Apr – June	Collar	52,000		80.00 – 104.50	80.00		102.44
	July – Sept	Collar	48,000		80.00 – 98.80	80.00		97.46
	Oct – Dec	Collar	48,000		80.00 – 98.80	80.00		97.46

Additional Disclosures about Derivative Instruments:

At December 31, 2012 and 2011, we had derivative financial instruments recorded in our Consolidated Balance Sheets as follows:



		Estimated Fair Value Asset (Liability) December 31,
Type of Contract	Balance Sheet Location	2012			2011
		In thousands
Derivatives not designated as hedging instruments:
Derivative Assets
Crude oil contracts	Derivative assets – current	$	19,477		$	23,452
Natural gas contracts	Derivative assets – current	—			23,950
Crude oil contracts	Derivative assets – long-term	36			29
Derivative Liabilities
Crude oil contracts	Derivative liabilities – current	(2,659		)	(22,610		)
Deferred premiums ⁽¹⁾	Derivative liabilities – current	(183		)	(3,913		)
Crude oil contracts	Derivative liabilities – long-term	(23,781		)	(18,702		)
Deferred premiums ⁽¹⁾	Derivative liabilities – long-term	—			(170		)
Total derivatives not designated as hedging instruments		$	(7,110	)	$	2,036


(1)	Deferred premiums payable relate to various oil floor contracts and are payable on a monthly basis through January 2013.

Note 10. Fair Value Measurements

The FASC Fair Value Measurements and Disclosures topic defines fair value as the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including

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Notes to Consolidated Financial Statements

assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:


•	Level 1 — Quoted prices in active markets for identical assets or liabilities as of the reporting date.

•

Level 2 — Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded oil and natural gas derivatives that are based on NYMEX pricing. Our costless collars are valued using the Black-Scholes model, an industry standard option valuation model, that takes into account inputs such as contractual prices for the underlying instruments, including maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

•

Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At December 31, 2011, instruments in this category also included non-exchange-traded natural gas derivatives swaps that were based on regional pricing other than NYMEX (i.e., Houston Ship Channel). Our basis swaps were estimated using discounted cash flow calculations based upon forward commodity price curves.

We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty’s credit quality for asset positions and our credit quality for liability positions. We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.

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Notes to Consolidated Financial Statements

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2012 and 2011:



	Fair Value Measurements Using:
	Quoted Prices in Active Markets		Significant Other Observable Inputs			Significant Unobservable Inputs
In thousands	(Level 1)		(Level 2)			(Level 3)		Total
December 31, 2012
Assets:
Oil derivative contracts	$	—	$	19,513		$	—	$	19,513
Liabilities:
Oil derivative contracts	—		(26,440		)	—		(26,440		)
Total	$	—	$	(6,927	)	$	—	$	(6,927	)

December 31, 2011
Assets:
Short-term investments	$	86,682	$	—		$	—	$	86,682
Oil and natural gas derivative contracts	—		23,481			23,950		47,431
Liabilities:
Oil and natural gas derivative contracts	—		(41,312		)	—		(41,312		)
Total	$	86,682	$	(17,831	)	$	23,950	$	92,801

The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the years ended December 31, 2012 and 2011:



	Year Ended December 31,
In thousands	2012				2011
Fair value of Level 3 instruments, beginning of year	$	23,950			$	16,478
Unrealized gains on commodity derivative contracts included in earnings	3,921				13,384
Receipts on settlement of commodity derivative contracts	(27,871		)		(5,912		)
Fair value of Level 3 instruments, end of year	$	—		10	$	23,950

The amount of total gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held at the reporting date	$	—			$	13,384

Since we do not use hedge accounting for our commodity derivative contracts, any gains and losses on our assets and liabilities are included in “Derivatives expense (income)” in the accompanying Consolidated Statements of Operations. Management's estimate of the fair market value of contingent consideration has not changed from the acquisition date to December 31, 2012; therefore, there has been no impact on the Consolidated Statements of Operations for the years ended December 31, 2012 and 2011.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

During 2012, we recorded a $15.1 million impairment charge for an investment in the preferred stock of an entity that was created to develop a gasification plant (in which we would offtake its CO₂ to use in our tertiary oil operations) as a result of this

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Notes to Consolidated Financial Statements

project not moving forward. This charge is classified as “Impairment of assets” in the Consolidated Statement of Operations for the year ended December 31, 2012.

Other Fair Value Measurements

The carrying value of our revolving bank credit facility approximates fair value, as it is subject to short-term floating interest rates that approximate the rates available to us for those periods. We use a market approach to determine fair value of our fixed-rate debt using observable market data. The fair values of our senior subordinated notes are based on quoted market prices. The estimated fair value of our total long-term debt as of December 31, 2012 and 2011, excluding pipeline financing and capital lease obligations, is $2,956.9 million and $2,638.2 million, respectively. We have other financial instruments consisting primarily of cash, cash equivalents, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.

Note 11. Commitments and Contingencies

Leases

We lease office space, equipment and vehicles that have non-cancelable lease terms. Leases entered into during 2012 have terms up to thirteen years. Lease payments associated with operating leases were $33.6 million, $52.3 million and $42.4 million in 2012, 2011 and 2010, respectively. We have subleased part of the office space included in our operating leases for which we received approximately $2.7 million, $2.4 million and $0.5 million in 2012, 2011 and 2010, respectively. In addition, we expect to receive approximately $3.6 million for 2013 through 2016 under these sublease agreements.

The following table summarizes by year the remaining non-cancelable future payments under these leases as of December 31, 2012:



In thousands	Pipeline Financing Leases			Capital Leases			Operating Leases
2013	$	30,817		$	35,429		$	10,656
2014	31,992			31,629			11,452
2015	32,591			30,139			12,300
2016	31,233			28,038			12,384
2017	30,678			22,052			12,720
Thereafter	296,226			31,806			80,562
Total minimum lease payments	453,537			179,093			$	140,074
Less: Amount representing interest	(217,293		)	(20,833		)
Present value of minimum lease payments	$	236,244		$	158,260

Commitments

We have entered into long-term commitments to purchase CO₂ that are either non-cancelable or cancelable only upon the occurrence of specified future events. The commitments continue for up to 20 years. The price we will pay for CO₂ varies depending on the amount of CO₂ delivered and the price of oil. We anticipate the contracts will provide us with approximately 335 MMcf/d to 675 MMcf/d of CO₂ at a cost of approximately $95 million to $190 million per year, assuming a $100 per Bbl NYMEX oil price.

We are party to long-term contracts that require us to deliver CO₂ to our industrial CO₂ customers at various contracted prices, plus we have a CO₂ delivery obligation to Genesis related to three CO₂ volumetric production payments (“VPPs”). Based upon the maximum amounts deliverable as stated in the industrial contracts and the VPPs, we estimate that we may be obligated to deliver up to 327 Bcf of CO₂ to these customers over the next 14 years. The maximum volume required in any given year is

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Notes to Consolidated Financial Statements

approximately 109 MMcf/d. Given the size of our Jackson Dome proven CO₂ reserves at December 31, 2012, our current production capabilities and our projected levels of CO₂ usage for our own tertiary flooding program, we believe that we can meet these contractual delivery obligations.

In conjunction with the August 1, 2011 Riley Ridge acquisition, we assumed the 20-year helium supply contract under which the original participants in Riley Ridge agreed to supply helium to a third-party purchaser. After the commencement date, the contract provides for the delivery of a minimum contracted quantity of helium, subject to adjustment after start-up of the Riley Ridge Plant, which if not supplied in accordance with the terms of the contract, may obligate us to compensate the third-party helium purchaser for the amount of the shortfall in an amount not to exceed $8.0 million per year.

Litigation

We are involved in various 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 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 a loss is probable and the amount can be reasonably estimated.

Other Contingencies

We are subject to audits in the various states in which we operate for sales and use taxes and severance taxes, and from time to time receive assessments for potential taxes that we may owe. In the past, settlement of these matters has not had a material adverse financial impact on us, and currently we have no material assessments for potential taxes.

We are subject to various possible contingencies that arise primarily from interpretation of federal and state laws and regulations affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Although we believe that we have complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. In addition, production rates, marketing and environmental matters are subject to regulation by various federal and state agencies.

Note 12. Supplemental Information

Significant Oil and Natural Gas Purchasers

Oil and natural gas sales are made on a day-to-day basis or under short-term contracts at the current area market price. We do not expect that the loss of any purchaser would have a material adverse effect upon our operations. For the years ended December 31, 2012, 2011 and 2010, two purchasers accounted for 10% or more of our oil and natural gas revenues: Marathon Petroleum Company LLC (39%, 43% and 46% in 2012, 2011 and 2010, respectively) and Plains Marketing LP (17%, 16% and 14% in 2012, 2011 and 2010, respectively).

Allowance for Doubtful Accounts

We record an allowance for doubtful accounts for receivables that we determine to be uncollectible based on the specific identification basis. The allowance for doubtful accounts, which is netted against “Trade and other receivables” on the Consolidated Balance Sheets, was $0.3 million at December 31, 2012 and 2011.

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Notes to Consolidated Financial Statements

Accounts Payable and Accrued Liabilities



	December 31,
In thousands	2012		2011
Accrued exploration and development costs	$	109,939	$	141,868
Accounts payable	86,051		99,444
Accrued interest	60,698		60,923
Accrued compensation	48,451		35,861
Accrued lease operating expenses	23,862		24,185
Taxes payable	27,523		13,455
Other	58,144		53,600
Total	$	414,668	$	429,336

Supplemental Cash Flow Information



	Year Ended December 31,
In thousands	2012			2011			2010
Supplemental cash flow information:
Cash paid for interest, expensed	$	137,950		$	137,259		$	151,831
Cash paid for interest, capitalized	77,432			60,540			66,815
Cash paid for income taxes	99,194			45,912			17,960
Cash received from income tax refunds	(38,004		)	(24,677		)	(15,107		)
Non-cash investing activities:
Increase in asset retirement obligations	56,290			24,694			53,579
Increase (decrease) in liabilities for capital expenditures	(26,882		)	74,697			(237		)
Sale of non-core assets ⁽¹⁾	(212,544		)	—			—
Purchase of Thompson Field ⁽¹⁾	212,544			—			—
Sale of Bakken area assets in Bakken Exchange Transaction ⁽²⁾	(1,621,611		)	—			—
Purchase of properties in Bakken Exchange Transaction ⁽²⁾	571,596			—			—
Issuance of Denbury common stock in connection with the Encore Merger	—			—			2,085,681
Vanguard common units received as consideration for sale of ENP	—			—			93,020


(1)	During 2012, $212.5 million of proceeds from the sale of certain non-core assets were paid by the purchaser directly to a qualified intermediary to facilitate a like-kind-exchange transaction for federal income tax purposes. The qualified intermediary subsequently released the funds to the previous owner of the Thompson Field to fund our acquisition of Thompson Field.

(2)

During 2012, we sold our Bakken area assets with a fair value as determined in accordance with FASC rules of $1.9 billion to ExxonMobil in exchange for a combination of cash and various property interests valued in accordance with FASC rules at $571.6 million. ExxonMobil paid a portion of the cash proceeds ($1.05 billion) directly to a qualified intermediary to facilitate a like-kind-exchange transaction under federal income tax rules under which we expect our Pending CCA Acquisition to qualify (see Note 13, Subsequent Events). The remaining $281.7 million in cash proceeds are reported as an investing activity on our Statement of Cash Flows for the year ending December 31, 2012.

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Notes to Consolidated Financial Statements

Note 13. Subsequent Events

Pending CCA Acquisition

In January 2013, we entered into an agreement to acquire producing assets in the Cedar Creek Anticline (“CCA”) of Montana and North Dakota from a wholly-owned subsidiary of ConocoPhillips for $1.05 billion in cash, before standard closing adjustments primarily for revenues and costs of the properties to be purchased from the January 1, 2013 effective date to the closing date. We plan to fund the acquisition out of a portion of the cash proceeds from the Bakken Exchange Transaction in order to qualify the acquisition for like-kind-exchange treatment under federal income tax rules. We expect the acquisition to close near the end of the first quarter of 2013.

New Senior Subordinated Notes

On February 5, 2013, we issued the 2023 Notes, which carry a coupon rate of 4.625%, and were sold at par. The net proceeds of $1.18 billion have been used to repurchase a portion of, or are intended to be used to redeem the remainder of, our outstanding 9½% Notes and 9¾% Notes and to reduce borrowings under our credit facility.

The 2023 Notes mature on July 15, 2023, and interest is payable on January 15 and July 15 of each year, commencing July 15, 2013. We may redeem the 2023 Notes in whole or in part at our option beginning January 15, 2018, at the following redemption prices: 102.313% on or after January 15, 2018; 101.542% on or after January 15, 2019; 100.771% on or after January 15, 2020; and 100% on or after January 15, 2021. Prior to July 15, 2016, we may at our option redeem up to an aggregate of 35% of the principal amount of the 2023 Notes at a price of 104.625% with the proceeds of certain equity offerings. In addition, at any time prior to July 15, 2018, we may redeem 100% of the principal amount of the 2023 Notes at a price equal to 100% of the principal amounts plus a “make whole” premium and accrued and unpaid interest. The indenture contains certain restrictions on our ability to: (1) incur additional debt; (2) pay dividends on our common stock or redeem, repurchase or retire such capital stock or subordinated debt unless certain leverage ratios are met; (3) make investments; (4) create liens on our assets; (5) create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to the Company; (6) engage in transactions with our affiliates; (7) transfer or sell assets; and (8) consolidate, merge or transfer all or substantially all of our assets and the assets of our subsidiaries. All of our significant subsidiaries fully and unconditionally guaranteed this debt.

Tender Offers

On January 22, 2013, we commenced cash tender offers to purchase $426.4 million principal amount of our 9¾% Notes and $224.9 million principal amount of our 9½% Notes. During February 2013, we accepted for purchase $191.7 million principal amount of the outstanding 9¾% Notes and $186.7 million principal amount of the outstanding 9½% Notes. We received sufficient consents in the solicitation to amend the indenture governing the 9½% Notes by entering into a supplemental indenture, which eliminated most of the restrictive covenants and certain events of default. The purchases under these tender offers were funded by the proceeds from the sale of our 2023 Notes. The tender offers expired on February 19, 2013. On February 5, 2013, we issued a notice of redemption for all remaining outstanding 9¾% Notes at 104.875% of par with a redemption date of March 7, 2013 and intend to call the 9½% Notes for redemption on or about May 1, 2013.

Stock Repurchase Program

Between January 1, 2013 and February 21, 2013, the Company repurchased an additional 3.5 million shares of Denbury common stock under the share repurchase program for $59.1 million, or $16.73 per share. From the time the share repurchase program commenced in October 2011 through February 21, 2013, we have repurchased a total of $521.0 million of common stock under the program, and are authorized to spend an additional $250.2 million under this repurchase program. See Note 7, Stockholders' Equity, for additional information.

Equity Award Grant

In January 2013, we granted equity incentive awards to our employees under the 2004 Plan. The grant included 1,545,077 shares of restricted stock valued at $16.77 per share (the closing price of Denbury’s common stock on January 4, 2013) and 605,802

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Notes to Consolidated Financial Statements

SARs with an exercise price of $16.77 and a weighted average grant date fair value ranging between $5.42 and $8.72 per unit. The awards generally vest 33% per year over a three-year period.

Note 14. Supplemental Oil and Natural Gas Disclosures (Unaudited)

Costs Incurred

The following table summarizes costs incurred and capitalized in oil and natural gas property acquisition, exploration and development activities. Property acquisition costs are those costs incurred to purchase, lease or otherwise acquire property, including both undeveloped leasehold and the purchase of reserves in place. Exploration costs include costs of identifying areas that may warrant examination and examining specific areas that are considered to have prospects containing oil and natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs, and carrying costs on undeveloped properties. Development costs are incurred to obtain access to proved reserve costs, including the cost of drilling development wells, and to provide facilities for extracting, treating, gathering and storing the oil and natural gas, and the cost of improved recovery systems.

We capitalize interest on unevaluated oil and natural gas properties that have ongoing development activities. Included in costs incurred in the table below is capitalized interest of $36.5 million in 2012, $44.9 million in 2011 and $32.6 million in 2010. Costs incurred also include new asset retirement obligations established, as well as changes to asset retirement obligations resulting from revisions in cost estimates or abandonment dates. Asset retirement obligations included in the table below were $38.8 million in 2012, $24.2 million in 2011 and $45.1 million in 2010. See Note 3, Asset Retirement Obligations, for additional information.

Costs incurred in oil and natural gas activities were as follows:



	Year Ended December 31,
In thousands	2012		2011		2010
Property acquisitions:
Proved	$	491,041	$	86,465	$	3,373,450
Unevaluated	115,270		17,858		1,297,695
Exploration	12,019		31,483		8,728
Development	1,111,314		1,144,243		658,758
Total costs incurred ⁽¹⁾	$	1,729,644	$	1,280,049	$	5,338,631


(1)	Capitalized general and administrative costs that directly relate to exploration and development activities were $49.2 million, $35.0 million and $20.1 million for the years ended December 31, 2012, 2011 and 2010, respectively.

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Notes to Consolidated Financial Statements

Oil and Natural Gas Operating Results

Results of operations from oil and natural gas producing activities, excluding corporate overhead and interest costs, were as follows:



	Year Ended December 31,
In thousands, except per BOE data	2012			2011			2010
Oil, natural gas, and related product sales	$	2,409,867		$	2,269,151		$	1,793,292
Lease operating costs	532,359			507,397			470,364
Marketing expenses	52,836			26,047			31,036
Taxes other than income	149,919			138,419			114,569
Depletion, depreciation and amortization	448,424			369,075			391,782
CO₂ properties and pipelines depletion and depreciation ⁽¹⁾	42,064			24,460			29,206
Commodity derivatives expense (income)	(4,834		)	(52,497		)	(21,414		)
Net operating income	1,189,099			1,256,250			777,749
Income tax provision	457,803			477,375			295,545
Results of operations from oil and natural gas producing activities	$	731,296		$	778,875		$	482,204

Depletion, depreciation and amortization per BOE	$	18.69		$	16.42		$	15.82


(1)	Represents an allocation of the depletion, depreciation and amortization of our CO₂ properties and pipelines associated with our tertiary oil producing activities.

Oil and Natural Gas Reserves

Net proved oil and natural gas reserve estimates for all years presented were prepared by DeGolyer and MacNaughton, independent petroleum engineers located in Dallas, Texas. These 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. See Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves below for a discussion of the effect of the different prices on reserve quantities and values. Operating costs, production and ad valorem taxes, and future development costs were based on current costs.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. Moreover, the present values should not be construed as the current market value of our oil and natural gas reserves or the costs that would be incurred to obtain equivalent reserves. Estimates of reserves as of year-end 2012, 2011 and 2010 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the applicable fiscal 12-month period. All of our reserves are located in the United States.

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Notes to Consolidated Financial Statements

Estimated Quantities of Proved Reserves



	Year Ended December 31,
	2012						2011						2010
	Oil (MBbl)		Gas (MMcf)		Total (MBOE)		Oil (MBbl)		Gas (MMcf)		Total (MBOE)		Oil (MBbl)		Gas (MMcf)		Total (MBOE)
Balance at beginning of year	357,733		625,208		461,934		338,276		357,893		397,925		192,879		87,975		207,542
Revisions of previous estimates	(7,099	)	(16,720	)	(9,886	)	(4,478	)	(14,058	)	(6,821	)	3,538		16,171		6,233
Revisions due to price changes	(401	)	(37,969	)	(6,729	)	2,558		485		2,639		2,780		811		2,915
Extensions and discoveries	14,910		10,005		16,579		42,936		52,339		51,658		26,313		130,245		48,021
Improved recovery ⁽¹⁾	69,543		—		69,543		264		—		264		30,173		—		30,173
Production	(24,462	)	(10,654	)	(26,238	)	(22,169	)	(10,783	)	(23,966	)	(21,870	)	(28,491	)	(26,619	)
Acquisition of minerals in place	24,677		20,598		28,110		346		239,332		40,235		155,021		622,984		258,852
Sales of minerals in place	(105,777	)	(108,827	)	(123,915	)	—		—		—		(50,558	)	(471,802	)	(129,192	)
Balance at end of year	329,124		481,641		409,398		357,733		625,208		461,934		338,276		357,893		397,925

Proved Developed Reserves:
Balance at beginning of year	239,741		125,970		260,736		219,077		110,516		237,496		116,192		69,513		127,778
Balance at end of year	236,009		64,191		246,708		239,741		125,970		260,736		219,077		110,516		237,496

(1)

Improved recovery reflects reserve additions which result from the application of secondary recovery methods such as water flooding, or tertiary recovery methods such as CO₂ flooding. In order to recognize proved tertiary oil reserves, we must either have an oil production response to CO₂ injections or the field must be analogous to an existing tertiary flood. The magnitude of proved reserves that we can book in any given year will depend on our progress with new floods and the timing of the production response.

We added 114.2 MMBOE of estimated proved reserves during 2012, including tertiary reserves of 69.5 MMBbls, primarily at Hastings and Oyster Bayou fields, 25.9 MMBOE from the acquisition of interests in the Thompson, Webster and Hartzog Draw fields and 11.5 MMBOE from our Bakken area assets prior to their sale in the fourth quarter of 2012. These increases were offset by the disposition of 123.9 MMBOE of reserves associated with disposed properties, including our Bakken area assets, and non-core assets in the Gulf Coast region and Paradox Basin in Utah.

Acquisitions of minerals in place during 2011 were primarily related to the acquisition of the remaining interest in Riley Ridge. Extensions and discoveries primarily include proved undeveloped reserves and were added primarily through additional drilling in the Bakken.

Acquisitions of minerals in place during 2010 were primarily from the Encore Merger and the initial acquisition of interests at Riley Ridge. The sales of minerals in place during 2010 were primarily due to the sale of the non-strategic Encore properties and our ownership interests in ENP. Extensions and discoveries primarily include reserves added at our Bakken and Haynesville fields. We added 39.4 MMBbls of tertiary proved oil reserves during 2010, primarily initial proved tertiary oil reserves at Delhi Field, plus upward revisions to reserves in other tertiary floods.

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Notes to Consolidated Financial Statements

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves

The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves (“Standardized Measure”) does not purport to present the fair market value of our oil and natural gas properties. An estimate of such value should consider, among other factors, anticipated future prices of oil and natural gas, the probability of recoveries in excess of existing proved reserves, the value of probable reserves and acreage prospects, and perhaps different discount rates. It should be noted that estimates of reserve quantities, especially from new discoveries, are inherently imprecise and subject to substantial revision.

Under the Standardized Measure, future cash inflows were estimated by applying a first-day-of-the-month 12-month average price to the estimated future production of year-end proved reserves. The product prices used in calculating these reserves have varied widely during the three-year period. These prices have a significant impact on both the quantities and value of the proved reserves, as reductions in oil and natural gas prices can cause wells to reach the end of their economic life much sooner and can make certain proved undeveloped locations uneconomical, both of which reduce the reserves. The following representative oil and natural gas prices were used in the Standardized Measure. These prices were adjusted by field to arrive at the appropriate corporate net price.



	December 31,
	2012		2011		2010
Oil (NYMEX)	$	94.71	$	96.19	$	79.43
Natural Gas (Henry Hub)	2.85		4.16		4.40

Future cash inflows were reduced by estimated future production, development and abandonment costs based on current cost, with no escalation to determine pre-tax cash inflows. Our future net inflows do not include a reduction for cash previously expended on our capitalized CO₂ assets that will be consumed in the production of proved tertiary reserves. Future income taxes were computed by applying the statutory tax rate to the excess of net cash inflows over our tax basis in the associated proved oil and natural gas properties. Tax credits and net operating loss carryforwards were also considered in the future income tax calculation. Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure.



	December 31,
In thousands	2012			2011			2010
Future cash inflows	$	34,779,549		$	38,165,122		$	26,698,819
Future production costs	(13,114,740		)	(12,570,015		)	(9,702,896		)
Future development costs	(2,034,174		)	(3,026,898		)	(1,912,457		)
Future income taxes	(6,672,857		)	(7,379,972		)	(4,700,023		)
Future net cash flows	12,957,778			15,188,237			10,383,443
10% annual discount for estimated timing of cash flows	(6,543,398		)	(8,180,632		)	(5,465,516		)
Standardized measure of discounted future net cash flows	$	6,414,380		$	7,007,605		$	4,917,927

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Notes to Consolidated Financial Statements

The following table sets forth an analysis of changes in the Standardized Measure of Discounted Future Net Cash Flows from proved oil and natural gas reserves:



	Year Ended December 31,
In thousands	2012			2011			2010
Beginning of year	$	7,007,605		$	4,917,927		$	2,457,385
Sales of oil and natural gas produced, net of production costs	(1,673,253		)	(1,597,288		)	(1,177,322		)
Net changes in sales prices	(584,526		)	4,646,086			2,062,181
Extensions and discoveries, less applicable future development and production costs	291,558			762,370			295,074
Improved recovery ⁽¹⁾	1,901,109			15,708			623,622
Previously estimated development costs incurred	376,199			354,228			193,947
Revisions of previous estimates, including revised estimates of development costs, reserves and rates of production	(797,975		)	(1,673,283		)	(285,158		)
Accretion of discount	875,383			729,234			307,546
Acquisition of minerals in place	767,267			29,737			3,671,439
Sales of minerals in place	(1,805,309		)	—			(1,474,443		)
Net change in income taxes	56,322			(1,177,114		)	(1,756,344		)
End of year	$	6,414,380		$	7,007,605		$	4,917,927


(1)	Improved recovery additions result from the application of secondary recovery methods such as water flooding or tertiary recovery methods such as CO₂ flooding.

Note 15. Supplemental CO₂ and Helium Disclosures (Unaudited)

Based on engineering reports prepared by DeGolyer and MacNaughton, proved CO₂ reserves, and helium reserves associated with our helium production rights, were estimated as follows (in MMcf):



	Year Ended December 31,
	2012	2011	2010
CO₂ Reserves
Gulf Coast region ⁽¹⁾	6,073,175	6,685,412	7,085,131
Rocky Mountain region ⁽²⁾	3,495,534	2,195,534	2,189,756

Helium Reserves Associated with Denbury's Production Rights
Rocky Mountain region ⁽³⁾	12,712	12,004	7,159

(1)

Proved CO₂ reserves in the Gulf Coast region consist of reserves from our reservoirs at Jackson Dome and are presented on a gross working interest (8/8ths) basis, of which our net revenue interest was approximately 4.8 Tcf, 5.3 Tcf and 5.6 Tcf at December 31, 2012, 2011 and 2010, respectively, and include reserves dedicated to volumetric production payments of 57.1 Bcf, 84.7 Bcf and 100.2 Bcf at December 31, 2012, 2011 and 2010, respectively.


(2)	Proved CO₂ reserves in the Rocky Mountain region consist of our reserves at Riley Ridge (presented on a gross working interest (8/8ths) basis) and our overriding royalty interest in LaBarge Field, of which our net revenue interest was approximately 2.9 Tcf, 1.6 Tcf and 0.9 Tcf at December 31, 2012, 2011 and 2010, respectively.


(3)	Reserves associated with helium production rights include helium reserves located in acreage in the Rocky Mountain region for which we have the right to extract the helium. The U.S. government retains title to the helium reserves and we

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retain the right to extract and sell the helium on behalf of the government in exchange for a fee. The helium reserves are presented net of the fee we will remit to the U.S. government.

Note 16. Unaudited Quarterly Information



In thousands, except per share amounts	March 31			June 30			September 30			December 31
2012
Revenues and other income	$	645,116		$	601,781		$	600,371		$	609,204
Derivatives expense (income)	45,275			(139,109		)	61,631			27,369
Other expenses	420,529			398,089			399,361			386,470
Net income	113,467			211,865			85,367			114,661
Net income per share:
Basic	0.29			0.55			0.22			0.30
Diluted	0.29			0.54			0.22			0.30
Cash flow provided by operating activities	291,654			440,966			293,506			384,765
Cash flow used for investing activities	(288,883		)	(560,341		)	(388,748		)	(138,869		)
Cash flow provided by (used for) financing activities	55,902			70,122			91,163			(118,676		)

2011
Revenues and other income	$	514,165		$	601,397		$	576,505		$	617,257
Derivatives expense (income)	170,750			(172,904		)	(210,154		)	159,811
Other expenses	366,361			350,499			343,339			377,577
Net income (loss)	(14,190		)	259,246			275,670			52,607
Net income (loss) per share:
Basic	(0.04		)	0.65			0.69			0.14
Diluted	(0.04		)	0.64			0.68			0.13
Cash flow provided by operating activities	124,832			398,521			315,739			365,722
Cash flow used for investing activities	(285,043		)	(347,797		)	(525,412		)	(447,706		)
Cash flow provided by (used for) financing activities	(93,801		)	(56,789		)	112,244			76,314

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) was performed under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2012, to ensure: that information that is required to be disclosed in the reports the Company files and submits under the Securities Exchange Act of 1934 is recorded, that is processed, summarized and reported within the time periods specified in the SEC's rules and forms; and that information that is required to be disclosed under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Evaluation of Changes in Internal Control over Financial Reporting

Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we have determined that, during the fourth quarter of fiscal 2012, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management's Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this report based on the framework in “Internal Control—Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles.

The effectiveness of our internal control over financial reporting as of December 31, 2012, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in the report that appears herein.

Important Considerations

The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error, and the risk of fraud. Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time. Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management.

Item 9B. Other Information

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

Except as disclosed below, information as to Item 10 will be set forth in the Proxy Statement (“Proxy Statement”) for the Annual Meeting of Shareholders to be held May 22, 2013 (“Annual Meeting”) and is incorporated herein by reference.

Code of Ethics

We have adopted a Code of Ethics for Senior Financial Officers and the Principal Executive Officer. This Code of Ethics, including any amendments or waivers, is posted on our website at www.denbury.com.

Item 11. Executive Compensation

Information as to Item 11 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information as to Item 12 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Information as to Item 13 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.

Item 14. Principal Accountant Fees and Services

Information as to Item 14 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

Financial Statements and Schedules. Financial statements and schedules filed as a part of this report are presented on page 65. All financial statement schedules have been omitted because they are not applicable, or the required information is presented in the financial statements or the notes to consolidated financial statements.

Exhibits. The following exhibits are included as part of this report.



Exhibit No.		Exhibit
2(a)		Agreement and Plan of Merger, dated as of October 31, 2009, by and between Encore Acquisition Company and Denbury Resources Inc. (incorporated by reference to Exhibit 2.1 of Form 8-K filed by the Company on November 5, 2009, File No. 001-12935).
2(b)		Exchange Agreement, dated as of September 19, 2012, by and among Denbury Onshore, LLC, XTO Energy Inc., and Exxon Mobil Corporation (incorporated by reference to Exhibit 2.1 of Form 8-K filed by the Company on September 25, 2012, File No. 001-12935).
2(c)		Closing Agreement and Amendment, dated as of November 30, 2012, by and among Denbury Onshore, LLC, XTO Energy Inc., and Exxon Mobil Corporation (incorporated by reference to Exhibit 2.2 of Form 8-K filed by the Company on December 6, 2012, File No. 001-12935).
2(d)		Second Closing Agreement and Amendment, dated as of December 21, 2012, by and among Denbury Onshore, LLC, XTO Energy Inc., and Exxon Mobil Corporation (incorporated by reference to Exhibit 2.1 of Form 8-K filed by the Company on December 26, 2012, File No. 001-12935).
2(e)		Purchase and Sale Agreement, dated as of January 14, 2013, by and between Burlington Resources Oil & Gas Company LP and Denbury Onshore, LLC (incorporated by reference to Exhibit 2.1 of Form 8-K filed by the Company on January 15, 2013, File No. 001-12935).
3(a)		Second Restated Certificate of Incorporation of Denbury Resources Inc. filed with the Delaware Secretary of State on August 21, 2012 (incorporated by reference to Exhibit 3(a) of Form 10-Q filed by the Company on November 8, 2012, File No. 001-12935).
3(b)		Amended and Restated Bylaws of Denbury Resources Inc. as of May 15, 2012 (incorporated by reference to Exhibit 3.2 of Form 8-K filed by the Company on May 21, 2012, File No. 001-12935).
4(a)		Indenture for 9.75% Senior Subordinated Notes due 2016, dated as of February 13, 2009, by and among Denbury Resources Inc., certain of its subsidiaries, and The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.1 of Form 8-K filed by the Company on February 17, 2009, File No. 001-12935).
4(b)		First Supplemental Indenture for 9.75% Senior Subordinated Notes due 2016, dated as of June 30, 2009, by and among Denbury Resources Inc., certain of its subsidiaries, and The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4(h) of Form 10-K filed by the Company on March 1, 2010, File No. 001-12935).
4(c)**		9.75% Senior Subordinated Note due 2016 issued on June 30, 2009 to Gareth Roberts (incorporated by reference to Exhibit 10.2 of Form 8-K filed by the Company on July 7, 2009, File No. 001-12935).
4(d)		Second Supplemental Indenture for 9.75% Senior Subordinated Notes due 2016, dated as of March 9, 2010, by and among Denbury Resources Inc., certain of its subsidiaries, and The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.6 of Form 8-K filed by the Company on March 12, 2010, File No. 001-12935).

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Exhibit No.		Exhibit
4(e)		Third Supplemental Indenture for 9.75% Senior Subordinated Notes due 2016, dated as of February 3, 2011, by and among Denbury Resources Inc., certain of its subsidiaries, and The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4(p) of Form 10-K filed by the Company on March 1, 2011, File No. 001-12935).
4(f)		Indenture for 8¼% Senior Subordinated Notes due 2020, dated as of February 10, 2010, by and among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 of Form 8-K filed by the Company on February 12, 2010, File No. 001-12935).
4(g)		First Supplemental Indenture for 8¼% Senior Subordinated Notes due 2020, dated as of March 9, 2010, by and among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.7 of Form 8-K filed by the Company on March 12, 2010, File No. 001-12935).
4(h)		Second Supplemental Indenture for 8¼% Senior Subordinated Notes due 2020, dated as of February 3, 2011, by and among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4(s) of Form 10-K filed by the Company on March 1, 2011, File No. 001-12935).
4(i)		Indenture for 6.25% Senior Subordinated Notes Due 2014, dated as of April 2, 2004, by and among Encore Acquisition Company, certain of its subsidiaries, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1.1 of Form 8-K filed by the Company on March 12, 2010, File No. 001-12935).
4(j)		First Supplemental Indenture for 6.25% Senior Subordinated Notes Due 2014, dated as of January 2, 2008, by and among Encore Acquisition Company, certain of its subsidiaries, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1.2 of Form 8-K filed by the Company on March 12, 2010, File No. 001-12935).
4(k)		Second Supplemental Indenture for 6.25% Senior Subordinated Notes Due 2014, dated as of January 27, 2010, by and among Encore Acquisition Company, certain of its subsidiaries, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1.3 of Form 8-K filed by the Company on March 12, 2010, File No. 001-12935).
4(l)		Third Supplemental Indenture for 6.25% Senior Subordinated Notes Due 2014, dated as of March 10, 2010, by and among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1.4 of Form 8-K filed by the Company on March 12, 2010, File No. 001-12935).
4(m)		Fourth Supplemental Indenture for 6.25% Senior Subordinated Notes Due 2014, dated as of February 3, 2011, by and among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4(x) of Form 10-K filed by the Company on March 1, 2011, File No. 001-12935).
4(n)		Indenture for 6.0% Senior Subordinated Notes due 2015, dated as of July 13, 2005, by and among Encore Acquisition Company, certain of its subsidiaries, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2.1 of Form 8-K filed by the Company on March 12, 2010, File No. 001-12935).
4(o)		First Supplemental Indenture for 6.0% Senior Subordinated Notes due 2015, dated as of January 2, 2008, by and among Encore Acquisition Company, certain of its subsidiaries, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2.2 of Form 8-K filed by the Company on March 12, 2010, File No. 001-12935).

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Exhibit No.		Exhibit
4(p)		Second Supplemental Indenture for 6.0% Senior Subordinated Notes due 2015, dated as of January 27, 2010, by and among Encore Acquisition Company, certain of its subsidiaries, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2.3 of Form 8-K filed by the Company on March 12, 2010, File No. 001-12935).
4(q)		Third Supplemental Indenture for 6.0% Senior Subordinated Notes due 2015, dated as of March 10, 2010, by and among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2.4 of Form 8-K filed by the Company on March 12, 2010, File No. 001-12935).
4(r)		Fourth Supplemental Indenture for 6.0% Senior Subordinated Notes due 2015, dated as of February 3, 2011, by and among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4(cc) of Form 10-K filed by the Company on March 1, 2011, File No. 001-12935).
4(s)		Indenture for Subordinated Debt Securities, dated as of November 16, 2005, by and among Encore Acquisition Company, certain of its subsidiaries, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3.1 of Form 8-K filed by the Company on March 12, 2010, File No. 001-12935).
4(t)		First Supplemental Indenture for 7.25% Senior Subordinated Notes due 2017, dated as of November 23, 2005, by and among Encore Acquisition Company, certain of its subsidiaries, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3.2 of Form 8-K filed by the Company on March 12, 2010, File No. 001-12935).
4(u)		Second Supplemental Indenture for 7.25% Senior Subordinated Notes due 2017, dated as of January 2, 2008, by and among Encore Acquisition Company, certain of its subsidiaries, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3.3 of Form 8-K filed by the Company on March 12, 2010, File No. 001-12935).
4(v)		Third Supplemental Indenture for 9.5% Senior Subordinated Notes due 2016, dated as of April 27, 2009, by and among Encore Acquisition Company, certain of its subsidiaries, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3.4 of Form 8-K filed by the Company on March 12, 2010, File No. 001-12935).
4(w)		Fourth Supplemental Indenture for Senior Subordinated Notes, dated as of January 27, 2010, by and among Encore Acquisition Company, certain of its subsidiaries, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3.5 of Form 8-K filed by the Company on March 12, 2010, File No. 001-12935).
4(x)		Fifth Supplemental Indenture for Senior Subordinated Notes, dated as of March 10, 2010, by and among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3.6 of Form 8-K filed by the Company on March 12, 2010, File No. 001-12935).
4(y)		Sixth Supplemental Indenture for Senior Subordinated Notes, dated as of February 3, 2011, by and among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4(jj) of Form 10-K filed by the Company on March 1, 2011, File No. 001-12935).
4(z)		Seventh Supplemental Indenture for Senior Subordinated Notes, dated as of February 5, 2013, by and among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 of Form 8-K filed by the Company on February 5, 2013, File No. 001-12935).
4(aa)		Indenture for 6 3/8% Senior Subordinated Notes due 2021, dated as of February 17, 2011, by and among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank, National Association, as Trustee, (incorporated by reference to Exhibit 4.1 of Form 8-K filed by the Company on February 22, 2011, File No. 001-12935).

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Exhibit No.		Exhibit
4(bb)		Indenture for 4 5/8% Senior Subordinated Notes due 2023, dated as of February 5, 2013, by and among Denbury Resources Inc., certain of its subsidiaries, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 of Form 8-K filed by the Company on February 5, 2013, File No. 001-12935).
10(a)		Credit Agreement, dated as of March 9, 2010, by and among Denbury Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on March 12, 2010, File No. 001-12935).
10(b)		First Amendment to Credit Agreement, dated as of May 13, 2010, by and among Denbury Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on May 19, 2010, File No. 001-12935).
10(c)		Second Amendment to Credit Agreement, dated as of September 30, 2010, by and among Denbury Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto (incorporated by reference to Exhibit 10.1 of Form 10-Q filed by the Company on November 9, 2010, File No. 001-12935).
10(d)		Third Amendment to Credit Agreement, dated as of December 17, 2010, by and among Denbury Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto (incorporated by reference to Exhibit 10(d) of Form 10-K filed by the Company on March 1, 2011, File No. 001-12935).
10(e)		Fourth Amendment to Credit Agreement, dated as of February 1, 2011, by and among Denbury Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto (incorporated by reference to Exhibit 10(e) of Form 10-K filed by the Company on March 1, 2011, File No. 001-12935).
10(f)		Fifth Amendment to Credit Agreement, dated as of May 19, 2011, by and among Denbury Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto (incorporated by reference to Exhibit 99.1 of Form 8-K filed by the Company on May 20, 2011, File No. 001-12935).
10(g)		Sixth Amendment to Credit Agreement, dated as of September 1, 2011, by and among Denbury Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on September 8, 2011, File No. 001-12935).
10(h)		Seventh Amendment to Credit Agreement, dated as of April 11, 2012, by and among Denbury Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto (incorporated by reference to Exhibit 4(a) of Form 10-Q filed by the Company on May 10, 2012, File No. 001-12935).
10(i)		Eighth Amendment to Credit Agreement, dated as of July 26, 2012, by and among Denbury Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto (incorporated by reference to Exhibit 4(a) of Form 10-Q filed by the Company on August 8, 2012, File No. 001-12935).
10(j)		Ninth Amendment to Credit Agreement, dated as of November 2, 2012, by and among Denbury Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto (incorporated by reference to Exhibit 10(a) of Form 10-Q filed by the Company on November 8, 2012, File No. 001-12935).

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Exhibit No.		Exhibit
10(k)*		Tenth Amendment to Credit Agreement, dated as of January 18, 2013, by and among Denbury Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto.
10(l)		Pipeline Financing Lease Agreement, dated as of May 30, 2008, by and between Genesis NEJD Pipeline, LLC, as Lessor, and Denbury Onshore, LLC, as Lessee (incorporated by reference to Exhibit 99.1 of Form 8-K filed by the Company on June 5, 2008, File No. 001-12935).
10(m)		Transportation Services Agreement, dated as of May 30, 2008, by and between Genesis Free State Pipeline, LLC and Denbury Onshore, LLC (incorporated by reference to Exhibit 99.2 of Form 8-K filed by the Company on June 5, 2008, File No. 001-12935).
10(n)		Purchase and Sale Agreement, dated as of March 31, 2010, effective as of May 1, 2010, by and between Encore Operating, L.P., as Seller, and Quantum Resources Management, LLC, as Buyer (incorporated by reference to Exhibit 10.6 of Form 10-Q filed by the Company on May 10, 2010, File No. 001-12935).
10(o)**		Denbury Resources Inc. Amended and Restated Stock Option Plan, effective as of December 5, 2007 (incorporated by reference to Exhibit 99.2 of Form 8-K filed by the Company on December 11, 2007, File No. 001-12935).
10(p)**		Denbury Resources Inc. Amended and Restated Employee Stock Purchase Plan, effective as of December 5, 2007 (incorporated by reference to Exhibit 99.4 of Form 8-K filed by the Company on December 11, 2007, File No. 001-12935).
10(q)**		Denbury Resources Inc. Amendment to Amended and Restated Employee Stock Purchase Plan (incorporated by reference to Exhibit 4.2 of Registration Statement on Form S-8 filed by the Company on June 23, 2009, File No. 333-160178).
10(r)**		Denbury Resources Inc. Amendment to Amended and Restated Employee Stock Purchase Plan (incorporated by reference to Exhibit 4.2 of Post-Effective Amendment No. 1 to Form S-8 filed by the Company on September 9, 2009, File No. 333-160178).
10(s)**		Denbury Resources Inc. Amendment to Amended and Restated Employee Stock Purchase Plan, effective as of May 18, 2011 (incorporated by reference to Exhibit 4.1 of Registration Statement on Form S-8 filed by the Company on June 30, 2011, File No. 333-175273).
10(t)**		Form of Indemnification Agreement, dated as of July 28, 1999, by and between Denbury Resources Inc. and its officers and directors (incorporated by reference to Exhibit 10 of Form 10-Q filed by the Company on August 11, 1999, File No. 001-12935).
10(u)* **		Denbury Resources Inc. Director Deferred Compensation Plan, as amended and restated effective as of December 13, 2012.
10(v)* **		Denbury Resources Inc. Severance Protection Plan, as amended and restated effective as of December 13, 2012.
10(w)* **		Denbury Resources Inc. 2004 Omnibus Stock and Incentive Plan, as amended and restated on December 13, 2012.
10(x)**		2004 Form of Restricted Stock Award that vests on retirement for grants to officers pursuant to the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. (incorporated by reference to Exhibit 10(l) of Form 10-K filed by the Company on March 15, 2005, File No. 001-12935).

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Exhibit No.		Exhibit
10(y)**		2009 Form of Restricted Stock Award to certain officers that cliff vests on March 31, 2012, pursuant to the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. (incorporated by reference to Exhibit 10(b) of Form 10-Q filed by the Company on May 11, 2009, File No. 001-12935).
10(z)**		2009 Form of Restricted Stock Award without change of control vesting to certain officers that cliff vests on March 31, 2012, pursuant to the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. (incorporated by reference to Exhibit 10(c) of Form 10-Q filed by the Company on May 11, 2009, File No. 001-12935).
10(aa)**		2009 Form of Performance Stock Award to certain officers pursuant to the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. (incorporated by reference to Exhibit 10(d) of Form 10-Q filed by the Company on May 11, 2009, File No. 001-12935).
10(bb)**		2009 Form of Performance Stock Award without change of control vesting to certain officers pursuant to the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. (incorporated by reference to Exhibit 10(e) of Form 10-Q filed by the Company on May 11, 2009, File No. 001-12935).
10(cc)**		2009 Form of Stock Appreciation Rights Agreement to certain officers that cliff vests on March 31, 2012 pursuant to the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. (incorporated by reference to Exhibit 10(f) of Form 10-Q filed by the Company on May 11, 2009, File No. 001-12935).
10(dd)**		2009 Form of Stock Appreciation Rights Agreement without change of control vesting pursuant to the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. (incorporated by reference to Exhibit 10(g) of Form 10-Q filed by the Company on May 11, 2009, File No. 001-12935).
10(ee)**		2010 Form of Performance Stock Award pursuant to the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. (incorporated by reference to Exhibit 99.2 of Form 8-K filed by the Company on May 25, 2010, File No. 001-12935).
10(ff)**		2010 Form of Performance Cash Award pursuant to the 2004 Omnibus Stock and Incentive Plan for Denbury Resources Inc. (incorporated by reference to Exhibit 99.3 of Form 8-K filed by the Company on May 25, 2010, File No. 001-12935).
10(gg)**		Founder's Retirement Agreement, effective as of June 30, 2009, by and between Denbury Resources Inc. and Gareth Roberts (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on July 7, 2009, File No. 001-12935).
10(hh)**		Amendment to Founder's Retirement Agreement, effective as of October 6, 2010, by and between Denbury Resources Inc. and Gareth Roberts (incorporated by reference to Form 8-K filed by the Company on October 12, 2010, File No. 001-12935).
10(ii)**		2011 Form of Performance Stock Award pursuant to the 2004 Omnibus Stock and Incentive Plan (incorporated by reference to Exhibit 10(a) to Form 10-Q filed by the Company on May 10, 2011, File No. 001-12935).
10(jj)**		2011 Form of Performance Cash Award pursuant to the 2004 Omnibus Stock and Incentive Plan (incorporated by reference to Exhibit 10(b) to Form 10-Q filed by the Company on May 10, 2011, File No. 001-12935).
10(kk)**		Officer Resignation Agreement, effective as of October 7, 2011, by and between Denbury Resources Inc. and Ronald T. Evans (incorporated by reference to Exhibit 10.1 of Form 10-Q filed by the Company on November 8, 2011, File No. 001-12935).
10(ll)**		2012 Form of Performance Stock Award pursuant to the 2004 Omnibus Stock and Incentive Plan (incorporated by reference to Exhibit 10(a) of Form 10-Q filed by the Company on May 10, 2012, File No. 001-12935).

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Exhibit No.		Exhibit
10(mm)**		2012 Form of Performance Cash Award pursuant to the 2004 Omnibus Stock and Incentive Plan (incorporated by reference to Exhibit 10(b) of Form 10-Q filed by the Company on May 10, 2012, File No. 001-12935).
10(nn)**		2012 Form of TSR Performance Award pursuant to the 2004 Omnibus Stock and Incentive Plan (incorporated by reference to Exhibit 10(c) of Form 10-Q filed by the Company on May 10, 2012, File No. 001-12935).
21*		List of subsidiaries of Denbury Resources Inc.
23(a)*		Consent of PricewaterhouseCoopers LLP.
23(b)*		Consent of DeGolyer and MacNaughton.
31(a)*		Certification of Chief Executive Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002.
31(b)*		Certification of Chief Financial Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002.
32*		Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99*		The summary of DeGolyer and MacNaughton's Report as of December 31, 2012, on oil and gas reserves (SEC Case) dated January 31 2013.

* Included herewith.

** Compensation arrangements.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Denbury Resources Inc. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



		DENBURY RESOURCES INC.

February 28, 2013		/s/ Mark C. Allen
		Mark C. Allen Sr. Vice President and Chief Financial Officer

February 28, 2013		/s/ Alan Rhoades
		Alan Rhoades Vice President and Chief Accounting Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Denbury Resources Inc. and in the capacities and on the dates indicated.



February 28, 2013		/s/ Phil Rykhoek
		Phil Rykhoek Director, President and Chief Executive Officer (Principal Executive Officer)

February 28, 2013		/s/ Mark C. Allen
		Mark C. Allen Sr. Vice President and Chief Financial Officer (Principal Financial Officer)

February 28, 2013		/s/ Alan Rhoades
		Alan Rhoades Vice President and Chief Accounting Officer (Principal Accounting Officer)

February 28, 2013		/s/ Wieland Wettstein
		Wieland Wettstein Director

February 28, 2013		/s/ Michael Beatty
		Michael Beatty Director

February 28, 2013		/s/ Michael Decker
		Michael Decker Director

February 28, 2013		/s/ Ron Greene
		Ron Greene Director



February 28, 2013		/s/ Greg McMichael
		Greg McMichael Director

February 28, 2013		/s/ Kevin Meyers
		Kevin Meyers Director

February 28, 2013		/s/ Randy Stein
		Randy Stein Director

February 28, 2013		/s/ Laura Sugg
		Laura Sugg Director

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INDEX TO EXHIBITS



Exhibit No.		Exhibit
10(k)		Tenth Amendment to Credit Agreement, dated as of January 18, 2013, by and among Denbury Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the financial institutions party thereto.
10(u)		Denbury Resources Inc. Director Deferred Compensation Plan, as amended and restated effective as of December 13, 2012.
10(v)		Denbury Resources Inc. Severance Protection Plan, as amended and restated effective as of December 13, 2012.
10(w)		Denbury Resources Inc. 2004 Omnibus Stock and Incentive Plan, as amended and restated on December 13, 2012.
21		List of subsidiaries of Denbury Resources Inc.
23(a)		Consent of PricewaterhouseCoopers LLP.
23(b)		Consent of DeGolyer and MacNaughton.
31(a)		Certification of Chief Executive Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002.
31(b)		Certification of Chief Financial Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002.
32		Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99		The summary of DeGolyer and MacNaughton's Report as of December 31, 2012, on oil and gas reserves (SEC Case) dated January 31 2013.

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