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 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.

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 CO2 assets, we are able to more purely focus our attention on tertiary recovery operations. These acquired assets include:

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• 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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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 CO2 injections, 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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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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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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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.

. . .