Item 2. 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 contained herein and in our Form 10-K for the year ended December 31, 2008, along with Management's Discussion and Analysis of Financial Condition and Results of Operations contained in such Form 10-K. Any terms used but not defined in the following discussion have the same meaning given to them in the Form 10-K. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with "Risk Factors" under Item 1A. of this report, along with "Forward-Looking Information" at the end of this section for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.
Overview
We are a growing independent oil and natural gas company engaged in acquisition, development and exploration activities in the U.S. Gulf Coast region. We are the largest oil and natural gas producer in Mississippi, own the largest reserves of carbon dioxide ("CO2") used for tertiary oil recovery east of the Mississippi River, own significant operating acreage in the Barnett Shale play near Fort Worth, Texas, and properties in Southeast Texas. Our goal is to increase the value of acquired properties through a combination of exploitation, drilling, and proven engineering extraction processes, with our most significant emphasis relating to tertiary recovery operations. Our corporate headquarters are in Plano, Texas (a suburb of Dallas), and we have four primary field offices located in Laurel, Mississippi; McComb, Mississippi; Jackson, Mississippi; and Aledo, Texas.
Operating Highlights. During the first quarter of 2009 we recorded a net loss of $18.3 million, our first quarterly loss in ten years, as compared to net income of $73.0 million in the first quarter of 2008. Although we achieved record oil and natural gas production during the first quarter of 2009, lower commodity prices reduced our revenues by approximately $200.4 million, and we recorded a non-cash fair value charge on our derivative commodity contracts of $106.4 million (approximately $65.9 million after tax).
Our oil and natural gas production for the first quarter of 2009 averaged 53,408 BOE/d, a 19% increase over first quarter 2008 levels, and an 11% sequential increase over levels in the fourth quarter of 2008. Our production growth was primarily due to production increases in both our tertiary oil fields and the Barnett Shale, and the volumes added by the Hastings Field acquisition that we completed in early February 2009 (see "Purchase of Hastings Field" below). Our tertiary oil production averaged 22,583 BOE/d during the first quarter of 2009, a 32% increase over the 17,156 BOE/d average for tertiary production in the first quarter of 2008, and a 3% increase over the 21,874 BOE/d average during the fourth quarter of 2008. Production in the Barnett Shale increased to 14,932 BOE/d for the first quarter of 2009, compared to 12,801 BOE/d during the first quarter of 2008, a 17% increase year-over-year, due primarily to additional sales of natural gas liquids that were produced during the third and fourth quarters of 2008, but not sold until the first quarter of 2009 due to plant shutdowns caused by Hurricane Ike. The acquisition of Hastings Field added 1,562 BOE/d to our first quarter 2009 production average. (See "Results of Operations - Operating Results - Production" for further discussion on the changes in our production volumes).
Despite the increase in our oil and natural gas production volumes in the first quarter of 2009, our oil and natural gas revenues were 46% lower in the first quarter of 2009 than in the prior year first quarter, as our average price received on a per BOE basis was approximately 54% lower in the current year period. The commodity price volatility, which began during the second half of 2008, continued through the first quarter of 2009. NYMEX oil prices moved from $44.60 per barrel at December 31, 2008 to as low as $34.00 per barrel in mid-February, and up to $49.66 per barrel as of March 31, 2009. NYMEX natural gas prices have continued their downward trend, falling from $5.62 per Mcf at December 31, 2008 to $3.78 per Mcf as of March 31, 2009.
Cash settlements on our oil commodity derivative contracts, which are not included in our oil and natural gas revenues, were $85.8 million received in the first quarter of 2009, as compared to a cash payment of $8.0 million in the first quarter of 2008. The non-cash fair value adjustments associated with our derivative contracts resulted in a $106.4 million charge in the first quarter of 2009 versus $38.7 million in the 2008 period.

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DENBURY RESOURCES INC. Management's Discussion and Analysis of Financial Condition and Results of Operations Our lease operating expenses on a gross basis for the first quarter of 2009 were approximately 14% higher than in the first quarter of 2008, but approximately 6% lower than in the fourth quarter of 2008. On a per BOE basis, our lease operating expenses were approximately 3% lower than in the first quarter of 2008 and approximately 13% lower than in the fourth quarter of 2008. With the lower commodity price environment, we have focused our efforts on improving our operating efficiency. These efforts, along with the reduction in our cost of CO2 due to lower oil prices and higher production volumes, have resulted in lower per BOE lease operating costs in the first quarter of 2009. Our gross general and administrative costs were approximately $6.7 million (42%) higher than in the first quarter of 2008, due primarily to higher employee costs, and the expensing of $2.6 million associated with our compensation arrangement for certain management of Genesis (see further discussion below under "Results of Operations - Production Expenses" and "Results of Operations - General and Administrative Expenses"). Interest expense also increased in the first quarter of 2009 primarily due to higher average debt levels and a higher average cost of money (i.e. higher interest rates), partially offset by higher levels of capitalized interest during the first quarter of 2009.
Purchase of Hastings Field. On February 2, 2009, we closed the acquisition of Hastings Field located near Houston, Texas for approximately $201 million in cash. Hastings Field is a significant potential tertiary oil flood that we plan to flood with CO2 delivered from Jackson Dome using our Green Pipeline, which is currently under construction. We originally entered into an agreement in November 2006 with a subsidiary of Venoco, Inc., that gave us the option to purchase their interest in the Hastings Field. As consideration for the purchase option, we made total payments of $50 million which makes our aggregate purchase price $251 million. The seller retained a 2% override and reversionary interest of approximately 25% following payout, as defined in the purchase agreement. We plan to commence flooding the field with CO2beginning in 2011, after completion of our Green Pipeline and construction of field recycling facilities. Under the purchase agreement, we are required to make net capital expenditures in this field totaling $179 million over the next six years, including our first obligation of $26.8 million during 2010, and are committed to begin CO2 injections averaging 50 MMcf/d by the fourth quarter of 2012. Production from this field averaged 1,562 BOE/d during the first quarter of 2009, representing approximately two months of production.
We have recorded the acquisition of Hastings Field in accordance with SFAS No. 141(R), "Business Combinations," which became effective for acquisitions after December 31, 2008. Based on these new rules, we have allocated $107.0 million of the $248.2 million adjusted purchase price to proved properties, approximately $2.4 million to land, oilfield equipment and other related assets, and the remaining $138.7 million to goodwill. See further discussion on this acquisition in Note 2 to the Unaudited Condensed Consolidated Financial Statements.
Management Succession Plan. On February 5, 2009, our Board of Directors adopted a management succession plan under which our current executive officers will assume new roles on or about June 30, 2009. Gareth Roberts, the Company's founder, will relinquish his position as President and CEO and become Co-Chairman of the Board of Directors and will assume a non-officer role as the Company's Chief Strategist. Phil Rykhoek, currently Senior Vice President and Chief Financial Officer, will become CEO; Tracy Evans, currently Senior Vice President - Reservoir Engineering, will become President and Chief Operating Officer; and Mark Allen, currently Vice President and Chief Accounting Officer, will become Senior Vice President and Chief Financial Officer.
Subordinated Debt Issuance. On February 13, 2009, we issued $420 million of 9.75% Senior Subordinated Notes due 2016 (the "Notes"). The Notes were sold to the public at 92.816% of par, plus accrued interest from February 13, 2009, which equates to an effective yield to maturity of approximately 11.25% (before offering expenses). Interest on the Notes will be paid on March 1 and September 1 of each year, beginning September 1, 2009. The Notes will mature on March 1, 2016. We used the net proceeds from the offering of approximately $381.4 million to repay most of the then outstanding debt on our bank credit facility. Capital Resources and Liquidity
In a continuing effort to mitigate the effects of the deterioration in the capital markets and the steep decline in commodity prices which began during mid-2008, we have taken additional measures during the first quarter of 2009 to improve our liquidity. During February 2009, we issued $420 million of 9.75% Senior Subordination Notes, and in March 2009 we entered into additional commodity derivative contracts for 2010 and 2011 to protect our cash flow. We used the $381.4 million proceeds from the Notes issuance to repay the majority of our then outstanding bank debt, freeing up our credit line for future capital needs. The new commodity derivative contracts include crude oil swaps covering 25,000 Bbls/d during the first quarter of 2010 at a weighted average price of $51.85 per barrel, crude oil collars covering

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DENBURY RESOURCES INC. Management's Discussion and Analysis of Financial Condition and Results of Operations 25,000 Bbls/d during the second quarter of 2010 with a floor price of $50.00 per barrel and a weighted average ceiling price of $74.60 per barrel, natural gas swaps for calendar year 2010 covering 55,000 MMBtu/d at a weighted average price of $5.66 per MMBtu and natural gas swaps for calendar year 2011 covering 40,000 MMBtu/d at a weighted average price of $6.21 per MMBtu.
We currently estimate our 2009 capital spending will be approximately $750 million, plus $201 million for the already closed Hastings Field acquisition. Our current 2009 capital budget includes approximately $485 million relating to our CO2 pipelines, the majority of which will be spent on the Green Pipeline. The budget also assumes that we fund approximately $100 million of budgeted equipment purchases with operating leases, which is dependent upon securing acceptable financing. Through May 8, 2009, we have completed approximately $18 million of these leases, and expect to close on an additional $20 million around mid-year. If we do not enter into $100 million of operating leases during 2009, our capital expenditures would increase accordingly, and we would anticipate funding those additional capital expenditures with our bank credit line.
The 2009 budget incorporates significantly reduced spending in the Barnett Shale and in other conventional areas such as the Heidelberg Selma Chalk, and a slower development program for our tertiary operations. Based on our current cash flow projections using $50.00 per barrel for oil and $5.00 per Mcf for natural gas prices, and including the expected cash settlements on our 2009 oil derivative contracts, we anticipate our projected 2009 capital expenditures of approximately $750 million, plus our already closed $201 million Hastings acquisition could, in the aggregate, exceed projected cash flow by as much as $450 million to $550 million. We have funded a portion of this shortfall with the approximately $381.4 million of net proceeds from our February 2009 subordinated debt issuance, and anticipate funding the remainder of this shortfall under our bank credit line.
As part of our semi-annual bank review, on April 1, 2009 our borrowing base and commitment amount were reaffirmed at $1.0 billion and $750 million, respectively. The borrowing base represents the amount that can be borrowed from a credit standpoint while the commitment amount is the amount the banks have committed to fund pursuant to the terms of the credit agreement. We anticipate this credit line will be sufficient for our 2009 plans, and do not expect our bank credit line to be reduced by our banks unless commodity prices were to decrease significantly from current levels. Based on current projections, we expect to have a total bank debt balance by the end of 2009 of between $150 million and $250 million, leaving us $500 million to $600 million of availability on our $750 million commitment amount.
We may raise additional capital during 2009 if it is possible to do so in a reasonably economic manner. Such additional capital sources could include the sale or joint venture of assets, a volumetric production payment, additional operating leases, or other options that become available during the year. 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 2009, we have contracted for certain capital expenditures, including construction of most of the Green Pipeline already in progress and two drilling rigs, and therefore the portion of capital that we could eliminate without significant penalty is limited (refer to Management's Discussion and Analysis of Financial Condition and Results of Operation- "Off-Balance Sheet Arrangements - Commitments and Obligations" in our 2008 Form 10-K for further information regarding these commitments).
Based on our long-term models, we expect our future capital spending needs to be less in the future than they have been in recent years, excluding any potential acquisitions. Therefore, if commodity prices remain at current levels after 2009, we anticipate that we will be able to match our capital spending with our projected cash flow from operations to preserve our liquidity to the extent we deem necessary, although any such spending reductions would most likely lower our anticipated rate of production growth.

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DENBURY RESOURCES INC. Management's Discussion and Analysis of Financial Condition and Results of Operations Sources and Uses of Capital Resources Capital Expenditure Summary Three Months Ended March 31, Amounts in thousands 2009 2008 Oil and natural gas exploration and development Drilling $ 20,588 $ 67,291 Geological, geophysical and acreage 3,791 4,942 Facilities 52,964 44,342 Recompletions 16,940 33,744 Capitalized interest 4,042 5,983 Total oil and natural gas exploration and development expenditures 98,325 156,302 Oil and natural gas property acquisitions 199,163 402 Total oil and natural gas capital expenditures 297,488 156,704 CO2 capital expenditures CO2 pipelines 143,508 15,398 CO2 producing fields 11,816 25,845 Capitalized interest 8,331 1,283 Total CO2 capital expenditures 163,655 42,526 Total $ 461,143 $ 199,230

Our first quarter 2009 capital expenditures were funded with $112.6 million of cash flow from operations, $15.0 million of net bank borrowings and $381.4 million of proceeds from the February 2009 issuance of 9.75% Senior Subordinated Notes. Our first quarter 2008 capital expenditures were essentially funded with $206.3 million of cash flow from operations, as the $48.9 million of proceeds from the second closing on our Louisiana property sale was used to reduce bank debt by $39.0 million during the first quarter, with the balance of funds from the property sale primarily used to fund other assets. Off-Balance Sheet Arrangements
Commitments and Obligations
Our obligations that are not currently recorded on our balance sheet consist of our operating leases and various obligations for development and exploratory expenditures arising from purchase agreements, our capital expenditure program, or other transactions common to our industry. In addition, in order to recover our proved undeveloped reserves, we must also fund the associated future development costs as forecasted in our proved reserve reports. Our derivative contracts, which are recorded at fair value in our balance sheets, are discussed in Note 6 to the Unaudited Condensed Consolidated Financial Statements.
On February 2, 2009, we closed our $201 million purchase of Hastings Field. Under the agreement, we are required to make aggregate net cumulative capital expenditures in this field of approximately $179 million over the next six years cumulating as follows: $26.8 million by December 31, 2010, $71.5 million by December 31, 2011, $107.2 million by December 31, 2012, $142.9 million by December 31, 2013, and $178.7 million by December 31, 2014. If we fail to spend the required amounts by the due dates, we are required to make a cash payment equal to 10% of the cumulative shortfall at each applicable date. Further, we are committed to injecting at least an average of 50 MMcf/day of CO2 (total of purchased and recycled) in the West Hastings Unit for the 90 day period prior to January 1, 2013. If such injections do not occur, we must either (1) relinquish our rights to initiate (or continue) tertiary operations and reassign to Venoco all assets previously purchased for the value of such assets at that time based upon the discounted value of the field's proved reserves using a 20% discount rate, or (2) make an additional payment of $20 million in January 2013, less any payments made for failure to meet the capital spending requirements as of December 31, 2012, and a $30 million payment for each subsequent year (less amounts paid for capital expenditure shortfalls) until the CO2 injection rate in the Hastings Field equals or exceeds the minimum required injection rate.

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DENBURY RESOURCES INC. Management's Discussion and Analysis of Financial Condition and Results of Operations We currently have long-term commitments to purchase CO2 from seven proposed gasification plants, three of which are in the Gulf Coast region and four in the Midwest region (Illinois, Indiana and Kentucky). The Midwest plants are not only conditioned on the specific plants being constructed, but also upon Denbury contracting additional volumes of CO2for purchase in the general area of the proposed plants that would provide an acceptable economic return on the CO2 pipeline that we would need to construct to transport these volumes to our existing CO2 pipeline system. If all of these plants were to be built, these CO2 sources are currently anticipated to provide us with aggregate CO2volumes of 1.0 Bcf/d to 1.7 Bcf/d. Due to the current economic conditions, the earliest we would expect any plant to be completed and providing CO2 would be 2013, and there is some doubt as to whether they will be constructed at all. The base price of CO2 per Mcf from these CO2 sources varies by plant and location, but is generally higher than our most recent all-in cost of CO2 from our natural sources (Jackson Dome) using current oil prices. Prices for CO2 delivered from these projects are expected to be competitive with the cost of our natural CO2 after adjusting for our share of potential carbon emissions reduction credits using estimated futures prices of carbon emissions reduction credits. If all seven plants are built, the aggregate purchase obligation for this CO2 would be around $210 million per year, assuming a $50 per barrel oil price, before any potential savings from our share of carbon emissions reduction credits. All of the contracts have price adjustments that fluctuate based on the price of oil. Construction has not yet commenced on any of these plants, and their construction is contingent on the satisfactory resolution of various issues, including financing. While it is likely that not every plant currently under contract will be constructed, there are several other plants under consideration that could provide CO2to us that would either supplement or replace the CO2 volumes from the seven proposed plants that we currently have contracts with. We are having ongoing discussions with several of these other potential sources.
Neither the amounts nor the terms of any other commitments or contingent obligations have changed significantly, from the year-end amounts reflected in our 2008 Form 10-K filed in March 2009 other than as discussed above, including our February 2009 subordinated debt issuance discussed in "Overview - Subordinated Debt Issuance". Please refer to Management's Discussion and Analysis of Financial Condition and Results of Operations - "Off-Balance Sheet Arrangements - Commitments and Obligations" contained in our 2008 Form 10-K for further information regarding our commitments and obligations. Results of Operations
CO2 Operations
Our focus on CO2 operations is becoming an ever-increasing part of our business and operations. We believe that there are significant additional oil reserves and production that can be obtained through the use of CO2, and we have outlined certain of this potential in our annual report and other public disclosures. In addition to its long-term effect, our focus on these types of operations impacts certain trends in our current and near-term operating results. Please refer to "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the section entitled "CO2 Operations" contained in our 2008 Form 10-K for further information regarding these matters.
During 2009, we plan to drill one additional CO2 source well to further increase our production capacity and reserves. We estimate that we are currently capable of producing between 900 MMcf/d and 1 Bcf/d of CO2. During the first quarter of 2009, our CO2 production averaged 732 MMcf/d, as compared to an average of approximately 554 MMcf/d during the first quarter of 2008. We used 87% of this production, or 640 MMcf/d, in our tertiary operations during the first quarter of 2009, and sold the balance to our industrial customers or to Genesis pursuant to our volumetric production payments.
We spent approximately $0.14 per Mcf to produce our CO2 during the first quarter of 2009, lower than our 2008 first quarter average of $0.22 per Mcf, primarily due to reduced royalty expense as a result of lower oil prices (to which royalties are principally tied) during the first quarter of 2009. Our estimated total cost per thousand cubic feet of CO2 during the first quarter of 2009 was approximately $0.23, after inclusion of depreciation and amortization expense, also down from the 2008 first quarter average total cost of $0.30 per Mcf.

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DENBURY RESOURCES INC. Management's Discussion and Analysis of Financial Condition and Results of Operations In addition to our natural source of CO2 and the proposed gasification plants discussed above (see "Off-Balance Sheet Arrangements - Commitments and Obligations"), we have ongoing discussions with owners of existing plants of various types that emit CO2 and we may be able to purchase their volumes. In order to capture such volumes, we (or the plant owner) would need to install additional equipment, which include at a minimum, compression and dehydration facilities. Most of these existing plants emit relatively small volumes of CO2,generally less than the proposed gasification plants, but such volumes may still be attractive if the source is located near our Green Pipeline. The capture of CO2 could also be influenced by anticipated federal legislation, which could impose economic penalties for the emission of CO2. We believe that we are a likely purchaser of CO2produced in our area of operations because of the scale of our tertiary operations, our CO2 pipeline infrastructure, and our large natural source of CO2 (Jackson Dome), which can act as a swing CO2 source to balance CO2 supplies and demands.
The following table summarizes our tertiary oil production and tertiary lease operating expense per barrel for each quarter in 2008 and the first quarter of 2009.

Average Daily Production (BOE/d) First Second Third Fourth First Quarter Quarter Quarter Quarter Quarter Tertiary Oil Field 2008 2008 2008 2008 2009 Phase I: Brookhaven 2,638 2,714 2,772 3,178 3,451 Little Creek area 1,807 1,661 1,556 1,706 1,619 Mallalieu area 6,099 6,260 5,339 5,056 4,490 McComb area 1,632 1,818 2,061 2,092 2,246 Lockhart Crossing - - 182 555 607 Phase II: Martinville 793 715 736 1,213 1,118 Eucutta 2,699 2,933 3,262 3,538 3,813 Soso 1,488 1,885 2,358 2,704 2,705 Phase III: Tinsley - 675 1,518 1,832 2,390 Phase IV: Cranfield - - - - 144 Total tertiary oil production 17,156 18,661 19,784 21,874 22,583 Tertiary operating expense per Bbl $ 20.81 $ 24.67 $ 26.81 $ 21.86 $ 20.48

Oil production from our tertiary operations averaged 22,583 BOE/d in the first quarter of 2009, a 32% increase over our first quarter 2008 tertiary . . .