8-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 8-K

CURRENT REPORT PURSUANT
TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of earliest event reported): November 4, 2008

DENBURY RESOURCES INC.

(Exact name of Registrant as specified in its charter)

Delaware

(State or other jurisdiction
of incorporation or organization)

1-12935	20-0467835
(Commission File Number)	(I.R.S. Employer Identification No.)

5100 Tennyson Parkway
Suite 1200
Plano, Texas	75024
(Address of principal executive offices)	(Zip code)

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

N/A

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Section 2 — Financial Information

     Item 2.02. Results of Operations and Financial Condition

          On November 4, 2008, Denbury Resources Inc. issued a press release announcing its third quarter 2008 financial and operating results. A copy of the press release is attached as Exhibit 99.1 to this Current Report on Form 8-K.

          As provided in General Instruction B.2 to Form 8-K, the information furnished in this Item 2.02 and in Exhibit 99.1 hereto shall not be deemed “filed” for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, nor shall it be deemed incorporated by reference in any filing with the Securities and Exchange Commission, except as shall be expressly provided by specific reference in such filing.

Section 9 — Financial Statements and Exhibits

     Item 9.01. Financial Statements and Exhibits.

(a)	Financial Statements of Businesses Acquired.
	Not applicable.
(b)	Pro forma Financial Information.
	Not applicable.
(c)	Shell Company Transactions.
	Not applicable.
(d)	Exhibits.

               The following exhibits are furnished in accordance with the provisions of Item 601 of Regulation S-K:

Exhibit
Number	Description of Exhibit
99.1	Denbury Press Release, dated November 4, 2008

SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	Denbury Resources Inc.      (Registrant)
Date: November 4, 2008	By:	/s/ Phil Rykhoek
		Phil Rykhoek
		Senior Vice President & Chief Financial Officer

EX-99.1

Exhibit 99.1

DENBURY RESOURCES INC.
PRESS RELEASE

Denbury Resources Announces Third Quarter Results
Further Reductions to 2009 Capital Budget
Anticipates 23% Increase in 2009 Tertiary Oil Production

News Release
Released at 7:30 AM CDT

     DALLAS, November 4, 2008 — Denbury Resources Inc. (NYSE symbol: DNR) (“Denbury” or the “Company”) today announced its third quarter 2008 financial and operating results. The Company posted record quarterly earnings of $157.5 million, or $0.64 per basic common share, more than double third quarter 2007 net income of $68.0 million, or $0.28 per basic common share, and 38% higher than second quarter 2008 net income of $114.1 million. The sequential increase in quarterly net income between the second and third quarters of 2008 was primarily attributable to non-cash fair value adjustments on the Company’s commodity derivative contracts. As a result of declining commodity prices, during the third quarter of 2008 the Company recognized an $86.1 million ($53.5 million after tax) non-cash fair value gain on the Company’s derivative commodity contracts, partially offset by a $30.4 million charge relating to a forfeited deposit on the cancelled Conroe Field acquisition. Comparatively, during the second quarter of 2008, the Company recorded a non-cash fair value charge on derivative contracts of approximately $30.2 million ($18.8 million after tax), a net swing of $116.3 million ($72.3 million after tax) in derivative contract fair value adjustments between the two quarters without giving effect to the non-recurring charge of $30.4 million relating to the forfeited acquisition deposit.

     The results for the first nine months of 2008 were also significantly higher than those in the 2007 comparable period as higher product prices and higher production levels more than offset higher expenses and non-cash fair value adjustments, with net income of $344.6 million in the first nine months of 2008 as compared to $147.2 million of net income in the first nine months of 2007.

     Adjusted cash flow from operations (cash flow from operations before changes in assets and liabilities, a non-GAAP measure) for the third quarter of 2008 was $211.2 million, an increase of 27% over third quarter 2007 adjusted cash flow from operations of $166.8 million, but a decrease of 19% from the 2008 second quarter amount, the sequential reduction related to a combination of slightly lower commodity prices and higher expenses, including the $30.4 million charge associated with the forfeited acquisition deposit. Net cash flow provided by operations, the GAAP measure, totaled $262.4 million during the third quarter of 2008, as compared to $169.2 million for the same measure during the third quarter of 2007, and $164.1 million for the second quarter of 2008. Adjusted cash flow and cash flow from operations differ in that the latter measure includes the changes in receivables, accounts payable and accrued liabilities during the quarter. (Please see the accompanying schedules for a reconciliation of net cash flow provided by operations, as defined by generally accepted accounting principles (GAAP), which is the GAAP measure, as opposed to adjusted cash flow from operations, which is the non-GAAP measure).

Production

     Production for the quarter was 45,913 BOE/d, a 12% increase over third quarter 2007 production after adjusting the 2007 period to remove production from the Company’s Louisiana natural gas properties sold in December 2007 and February 2008, and a 2% sequential decrease when compared to second quarter of 2008 average production. Although there was minimal physical property damage from Hurricanes Gustav and Ike, the Company’s third quarter 2008 production was negatively impacted by the storms, reducing total Company production by approximately 1,250 BOE/d, of which approximately 550 Bbls/d related to the Company’s Phase I tertiary oil production. In spite of the deferred production, the Company’s oil production from tertiary operations increased to 19,784 Bbls/d, a 6% sequential increase over second quarter 2008 production levels and a 23% increase over third quarter 2007 production levels. Tertiary oil production from Tinsley Field (Phase III) continued to increase, averaging 1,518 Bbls/d during the third quarter of 2008, up from 675 Bbls/d during the second quarter of 2008. The majority of the remaining production increase came from two of the Company’s Phase II operations (Soso and Eucutta Fields), as the Phase I production declined slightly, primarily as a result of the hurricanes. The Company did see initial tertiary oil production from Lockhart Crossing Field in the third quarter, averaging 182 Bbls/d during the quarter, allowing the Company to record incremental proved reserves of approximately 4.2 million barrels of oil (“MMBbls”) at that field, approximately 75% of that field’s ultimate anticipated recoverable tertiary reserves.

     Average production from the Barnett Shale increased 23% to 12,339 BOE/d in the third quarter of 2008 as compared to average production of 10,063 BOE/d for the third quarter of 2007. Barnett Shale production was down 8% on a sequential basis from levels in the second quarter of 2008, as the Company deferred an estimated 650 BOE/d in the third quarter of 2008 as a result of the two hurricanes shutting down third-party pipelines and facilities in the Gulf Coast, which in turn required the Company to shut-in a significant portion of the Company’s Barnett Shale production for a period of time. Production from this area has been relatively steady during 2008 with the Company’s current drilling program of 45 to 50 wells per year.

Third Quarter 2008 Financial Results

     Oil and natural gas revenues, excluding the impact of any derivative contracts, increased 62% between the respective third quarters as a result of higher commodity prices. Sequentially, oil and gas revenues decreased 3% from second quarter of 2008 levels, corresponding to a similar decline in commodity prices. Excluding any adjustment for the sale of Louisiana properties and the deferred production relating to the 2008 hurricanes, the Company’s production levels were approximately the same in the comparable third quarters and in the second quarter of 2008. The Company paid $24.1 million on its derivative contract settlements in the third quarter of 2008 as compared to cash receipts of $9.4 million on derivative contracts during the third quarter of 2007.

     Company-wide oil price differentials (Denbury’s net oil price received as compared to NYMEX prices) improved during the third quarter of 2008, averaging $6.06 per Bbl below NYMEX as compared to $9.64 per Bbl below NYMEX during the second quarter of 2008. Average oil price differentials during the current and prior quarter were both significantly worse than the $2.91 per Bbl average differential in the third quarter of 2007, as the Company’s oil price differentials were unusually low during the first three quarters of last year due to anomalies in the crude oil markets during that time.

     The Company’s average NYMEX natural gas differential was a positive variance of $0.75 per Mcf in the third quarter of 2008, as compared to a negative variance of $0.10 per Mcf during the third quarter of 2007, both significantly better than the negative variance of $0.93 per Mcf during the second quarter of 2008. This positive variance is primarily due to decreasing natural gas prices during the third quarter of 2008. Since most of the Company’s natural gas is sold on an index price that is set near the first of each month and fixed for the entire month, variances become more favorable if NYMEX natural gas prices decrease throughout the quarter.

     Lease operating expenses increased between the comparable third quarters on both a per BOE basis and on an absolute dollar basis. Lease operating expenses averaged $20.20 per BOE in the third quarter of 2008, up from $14.10 per BOE in the third quarter of 2007, and an average of $18.23 per BOE during the second quarter of 2008. The increase over the prior year’s third quarter level was primarily a result of (i) the Company’s increasing emphasis on tertiary operations with their inherently higher operating costs, (ii) higher overall industry costs for services, equipment and personnel, and (iii) additional lease payments for certain equipment of which is part of the Company’s tertiary production facilities. Since approximately half of the Company’s tertiary operating expenses are for the cost of power and CO₂ which have a high degree of correlation with commodity prices, higher commodity prices have caused a corresponding increase in tertiary operating cost per BOE. A majority of the increase of third quarter 2008 costs over those in the second quarter of 2008 relates to an incremental $4.0 million in workover costs, primarily related to remedial well work to repair tubing in multiple wells at Eucutta Field. The sale of the Louisiana natural gas properties also caused an increase in per BOE expenses. If these Louisiana properties which were subsequently sold were excluded from third quarter 2007 results, the Company’s operating costs during that period would have been approximately $0.95 per BOE higher than as reported, or $15.05 per BOE, closer to more recent quarterly results.

     Production taxes and marketing expenses generally change in proportion to production volumes and commodity prices, the primary reason for the increase in these costs in the third quarter of 2008 over third quarter 2007 levels.

     General and administrative expenses increased 30% on a per BOE basis between the two third quarter periods, averaging $3.55 per BOE in the third quarter of 2008, up from $2.74 per BOE in the prior year’s third quarter, but about the same as the $3.51 per BOE level in the second quarter of 2008. The majority of the increase relates to higher personnel-related costs as a result of salary increases and continued growth in the Company’s total number of employees.

     Interest expense, net of capitalized interest, increased 26% from the prior year’s third quarter levels. The Company’s average debt level (including the financing leases with Genesis), was 6% higher in the third quarter of 2008 as compared to debt levels in the third quarter of 2007 and the average interest rate increased as a result of the two CO₂ pipeline financing lease transactions with Genesis in May 2008 which carry a higher imputed rate of interest. The higher rate of interest is partially offset by the cash distributions that the Company receives from Genesis, but these cash distributions from Genesis are not recognized in the Company’s income statement, but as an adjustment to the Company’s investment in Genesis. The higher interest expense was partially offset by an increased amount of capitalized interest, $6.7 million during the third quarter of 2008 as compared to $5.4 million in the third quarter of 2007, resulting from the

growing expenditures on certain of the Company’s CO₂ tertiary projects and pipelines and a higher average rate of interest.

     Depletion, depreciation and amortization (“DD&A”) expenses increased $3.5 million (7%) in the third quarter of 2008 as compared to DD&A in the prior year’s third quarter. The DD&A rate on oil and natural gas properties in the third quarter of 2008 was $11.69 per BOE, up from $11.43 per BOE in the prior year’s third quarter, and up slightly from the $11.53 per BOE rate incurred during the second quarter of 2008. The recognition of 29.8 MMBbls of proven tertiary reserves at Tinsley Field in the second quarter of 2008 and 4.2 MMBbls at Lockhart Crossing in the third quarter of 2008 did not materially change the DD&A rate as the aggregate amount of the previous unevaluated costs and future development costs for these fields divided by the incremental barrels was about the same as the Company’s DD&A rate prior to the recognition of these new reserves. The Company anticipates recognizing additional proved reserves at both tertiary fields over time, which is expected to bring down the average ultimate capital cost per barrel.

Outlook

     Adjusting for the deferred production relating to the two hurricanes, the Company’s third quarter production results were generally on track with its prior guidance. As such, the Company is leaving its prior guidance for 2008 unchanged, except for a slight adjustment to account for the deferred production, or an adjusted guidance of approximately 19,850 Bbls/d for estimated tertiary production and 46,650 BOE/d for the entire Company. The Company currently estimates that it will spend between $900 million and $950 million in 2008, less than its current budget of $1.0 billion, although a portion of the unused budget may be carried over into 2009.

     In early October, the Company announced its preliminary 2009 capital budget of $825 million, an amount that did not include the Barnett Shale (as it was presumed at that time that these properties would be sold), nor did it consider any possible carryover items from 2008. If such items were included, the total capital budget would be almost $1.0 billion. In light of the continued lack of liquidity in the capital markets, the Company has further revised its all inclusive 2009 capital expenditure budget downward by $250 million to $750 million. The revised 2009 capital budget retains approximately $485 million relating to the Company’s CO₂ pipelines, the majority of which is for the Green pipeline, and assumes the Company lease finances approximately $100 million of tertiary production facility expenditures, which is conditioned on obtaining acceptable lease financing terms. The revised 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 its tertiary operations. Based on this revised capital budget, the Company’s 2009 tertiary oil production is projected to be approximately 24,500 Bbls/d and the Company’s total production (including the Barnett Shale and the assumed purchase of Hastings Field effective February 1, 2009) is projected to be approximately 50,000 BOE/d, a projected increase of 23% for the Company’s tertiary oil production and a projected increase of 7% for the total Company production over estimated 2008 totals.

     Denbury’s total debt (principal amount excluding capital and financing leases) as of October 31, 2008 was approximately $525 million, all of which is subordinated debt maturing between 2013 and 2015. In addition, the Company had approximately $75 million of cash as of that date and its entire $750 million of availability on its currently unused bank credit line.

     Gareth Roberts, Chief Executive Officer, said: “We’re glad to report that our tertiary production is generally on track and by the end of October was producing almost 22,000 Bbls/d. Like most of our peers, we have scaled back our 2009 capital spending program in order to maintain a strong balance sheet, but unlike most, even with the scaled back spending, we are able to project a 23% increase in 2009 tertiary oil production. We are able to do this because much of our anticipated growth in tertiary production is expected to come as a result of capital spending in prior years.”

     “We continue to market our Barnett Shale properties but due to current market conditions, we have begun to make plans assuming that the properties will not be sold. As discussed above, we have significantly scaled back our projected Barnett Shale spending during 2009, which will cause our Barnett production to gradually decline during the year, but we desire to use the cash flow generated from those properties for our other needs. With the additional reductions in capital spending, the likely cash contribution from our Barnett Shale properties, and the decline in the projected purchase price of the Hastings Field (as a result of the reduced oil prices), we believe that we are well positioned to continue our business model, although at a reduced development pace due to commodity prices. Based on current commodity prices of $65.00 per Bbl and $6.50 per Mcf, we project that we will borrow between $400 million and $500 million by the end of 2009, far less than our availability under our bank credit line, a bank line that was increased in early October 2008 from $350 million to $750 million. Given that approximately 75% of our 2009 oil is hedged, we believe we can stay close to these projections even if prices further deteriorate, and we stand ready to further reduce 2009 expenditures should that be necessary. For 2010 and future years, we will adjust our capital spending as needed to match our cash inflows so as to maintain our liquidity, and even if prices decline further, we believe we can deliver recurring production growth in spite of the market conditions.”

Conference Call

     The public is invited to listen to the Company’s conference call broadcast live over the Internet today, November 4, 2008 at 10:00 a.m. CDT. Gareth Roberts, President and Chief Executive Officer, Phil Rykhoek, Senior Vice President and Chief Financial Officer, Bob Cornelius, Senior Vice President — Operations and Tracy Evans, Senior Vice President of Reservoir Engineering, will lead the call. The call may be accessed on the Company’s website at www.denbury.com. If you are unable to participate during the live broadcast, the call will be archived on our website for approximately 30 days. The audio portion of the call will also be available for playback by phone for one month after the call by dialing 877-660-6853 or 201-612-7415; account number passcode number 286 and conference ID passcode 299919 are both required for replay.

Financial and Statistical Data Tables

     Following are financial highlights for the comparative three and nine month periods ended September 30, 2008 and 2007. All production volumes and dollars are expressed on a net revenue interest basis with gas volumes converted at 6:1.

THIRD QUARTER FINANCIAL HIGHLIGHTS
(Amounts in thousands of U.S. dollars, except per share and unit data)
(Unaudited)

	Three Months Ended
	September 30,							Percentage
	2008			2007				Change
Revenues:
Oil sales		321,965			190,685		+		69	%
Natural gas sales		80,143			57,528		+		39	%
CO2 sales and transportation fees		3,471			3,594		-		3	%
Interest income and other		4,675			1,702		+		> 100	%
Total revenues		410,254			253,509		+		62	%
Expenses:
Lease operating expenses		85,308			59,323		+		44	%
Production taxes and marketing expense		19,335			12,676		+		53	%
CO2 operating expenses		1,240			1,304		-		5	%
General and administrative		15,005			11,541		+		30	%
Interest, net		10,906			8,628		+		26	%
Depletion and depreciation		56,324			52,797		+		7	%
Commodity derivative income		(62,007	)		(3,973	)	+		> 100	%
Abandoned acquisition costs		30,426			—		+		N/A
Total expenses		156,537			142,296		+		10	%
Income before income taxes		253,717			111,213		+		> 100	%
Income tax provision
Current income taxes		12,689			5,197		+		> 100	%
Deferred income taxes		83,480			38,028		+		> 100	%
NET INCOME		157,548			67,988		+		> 100	%
Net income per common share (1):
Basic		0.64			0.28		+		> 100	%
Diluted		0.63			0.27		+		> 100	%
Weighted average common shares (1):
Basic		244,426			240,867		+		1	%
Diluted		251,831			250,449		+		1	%
Production (daily — net of royalties):
Oil (barrels)		31,078			28,680		+		8	%
Gas (mcf)		89,009			102,239		-		13	%
BOE (6:1)		45,913			45,720		-		—
Unit sales price (including derivative settlements):
Oil (per barrel)		108.70			71.12		+		53	%
Gas (per mcf)		8.21			7.44		+		10	%
BOE (6:1)		89.50			61.25		+		46	%
Unit sales price (excluding derivative settlements):
Oil (per barrel)		112.61			72.27		+		56	%
Gas (per mcf)		9.79			6.12		+		60	%
BOE (6:1)		95.20			59.01		+		61	%

	Three Months Ended
	September 30,							Percentage
	2008			2007				Change
Oil and gas derivative contracts
Cash receipt (payment) on settlements		(24,072	)		9,414		-		> 100	%
Non-cash fair value adjustment income (expense)		86,079			(5,441	)	+		> 100	%
Total income from contracts		62,007			3,973		+		> 100	%
Non-GAAP financial measure (2)
Adjusted cash flow from operations (non-GAAP measure)		211,169			166,776		+		27	%
Net change in assets and liabilities relating to operations		51,273			2,438		+		> 100	%
Cash flow from operations (GAAP measure)		262,442			169,214		+		55	%
Oil & gas capital investments		138,773			168,853		-		18	%
CO2 capital investments		127,583			33,981		+		> 100	%
BOE data (6:1)
Oil and natural gas revenues		95.20			59.01		+		61	%
Gain (loss) on settlements of derivative contracts		(5.70	)		2.24		-		> 100	%
Lease operating expenses		(20.20	)		(14.10	)	+		43	%
Production taxes and marketing expense		(4.58	)		(3.01	)	+		52	%
Production netback		64.72			44.14		+		47	%
Non-tertiary CO2 operating margin		0.53			0.54		-		2	%
General and administrative		(3.55	)		(2.74	)	+		30	%
Net cash interest expense and other income		(2.10	)		(1.61	)	+		30	%
Abandoned acquisition costs		(7.20	)		—				N/A
Current income taxes and other		(2.41	)		(0.68	)	+		> 100	%
Changes in asset and liabilities relating to operations		12.14			0.58		+		> 100	%
Cash flow from operations		62.13			40.23		+		54	%

(1)	Adjusted for 2-for-1 stock split effective December 5, 2007.
(2)	See “Non-GAAP Measures” at the end of this report.

NINE MONTH FINANCIAL HIGHLIGHTS
(Amounts in thousands of U.S. dollars, except per share and unit data)
(Unaudited)

	Nine Months Ended
	September 30,					Percentage
	2008		2007			Change
Revenues:
Oil sales		899,368		459,995	+		96	%
Natural gas sales		229,180		174,831	+		31	%
CO2 sales and transportation fees		9,705		10,079	-		4	%
Interest income and other		7,321		5,269	+		39	%
Total revenues		1,145,574		650,174	+		76	%
Expenses:
Lease operating expenses		228,134		167,087	+		37	%
Production taxes and marketing expense		56,601		33,266	+		70	%
CO2 operating expenses		2,836		3,211	-		12	%
General and administrative		45,821		34,669	+		32	%
Interest, net		23,988		23,059	+		4	%
Depletion and depreciation		160,896		140,059	+		15	%
Commodity derivative expense		43,591		7,885	+		> 100	%
Abandoned acquisition costs		30,426		—			N/A
Total expenses		592,293		409,236	+		45	%
Income before income taxes		553,281		240,938	+		> 100	%
Income tax provision
Current income taxes		44,769		14,158	+		> 100	%
Deferred income taxes		163,909		79,609	+		> 100	%
NET INCOME		344,603		147,171	+		> 100	%
Net income per common share (1):
Basic		1.41		0.61	+		> 100	%
Diluted		1.36		0.59	+		> 100	%
Weighted average common shares (1):
Basic		243,604		239,489	+		2	%
Diluted		252,708		250,809	+		1	%
Production (daily — net of royalties):
Oil (barrels)		30,859		26,319	+		17	%
Gas (mcf)		89,087		94,129	-		5	%
BOE (6:1)		45,707		42,007	+		9	%
Unit sales price (including derivative settlements):
Oil (per barrel)		102.74		63.46	+		62	%
Gas (per mcf)		8.16		7.71	+		6	%
BOE (6:1)		85.27		57.05	+		49	%
Unit sales price (excluding derivative settlements):
Oil (per barrel)		106.37		64.02	+		66	%
Gas (per mcf)		9.39		6.80	+		38	%
BOE (6:1)		90.11		55.36	+		63	%

	Nine Months Ended
	September 30,							Percentage
	2008			2007				Change
Oil and gas derivative contracts
Cash receipt (payment) on settlements		(60,714	)		19,384		-		> 100	%
Non-cash fair value adjustment income (expense)		17,123			(27,269	)	+		> 100	%
Total expense from contracts		(43,591	)		(7,885	)	+		> 100	%
Non-GAAP financial measure: (2)
Adjusted cash flow from operations (non-GAAP measure)		657,035			401,496		+		64	%
Net change in assets and liabilities relating to operations		(24,264	)		(36,685	)	-		34	%
Cash flow from operations (GAAP measure)		632,771			364,811		+		73	%
Oil & gas capital investments		440,133			514,822		-		15	%
CO2 capital investments		236,433			102,408		+		> 100	%
Proceeds from sales of properties		48,948			5,967		+		> 100	%
Cash and cash equivalents		175,310			39,414		+		> 100	%
Total assets		3,468,532			2,674,364		+		30	%
Total long-term debt (principal amount excluding capital leases and pipeline financings)		525,000			755,000		-		30	%
Financing leases		250,311			—				N/A
Total stockholders’ equity		1,787,985			1,290,480		+		39	%
BOE data (6:1)
Oil and natural gas revenues		90.11			55.36		+		63	%
Gain (loss) on settlements of derivative contracts		(4.84	)		1.69		-		> 100	%
Lease operating expenses		(18.22	)		(14.57	)	+		25	%
Production taxes and marketing expense		(4.52	)		(2.90	)	+		56	%
Production netback		62.53			39.58		+		58	%
Non-tertiary CO2 operating margin		0.55			0.60		-		8	%
General and administrative		(3.66	)		(3.02	)	+		21	%
Net cash interest expense and other income		(1.59	)		(1.49	)	+		7	%
Abandoned acquisition costs		(2.43	)		—				N/A
Current income taxes and other		(2.93	)		(0.66	)	+		> 100	%
Changes in asset and liabilities relating to operations		(1.94	)		(3.20	)	-		39	%
Cash flow from operations		50.53			31.81		+		59	%

(1)	Adjusted for 2-for-1 stock split effective December 5, 2007.
(2)	See “Non-GAAP Measures” at the end of this report.

Non-GAAP Measures

     Adjusted cash flow from operations is a non-GAAP measure that represents cash flow provided by operations before changes in assets and liabilities, as summarized from the Company’s Consolidated Statements of Cash Flows. Adjusted cash flow from operations measures the cash flow earned or incurred from operating activities without regard to the collection or payment of associated receivables or payables. The Company believes that it is important to consider this measure separately, as it believes it can often be a better way to discuss changes in operating trends in its business caused by changes in production, prices, operating costs and so forth, without regard to whether the earned or incurred item was collected or paid during that period. Adjusted cash flow from operations is not a measure of financial performance

under GAAP and should not be considered as an alternative to cash flows from operations, investing, or financing activities, nor as a liquidity measure or indicator of cash flows. For a further discussion, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Operating Results” in the Company’s latest Form 10-Q or Form 10-K.

     Denbury Resources Inc. (www.denbury.com) is a growing independent oil and gas company. The Company is the largest oil and natural gas operator in Mississippi, owns the largest reserves of CO₂ used for tertiary oil recovery east of the Mississippi River, and holds significant operating acreage onshore Alabama, in the Barnett Shale play near Fort Worth, Texas, and properties in Southeast Texas. The Company’s goal is to increase the value of acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with its most significant emphasis relating to tertiary recovery operations.

     This press release, other than historical financial information, contains forward looking statements that involve risks and uncertainties including expected reserve quantities and values relating to the Company’s proved and probable reserves, the Company’s potential reserves from its tertiary operations, forecasted production levels relating to the Company’s tertiary operations and overall production levels, estimated capital expenditures for 2008 and 2009, pricing assumptions based on current and projected oil and natural gas prices, anticipated transactions, and other risks and uncertainties detailed in the Company’s filings with the Securities and Exchange Commission, including Denbury’s most recent reports on Form 10-K and Form 10-Q. These risks and uncertainties are incorporated by this reference as though fully set forth herein. These statements are based on engineering, geological, financial and operating assumptions that management believes are reasonable based on currently available information; however, management’s assumptions and the Company’s future performance are both subject to a wide range of business risks, and there is no assurance that these goals and projections can or will be met. Actual results may vary materially.

For further information contact:

Gareth Roberts, President and CEO, 972-673-2000
Phil Rykhoek, Sr. VP and Chief Financial Officer, 972-673-2000
www.denbury.com