Exhibit 99.1

DENBURY RESOURCES INC.
P R E S S R E L E A S E

Denbury Resources Announces Second Quarter Results
Tertiary Production Increases 7% Sequentially
10.9 MMBbls of Estimated Proved Reserves Added at Cranfield Field

News Release
Released at 7:30 AM CDT

     DALLAS, August 4, 2009 — Denbury Resources Inc. (NYSE symbol: DNR) (“Denbury” or the “Company”) today announced its second quarter 2009 financial and operating results. The Company posted a loss for the second quarter of 2009 of $87.2 million, or $0.35 per basic common share, as compared to net income of $114.1 million, or $0.47 per basic common share, in the comparative second quarter of 2008, the change primarily due to lower oil and natural gas commodity prices and a non-cash charge in the most recent quarter for the decrease in fair value of commodity derivative contracts. The current quarter results include a non-cash charge of $194.8 million ($120.8 million after taxes) for the change in fair value of the Company’s derivative commodity contracts, and a $10.0 million compensation charge ($6.2 million after tax) associated with the retirement of Gareth Roberts as CEO and President of the Company on June 30, 2009. Excluding these items, the Company’s adjusted net income (a non-GAAP measure) for the quarter would have been $39.7 million, or $0.16 per basic common share, as compared to $132.8 million, or $0.55 per share, earned in the prior year quarter, after adjusting for non-cash fair value commodity derivative charges of $30.2 million ($18.7 million after taxes) in the prior year period. (Please see the accompanying schedules for a reconciliation of net income, as defined by generally accepted accounting principles (GAAP), the GAAP measure, as opposed to adjusted net income excluding those items noted above, the non-GAAP measure).

     Adjusted cash flow from operations (cash flow from operations before changes in assets and liabilities, a non-GAAP measure) for the second quarter of 2009 was $108.2 million, a decrease of 58% from second quarter 2008 adjusted cash flow from operations of $259.1 million. Net cash flow provided by operations, the GAAP measure, totaled $148.2 million during the second quarter of 2009, as compared to $164.1 million for the same measure during 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 GAAP, which is the GAAP measure, as opposed to adjusted cash flow from operations, which is the non-GAAP measure).

Production

     Production for the second quarter of 2009 averaged 52,269 BOE/d, a 13% increase over second quarter 2008 production, but a 2% decrease from production levels in the first quarter of 2009. The sequential decrease was due primarily to the sale in the first quarter of 2009 of a significant inventory of natural gas liquids from the Barnett Shale, which had been produced but not sold during the third and fourth quarters of 2008 as a result of plant shutdowns caused by Hurricane Ike. The increase over the prior year second quarter period was primarily due to a 29% increase in tertiary oil production and production from Hastings Field which the Company acquired in February 2009 (2,189 BOE/d in the second quarter).

     During the second quarter of 2009 the Company’s tertiary production averaged 24,092 Bbls/d, which included 250 Bbls/d from tertiary production response at Heidelberg Field, a little earlier than anticipated. In addition, Tinsley, Eucutta and McComb Fields continued to have strong increases, averaging 3,402 Bbls/d, 4,145 Bbls/d and 2,429 Bbls/d, respectively. Although the Company’s tertiary production increased 1,509 Bbls/d (7%) between the first and second quarters of 2009, that increase was not enough to offset production decreases in the Company’s Barnett Shale production as discussed above and decreases in Mississippi non-tertiary production primarily due to anticipated declines in production from Heidelberg and Sharon Fields. Based on the tertiary production response at Cranfield Field, which averaged 338 Bbls/d during the second quarter of 2009, the Company recognized 10.9 million barrels of estimated proved reserves at Cranfield as of June 30, 2009.

Second Quarter 2009 Financial Results

     Oil and natural gas revenues, excluding the impact of any derivative contracts, decreased 49% between the respective second quarters as lower commodity prices decreased revenues by 62% and higher production offset a portion of that decrease, improving revenues by 13%. On a sequential basis, oil and natural gas revenues increased 26% between the first and second quarters of 2009, as higher commodity prices increased revenues by 27% and lower production decreased revenues by 1%.

     The Company received $42.0 million on its derivative contract settlements in the second quarter of 2009 as compared to cash payments of $28.6 million made on derivative contracts during the second quarter of 2008. During the first quarter of 2009, the Company collected $85.8 million on its derivative contracts. Almost all of the increase in revenues on a sequential basis between the first and second quarters of 2009 that was due to higher commodity prices, was offset by the reduction in cash receipts on the Company’s derivative contracts between the same two periods. Since approximately 80% of the Company’s 2009 oil production is hedged with a collar of $75 and $115 per barrel, fluctuations outside of that range have very little impact on cash flow.

     The Company recorded a $194.8 million non-cash fair value charge to earnings in the second quarter of 2009 on its commodity derivative contracts as compared to a $30.2 million charge in the second quarter of 2008. The Company also had a $106.4 million non-cash fair value charge to earnings in the first quarter of 2009 on its commodity derivative contracts.

     Company-wide oil price differentials (Denbury’s net oil price received as compared to NYMEX prices) were worse during the second quarter of 2009 than in the first quarter of 2009, averaging $5.30 per Bbl below NYMEX as compared to $3.99 below NYMEX during the first quarter of 2009, both significantly better than the differential during the second quarter of 2008, which averaged $9.64 below NYMEX. The lower differentials in the current year periods were primarily due to the lower oil prices during 2009.

     Lease operating expenses decreased between the comparable second quarters on a per BOE basis, but increased on an absolute dollar basis. Lease operating expense on a BOE basis averaged $17.59 per BOE in the second quarter of 2009, up from $15.59 per BOE in the first quarter of 2009, and

lower than the $18.23 per BOE incurred during the second quarter of 2008. The Company’s lease operating expenses on its tertiary properties averaged $20.86 per BOE during the second quarter of 2009, a slight increase from the $20.48 average per BOE in the first quarter of 2009, and a significant decrease from the prior year’s second quarter average of $24.67 per BOE. The decrease in per BOE tertiary operating costs from the prior year period levels is primarily due to lower CO₂ costs, which are partially tied to oil prices, and to reduced workover costs. The increase in per BOE tertiary operating costs from the first to second quarter in 2009 is primarily due to higher equipment rental charges resulting from additional operating equipment leases closed in the first half of 2009, the impact of new fields moving into the productive phase, and an increase in the cost of CO₂ as a result of higher oil prices during the second quarter.

     Production taxes and marketing expenses decreased during the second quarter of 2009 as compared to these costs in the prior year second quarter, generally due to the decrease in commodity prices.

     General and administrative expenses increased significantly between the first quarter of 2009 and second quarter of 2009, averaging $6.97 per BOE in the second quarter of 2009, up from $4.71 per BOE in the first quarter of 2009, and up from $3.51 per BOE in the second quarter of 2008. Included in the current quarter is a $10.0 million compensation charge associated with the retirement of Gareth Roberts as CEO and President of the Company on June 30, 2009, consisting of $3.65 million in cash compensation and $6.35 million of the Company’s 9.75% Senior Subordinated Notes due 2016. Also included in general and administrative expense during the quarter is a $2.9 million charge related to incentive compensation awards for the management of Genesis, up slightly from the $2.6 million recognized in the first quarter of 2009, the first period following the award grant in December 2008. On a per BOE basis, excluding the Founder’s Retirement Agreement charge and the incentive compensation for Genesis management, the Company’s general and administrative costs were $4.25 per BOE for the second quarter of 2009, $4.17 per BOE for the first quarter of 2009 and $3.51 per BOE for the second quarter of 2008, with the majority of the increase in these per BOE amounts due primarily to increases in employee-related costs.

     Interest expense increased between the comparative second quarters and sequentially between the first and second quarters of 2009, as the Company’s average debt level was 95% higher in the second quarter of 2009 as compared to debt levels in the second quarter of 2008, and 20% higher than debt levels in the first quarter of 2009. The increase in our debt level is primarily a result of the $201 million Hastings Field acquisition in February 2009, coupled with incremental borrowings to fund other capital expenditures. Our average interest rate also increased compared to levels in the second quarter of 2008, due to the February 2009 issuance of $420 million of 9.75% Senior Subordinated Notes issued at a discount to yield 11.25%, and the two pipeline dropdown transactions with Genesis completed in the second quarter of 2008, which have a higher imputed rate of interest than the Company’s other debt outstanding at that time. Partially offsetting these higher interest charges were higher levels of capitalized interest during the second quarter of 2009, primarily associated with the Company’s construction of CO₂ pipelines. The Company capitalized $15.4 million of interest in the second quarter of 2009 as compared to $12.4 million in the first quarter of 2009 and $5.5 million in the second quarter of 2008.

     Depletion, depreciation and amortization (“DD&A”) expenses increased $7.0 million (13%) in the second quarter of 2009 as compared to DD&A in the prior year second quarter. The DD&A rate

on oil and natural gas properties in the second quarter of 2009 was $11.42 per BOE, up from $11.29 per BOE in the first quarter of 2009, but down from the prior year’s second quarter level of $11.53 per BOE. The recognition of 10.9 MMBbls of proved reserves at Cranfield Field and the sale of a portion of our Barnett Shale reserves did not significantly affect our DD&A rate in the second quarter.

     Current income taxes increased during the second quarter as a result of the Company’s sale of a portion of its Barnett Shale assets. In total, the Company currently expects to incur approximately $25 million in cash taxes associated with the sale of which $16 million was recorded in the second quarter of 2009, representative of the portion of the sale that was completed as of June 30, 2009. The remainder will be recorded in the third quarter of 2009 in conjunction with the portion of the sale completed in July 2009.

Outlook

     As previously announced, as a result of the sale of 60% of the Company’s Barnett Shale properties, the Company lowered its 2009 production guidance to an adjusted full year 2009 average of 47,500 BOE/d. The Company is reaffirming its tertiary production guidance of 24,500 Bbls/d for the same period, which represents a 26% increase over its 2008 average tertiary production level. Denbury’s 2009 capital budget remains at approximately $750 million, of which approximately 90% is related to tertiary operations, excluding the $201 million Hastings Field acquisition. Any acquisitions made by the Company would be in addition to these current capital budget amounts. At July 31, 2009, Denbury had $951 million of subordinated debt and effectively no bank debt.

     Phil Rykhoek, Chief Executive Officer, said: “Our tertiary production continues to grow and we remain on track to achieve our projected 2009 forecast of 24,500 Bbls/d for that production. Tertiary production averaged 24,092 Bbls/d this quarter, a 7% sequential increase over last quarter, with the most significant increase coming from Tinsley Field, supplemented by an earlier than expected production response at Heidelberg Field. Our tertiary operating expenses came in about as expected on a BOE basis, up only slightly from the prior quarter levels, with most of the sequential incremental cost attributable to an increase in equipment lease financing payments. This quarter we were also able to recognize an additional 10.9 MMBbls of estimated proved reserves at Cranfield, one of our newer tertiary floods which commenced production earlier this year. The next significant reserve additions will likely be at Delhi Field during 2010, a field at which we expect to commence CO₂ injections in the fourth quarter, with an initial oil production response expected around mid-year 2010.

     We have recently completed our sale of 60% of our interest in the Barnett Shale, using the proceeds to temporarily retire our bank debt in the near-term, giving us $750 million of currently available liquidity. We plan to use the net Barnett proceeds of approximately $235 million (after the incremental taxes) to increase our capital spending in our 2010 tertiary development program. We have not yet finalized our 2010 capital budget, but if prices remain at or above current levels, we would anticipate that it will be between $600 million and $800 million. Our focus next year will continue to be our tertiary operations, focusing on our tertiary oil fields and Jackson Dome, rather than CO₂ pipelines as is the case during 2009. As a result of the Barnett sale, we have become much more weighted towards oil, with oil representing over 80% of our production on a pro forma basis. We see this as an enviable position in our industry, given the higher price realizations and margins

that currently exist on oil versus natural gas. We look forward to the future and the continued expansion of our successful program.”

Conference Call

     The public is invited to listen to the Company’s conference call set for today, August 4, 2009 at 10:00 A.M. CDT. The call will be broadcast live over the Internet at our web site: www.denbury.com. If you are unable to participate during the live broadcast, the call will be archived on our web site for approximately 30 days and will also be available for playback for one week by dialing 877-344-7529, passcode 432278.

Financial and Statistical Data Tables

     Following are financial highlights for the comparative three and six month periods ended June 30, 2009 and 2008. All production volumes and dollars are expressed on a net revenue interest basis with gas volumes converted at 6:1.

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

	Three Months Ended
	June 30,					Percentage
	2009			2008		Change
Revenues:
Oil sales		188,170			326,962		-	42	%
Natural gas sales		23,382			86,281		-	73	%
CO2 sales and transportation fees		2,884			3,383		-	15	%
Interest income and other		2,956			1,359		+	> 100	%
Total revenues		217,392			417,985		-	48	%
Expenses:
Lease operating expenses		83,658			76,825		+	9	%
Production taxes and marketing expense		10,784			20,530		-	47	%
CO2 operating expenses		1,095			453		+	> 100	%
General and administrative		33,135			14,811		+	> 100	%
Interest, net		14,904			8,141		+	83	%
Depletion and depreciation		61,695			54,733		+	13	%
Commodity derivative expense		152,789			58,817		+	> 100	%
Total expenses		358,060			234,310		+	53	%
Income (loss) before income taxes		(140,668	)		183,675		-	> 100	%
Income tax provision (benefit)
Current income taxes		24,127			10,844		+	> 100	%
Deferred income taxes		(77,555	)		58,778		-	> 100	%
NET INCOME (LOSS)		(87,240	)		114,053		-	> 100	%
Net income (loss) per common share:
Basic		(0.35	)		0.47		-	> 100	%
Diluted		(0.35	)		0.45		-	> 100	%
Weighted average common shares:
Basic		246,084			243,623		+	1	%
Diluted		246,084			252,401		-	3	%
Production (daily - net of royalties):
Oil (barrels)		37,921			31,332		+	21	%
Gas (mcf)		86,088			89,835		-	4	%
BOE (6:1)		52,269			46,305		+	13	%
Unit sales price (including derivative settlements):
Oil (per barrel)		66.70			110.42		-	40	%
Gas (per mcf)		2.98			8.54		-	65	%
BOE (6:1)		53.31			91.28		-	42	%
Unit sales price (excluding derivative settlements):
Oil (per barrel)		54.53			114.67		-	52	%
Gas (per mcf)		2.98			10.55		-	72	%
BOE (6:1)		44.48			98.07		-	55	%

	Three Months Ended
	June 30,						Percentage
	2009			2008			Change
Oil and natural gas derivative contracts
Cash receipt (payment) on settlements		42,002			(28,594	)		+	> 100	%
Non-cash fair value adjustment expense		(194,791	)		(30,223	)		+	> 100	%
Total expense from contracts		(152,789	)		(58,817	)		+	> 100	%
Non-GAAP financial measure (1)
Net income (loss) (GAAP measure)		(87,240	)		114,053			-	> 100	%
Non-cash fair value charge on derivative contracts (net of taxes)		120,770			18,738			+	> 100	%
Founder’s retirement compensation (net of taxes)		6,200			—				N/A
Adjusted net income excluding non-cash fair value charge on derivative contracts and special charges (non-GAAP measure)		39,730			132,791			-	70	%
Non-GAAP financial measure (1)
Cash flow from operations (GAAP measure)		148,170			164,072			-	10	%
Net change in assets and liabilities relating to operations		(39,966	)		95,051			-	> 100	%
Adjusted cash flow from operations (non-GAAP measure)		108,204			259,123			-	58	%
Oil & natural gas capital investments		80,920			145,161			-	44	%
CO2 capital investments		204,673			62,209			+	> 100	%
Proceeds from sales of properties		221,730			(5,196	)		+	> 100	%
BOE data (6:1)
Oil and natural gas revenues		44.48			98.07			-	55	%
Gain (loss) on settlements of derivative contracts		8.83			(6.79	)		+	> 100	%
Lease operating expenses		(17.59	)		(18.23	)		-	4	%
Production taxes and marketing expense		(2.27	)		(4.87	)		-	53	%
Production netback		33.45			68.18			-	51	%
Non-tertiary CO2 operating margin		0.38			0.70			-	46	%
General and administrative		(6.97	)		(3.51	)		+	99	%
Net cash interest expense and other income		(2.52	)		(1.79	)		+	41	%
Current income taxes and other		(1.59	)		(2.08	)		-	24	%
Changes in assets and liabilities relating to operations		8.40			(22.56	)		-	> 100	%
Cash flow from operations		31.15			38.94			-	20	%

(1) See “Non-GAAP Measures” at the end of this report.

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

	Six Months Ended
	June 30,					Percentage
	2009			2008		Change
Revenues:
Oil sales		321,435			577,403		-	44	%
Natural gas sales		58,186			149,037		-	61	%
CO2 sales and transportation fees		6,049			6,234		-	3	%
Interest income and other		5,481			2,646		+	> 100	%
Total revenues		391,151			735,320		-	47	%
Expenses:
Lease operating expenses		158,608			142,826		+	11	%
Production taxes and marketing expense		19,976			37,266		-	46	%
CO2 operating expenses		2,395			1,596		+	50	%
General and administrative		55,790			30,816		+	81	%
Interest, net		27,101			13,082		+	> 100	%
Depletion and depreciation		123,620			104,572		+	18	%
Commodity derivative expense		173,304			105,598		+	64	%
Total expenses		560,794			435,756		+	29	%
Income (loss) before income taxes		(169,643	)		299,564		-	> 100	%
Income tax provision (benefit)
Current income taxes		24,300			32,080		-	24	%
Deferred income taxes		(88,406	)		80,429		-	> 100	%
NET INCOME (LOSS)		(105,537	)		187,055		-	> 100	%
Net income (loss) per common share:
Basic		(0.43	)		0.77		-	> 100	%
Diluted		(0.43	)		0.74		-	> 100	%
Weighted average common shares:
Basic		245,830			243,189		+	1	%
Diluted		245,830			252,603		-	3	%
Production (daily - net of royalties):
Oil (barrels)		37,781			30,748		+	23	%
Gas (mcf)		90,327			89,127		+	1	%
BOE (6:1)		52,836			45,602		+	16	%
Unit sales price (including derivative settlements):
Oil (per barrel)		65.70			99.69		-	34	%
Gas (per mcf)		3.56			8.13		-	56	%
BOE (6:1)		53.06			83.11		-	36	%
Unit sales price (excluding derivative settlements):
Oil (per barrel)		47.00			103.18		-	54	%
Gas (per mcf)		3.56			9.19		-	61	%
BOE (6:1)		39.70			87.53		-	55	%

	Six Months Ended
	June 30,						Percentage
	2009			2008			Change
Oil and natural gas derivative contracts
Cash receipt (payment) on settlements		127,838			(36,642	)		+	> 100	%
Non-cash fair value adjustment expense		(301,142	)		(68,956	)		+	> 100	%
Total expense from contracts		(173,304	)		(105,598	)		+	64	%
Non-GAAP financial measure (1)
Net income (loss) (GAAP measure)		(105,537	)		187,055			-	> 100	%
Non-cash fair value charge on derivative contracts (net of taxes)		186,708			42,753			+	> 100	%
Founder’s retirement compensation (net of taxes)		6,200			—				N/A
Adjusted net income excluding non-cash fair value charge on derivative contracts and special charges (non-GAAP measure)		87,371			229,808			-	62	%
Non-GAAP financial measure (1)
Cash flow from operations (GAAP measure)		260,789			370,329			-	30	%
Net change in assets and liabilities relating to operations		(9,425	)		75,537			-	> 100	%
Adjusted cash flow from operations (non-GAAP measure)		251,364			445,866			-	44	%
Oil & natural gas capital investments		412,252			306,011			+	35	%
CO2 capital investments		399,406			110,198			+	> 100	%
Proceeds from sales of properties		240,087			49,029			+	> 100	%
Cash and cash equivalents		59,959			147,009			-	59	%
Total assets		3,858,598			3,273,114			+	18	%
Total long-term debt (principal amount excluding capital leases and pipeline financings)		996,350			525,000			+	90	%
Financing leases		250,423			250,248			+	0	%
Total stockholders’ equity		1,754,935			1,624,668			+	8	%
BOE data (6:1)
Oil and natural gas revenues		39.70			87.53			-	55	%
Gain (loss) on settlements of derivative contracts		13.36			(4.42	)		+	> 100	%
Lease operating expenses		(16.59	)		(17.21	)		-	4	%
Production taxes and marketing expense		(2.09	)		(4.49	)		-	53	%
Production netback		34.38			61.41			-	44	%
Non-tertiary CO2 operating margin		0.38			0.56			-	32	%
General and administrative		(5.83	)		(3.71	)		+	57	%
Net cash interest expense and other income		(2.33	)		(1.34	)		+	74	%
Current income taxes and other		(0.32	)		(3.20	)		-	90	%
Changes in assets and liabilities relating to operations		0.99			(9.10	)		-	> 100	%
Cash flow from operations		27.27			44.62			-	39	%

(1) See “Non-GAAP Measures” at the end of this report.

Non-GAAP Measures

     Adjusted net income excluding the fair value charge on the Company’s derivative contracts and the Founder’s Retirement Award is a non-GAAP measure. This measure reflects net income without regard to the fair value adjustments on the Company’s derivative contracts or other special items. The Company believes that it is important to consider this measure separately as it is a better reflection of the ongoing comparable results of the Company, without regards to changes in the market value of the Company’s derivative contracts during the period or other special charges.

     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.

     Denbury Resources Inc. (www.denbury.com) is a growing independent oil and natural 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 interests in the Barnett Shale play near Fort Worth, Texas, and properties onshore in Louisiana, Alabama and Southeast Texas. The Company’s goal is to increase the value of acquired properties through tertiary recovery operations, combined with a combination of exploitation, drilling and proven engineering extraction practices.

     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 reserves, the Company’s potential reserves from its tertiary operations, forecasted 2009 production levels relating to the Company’s tertiary operations and overall production, estimated capital expenditures for 2009 or future years, 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:

Phil Rykhoek, CEO, 972-673-2000
Mark Allen, Senior VP and Chief Financial Officer, 972-673-2000
www.denbury.com