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 5, 2009

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 5, 2009, Denbury Resources Inc. issued a press release announcing its third quarter 2009 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 5, 2009

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 5, 2009	By:	/s/ Mark C. Allen
		Mark C. Allen
		Senior Vice President & Chief Financial Officer

EX-99.1

Exhibit 99.1

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

Denbury Resources Announces Third Quarter Results
Delta (Delhi) Pipeline Ready for Service

News Release
Released at 7:30 AM CST

     DALLAS, November 5, 2009 — Denbury Resources Inc. (NYSE symbol: DNR) (“Denbury” or the “Company”) today announced its third quarter 2009 financial and operating results. The Company posted net income for the third quarter of 2009 of $26.9 million, or $0.11 per basic common share, as compared to net income of $157.5 million, or $0.64 per basic common share, in the comparative third quarter of 2008. The reduction in net income between the periods is primarily due to lower oil and natural gas commodity prices coupled with reduced natural gas production due to the sale of 60% of the Company’s Barnett Shale natural gas assets in mid-2009, and a $108.4 million net decrease in the fair value changes in commodity derivative contracts in the comparative periods.

     The current quarter results include a non-cash charge of $22.3 million ($13.8 million after taxes) for the change in fair value of the Company’s commodity derivative contracts as compared to a non-cash gain of $86.1 million ($53.4 million after taxes) in the prior year period. Excluding these non-cash fair value adjustments, the Company’s adjusted net income (a non-GAAP measure) for the third quarter of 2009 would have been $40.7 million, or $0.16 per basic common share, as compared to $123.0 million, or $0.50 per basic common share, earned in the prior year quarter, after adjusting for that quarter’s non-cash fair value gain on commodity derivative contracts and a $30.4 million ($18.9 million after taxes) charge related to the cancelled Conroe Field acquisition in the prior year period. (Please see the accompanying schedules for a reconciliation of net income, as defined by generally accepted accounting principles (GAAP), 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 operating assets and liabilities, a non-GAAP measure) for the third quarter of 2009 was $134.3 million, a decrease of 36% from third quarter 2008 adjusted cash flow from operations of $211.2 million. Net cash flow provided by operations, the GAAP measure, totaled $142.9 million during the third quarter of 2009, as compared to $262.4 million during the third 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, as opposed to adjusted cash flow from operations, which is the non-GAAP measure).

Production

     Oil and natural gas production for the third quarter of 2009 averaged 42,659 BOE/d, a 10% increase from third quarter 2008 production, after adjusting for the 2009 sale of 60% of the Company’s Barnett Shale natural gas assets. The increase over the prior year third quarter period was primarily due to a 23% increase in tertiary oil production and production from Hastings Field (2,083 BOE/d in the current year quarter), which the Company acquired in February 2009, offset in part by the expected decrease in the

Company’s non-tertiary Mississippi production. The non-tertiary Mississippi production decline was primarily from the Selma Chalk natural gas production as a result of limited drilling activity there in 2009 and non-tertiary Heidelberg oil as additional areas of the field were shut-in in order to expand the tertiary flooding to those areas. On a sequential basis, the Company’s oil and natural gas production decreased 4%, primarily due to the decreases in non-tertiary Mississippi production offset in part by a slight increase in the Company’s tertiary production.

     During the third quarter of 2009, the Company’s tertiary production averaged 24,347 Bbls/d, which included 829 Bbls/d from tertiary production response at Heidelberg Field. During the quarter, the Company had strong production increases compared to the prior quarter, at Tinsley (averaging 3,558 Bbls/d, a 5% increase), Soso (averaging 2,813 Bbls/d, a 9% increase), Lockhart Crossing (averaging 882 Bbls/d, a 26% increase), and Cranfield (averaging 572 Bbls/d, a 69% increase). These increases were offset in part by planned downtime at Mallalieu Field for facility expansion during the quarter, and the Company also expanded its facilities at Tinsley Field, earlier than originally planned, reducing the production rate of growth at that field during the third quarter.

Third Quarter 2009 Financial Results

     Oil and natural gas revenues, excluding the impact of any derivative contracts, decreased 45% between the respective third quarters as lower commodity prices decreased revenues by 38% and lower production (primarily due to the sale of 60% of the Company’s Barnett Shale natural gas assets), decreased revenues by 7%. On a sequential basis, oil and natural gas revenues increased 5% between the second and third quarters of 2009, as higher commodity prices in the third quarter increased revenues by 22% and lower production decreased revenues by 17%.

     The Company received $18.5 million on its derivative contract settlements in the third quarter of 2009, as compared to cash payments of $24.1 million made on derivative contracts during the third quarter of 2008. During the first and second quarters of 2009, the Company collected $85.8 million and $42.0 million, respectively, on its derivative contracts. Approximately 80% of the Company’s 2009 oil production is hedged using a collar with a $75 floor and a $115 ceiling per barrel, therefore commodity price fluctuations outside of that range have very little impact on cash flow.

     The Company recorded a $22.3 million non-cash fair value charge to earnings in the third quarter of 2009 on its commodity derivative contracts as compared to an $86.1 million gain in the third quarter of 2008. The Company also had non-cash fair value charges of $106.4 million and $194.8 million during the first and second quarters of 2009, respectively, on its commodity derivative contracts.

     Company-wide oil price differentials (Denbury’s net oil price received as compared to NYMEX prices) improved during the third quarter of 2009 as compared to differentials in the second quarter of 2009, averaging $3.47 per Bbl below NYMEX as compared to $5.30 per Bbl below NYMEX during the second quarter of 2009, both significantly better than the differential during the third quarter of 2008, which averaged $6.06 per Bbl below NYMEX. The lower differential in the current quarter was primarily due to the reduced natural gas liquid production associated with the sold Barnett Shale properties which have a significantly higher differential to NYMEX.

     Lease operating expenses decreased 2% between the comparable third quarters on an absolute basis, but increased on a per BOE basis primarily due to the Barnett Shale property sale in mid-2009. Lease operating expenses averaged $21.22 per BOE in the third quarter of 2009, compared to $19.90 per BOE in the second quarter of 2009 and $22.88 per BOE in the third quarter of 2008 (both comparable amounts adjusted for the Barnett Shale property sale). The Company’s lease operating expenses on its tertiary properties averaged $23.14 per Bbl during the third quarter of 2009, lower than the prior year’s third quarter average of $26.81 per Bbl, but higher than the second quarter 2009 average of $20.86 per Bbl. The decrease in per barrel tertiary operating costs from the prior year period is primarily due to lower oil prices, which reduces the Company’s cost of CO₂. The increase in per BOE tertiary operating costs from the second to third quarter of 2009 is primarily due to an increase in workover expenses between the sequential periods, an increase in the cost of CO₂ as a result of higher oil prices during the third quarter, and incremental equipment leases.

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

     General and administrative expenses increased between the comparative third quarters of 2009 and 2008, averaging $6.12 per BOE in the third quarter of 2009, up from $3.55 per BOE in the third quarter of 2008. Our G&A costs increased $9.0 million from the prior year third quarter levels, due primarily to higher employee costs and to the expensing of approximately $3.6 million associated with our compensation arrangement with certain management of Genesis. In addition, the G&A costs per BOE increased in the third quarter of 2009 as a result of the Barnett Shale sale, which reduced overall production.

     Interest expense decreased in the third quarter of 2009 as compared to both the third quarter of 2008 and the second quarter of 2009. The decrease in interest expense between the respective third quarters is due to increased interest capitalization relating mainly to the Company’s CO₂ pipelines currently under construction, offset in part by higher average debt levels. Interest capitalization was $20.9 million during the third quarter of 2009, $15.5 million during the second quarter of 2009, and $6.7 million during the third quarter of 2008.

     Depletion, depreciation and amortization (“DD&A”) expenses decreased $2.8 million (5%) in the third quarter of 2009 as compared to DD&A in the prior year third quarter. The DD&A rate on oil and natural gas properties in the third quarter of 2009 was $11.66 per BOE, up from $11.42 per BOE in the second quarter of 2009, but down slightly from the prior year’s third quarter level of $11.69 per BOE.

     The Company recognized a current income tax benefit in the third quarter of 2009 and a slightly lower tax rate as a result of return to provision revisions and to the Company’s estimated taxes related to its Barnett Shale property sale completed in the second and third quarters of 2009.

Outlook

     In light of the recently announced acquisition of Encore Acquisition Company, the Company has entered into crude oil derivative contracts for the second half of 2010 and calendar 2011 as follows: 5,000 barrels per day during the third and fourth quarters of 2010 with a floor price of $70 per barrel and

an average ceiling price of $96.50 per barrel, and 25,000 barrels per day during 2011 with a floor price of $70 per barrel and an average ceiling price of $102.58 per barrel.

     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, and the Company is reaffirming this annual target. Also previously announced, as a result of a combination of minor factors, the Company reduced its 2009 tertiary production guidance by 1%, from 24,500 Bbls/d to 24,200 Bbls/d, which represents a 25% increase over its 2008 average tertiary production level. The Company’s tertiary production has continued to increase early in the fourth quarter and has averaged between 25,500 Bbls/d and 26,000 Bbls/d during the last two weeks of October 2009, on track to meet its revised annual target of 24,200 Bbls/d. The Company anticipates that its average 2010 tertiary production will be approximately 27,000 Bbls/d, a projected 12% increase over 2009 projected levels. The Company plans to give overall total Company production guidance for 2010 at its forthcoming analyst meeting on November 12^th and 13^th, as well as a 2010 capital budget. Excluding the $201 million Hastings Field acquisition, Denbury’s 2009 capital budget remains at approximately $750 million (excluding capitalized interest and assuming $100 million in equipment leases), of which approximately 90% is related to tertiary operations and over two-thirds for CO₂ pipelines. Any acquisitions made by the Company would be in addition to these current capital budget amounts. At October 31, 2009, Denbury had $951 million of subordinated debt and approximately $25 million of net bank debt.

     Phil Rykhoek, Chief Executive Officer, said: “While our tertiary production is slightly below target this quarter, the tertiary production response during October was strong, putting us on a path to end 2009 with 25% tertiary growth year over year. Our Gulf Coast tertiary program is working well, in-line with projections. We have completed our Delta Pipeline and expect to commence CO₂ injection at Delhi Field next week. First tertiary oil production from Delhi is anticipated around mid-year 2010 and we should be able to recognize proved reserves there before year-end 2010. Our Green Pipeline is on schedule for completion to Oyster Bayou Field during the first quarter of 2010 and is expected to be completed to Hastings Field by late next year. We should begin CO₂ injections at Oyster Bayou around mid-year 2010 with initial production response expected there in early 2011.”

     “For 2010, we expect our tertiary production to increase approximately 12% over 2009 projections, a strong increase considering the majority of our capital expenditures were on pipelines during this year. Although the precise numbers are not quite finalized, we expect to increase the spending on our tertiary fields significantly in 2010 and expect to reap the results of that investment in 2011, where tertiary production growth is expected to be toward the upper end of our range. Our goal is to prove-up some of our Jackson Dome probable reserves next year with the first of three planned wells scheduled to commence drilling early in the year. At our analyst meeting next week, we will discuss our 2010 plans in more detail.”

Conference Call

     The public is invited to listen to the Company’s conference call set for today, November 5, 2009 at 11:00 A.M. CST. The call will be broadcast live over the Internet at our website: 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 and will also be available for playback for one week by dialing 877-344-7529, passcode 434583.

Analyst Conferences

     Denbury will be hosting a conference for analysts and asset managers on November 12, 2009 in Jackson, Mississippi, with several of the Company’s senior management presenting specific operational and financial updates. The Company presentation will be webcast live on Denbury’s website, www.denbury.com, on November 12^th from 2:00 p.m. CST to approximately 5:00 p.m. CST, and will be archived and available on the same website for approximately 30 days following the conference. The slide presentation that will be used at the conference will be available on Denbury’s website on November 12^th, and will include updated operational and comparative financial data and an in-depth review of the Company’s significant properties. The presentations will be followed by a field trip on November 13^th to one of Denbury’s tertiary oil fields. Approximately 39 analysts and selected asset managers have signed up for the conference.

     Following the November 12^th conference, Denbury will also be hosting a summary conference for analysts and asset managers on November 16, 2009 in New York, and on November 18, 2009 in Boston, both from 8:00 a.m. EST until approximately 10:00 a.m. EST. Registration for the conferences is ongoing. For additional information, please contact Laurie Burkes at 972-673-2166 or laurie.burkes@denbury.com.

Financial and Statistical Data Tables

     Following are financial highlights for the comparative three and nine month periods ended September 30, 2009 and 2008. 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
	2009			2008				Change
Revenues:
Oil sales		208,128			321,965		–		35	%
Natural gas sales		13,193			80,143		–		84	%
CO2 sales and transportation fees		3,659			3,471		+		5	%
Interest income and other		2,269			4,675		–		51	%
Total revenues		227,249			410,254		–		45	%
Expenses:
Lease operating expenses		83,300			85,308		–		2	%
Production taxes and marketing expense		10,461			19,335		–		46	%
CO2 operating expenses		1,047			1,240		–		16	%
General and administrative		24,038			15,005		+		60	%
Interest, net		9,859			10,906		–		10	%
Depletion and depreciation		53,525			56,324		–		5	%
Commodity derivative expense (income)		3,757			(62,007	)	–		>100	%
Abandoned acquisition costs		—			30,426		–		100	%
Total expenses		185,987			156,537		+		19	%
Income before income taxes		41,262			253,717		–		84	%
Income tax provision (benefit)
Current income taxes		(6,160	)		12,689		–		>100	%
Deferred income taxes		20,537			83,480		–		75	%
NET INCOME		26,885			157,548		–		83	%
Net income per common share:
Basic		0.11			0.64		–		83	%
Diluted		0.11			0.63		–		83	%
Weighted average common shares:
Basic		246,795			244,426		+		1	%
Diluted		252,189			251,831		+		0	%
Production (daily — net of royalties):
Oil (barrels)		34,926			31,078		+		12	%
Gas (mcf)		46,399			89,009		–		48	%
BOE (6:1)		42,659			45,913		–		7	%
Unit sales price (including derivative settlements):
Oil (per barrel)		70.54			108.70		–		35	%
Gas (per mcf)		3.09			8.21		–		62	%
BOE (6:1)		61.11			89.50		–		32	%
Unit sales price (excluding derivative settlements):
Oil (per barrel)		64.77			112.61		–		42	%
Gas (per mcf)		3.09			9.79		–		68	%
BOE (6:1)		56.39			95.20		–		41	%

	Three Months Ended
	September 30,							Percentage
	2009			2008				Change
Oil and natural gas derivative contracts
Cash receipt (payment) on settlements		18,527			(24,072	)	–		>100	%
Non-cash fair value adjustment income (expense)		(22,284	)		86,079		–		>100	%
Total income (expense) from contracts		(3,757	)		62,007		–		>100	%
Non-GAAP financial measure (1)
Net income (GAAP measure)		26,885			157,548		–		83	%
Non-cash fair value adjustments on derivative contracts (net of taxes)		13,816			(53,369	)	–		>100	%
Abandoned acquisition costs (net of taxes)		—			18,864		–		100	%
Adjusted net income excluding certain items (non-GAAP measure)		40,701			123,043		–		67	%
Non-GAAP financial measure (1)
Cash flow from operations (GAAP measure)		142,945			262,442		–		46	%
Net change in assets and liabilities relating to operations		(8,635	)		(51,273	)	–		83	%
Adjusted cash flow from operations (non-GAAP measure)		134,310			211,169		–		36	%
Oil & natural gas capital investments (including acquisitions)		75,097			134,365		–		44	%
CO2 capital investments		144,130			101,719		+		42	%
Proceeds from sales of properties		63,363			(81	)	–		>100	%
BOE data (6:1)
Oil and natural gas revenues		56.39			95.20		–		41	%
Gain (loss) on settlements of derivative contracts		4.72			(5.70	)	–		>100	%
Lease operating expenses		(21.22	)		(20.20	)	+		5	%
Production taxes and marketing expense		(2.67	)		(4.58	)	–		42	%
Production netback		37.22			64.72		–		42	%
Non-tertiary CO2 operating margin		0.67			0.53		+		26	%
General and administrative		(6.12	)		(3.55	)	+		72	%
Net cash interest expense and other income		(1.89	)		(2.10	)	–		10	%
Abandoned acquisition costs		—			(7.20	)	–		100	%
Current income taxes and other		4.34			(2.41	)	–		>100	%
Changes in assets and liabilities relating to operations		2.20			12.14		–		82	%
Cash flow from operations		36.42			62.13		–		41	%

(1) 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
	2009			2008			Change
Revenues:
Oil sales		529,563			899,368	–		41	%
Natural gas sales		71,379			229,180	–		69	%
CO2 sales and transportation fees		9,708			9,705	+		0	%
Interest income and other		7,750			7,321	+		6	%
Total revenues		618,400			1,145,574	–		46	%
Expenses:
Lease operating expenses		241,908			228,134	+		6	%
Production taxes and marketing expense		30,437			56,601	–		46	%
CO2 operating expenses		3,442			2,836	+		21	%
General and administrative		79,828			45,821	+		74	%
Interest, net		36,960			23,988	+		54	%
Depletion and depreciation		177,145			160,896	+		10	%
Commodity derivative expense		177,061			43,591	+		>100	%
Abandoned acquisition costs		—			30,426	–		100	%
Total expenses		746,781			592,293	+		26	%
Income (loss) before income taxes		(128,381	)		553,281	–		>100	%
Income tax provision (benefit)
Current income taxes		18,140			44,769	–		59	%
Deferred income taxes		(67,869	)		163,909	–		>100	%
NET INCOME (LOSS)		(78,652	)		344,603	–		>100	%
Net income (loss) per common share:
Basic		(0.32	)		1.41	–		>100	%
Diluted		(0.32	)		1.36	–		>100	%
Weighted average common shares:
Basic		246,156			243,604	+		1	%
Diluted		246,156			252,708	–		3	%
Production (daily — net of royalties):
Oil (barrels)		36,819			30,859	+		19	%
Gas (mcf)		75,523			89,087	–		15	%
BOE (6:1)		49,406			45,707	+		8	%
Unit sales price (including derivative settlements):
Oil (per barrel)		67.25			102.74	–		35	%
Gas (per mcf)		3.46			8.16	–		58	%
BOE (6:1)		55.40			85.27	–		35	%
Unit sales price (excluding derivative settlements):
Oil (per barrel)		52.68			106.37	–		50	%
Gas (per mcf)		3.46			9.39	–		63	%
BOE (6:1)		44.55			90.11	–		51	%

	Nine Months Ended
	September 30,							Percentage
	2009			2008				Change
Oil and natural gas derivative contracts
Cash receipt (payment) on settlements		146,365			(60,714	)	–		>100	%
Non-cash fair value adjustment income (expense)		(323,426	)		17,123		–		>100	%
Total expense from contracts		(177,061	)		(43,591	)	+		>100	%
Non-GAAP financial measure (1)
Net income (loss) (GAAP measure)		(78,652	)		344,603		–		>100	%
Non-cash fair value adjustments on derivative contracts (net of taxes)		200,524			(10,616	)	–		>100	%
Founder’s retirement compensation (net of taxes)		6,200			—				N/A
Abandoned acquisition costs (net of taxes)		—			18,864		–		100	%
Adjusted net income excluding certain items (non-GAAP measure)		128,072			352,851		–		64	%
Non-GAAP financial measure (1)
Cash flow from operations (GAAP measure)		403,734			632,771		–		36	%
Net change in assets and liabilities relating to operations		(18,060	)		24,264		–		>100	%
Adjusted cash flow from operations (non-GAAP measure)		385,674			657,035		–		41	%
Oil & natural gas capital investments (including acquisitions)		487,349			440,376		+		11	%
CO2 capital investments		543,536			211,917		+		>100	%
Proceeds from sales of properties		303,450			48,948		+		>100	%
Cash and cash equivalents		21,689			175,310		–		88	%
Total assets		3,903,260			3,468,532		+		13	%
Total long-term debt (principal amount excluding capital leases and pipeline financings)		971,350			525,000		+		85	%
Financing leases		250,744			250,311		+		0	%
Total stockholder’s equity		1,790,659			1,787,985		+		0	%
BOE data (6:1)
Oil and natural gas revenues		44.55			90.11		–		51	%
Gain (loss) on settlements of derivative contracts		10.85			(4.84	)	–		>100	%
Lease operating expenses		(17.94	)		(18.22	)	–		2	%
Production taxes and marketing expense		(2.26	)		(4.52	)	–		50	%
Production netback		35.20			62.53		–		44	%
Non-tertiary CO2 operating margin		0.46			0.55		–		16	%
General and administrative		(5.92	)		(3.66	)	+		62	%
Net cash interest expense and other income		(2.21	)		(1.59	)	+		39	%
Abandoned acquisition costs		—			(2.43	)	–		100	%
Current income taxes and other		1.06			(2.93	)	–		>100	%
Changes in assets and liabilities relating to operations		1.34			(1.94	)	–		>100	%
Cash flow from operations		29.93			50.53		–		41	%

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

Non-GAAP Measures

     Adjusted net income excluding certain items 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 certain 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 regard to changes in the market value of the Company’s derivative contracts during the period or other certain items.

     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, along 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