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): August 5, 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 August 5, 2008, Denbury Resources Inc. issued a press release announcing its second 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 August 5, 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: August 5, 2008	By:	/s/ Phil Rykhoek
		Phil Rykhoek
		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 Second Quarter Results
29.8 MMBbls of Proved Reserves Added at Tinsley Field

News Release
Released at 7:30 AM CDT

     DALLAS, August 5, 2008 — Denbury Resources Inc. (NYSE symbol: DNR) (“Denbury” or the “Company”) today announced its second quarter 2008 financial and operating results. The Company posted quarterly earnings for the second quarter of 2008 of $114.1 million, or $0.47 per basic common share, 82% higher than second quarter 2007 net income of $62.6 million, or $0.26 per basic common share, and 56% higher than first quarter of 2008 net income of $73.0 million. The higher net income in the second quarter 2008 period was attributable to higher oil prices and higher production levels, partially offset by a $30.2 million ($18.8 million after tax) non-cash fair value charge on the Company’s derivative contracts, $28.6 million of net cash payments made on the same derivative contracts and higher overall expenses. Comparatively, in the second quarter of 2007, the Company recorded non-cash fair value income on derivative contracts of approximately $13.3 million ($8.1 million after tax), a delta of $43.5 million ($26.9 million after tax).

     The 2008 six month results also were significantly higher for similar reasons with net income of $187.1 million in the first half of 2008 as compared to $79.2 million in the first half of 2007.

     Adjusted cash flow from operations (cash flow from operations before changes in assets and liabilities, a non-GAAP measure) for the second quarter of 2008 was $259.1 million, an increase of 99% over second quarter 2007 adjusted cash flow from operations of $130.5 million. Net cash flow provided by operations, the GAAP measure, totaled $164.1 million during the second quarter of 2008, as compared to $102.3 million for the same measure during the second quarter of 2007. 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 46,305 BOE/d, a 25% increase over the second quarter of 2007 production after adjusting for production from our Louisiana natural gas properties sold in December 2007 and February 2008, and a 4% sequential increase over the first quarter of 2008 average production level. Oil production from the Company’s tertiary operations averaged 18,661 BOE/d, an increase of 36% over 2007’s second quarter tertiary production level of 13,683 BOE/d, and a 9% sequential increase over the first quarter of 2008 tertiary production level of 17,156 BOE/d. The Company had initial tertiary production from Tinsley Field (Phase III) during the second quarter of 2008, averaging 675 Bbls/d. As a result of this production response to CO₂ injections, the Company recorded proved reserves of approximately 29.8 million barrels

of oil (“MMBbls”) at Tinsley Field, approximately 75% of the anticipated ultimate tertiary reserves expected to be recovered from that field. As a result of the recognition of these proved reserves, as of June 30, 2008 on a PV10 proved reserve basis, Tinsley Field became the highest valued field in the Company. The majority of the remaining production increase in tertiary production over second quarter 2007 tertiary production levels came from the Company’s Phase II tertiary operations in Eastern Mississippi, which contributed approximately two-thirds of the comparative quarterly increase.

     Average production from the Barnett Shale increased 61% to 13,434 BOE/d in the second quarter of 2008 as compared to average production of 8,368 BOE/d for the second quarter of 2007, although as expected, Barnett Shale production was up only slightly on a sequential basis from levels in the fourth quarter of 2007 and first quarter of 2008. The Company is maintaining a steady drilling program of 45 to 50 wells per year, which is currently expected to maintain a relatively steady production level. The balance of the Company’s other production declined slightly from first quarter 2008 levels, as expected.

Second Quarter 2008 Financial Results

     Oil and natural gas revenues, excluding the impact of any derivative contracts, increased 90% between the respective second quarters as higher commodity prices increased revenue by 80% and higher production increased revenue by 10%. The Company paid $28.6 million on its derivative contract settlements in the second quarter of 2008 as compared to cash receipts of $1.7 million on derivative contracts during the second quarter of 2007. The Company incurred a $30.2 million non-cash fair value charge to earnings in the second quarter of 2008 on its derivative contracts as compared to a $13.3 million non-cash fair value gain in the second quarter of 2007, a delta of $43.5 million.

     Company-wide oil price differentials (Denbury’s net oil price received as compared to NYMEX prices) worsened during the second quarter of 2008 to one of the widest price spreads in the Company’s history, particularly on the heavier sour crudes and the Barnett Shale liquid production, averaging $9.64 per Bbl below NYMEX as compared to $6.50 per Bbl below NYMEX during the first quarter of 2008. Average oil price differentials during the current and prior quarter were both significantly worse than the $1.61 per Bbl average differential in the second quarter of 2007, as the Company’s oil 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 negative variance of $0.93 per Mcf in the second quarter of 2008, about the same as the negative variance of $0.90 per Mcf during the first quarter of 2008, but significantly higher than the positive variance of $0.07 per Mcf during the second quarter of 2007. This negative variance is partially due to increasing natural gas prices during the first half 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 less favorable if NYMEX natural gas prices increase throughout the quarter. Further, the sale of the Company’s Louisiana natural gas properties also contributed to a higher negative variance as the properties which were sold typically received above NYMEX pricing.

     Lease operating expenses increased between the comparable second quarters on both a per BOE basis and on an absolute dollar basis. Lease operating expenses averaged $18.23 per BOE in the second quarter of 2008, up from $15.00 per BOE in the second quarter of 2007, and an average of $16.15 per BOE during the first quarter of 2008. The increase over prior year’s second 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 of our new tertiary production facilities. Since over one-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, the higher commodity prices have caused a corresponding increase in tertiary operating cost per BOE. A significant portion of the increased cost on a per BOE basis also resulted from the sale of the Louisiana natural gas properties. If these sold properties were excluded from second quarter 2007 results, the Company’s operating costs during that period would have been approximately $1.17 per BOE higher than as reported, or $16.17 per BOE, more in line with the current quarter results.

     Historically, the Company expensed all costs associated with injecting CO₂ used in its tertiary operations. Beginning January 1, 2008, the Company began capitalizing injection costs in fields that have not yet seen an oil production response to the CO₂ injections, although after a production response occurs, all subsequent injection costs will be expensed. Had we continued with the prior accounting methodology of expensing all tertiary injection costs, we would have expensed an additional $2.9 million in the first quarter of 2008, or approximately $1.84 per BOE (tertiary properties only), as the Company had injection costs during the period in fields without production, primarily the two new tertiary floods at Tinsley and Lockhart Crossing Fields. During the second quarter of 2008, the Company would have expensed an additional $1.4 million or $0.85 per BOE (tertiary properties only) had we followed the Company’s prior year accounting methodology. The injection costs that the Company capitalized during the second quarter of 2008 were lower following the commencement of tertiary production at Tinsley Field in April. During the first half of 2007, the impact of this accounting methodology was not material as only $0.6 million would have been capitalized under the new accounting procedure.

     Production taxes and marketing expenses generally change in proportion to production volumes and commodity prices, the primary reason for the increase in the second quarter of 2008.

     General and administrative expenses increased 14% on a per BOE basis between the two second quarter periods, averaging $3.51 per BOE in the second quarter of 2008, up from $3.07 per BOE in the prior year’s second quarter. 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.

     The Company’s average debt level was 7% higher in the second quarter of 2008 as compared to debt levels in the second quarter of 2007. Because of the significant expenditures made during 2006 and 2007 on unevaluated properties, the Company capitalized $5.5 million of interest expense in the second quarter of 2008 related to these unevaluated properties (including CO₂ pipelines under construction), as compared to $4.3 million during the second quarter of 2007, more than offsetting the higher debt levels and reducing the Company’s overall interest expense between the two periods by 3%. The amount of interest capitalized during the second quarter of

2008 decreased by approximately $1.7 million as compared to the amount capitalized during the first quarter of 2008 as the Company discontinued its capitalization of interest at Tinsley Field following the commencement of tertiary production and recording of proved reserves at that field.

     Depletion, depreciation and amortization (“DD&A”) expenses increased $8.5 million (18%) in the second quarter of 2008 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 2008 was $11.53 per BOE, up from $10.94 per BOE in the prior year second quarter, and up slightly from the $11.00 per BOE rate during the first quarter of 2008. The recognition of 29.8 MMBbls of proven reserves at Tinsley Field did not materially change the DD&A rate as the aggregate of the previously unevaluated costs and future development costs for this field divided by the 29.8 MMBbls was about the same as the existing Company’s DD&A rate. The Company anticipates recognizing additional proven reserves at Tinsley over time which are expected to bring the average ultimate unit cost to less than $10 per barrel at that field.

Outlook

     The Company has reviewed and revised its entire tertiary production model taking into account such things as well and field response to date, and anticipated timing for goods and services in the current competitive operating environment. The revised production model will be posted today as part of the latest analyst presentation on the Company’s website (www.denbury.com). For 2008, the Company has lowered its anticipated tertiary production to 20,000 Bbls/d, a 35% increase over the 2007 average production, but down from its prior target of 22,000 Bbl/d. Correspondingly, the Company’s total production anticipated for 2008 was reduced from 49,000 BOE/d to 47,000 BOE/d, representing a 20% increase in production over the Company’s 2007 production levels after adjusting for the Louisiana property sale.

     The Company recently obtained approval from the Internal Revenue Service (“IRS”) to change its method of tax accounting for certain assets used in its tertiary oilfield recovery operations. Previously, the Company capitalized and depreciated these costs, but has obtained IRS approval to deduct these costs once the assets are placed into service. As a result, the Company expects to receive tax refunds of approximately $6.0 million through the 2007 tax year and has reduced its current income tax expense by $19 million in the second quarter of 2008 to adjust for the impact of this change through the first six months of 2008. The reduction in current income tax expense has been offset be a corresponding change to deferred income tax expense of approximately the same amount. Although this change is not expected to have a significant impact on the Company’s overall tax rate, it is anticipated that it will reduce the amount of cash taxes the Company expects to pay over the next several years. This acceleration of tax deductions and resultant lower current cash income taxes will likely change the overall economics of certain financing, re-capitalization type transactions the Company has historically utilized (see below).

     In order to fully take advantage of the change in tax accounting discussed above, the Company has discontinued its prior practice of leasing certain tertiary facility equipment. The discontinuance of these lease financing transactions will increase the Company’s 2008 capital budget by approximately $78 million, with the offset being a reduction of future lease operating expenses. Denbury’s revised 2008 development and exploration budget is approximately $1.0 billion, an increase of approximately $100 million, with approximately 75% of our revised budget

related to tertiary operations. Any acquisitions made by the Company would be in addition to these current capital budget amounts.

     The economic impact of the change in tax accounting will also likely affect certain types of future asset “drop-downs” to Genesis. Transactions which are not sales for tax purposes, such as the recent $175 million financing lease on the NEJD CO₂ pipeline, would not be affected, provided they meet other necessary tax structuring criteria. Those transactions which do constitute a sale for tax purposes, such as the recent $75 million sale and associated long-term transportation service agreement with Genesis on the Free State CO₂ pipeline, are likely to be discontinued.

     Denbury’s total debt (principal amount excluding capital and financing leases) as of July 31, 2008 was approximately $525 million, all of which is subordinated debt. In addition, the Company had approximately $150 million of excess cash as of that date.

     Gareth Roberts, Chief Executive Officer, said: “Our biggest tertiary flood to date, Tinsley Field (Phase III), is performing well in its initial stages, allowing us to recognize 29.8 MMBbls of proven reserves this quarter, about 75% of the reserves that we ultimately expect to recover from that field. Lockhart Crossing (Phase I) also commenced production very late in the quarter and is looking favorable. CO₂ injections have started at Cranfield (Phase IV), and we continue to work toward commencing floods at Heidelberg (Phase II) and Delhi (Phase V) in 2009 following completion of necessary pipelines, infrastructure and facilities. Recently, we have reviewed our results to date, applied what we have learned, and concluded that we needed to revise our production forecasts and model. The net result of our forecast revisions is to push the projected peak out one to two years, which has a minimal impact on our net present value. We have not changed our proved plus probable reserve forecasts as the overall program is working well. We have already produced over 23 million barrels of oil to date from our tertiary operations and anticipate recovering over 380 million barrels of additional oil from the fields that we currently own or have a contractual right to purchase (proved plus probable using the mid-points of ranges). We continue to pursue other sources of CO₂ from both our natural source at Jackson Dome and from potential anthropogenic sources. While the development of anthropogenic sources has been slower than we initially expected, we are confident that we can bridge the timing gap with incremental production and reserves from Jackson Dome and a portion of the capital budget increase from $900 million to $1.0 billion is dedicated to that purpose. Our program is working, our plans and strategy have not changed, we continue to be enthusiastic about the future and we continue to pursue potential expansion opportunities.”

Conference Call

     The public is invited to listen to the Company’s conference call set for today, August 5, 2008 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 888-203-1112 or 719-457-0820, passcode 2032184.

Financial and Statistical Data Tables

     Following are financial highlights for the comparative three and six month periods ended June 30, 2008 and 2007. 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
	2008		2007				Change
Revenues:
Oil sales		326,962		151,178		+		> 100	%
Natural gas sales		86,281		66,301		+		30	%
CO2 sales and transportation fees		3,383		3,394		-		0	%
Interest and other income		1,359		1,637		-		17	%
Total revenues		417,985		222,510		+		88	%
Expenses:
Lease operating expenses		76,825		57,207		+		34	%
Production taxes and marketing expense		20,530		10,386		+		98	%
CO2 operating expenses		453		1,204		-		62	%
General and administrative		14,811		11,694		+		27	%
Interest, net		8,141		8,356		-		3	%
Depletion and depreciation		54,733		46,235		+		18	%
Commodity derivative expense (income)		58,817		(15,049	)	+		> 100	%
Total expenses		234,310		120,033		+		95	%
Income before income taxes		183,675		102,477		+		79	%
Income tax provision
Current income taxes		10,844		7,343		+		48	%
Deferred income taxes		58,778		32,567		+		80	%
NET INCOME		114,053		62,567		+		82	%
Net income per common share (1):
Basic		0.47		0.26		+		81	%
Diluted		0.45		0.25		+		80	%
Weighted average common shares (1):
Basic		243,623		239,586		+		2	%
Diluted		252,401		249,537		+		1	%
Production (daily — net of royalties):
Oil (barrels)		31,332		26,172		+		20	%
Gas (mcf)		89,835		94,459		-		5	%
BOE (6:1)		46,305		41,916		+		10	%
Unit sales price (including derivative settlements):
Oil (per barrel)		110.42		63.01		+		75	%
Gas (per mcf)		8.54		8.04		+		6	%
BOE (6:1)		91.28		57.47		+		59	%
Unit sales price (excluding derivative settlements):
Oil (per barrel)		114.67		63.48		+		81	%
Gas (per mcf)		10.55		7.71		+		37	%
BOE (6:1)		98.07		57.02		+		72	%

	Three Months Ended
	June 30,							Percentage
	2008			2007				Change
Oil and gas derivative contracts
Cash receipt (payment) on settlements		(28,594	)		1,719		-		> 100	%
Non-cash fair value adjustment income (expense)		(30,223	)		13,330		-		> 100	%
Total income (expense) from contracts		(58,817	)		15,049		-		> 100	%
Non-GAAP financial measure (2)
Adjusted cash flow from operations (non-GAAP measure)		259,123			130,493		+		99	%
Net change in assets and liabilities relating to operations		(95,051	)		(28,241	)	+		> 100	%
Cash flow from operations (GAAP measure)		164,072			102,252		+		60	%
Oil & gas capital investments		144,656			167,813		-		14	%
CO2 capital investments		66,324			37,011		+		79	%
Proceeds from sales of properties		(5,196	)		5,835		-		> 100	%
BOE data (6:1)
Oil and natural gas revenues		98.07			57.02		+		72	%
Gain (loss) on settlements of derivative contracts		(6.79	)		0.45		-		> 100	%
Lease operating expenses		(18.23	)		(15.00	)	+		22	%
Production taxes and marketing expense		(4.87	)		(2.72	)	+		79	%
Production netback		68.18			39.75		+		72	%
Non-tertiary CO2 operating margin		0.70			0.57		+		23	%
General and administrative		(3.51	)		(3.07	)	+		14	%
Net cash interest expense and other income		(1.79	)		(1.65	)	+		8	%
Current income taxes and other		(2.08	)		(1.39	)	+		50	%
Changes in assets and liabilities relating to operations		(22.56	)		(7.40	)	+		> 100	%
Cash flow from operations		38.94			26.81		+		45	%

(1)	Adjusted for 2-for-1 stock split effective December 5, 2007
(2)	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
	2008		2007			Change
Revenues:
Oil sales		577,403		269,310	+		> 100	%
Natural gas sales		149,037		117,303	+		27	%
CO2 sales and transportation fees		6,234		6,485	-		4	%
Interest and other income		2,646		3,567	-		26	%
Total revenues		735,320		396,665	+		85	%
Expenses:
Lease operating expenses		142,826		107,764	+		33	%
Production taxes and marketing expense		37,266		20,590	+		81	%
CO2 operating expenses		1,596		1,907	-		16	%
General and administrative		30,816		23,128	+		33	%
Interest, net		13,082		14,431	-		9	%
Depletion and depreciation		104,572		87,262	+		20	%
Commodity derivative expense		105,598		11,858	+		> 100	%
Total expenses		435,756		266,940	+		63	%
Income before income taxes		299,564		129,725	+		> 100	%
Income tax provision
Current income taxes		32,080		8,961	+		> 100	%
Deferred income taxes		80,429		41,581	+		93	%
NET INCOME		187,055		79,183	+		> 100	%
Net income per common share (1):
Basic		0.77		0.33	+		> 100	%
Diluted		0.74		0.32	+		> 100	%
Weighted average common shares (1):
Basic		243,189		238,789	+		2	%
Diluted		252,603		249,459	+		1	%
Production (daily — net of royalties):
Oil (barrels)		30,748		25,119	+		22	%
Gas (mcf)		89,127		90,007	-		1	%
BOE (6:1)		45,602		40,120	+		14	%
Unit sales price (including derivative settlements):
Oil (per barrel)		99.69		59.02	+		69	%
Gas (per mcf)		8.13		7.87	+		3	%
BOE (6:1)		83.11		54.61	+		52	%
Unit sales price (excluding derivative settlements):
Oil (per barrel)		103.18		59.23	+		74	%
Gas (per mcf)		9.19		7.20	+		28	%
BOE (6:1)		87.53		53.24	+		64	%

	Six Months Ended
	June 30,							Percentage
	2008			2007				Change
Oil and gas derivative contracts
Cash receipt (payment) on settlements		(36,642	)		9,970		-		> 100	%
Non-cash fair value adjustment expense		(68,956	)		(21,828	)	+		> 100	%
Total expense from contracts		(105,598	)		(11,858	)	+		> 100	%
Non-GAAP financial measure (2)
Adjusted cash flow from operations (non-GAAP measure)		445,866			234,720		+		90	%
Net change in assets and liabilities relating to operations		(75,537	)		(39,123	)	+		93	%
Cash flow from operations (GAAP measure)		370,329			195,597		+		89	%
Oil & gas capital investments		301,360			345,969		-		13	%
CO2 capital investments		108,850			68,427		+		59	%
Proceeds from sales of properties		49,029			5,840		+		> 100	%
Cash and cash equivalents		147,009			32,577		+		> 100	%
Total assets		3,273,114			2,466,851		+		33	%
Total long-term debt (principal amount excluding capital leases and pipeline financings)		525,000			695,000		-		24	%
Financing leases		250,248			-				N/A
Total stockholders’ equity		1,624,668			1,210,992		+		34	%
BOE data (6:1)
Oil and natural gas revenues		87.53			53.24		+		64	%
Gain (loss) on settlements of derivative contracts		(4.42	)		1.37		-		> 100	%
Lease operating expenses		(17.21	)		(14.84	)	+		16	%
Production taxes and marketing expense		(4.49	)		(2.84	)	+		58	%
Production netback		61.41			36.93		+		66	%
Non-tertiary CO2 operating margin		0.56			0.63		-		11	%
General and administrative		(3.71	)		(3.18	)	+		17	%
Net cash interest expense and other income		(1.34	)		(1.43	)	-		6	%
Current income taxes and other		(3.20	)		(0.62	)	+		> 100	%
Changes in assets and liabilities relating to operations		(9.10	)		(5.39	)	+		69	%
Cash flow from operations		44.62			26.94		+		66	%

(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.

     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 significant operating acreage in the Barnett Shale play near Fort Worth, Texas, onshore Louisiana and Alabama, and properties in 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 2008 production levels relating to the Company’s tertiary operations and overall production, estimated capital expenditures for 2008 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:

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