Denbury Resources Inc. (NYSE: DNR) ("Denbury" or the "Company") today announced its second quarter 2011 financial and operating results.

The Company recognized net income during the second quarter of 2011 of $259.2 million, or $0.65 per basic common share, as compared to net income of $135.4 million, or $0.34 per basic common share, in the second quarter of 2010. Net income, as adjusted to exclude non-cash derivative gains and other non-cash or unusual items, was approximately $146.7 million, or $0.37 per basic common share, in the second quarter of 2011 versus $72.9 million, or $0.18 per basic common share, in the prior year second quarter. The primary non-cash item included in second quarter of 2011 and 2010 results was a $183.8 million ($114.0 million net of taxes) and $125.9 million ($78.0 million net of taxes), respectively, non-cash gain on the change in the fair value of derivatives.

See the accompanying schedules for a reconciliation of “net income” as defined by generally accepted accounting principles (“GAAP”) to the non-GAAP measure “adjusted net income.” The Company completed the acquisition of Encore on March 9, 2010; therefore, the operating results for the comparative first six months of 2010 only include amounts associated with Encore for the period from March 9, 2010 to June 30, 2010.

Adjusted cash flow from operations (cash flow from operations before changes in assets and liabilities, a non-GAAP measure) for the second quarter of 2011 was a Company quarterly record of $344.1 million, as compared to adjusted cash flow from operations of $240.9 million in the second quarter of 2010, with the increase due primarily to higher oil prices during the second quarter of 2011. Cash flow from operations, the GAAP measure, totaled $398.5 million during the second quarter of 2011, compared to $271.1 million during the second quarter of 2010. Adjusted cash flow from operations and cash flow from operations differ in that the latter measure includes the changes in receivables, accounts payable and accrued liabilities during the quarter (see the accompanying schedules for a reconciliation of the GAAP measure “net cash flow from operations,” to “adjusted cash flow from operations,” which is the non-GAAP measure discussed above). Net decreases in operating assets and liabilities of $54.5 million during the second quarter of 2011 were primarily due to increases in accounts payable and accrued liabilities, and an increase in oil and gas production payable due to higher oil prices.

Production

The Company’s oil and natural gas production averaged 64,919 barrels of oil equivalent per day (“BOE/d”) during the second quarter of 2011, a 2% increase compared to continuing production of 63,585 BOE/d during the second quarter of 2010, with continuing production in the 2010 period excluding 20,526 BOE/d of production from non-strategic Encore properties and our interests in Encore Energy Partners LP (“ENP”), both of which were sold between May and December 2010. The increase in continuing production is attributable to higher production from the Company’s Bakken and tertiary properties, partially offset by natural production declines at other non-tertiary properties.

Production from the Company’s tertiary operations increased 8% in the second quarter of 2011, averaging 30,771 barrels of oil per day (“Bbls/d”), as compared to 28,507 Bbls/d of average production in the second quarter of 2010. This increase in production was primarily due to production growth in response to continued expansion of the tertiary floods in Tinsley, Heidelberg and Delhi Fields. Offsetting these production gains were normal production declines in the Company’s mature tertiary fields. Second quarter 2011 average tertiary production was essentially flat with the 30,825 Bbls/d of tertiary production in the first quarter of 2011.

The Company’s Bakken area production for the second quarter of 2011 averaged 7,626 BOE/d, a 33% increase over first quarter 2011 Bakken production levels and a 69% increase over second quarter 2010 production levels there. The Company currently has five rigs operating in the Bakken, anticipates adding a sixth operated rig late in the third quarter or early fourth quarter of 2011 to test the Almond area, and plans to add a seventh rig by year-end. The Company completed approximately 16 operated wells in the Bakken during the first six months of 2011.

Review of Second Quarter 2011 Financial Results

The Company’s second quarter oil and natural gas revenues increased 21% as compared to revenues in the prior year second quarter, as significantly higher oil prices and improved oil price differentials increased revenues by 44% before offsets due to lower production levels related to the 2010 property sales, which decreased revenues by 23%. Oil and natural gas revenues per barrel of oil equivalent (“BOE”), excluding the impact of any derivative contracts, were 57% higher in the second quarter of 2011 than in the second quarter of 2010 ($100.06 per BOE as compared to $63.76 per BOE) due to the higher oil prices and a higher percentage of oil production. During the second quarter of 2011, 92% of the Company’s production was oil, as compared to 78% in the second quarter of 2010, primarily due to the properties sold during 2010, which had a higher percentage of natural gas production.

The Company recorded a $183.8 million non-cash fair value gain in the second quarter of 2011 on the change in fair value of its derivative contracts, as compared to a $125.9 million non-cash fair value gain on these contracts in the second quarter of 2010. The Company made cash payments of $10.9 million on its derivative contracts in the second quarter of 2011, as compared to cash receipts of $2.8 million during the second quarter of 2010.

During the second quarter of 2011, the Company’s oil price differentials (Denbury’s received net oil price compared to NYMEX West Texas Intermediate (“WTI”) prices) improved significantly, primarily due to the favorable price differential for crude oil sold under Light Louisiana Sweet (“LLS”) index pricing. Company-wide oil price differentials in the second quarter of 2011 were $3.72 per Bbl above NYMEX, as compared to an average negative differential of $4.13 per Bbl below NYMEX in the second quarter of 2010 and an average negative differential of $0.59 per Bbl during the first quarter of 2011. During the latter part of the first quarter, the LLS index price increased significantly more than NYMEX prices, causing the LLS to NYMEX differential to increase significantly, and it remained high throughout the second quarter. For the second quarter of 2011 this LLS differential averaged a positive $15.32 per barrel on a trade-month basis, as compared to a $9.28 positive differential in the first quarter of 2011 and a more typical $3.21 positive differential in the second quarter of 2010. It is uncertain how long the LLS differential will remain at this level. The Company currently sells approximately (a) 40% of its crude oil based on the LLS index price, although due to contract provisions it may not realize the full differential; (b) approximately 40% based on WTI prices; and (c) approximately 20% based on various other indexes, most of which also improved relative to WTI, but to a lesser degree.

Lease operating expenses decreased 1% on a per BOE basis sequentially, but increased 32% on a per BOE basis between the respective second quarters. The sequential decrease was primarily due to lower workover costs in the Company’s tertiary operations in the second quarter, as the first quarter included above-normal workover costs, primarily at Brookhaven Field. The overall increase on a per BOE basis between the respective second quarters was primarily due to the sale of non-strategic legacy Encore and ENP properties during 2010, which generally had a lower operating cost per BOE than Denbury’s tertiary operations and other legacy properties. Denbury’s tertiary operating expense decreased 8% on a per Bbl basis sequentially, averaging $23.35 per Bbl in the second quarter of 2011, as compared to $25.40 per Bbl in the first quarter of 2011, the savings primarily due to the aforementioned decrease in workover expenses. Tertiary operating expenses were higher than the $21.37 per Bbl in the prior-year second quarter, primarily due to higher workover costs and CO 2 costs, with the cost of CO 2 increasing due to higher oil prices and increased injection volumes. Production taxes and marketing expenses increased during the second quarter of 2011 as compared to second quarter 2010 levels, primarily as a result of higher oil prices.

General and administrative (“G&A”) expenses decreased 30% sequentially, totaling $30.9 million in the second quarter of 2011, as compared to $43.8 million in the first quarter of 2011, due primarily to lower compensation and employee-related costs and lower professional fees in the current quarter. The first quarter of 2011 included higher payroll tax burdens and 401(k) match associated with bonus payouts, the true-up of long-term incentive compensation estimates, incremental costs associated with relocating the Company’s headquarters and higher professional fees associated with year-end work. Current quarter G&A expenses totaling $30.9 million were approximately the same as the $31.2 million of these expenses in the prior-year second quarter. On a BOE basis, G&A expense was $5.23 per BOE in the second quarter of 2011, as compared to $4.07 in the prior year quarter. Lower production attributable to the 2010 sale of properties was the primary factor relating to the higher cost per BOE, as any cost savings as a result of the property sales were offset by other expenses, including compensation increases effective at the beginning of 2011 and incremental expense attributable to the legacy Encore office leases and the new Denbury headquarters.

During the second quarter of 2011, the amount of interest that the Company capitalized decreased from approximately $23.9 million in the second quarter of 2010 to approximately $13.2 million in the current quarter. The 45% decrease between the two quarters is primarily attributable to the partial completion of the Green Pipeline in June 2010 and completion of the final segment in December 2010, after which interest capitalization on that line ceased. Interest expense decreased between the respective second quarters as cash interest expense decreased due to lower average debt outstanding during the second quarter of 2011, partially offset by the reduction in capitalized interest. A significant portion of the incremental debt incurred in conjunction with the Encore merger was subsequently repaid during the second half of 2010 through the proceeds of the non-strategic asset sales.

Depletion, depreciation and amortization (“DD&A”) expense for the second quarter of 2011 was $17.52 per BOE as compared to $16.88 per BOE in the prior year quarter, the increase primarily due to the incremental capital expenditures in the Bakken, which carries a higher finding cost per barrel than the Company’s tertiary operations, and upward adjustments to future development costs to reflect cost inflation in the oil and gas industry. These increases were partially offset by the asset sales during 2010 noted above, the acquisition of Riley Ridge in 2010, and lower DD&A on our CO 2 assets due to the incremental CO 2 proved reserves recognized in 2010.

Increase in Proved Oil and Natural Gas Reserves

During the first six months of 2011, the Company added approximately 30.9 million barrels of oil equivalent (“MMBOE”) of proved reserves, replacing approximately 266% of what the Company produced during the period. These reserve additions include 28.1 MMBOE of estimated reserves at the Company’s Bakken properties, and other minor reserve revisions to the Company’s oil and gas properties. These additions do not include the approximately 250 Bcf of natural gas (41.7 MMBOE) associated with the Riley Ridge acquisition completed in August 2011, which is discussed below.

Completion of Acquisition of Remaining Riley Ridge Working Interest

On August 1, 2011, the Company completed the previously announced acquisition of the remaining 57.5% working interest in the Riley Ridge Federal Unit (“Riley Ridge”) and a 33% working interest in an additional 28,000 acres adjoining Riley Ridge. As a result of the transaction, Denbury became the operator of both projects.

Combining this acquisition with the interest in Riley Ridge that the Company acquired in October 2010, the Company estimates that its total ownership at Riley Ridge currently contains estimated proved reserves of 435 Bcf of natural gas, 15.5 Bcf of helium and 2.4 Tcf of CO 2. The adjacent 28,000 acres is estimated to contain additional probable reserves of 250 to 300 Bcf of natural gas, 9.5 to 11.5 Bcf of helium and 2.0 to 2.2 Tcf of CO 2, net to Denbury’s interest. The first production of natural gas and helium from Riley Ridge is expected to begin late in the fourth quarter of 2011, with initial production of CO 2 expected in four to five years following construction of both additional facilities to separate the CO 2 from the remaining gas stream, and a CO 2 pipeline to the field.

Outlook

As a result of revisions in the timing of anticipated tertiary oil production increases and delays due to weather in the Company’s Bakken operations, the Company is lowering its overall 2011 production guidance from a year-over-year growth rate of 8% to one of 5% (based on pro forma 2010 continuing production, adjusted to include legacy Encore production during the pre-acquisition period), which translates into a change in previous yearly guidance from 67,400 BOE/d to 65,600 BOE/d. This revised forecast includes an approximate 5% reduction to the Company’s 2011 tertiary production estimate from 32,500 Bbls/d to 31,000 Bbls/d, primarily due to slower than anticipated increases in near-term production at the Company’s Heidelberg and Tinsley Fields. This reduction in tertiary production is not anticipated to have any impact on the amount of oil ultimately recoverable. Additionally, the Company is reducing its 2011 estimated Bakken area production from an anticipated 8,700 BOE/d to 8,400 BOE/d due to weather delays during the first half of the year, which have impacted the schedule for drilling, completion and production of wells in this area. Although still preliminary, the Company expects to have significantly higher production growth in 2012 as a result of initial oil production expected at Hastings and Oyster Bayou, our two new tertiary floods, and further growth from accelerated drilling in the Bakken area.

The Company’s 2011 capital expenditure budget has been increased by $50.0 million to be spent developing the recent Riley Ridge acquisition, to $1.35 billion, excluding acquisitions.

Phil Rykhoek, Chief Executive Officer, said, “Our results underline the benefits of our being so heavily weighted toward oil in this commodity price environment, enabling us to report record quarterly cash flow from operations, even with lower than targeted production growth. Not only are we more than 90% oil-weighted, but we sell approximately 60% of our oil based on price indexes other than NYMEX WTI prices, resulting in our first ever positive NYMEX oil price differential on a total corporate basis. We expect production growth to accelerate in 2012, as our long-term projects to flood our two newest tertiary fields, Hastings and Oyster Bayou Fields, are on schedule, with anticipated initial oil production expected late this year and late in the first quarter of 2012, respectively, and our Bakken well results in the Cherry area, our largest acreage position, continue to exceed expectations. Although we would prefer that production increases from our various efforts would occur sooner rather than later, we are confident that any short-term production deferral will have little or no impact on our long-term value and reserve potential. We also took a significant step forward this month in the execution of our long-term strategy in the Rockies, as we acquired the remaining interest at Riley Ridge, which we believe gives us control of our own destiny through ownership of more than enough CO 2 for our existing tertiary assets in that region. We also anticipate that the combined operations at Riley Ridge will provide us with a less expensive source of CO 2 than we currently have at Jackson Dome, which was already one of the least expensive CO 2 sources in the industry. This month, we expect to commence construction of our first CO 2 pipeline in the Rockies, the initial phase of our development plans there, as we begin to replicate our Gulf Coast EOR strategy in that region. We are enthused how our profitable, repeatable strategy is working - we have a unique niche in the marketplace, and we are excited to be there."

Conference Call

The public is invited to listen to the Company’s conference call set for today, August 4, 2011, at 10:00 A.M. CDT. 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 month after the call by dialing (800) 475-6701 or (320) 365-3844 and entering access code 189715.

Financial and Statistical Data Tables

Following are unaudited financial highlights for the three and six month periods ended June 30, 2011 and 2010. All production volumes and dollars are expressed on a net revenue interest basis with gas volumes converted to equivalent barrels at 6:1.
         
THREE MONTH FINANCIAL HIGHLIGHTS
(Amounts in thousands of U.S. dollars, except per share and unit data)
(Unaudited)
Three Months Ended
June 30, Percentage
2011   2010   Change
Revenues
Oil sales 575,928 443,984 + 30%
Natural gas sales 15,171 44,044 - 66%
CO2 sales and transportation fees 5,343 4,690 + 14%
Interest income and other income 4,955   4,492   + 10%
Total revenues 601,397   497,210   + 21%
 
Expenses
Lease operating expenses 129,932 127,743 + 2%
Production taxes and marketing expenses 39,688 38,100 + 4%
CO2 discovery and operating expenses 1,869 1,681 + 11%
General and administrative 30,900 31,192 - 1%
Interest, net 42,249 43,483 - 3%
Depletion, depreciation, and amortization 103,495 129,209 - 20%
Derivatives income (172,904 ) (128,674 ) + 34%
Loss on early extinguishment of debt 348 - N/A
Transaction and other costs related to the Encore merger 2,018   22,784   - 91%
Total expenses 177,595   265,518   - 33%
 
Income before income taxes 423,802 231,692 + 83%
 
Income tax provision
Current income taxes 12,028 6,941 + 73%
Deferred income taxes 152,528   74,422   + >100%
 
Consolidated net income 259,246 150,329 + 72%
Less: net income attributable to noncontrolling interest -   (14,962 ) - 100%
 
NET INCOME ATTRIBUTABLE TO DENBURY STOCKHOLDERS 259,246   135,367   + 92%
 
Net income per common share
Basic 0.65 0.34 + 91%
Diluted 0.64 0.34 + 88%
 
Weighted average common shares outstanding
Basic 398,631 395,548 + 1%
Diluted 403,919 400,867 + 1%
 
Production (daily - net of royalties)
Oil (barrels) 59,538 65,942 - 10%
Gas (mcf) 32,283 109,014 - 70%
BOE (6:1) 64,919 84,111 - 23%
 
Unit sales price (including derivative settlements)
Oil (per barrel) 103.17 71.68 + 44%
Gas (per mcf) 7.22 6.12 + 18%
BOE (6:1) 98.21 64.13 + 53%
 
Unit sales price (excluding derivative settlements)
Oil (per barrel) 106.30 73.99 + 44%
Gas (per mcf) 5.16 4.44 + 16%
BOE (6:1) 100.06 63.76 + 57%
         
Three Months Ended
June 30, Percentage
2011     2010 Change
 
Derivative contracts
Cash receipt (payment) on settlements (10,942 ) 2,801 - >100%
Non-cash fair value adjustment income 183,846   125,873   + 46%
Total income from derivative contracts 172,904   128,674   + 34%
 
Non-GAAP financial measure (1)
Net income attributable to Denbury stockholders (GAAP measure) 259,246 135,367 + 92%
Non-cash fair value adjustments on derivative contracts (net of taxes) (113,985 ) (78,041 ) + 46%
Transaction and other costs related to the Encore merger (net of taxes) 1,251 14,126 - 91%
Loss on early extinguishment of debt (net of taxes) 216 - N/A
Decrease in deferred tax expense due to rate decrease - (2,961 ) - 100%
Adjustments attributable to noncontrolling interest -   4,368   - 100%
Adjusted net income excluding certain items (non-GAAP measure) 146,728   72,859   + >100%
 
Non-GAAP financial measure (1)
Consolidated net income (GAAP measure) 259,246 150,329 + 72%
Adjustments to reconcile to cash flow from operations:
Depletion, depreciation and amortization 103,495 129,209 - 20%
Deferred income taxes 152,528 74,422 + >100%
Non-cash fair value derivative adjustments (183,846 ) (125,873 ) + 46%
Loss on early extinguishment of debt 348 - N/A
Other 12,287   12,813   - 4%
Adjusted cash flow from operations (non-GAAP measure) 344,058 240,900 + 43%
Net change in assets and liabilities relating to operations 54,463   30,223   + 80%
Cash flow from operations (GAAP measure) 398,521   271,123   + 47%
 
Oil and natural gas capital investments (excluding Encore Merger) 283,986 248,429 + 14%
CO2 capital investments 7,980 27,895 - 71%
Pipelines and plants capital investments 56,263 51,909 + 8%
 
BOE data (6:1)
Oil and natural gas revenues 100.06 63.76 + 57%
Gain (loss) on settlements of derivative contracts (1.85 ) 0.37 - >100%
Lease operating expenses (21.99 ) (16.69 ) + 32%
Production taxes and marketing expenses (6.72 ) (4.98 ) + 35%
Production netback 69.50 42.46 + 64%
Non-tertiary CO2 operating margin 0.59 0.39 + 51%
General and administrative (5.23 ) (4.07 ) + 29%
Transaction and other costs related to the Encore merger (0.34 ) (2.98 ) - 89%
Net cash interest expense and other income (5.54 ) (4.43 ) + 25%
Current income taxes and other (0.74 ) 0.10 - >100%
Changes in assets and liabilities relating to operations 9.22   3.95   + >100%
Cash flow from operations 67.46   35.42   + 90%
 
(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
2011 2010 Change
Revenues
Oil sales 1,068,766 749,188 + 43%
Natural gas sales 28,525 69,726 - 59%
CO2 sales and transportation fees 10,267 9,187 + 12%
Gain on sale of interest in Genesis - 101,540 - 100%
Interest income and other income 8,004   6,390   + 25%
Total revenues 1,115,562   936,031   + 19%
 
Expenses
Lease operating expenses 257,029 223,963 + 15%
Production taxes and marketing expenses 72,439 57,417 + 26%
CO2 discovery and operating expenses 4,023 3,049 + 32%
General and administrative 74,746 63,901 + 17%
Interest, net 91,026 69,899 + 30%
Depletion, depreciation, and depreciation 197,089 211,081 - 7%
Derivatives income (2,154 ) (169,899 ) - 99%
Loss on early extinguishment of debt 16,131 - N/A
Transaction and other costs related to the Encore merger 4,377   67,783   - 94%
Total expenses 714,706   527,194   + 36%
 
Income before income taxes 400,856 408,837 - 2%
 
Income tax provision
Current income taxes 11,180 7,610 + 47%
Deferred income taxes 144,620   150,694   - 4%
 
Consolidated net income 245,056 250,533 - 2%
Less: net income attributable to noncontrolling interest -   (18,278 ) - 100%
 
NET INCOME ATTRIBUTABLE TO DENBURY STOCKHOLDERS 245,056   232,255   + 6%
 
Net income per common share
Basic 0.62 0.67 - 7%
Diluted 0.61 0.66 - 8%
 
Weighted average common shares
Basic 398,032 345,126 + 15%
Diluted 403,703 350,326 + 15%
 
Production (daily - net of royalties)
Oil (barrels) 59,002 55,185 + 7%
Gas (mcf) 31,579 81,108 - 61%
BOE (6:1) 64,265 68,703 - 6%
 
Unit sales price (including derivative settlements)
Oil (per barrel) 98.02 67.26 + 46%
Gas (per mcf) 7.20 6.14 + 17%
BOE (6:1) 93.53 61.27 + 53%
 
Unit sales price (excluding derivative settlements)
Oil (per barrel) 100.08 75.00 + 33%
Gas (per mcf) 4.99 4.75 + 5%
BOE (6:1) 94.33 65.85 + 43%
         
Six Months Ended
June 30, Percentage
2011       2010   Change
 
Derivative contracts
Cash payment on settlements (9,354 ) (57,000 ) - 84%
Non-cash fair value adjustment income 11,508   226,899   - 95%
Total income from derivative contracts 2,154   169,899   - 99%
 
Non-GAAP financial measure (1)
Net income attributable to Denbury stockholders (GAAP measure) 245,056 232,255 + 6%
Non-cash fair value adjustments on derivative contracts (net of taxes) (7,135 ) (140,677 ) - 95%
Transaction and other costs related to the Encore merger (net of taxes) 2,714 44,878 - 94%
Loss on early extinguishment of debt (net of taxes) 10,001 -
Gain on sale of interest in Genesis (net of taxes) - (62,955 ) - 100%
Decrease in deferred tax expense due to rate decrease - 7,072 - 100%
Interest on newly issued debt one month prior to merger (net of taxes) - 4,263 100%
Adjustments attributable to noncontrolling interest -   5,407   - 100%
Adjusted net income excluding certain items (non-GAAP measure) 250,636   90,243   + >100%
 
Non-GAAP financial measure (1)
Consolidated net income (GAAP measure) 245,056 250,533 - 2%
Adjustments to reconcile to cash flow from operations:
Depletion, depreciation and amortization 197,089 211,081 - 7%
Deferred income taxes 144,620 150,694 - 4%
Non-cash fair value derivative adjustments (11,508 ) (226,899 ) - 95%
Loss on early extinguishment of debt 16,131 - N/A
Gain on sale of interest in Genesis - (101,540 ) - 100%
Other 23,887   23,001   + 4%
Adjusted cash flow from operations (non-GAAP measure) 615,275 306,870 + >100%
Net change in assets and liabilities relating to operations (91,922 ) 77,421   - >100%
Cash flow from operations (GAAP measure) 523,353   384,291   + 36%
 
Oil & natural gas capital investments (excluding Encore Merger) 504,083 341,416 + 48%
CO2 capital investments 31,731 44,274 - 28%
Pipelines and plants capital investments 98,669 108,177 - 9%
Cash paid in Encore Merger, net of cash acquired - 801,489 - 100%
Proceeds from sales of properties - 881,344 - 100%
Proceeds from sale of interest in Genesis - 162,622 - 100%
 
Cash and cash equivalents 121,792 67,474 + 81%
Total assets 9,339,423 9,745,837 - 4%

Total long-term debt (principal amount excluding capital leases and pipeline financings)
2,051,348 2,461,349 - 17%
Financing leases 246,503 250,846 - 2%
Total stockholders' equity 4,648,314 4,310,241 + 8%
 
BOE data (6:1)
Oil and natural gas revenues 94.33 65.85 + 43%
Loss on settlements of derivative contracts (0.80 ) (4.58 ) - 83%
Lease operating expenses (22.10 ) (18.01 ) + 23%
Production taxes and marketing expenses (6.23 ) (4.62 ) + 35%
Production netback 65.20 38.64 + 69%
Non-tertiary CO2 operating margin 0.53 0.49 + 8%
General and administrative (6.43 ) (5.14 ) + 25%
Transaction and other costs related to Encore merger (0.38 ) (5.45 ) - 93%
Net cash interest expense and other income (6.31 ) (4.53 ) + 39%
Current income taxes and other 0.28 0.66 - 58%
Changes in assets and liabilities relating to operations (7.90 ) 6.23   - >100%
Cash flow from operations 44.99   30.90   + 46%
 
(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 an important 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 producer in both Mississippi and Montana, owns the largest reserves of CO 2 used for tertiary oil recovery east of the Mississippi River, and holds significant operating acreage in the Rocky Mountain and Gulf Coast regions. The Company's goal is to increase the value of acquired properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis on our CO 2 tertiary recovery operations.

This press release, other than historical financial information, contains forward-looking statements that involve risks and uncertainties, including forecasted amounts and timing of the 2011 production from the Company's tertiary operations and overall production activities, estimated capital expenditures for 2011 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.

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