DNR - 2013.05.02 - 8K EX 99.1

PLANO, TX - May 2, 2013 - Denbury Resources Inc. (NYSE: DNR) ("Denbury" or the "Company") today announced adjusted net income (a non-GAAP measure)⁽¹⁾ of $123 million for the first quarter of 2013, or $0.33 per diluted share. This compares to $137 million of adjusted net income, or $0.36 per diluted share for the fourth quarter of 2012⁽²⁾, and $161 million of adjusted net income, or $0.41 per diluted share, for the prior year first quarter. First quarter of 2013 net income (the GAAP measure) was $88 million, or $0.23 per diluted share, on quarterly revenues of $580 million. This compares to net income of $115 million, or $0.30 per diluted share, on revenues of $603 million for the fourth quarter of 2012, and net income of $113 million, or $0.29 per diluted share, on revenues of $640 million for the prior year first quarter.

Adjusted cash flow from operations (a non-GAAP measure)⁽¹⁾ for both the first quarter of 2013 and the fourth quarter of 2012 was $316 million ($358 million in the fourth quarter of 2012 if the increase in current income taxes related to the Bakken transaction⁽³⁾ is excluded)⁽²⁾ and compares to $352 million for the prior year first quarter. Net cash provided by operating activities (the GAAP measure) was $269 million for the first quarter of 2013, compared to $385 million for the fourth quarter of 2012 and $292 million for the prior year first quarter.

Phil Rykhoek, Denbury's President and CEO, commented, "We are off to a strong start in 2013 as we continue to execute on our proven, unique, and repeatable growth strategy. Quarterly oil production from our core tertiary business exceeded our expectations, reaching a new record level in the first quarter, while our realized oil price premium in the quarter was our highest ever. From a total production standpoint, the first quarter was a transition quarter for us as we sold our Bakken area assets in the fourth quarter of 2012 but did not acquire the replacement assets in the Cedar Creek Anticline until almost the end of the first quarter of 2013. These newly acquired properties are currently producing around 11,000 BOE/d net to our interest, and we expect over 20% of our total daily production to come from the Cedar Creek Anticline for the remainder of 2013.

“With the solid start to the year, we now estimate that both our tertiary and total production will be in the upper half of our currently estimated 2013 production ranges. Further, with our well-defined and lower-risk growth outlook and the high returns of our tertiary investments, we are uniquely positioned to grow per-share value for the foreseeable future.”

Production for the first quarter of 2013 averaged 63,823 BOE/d, which included 39,057 Bbls/d from tertiary properties and 24,766 BOE/d from non-tertiary properties. First quarter total production was down approximately 11%, or 7,709 BOE/d, compared to that in the first quarter of 2012, principally due to the asset sales in late 2012. Excluding the impact of asset sales, continuing production was up approximately 17%, or 9,338 BOE/d, due in part to a 17% increase in tertiary production, or 5,800 BOE/d, and the remainder primarily due to 2012 acquisitions. The sequential and year-over-year quarterly tertiary production increases reflect growing production at the Company's newest tertiary floods at Hastings and Oyster Bayou fields combined with production gains from the expanding tertiary floods at Delhi and Tinsley fields. The increases in non-tertiary production for the same periods were the result of the assets acquired in 2012 and 2013.

Oil and natural gas revenues, excluding the impact of derivative contracts, decreased 9% when comparing the first quarters of 2013 and 2012, as the decline in production related to asset divestitures more than offset an increase in realized oil prices. Denbury's average realized oil price, excluding derivative contracts, was $105.59 in the first quarter of 2013, compared to $102.52 in the prior year first quarter. Denbury's oil price differential (the difference between the average price at which the Company sold its production and the average NYMEX price) improved significantly from the prior year first quarter level as the Light Louisiana Sweet (LLS) index premium improved and a greater percentage of the Company's production was sold in the Gulf Coast region following the Bakken transaction. Company-wide oil price differentials in the first quarter of 2013 were $11.17 per barrel (“Bbl”) above NYMEX prices, compared to $0.37 per Bbl below NYMEX in the prior year first quarter. During the first quarter of 2013, the Company sold 53% of its crude oil at prices based on the LLS index price, 26% at prices partially tied to the LLS index price, and the balance at prices based on various other indexes tied to NYMEX prices, primarily in the Rocky Mountain region.

Lease operating expenses increased 15% on a per BOE basis to $24.47 per BOE in the first quarter of 2013 from $21.19 per BOE in the first quarter of 2012, primarily due to the divestiture during the fourth quarter of 2012 of the Company's Bakken area assets which had relatively low operating costs per BOE. Tertiary operating expenses averaged $24.70 per Bbl in the first quarter of 2013, down from $26.74 per Bbl in the prior year first quarter. The decrease in tertiary operating expenses between the periods was primarily the result of the 17% increase in tertiary production which more than offset the additional costs related to operating new tertiary floods at Oyster Bayou and Hastings fields.

General and administrative (“G&A”) expenses totaled $42 million in the first quarter of 2013, compared to $37 million in the prior year first quarter. The increase in G&A expense was primarily due to higher compensation and employee-related costs due to increased headcount and merit-based compensation increases.

Interest expense, net of capitalized interest, in the first quarter of 2013 was $36 million, unchanged from the prior year first quarter level. The impact of a $484 million increase in average debt outstanding from the first quarter of 2012 to the first quarter of 2013 was offset by a reduction in the Company's average interest rate, to 6.7% from 7.6%, and an increase in capitalized interest related to projects not yet in service. Denbury recognized a pre-tax loss on early extinguishment of debt of $44 million in the first quarter of 2013 related to the early redemption of most of its 9 1/2% and 9 3/4% senior subordinated notes, which the Company refinanced with the issuance of 4 5/8% senior subordinated notes due 2023.

Denbury recorded a noncash pre-tax charge of $12 million in the first quarter of 2013 due to changes in the fair values of the Company's derivative contracts, compared to a noncash pre-tax charge of $44 million on fair value changes in the prior year first quarter.

The Company's overall depletion, depreciation and amortization (“DD&A”) rate was $19.65 per BOE in the first quarter of 2013, compared to $18.57 per BOE in the prior year first quarter. This increase per BOE was primarily driven by higher DD&A expense from the change in classification of equipment leases from operating to capital during 2012, combined with the impact of lower production in the current year period. The impact of these items was offset in part by the DD&A reduction related to the divestiture of the Company's Bakken area assets during the fourth quarter of 2012.

Denbury completed the acquisition of producing property interests in the Cedar Creek Anticline from ConocoPhillips near the end of the first quarter of 2013. As previously incorporated into its 2013 production estimates, Denbury expects the acquired properties to contribute about 7,700 BOE/d to full-year 2013 average daily production, which reflects estimated average daily production of about 10,200 BOE/d from the acquisition date through the end of 2013. Approximately 99% of this production is estimated to be oil and natural gas liquids. With the better-than-expected start to 2013, Denbury now expects tertiary and total production to average in the upper half of the estimated ranges (which remain unchanged) shown in the following table:

Denbury's 2013 capital expenditure budget was recently increased by $60 million, to $1.06 billion. The additional $60 million will primarily fund capital projects on the newly acquired Cedar Creek Anticline properties and capital projects scheduled for 2012 that were carried into 2013. The budgeted amount excludes potential acquisitions, and approximately $160 million of estimated capitalized costs (including capitalized corporate exploration and development overhead; geological and geophysical costs; capitalized interest; and pre-production start-up costs associated with new tertiary floods), which is up from the previous estimate of these capitalized costs of $125 million. Denbury expects its 2013 capital expenditure budget to be fully funded with its estimated cash flow generated from operations in 2013 assuming NYMEX oil prices average in the low $90 per Bbl range for the year.

Denbury continues to repurchase shares from time to time under its share repurchase program, acquiring a total of 4.7 million shares in 2013 through the end of April, to bring total purchases under such program since its commencement in October 2011 to nearly 36 million shares, or about 9% of shares outstanding at September 30, 2011, at an average cost of just over $15 per share. Another $229 million of share repurchases remained authorized under the program as of April 30, 2013.

Denbury will host a conference call to review and discuss first quarter 2013 financial and operating results and financial and operating guidance for the remainder of 2013 today, Thursday, May 2, at 10:00 A.M. (Central). Individuals who would like to participate should dial 800.230.1096 or 612.332.0725 ten minutes before the scheduled start time and provide the confirmation number 260590 to the operator. To access a live audio webcast of the conference call, please visit the investor relations section of the Company's website at www.denbury.com. The audio webcast will be archived on the website for at least 30 days, and a telephonic replay will be accessible for one month after the call by dialing 800.475.6701 or 320.365.3844 and entering confirmation number 260590.

Denbury's 2013 Annual Meeting of Stockholders will be held on Wednesday, May 22, 2013, at 3:00 P.M. (Central), at The Westin Stonebriar Hotel located at 1549 Legacy Drive, Frisco, Texas. The record date for determination of shareholders entitled to vote at the annual meeting was the close of business on Thursday, March 28, 2013.

Denbury is a growing domestic independent oil and natural gas company. The Company's primary focus is on enhanced oil recovery utilizing carbon dioxide and its operations are focused in two key operating areas: the Gulf Coast and Rocky Mountain regions. Denbury is the largest combined oil and natural gas producer in both Mississippi and Montana, and owns the largest reserves of carbon dioxide used for tertiary oil recovery east of the Mississippi River. 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 relating to tertiary recovery operations. For more information about Denbury, please visit www.denbury.com.

This press release, other than historical financial information, contains forward-looking statements that involve risks and uncertainties including estimated 2013 production and capital expenditures, estimated production from pending asset acquisitions, estimated cash generated from operations in 2013 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



	Three Months Ended
	March 31,
In thousands, except per share data	2013		2012
Revenues and other income
Oil sales	$	566,143	$	623,706
Natural gas sales	7,510		9,795
CO₂ sales and transportation fees	6,558		6,795
Interest income and other income	2,875		4,820
Total revenues and other income	583,086		645,116
Expenses
Lease operating expenses	140,542		137,964
Marketing expenses	9,796		10,830
CO₂ discovery and operating expenses	3,722		6,205
Taxes other than income	38,011		43,694
General and administrative expenses	41,889		36,607
Interest expense, net of capitalized interest of 21,705 and 19,445, respectively	36,034		36,314
Depletion, depreciation and amortization	112,898		120,895
Derivatives expense (income)	11,929		45,275
Loss on early extinguishment of debt	44,223		—
Impairment of assets	—		17,300
Other expenses	2,107		10,720
Total expenses	441,151		465,804
Income before income taxes	141,935		179,312
Income tax provision
Current income taxes	10,519		28,708
Deferred income taxes	43,845		37,137
Net income	$	87,571	$	113,467

Net income per common share:
Basic	$	0.24	$	0.29
Diluted	0.23		0.29
Weighted average common shares outstanding:
Basic	369,396		386,367
Diluted	372,867		390,943



	Three Months Ended
	March 31,
In thousands	2013			2012
Net income (GAAP measure)	$	87,571		$	113,467
Noncash fair value adjustments on commodity derivatives	11,929			44,085
Loss on early extinguishment of debt	44,223			—
Impairment of assets	—			17,300
CO₂ discovery and operating expenses – CO₂ exploration costs	—			4,925
Other expenses – acquisition transaction costs	2,107			—
Other expenses – helium nonperformance accrual	—			3,900
Other expenses – allowance for collectability on outstanding loans	—			3,683
Other expenses – loss on sale of Vanguard common units	—			3,137
Estimated income taxes on above adjustments to net income	(22,430		)	(29,272		)
Adjusted net income (non-GAAP measure)	$	123,400		$	161,225



	Three Months Ended
In thousands	March 31,
In thousands	2013			2012
Net income (GAAP measure)	$	87,571		$	113,467
Adjustments to reconcile to adjusted cash flow from operations:
Depletion, depreciation, and amortization	112,898			120,895
Deferred income taxes	43,845			37,137
Stock-based compensation	7,908			7,913
Noncash fair value adjustments on commodity derivatives	11,929			44,085
Loss on early extinguishment of debt	44,223			—
Impairment of assets	—			17,300
Other	7,372			11,427
Adjusted cash flow from operations (non-GAAP measure)	315,746			352,224
Net change in assets and liabilities relating to operations	(46,570		)	(60,570		)
Cash flow from operations (GAAP measure)	$	269,176		$	291,654



	Three Months Ended
	March 31,
Average Daily Volumes (BOE/d) (6:1)	2013	2012
Tertiary oil production
Gulf Coast region
Mature properties:
Brookhaven	2,305	3,014
Eucutta	2,636	3,090
Mallalieu	2,116	2,585
Other mature properties ⁽¹⁾	7,800	8,012
Delhi	5,827	4,181
Hastings	3,956	618
Heidelberg	3,943	3,583
Oyster Bayou	2,252	877
Tinsley	8,222	7,297
Total tertiary oil production	39,057	33,257
Non-tertiary oil and gas production
Gulf Coast region
Mississippi	3,013	4,573
Texas	6,692	3,674
Other	1,153	1,281
Total Gulf Coast region	10,858	9,528
Rocky Mountain region
Cedar Creek Anticline	8,745	8,496
Other	5,163	3,204
Total Rocky Mountain region	13,908	11,700
Total non-tertiary oil production	24,766	21,228
Total continuing production	63,823	54,485
Properties disposed:
Bakken area assets	—	15,285
2012 Non-core asset divestitures	—	1,762
Total production	63,823	71,532



	Three Months Ended
	March 31,
	2013		2012
Production (daily – net of royalties):
Oil (barrels)	59,577		66,857
Gas (mcf)	25,477		28,052
BOE (6:1)	63,823		71,532
Unit sales price (excluding derivative settlements):
Oil (per barrel)	$	105.59	$	102.52
Gas (per mcf)	3.28		3.84
BOE (6:1)	99.87		97.32
Unit sales price (including derivative settlements):
Oil (per barrel)	$	105.59	$	101.16
Gas (per mcf)	3.28		6.59
BOE (6:1)	99.87		97.14



	Three Months Ended
	March 31,
	2013			2012
Oil and natural gas revenues	$	99.87		$	97.32
Loss on settlements of derivative contracts	—			(0.18		)
Lease operating expenses	(24.47		)	(21.19		)
Production and ad valorem taxes	(6.17		)	(6.31		)
Marketing expenses, net of third party purchases	(1.41		)	(1.66		)
Production netback	67.82			67.98
CO₂ sales, net of operating and exploration expenses	0.49			0.08
General and administrative expenses	(7.29		)	(5.62		)
Interest expense, net	(6.27		)	(5.59		)
Other	0.22			(2.75		)
Changes in assets and liabilities relating to operations	(8.11		)	(9.30		)
Cash flow from operations	46.86			44.80
DD&A	(19.65		)	(18.57		)
Deferred income taxes	(7.63		)	(5.71		)
Loss on early extinguishment of debt	(7.70		)	—
Noncash commodity derivative adjustments	(2.08		)	(6.78		)
Impairment of assets	—			(2.66		)
Other noncash items	5.45			6.35
Net income	$	15.25		$	17.43



	Three Months Ended
	March 31,
In thousands	2013		2012
Capital expenditures by project:
Tertiary oil fields	$	169,829	$	113,578
CO₂ pipelines	8,818		14,151
CO₂ sources ⁽¹⁾	30,266		50,479
Other areas	61,997		162,555
Capital expenditures before acquisitions and capitalized interest	270,910		340,763
Less: recoveries from sale/leaseback transactions	—		(21,002		)
Net capital expenditures excluding acquisitions and capitalized interest	270,910		319,761
Property acquisitions ⁽²⁾	999,859		1,234
Capitalized interest	21,705		19,445
Capital expenditures, net of sale/leaseback transactions	$	1,292,474	$	340,440



	Three Months Ended
	March 31,
In thousands	2013			2012
Cash payment on settlements of derivative contracts	$	—		$	(1,190	)
Noncash fair value adjustments on derivatives – expense	(11,929		)	(44,085		)
Total expense from commodity derivative contracts	$	(11,929	)	$	(45,275	)



	March 31,		December 31,
In thousands	2013		2012
Cash and cash equivalents	$	62,269	$	98,511
Restricted cash	50,460		1,050,015
Total assets	11,316,765		11,139,342

Borrowings under bank credit facility	$	275,000	$	700,000
Borrowings under senior subordinated notes (principal only)	2,638,285		2,051,350
Financing and capital leases	381,787		394,504
Total debt (principal only)	$	3,295,072	$	3,145,854

Total stockholders' equity	$	5,145,880	$	5,114,889

Adjusted net income is a non-GAAP measure provided as a supplement to present an alternative net income measure which excludes expense and income items (and their related tax effects) not directly related to the Company's ongoing operations. The excluded items are those which reflect the fair value adjustments on the Company's derivative contracts, impairment of assets, the portion of CO₂ discovery and operating expenses attributable to exploration costs, transaction-related expenses, and the cost of early debt extinguishment. Management believes that adjusted net income may be helpful to investors, and is widely used by the investment community, while also being used by management in evaluating the comparability of the Company's ongoing operational trends and results. Adjusted net income should not be considered in isolation or as a substitute for net income reported in accordance with GAAP, but rather to provide additional information useful in evaluating the Company's operational trends and performance.

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 additional measure, along with cash flow from operations, as it believes the non-GAAP measure 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.



Operating Area		2013 Estimated Production (BOE/d)
Tertiary		36,500 - 39,500
Cedar Creek Anticline		16,200
Other Rockies Non-Tertiary		5,400
Texas Non-Tertiary		6,300
Other Gulf Coast Non-Tertiary		4,300
Total Production		68,700 - 71,700



	Three Months Ended
	March 31,
In thousands	2013		2012
Cash provided by (used in):
Operating activities	269,176		291,654
Investing activities	(320,646	)	(288,883	)
Financing activities	15,228		55,902


•	Increased average quarterly oil production from tertiary operations to a new record level of 39,057 barrels per day (“Bbls/d”), 17% higher than 2012's first quarter level and 4% higher than the fourth quarter of 2012 level.


•	Commenced injection of CO₂ captured from two industrial facilities in the Gulf Coast region. These facilities are expected to provide a combined approximate 70 million cubic feet per day of CO₂ to Denbury's Gulf Coast region tertiary operations and illustrate the Company's unique ability to use and store CO₂ that would otherwise be released into the atmosphere.


⁽¹⁾	See accompanying Schedules that reconcile GAAP to non-GAAP measures along with a statement indicating why the Company believes the non-GAAP measures provide useful information for investors.


⁽²⁾	The GAAP to non-GAAP reconciliations for the fourth quarter of 2012 are part of the Company's fourth quarter 2012 earnings release which is an exhibit to its February 21, 2013 Form 8-K.


⁽³⁾	Full description of the Bakken transaction is provided in the Company's September 20, 2012 Form 8-K as amended December 26, 2012 and January 18, 2013 on Forms 8-K/A.


•	Issued $1.2 billion of 4 5/8% senior subordinated notes due 2023 in conjunction with refinancing approximately $651 million principal amount of senior subordinated notes with interest rates of 9 1/2% and 9 3/4% and reduced outstanding borrowings on our bank credit facility with the additional proceeds.


(1)	Other mature properties include Cranfield, Little Creek, Lockhart Crossing, Martinville, McComb and Soso fields.


(1)	Includes capital expenditures related to the Riley Ridge gas plant.


(2)	Property acquisitions during the three months ended March 31, 2013 include capital expenditures of approximately $1.0 billion related to acquisitions during the period that are not reflected as an Investing Activity on our Unaudited Condensed Consolidated Statements of Cash Flows due to the movement of proceeds through a qualified intermediary.


(1)	For the three months ended March 31, 2012, includes $140.1 million of cash from the sale of non-core assets in February 2012 which was held by a qualified intermediary in support of a like-kind-exchange transaction to fund a portion of the acquisition cost of Thompson Field.