DENBURY INC - FORM 8-K - EX-99.1 - EXHIBIT 99.1

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Exhibit 99.1

DENBURY REPORTS THIRD QUARTER 2014 RESULTS

PLANO, TX – November 5, 2014 – Denbury Resources Inc. (NYSE: DNR) ("Denbury" or the "Company") today announced adjusted net income (a non-GAAP measure) of $91 million for the third quarter of 2014, or $0.26⁽¹⁾ per diluted share. On a GAAP basis, the Company recorded net income of $269 million, or $0.77 per diluted share, for the quarter. Adjusted net income⁽¹⁾ for the third quarter of 2014 differs from GAAP net income due to the exclusion of both (1) a gain of $277 million (pre-tax) for noncash fair value adjustments on commodity derivatives (a non-GAAP measure)⁽¹⁾and (2) a $9.9 million net reduction (pre-tax) in lease operating expenses related to the Company’s Delhi Field remediation (reflective of a $23.9 million net insurance reimbursement offset by $14.0 million of additional third-party property and commercial damage claims recorded during the quarter).

Sequential and year-over-year quarterly comparisons of selected financial items are shown in the following table:



	Quarter Ended
(in millions, except per share amounts)	Sept. 30, 2014	June 30, 2014	Sept. 30, 2013
Revenues	$633	$669	$674
Net income (loss)	269	(55)	102
Adjusted net income⁽¹⁾ (non-GAAP measure)	91	93	165
Net income (loss) per diluted share	0.77	(0.16)	0.28
Adjusted net income per diluted share⁽¹⁾⁽²⁾ (non-GAAP measure)	0.26	0.26	0.45
Cash flow from operations	340	330	305
Adjusted cash flow from operations⁽¹⁾⁽³⁾ (non-GAAP measure)	316	314	352

Adjusted net income⁽¹⁾ for the third quarter of 2014 decreased by $2 million on a sequential-quarter basis as lower production and lower realized prices (including derivative settlements) during the third quarter were largely offset by a benefit received on taxes other than income. Adjusted net income⁽¹⁾ for the third quarter of 2014 decreased by $74 million from the prior-year quarter level largely due to the effect in the 2014 period of lower realized prices (including derivative settlements), higher depletion, depreciation, and amortization, and higher lease operating expenses, offset in part by higher production.

Sequentially, the level of adjusted cash flow from operations (a non-GAAP measure)⁽¹⁾⁽³⁾ increased $2 million from that in the second quarter of 2014 and decreased $36 million from that in the prior-year third quarter. These changes were the result of many of the same items that drove changes in adjusted net income⁽¹⁾, excluding the change in depletion, depreciation, and amortization, as well as changes in both current income taxes and Delhi remediation costs and insurance reimbursements.


⁽¹⁾	A non-GAAP measure. 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⁾	For the three months ended June 30, 2014, calculated using average diluted shares outstanding of 350.2 million.


⁽³⁾	Adjusted cash flow from operations reflects cash flow from operations before working capital changes but is not adjusted for nonrecurring items.

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Management Comment

Phil Rykhoek, Denbury’s President and CEO, commented, "While our overall production declined sequentially in the third quarter due to unplanned downtime at a few of our non-tertiary fields, our tertiary production achieved a new record level, increasing 2% from the prior quarter level. We anticipate overall sequential production growth in the fourth quarter of 2014 and currently expect our full-year 2014 average daily production to approximate our year-to-date average daily production rate of 74,283 barrels of oil equivalent per day (“BOE/d”). With the majority of our expense line items decreasing on a sequential-quarter basis in the third quarter, our adjusted cash flow from operations⁽¹⁾⁽³⁾ increased slightly from the second quarter level, allowing us to generate free cash flow during the quarter. Year-to-date in 2014, our adjusted cash flow from operations⁽¹⁾⁽³⁾ has exceeded our capital expenditures and dividend payments by approximately $90 million.

“We have received $23.9 million, net, from our primary insurance carrier for reimbursement of costs previously incurred for our Delhi Field remediation, and we are continuing to further pursue reimbursement under our additional layers of coverage. In addition, we received an enhanced oil recovery project tax exemption for our Hastings Field, which resulted in a $7.5 million cumulative reduction in severance taxes and will result in lower severance tax payments at the field in the future.

“We are well insulated from the recent drop in oil prices in the near-term, as we have fixed-price swaps covering 58,000 barrels per day (“Bbls/d”) of our fourth quarter of 2014 oil production at an average WTI NYMEX price of approximately $92.50. In order to provide greater cash flow certainty in the future, during the third quarter of 2014, we added to our sizeable hedge positions for 2015 and continued to build our first half of 2016 hedge positions with a combination of enhanced swaps and three-way collars. We look forward to discussing our plans for 2015 at our annual analyst day on November 18, 2014.”

Production

Production for the third quarter of 2014 averaged 73,810 BOE/d, which included 41,627 Bbls/d of oil from tertiary properties and 32,183 BOE/d from non-tertiary properties. Denbury’s third quarter of 2014 production was 96% oil, slightly higher than in the same prior-year period. Tertiary oil production was up 2%, or 730 Bbls/d, on a sequential-quarter basis, and up 11%, or 4,114 Bbls/d, from the third quarter of 2013 levels. The tertiary production increase over third quarter of 2013 levels was primarily due to production growth in response to continued field development and expansion of facilities in the Gulf Coast region CO₂ floods of Hastings, Heidelberg, Oyster Bayou, and Tinsley fields and production in the Rocky Mountain region from Bell Creek Field, partially offset by mature area production declines. On a sequential-quarter basis, the tertiary production increase was primarily driven by production growth at Bell Creek Field in the Rocky Mountain region and Hastings, Heidelberg, and Oyster Bayou fields in the Gulf Coast region. Tertiary production declines at Tinsley Field also impacted the sequential-quarterly comparison.

Non-tertiary oil equivalent production was down 7%, or 2,240 BOE/d, from the second quarter of 2014 levels, and down 5%, or 1,835 BOE/d, from the prior-year third quarter amounts. These decreases in non-tertiary oil equivalent production were primarily due to unplanned downtime at a few non-tertiary fields during the third quarter of 2014, particularly Cedar Creek Anticline (“CCA”) and Riley Ridge in the Rocky Mountain region and Conroe Field in the Gulf Coast region. CCA production was negatively impacted by an electrical panel failure causing a water injection facility to be offline for approximately two months, and Conroe Field production was reduced by downtime of a third-party natural gas processing plant for most of the quarter. The interruptions at CCA and Conroe fields resulted in non-tertiary production decreases of approximately 500 BOE/d and 800 BOE/d, respectively, during the third quarter of 2014. At Conroe Field, the third-party processing plant was returned to service, and the impacted production resumed late in the third quarter. At CCA, the electrical panel was repaired and water injection facility placed back in service late in the third quarter, which should allow for gradual production growth at the field during the fourth quarter. Natural gas production at Riley Ridge was negligible during the third quarter of 2014 due

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to unplanned downtime caused by issues with the plant’s gas supply wells. The Company is developing a comprehensive plan to address these well issues and other ongoing issues at the Riley Ridge plant. As a result, Riley Ridge’s natural gas and helium production is currently not expected to resume until late 2015.

Review of Financial Results

Oil and natural gas revenues, excluding the impact of derivative contracts, decreased 7% when comparing the third quarters of 2014 and 2013, as the 10% decline in realized commodity prices more than offset the 3% increase in production. Denbury’s average realized oil price, excluding derivative contracts, was $94.78 in the third quarter of 2014, compared to $105.91 in the prior-year third quarter. Denbury’s oil price differential (the difference between the average price at which the Company sold its production and the average NYMEX price) decreased from the prior-year third quarter level, as both the Light Louisiana Sweet (LLS) index premium and the differentials in the Rocky Mountain region declined. Company-wide oil price differentials in the third quarter of 2014 were $2.53 per barrel (“Bbl”) below NYMEX prices, compared to $0.03 per Bbl below NYMEX in the prior-year third quarter. During the third quarter of 2014, the Company sold 43% of its crude oil at prices based on the LLS index price, 23% 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 averaged $24.32 per BOE in the third quarter of 2014, excluding Delhi insurance reimbursements and additional remediation costs that were both recorded in the quarter, an increase of 2% from the $23.82 per-BOE average in the second quarter of 2014 and an increase of 5% from the $23.24 per-BOE average in the prior-year third quarter. The increase on a sequential-quarter basis was primarily due to the 2% decline in total production as lease operating expenses were relatively flat on an absolute-dollar basis as higher well workover costs at Riley Ridge were offset by a reduction in CO₂ costs mainly driven by lower utilization and oil prices. The year-over-year increase was primarily attributable to an increase in well workover costs at Riley Ridge, higher power and CO₂ costs, and costs associated with the expansion of the Company’s CO₂ floods, including its newest tertiary flood at Bell Creek Field. Tertiary lease operating expenses (excluding the quarter’s Delhi insurance reimbursements and remediation costs) averaged $24.98 per Bbl in the third quarter of 2014, down from $26.57 per Bbl in the second quarter of 2014 and down slightly from $25.08 per Bbl in the prior-year third quarter. On a sequential-quarter basis, per-barrel tertiary operating costs were lower due to lower power and CO₂ costs. The year-over-year decrease in per-barrel tertiary operating expenses was primarily the result of lower workover costs.

Taxes other than income, which includes ad valorem, production, and franchise taxes, decreased $10.9 million on a sequential-quarter basis and $9.3 million from the prior-year third quarter level. The levels of taxes other than income during most periods are generally aligned with fluctuations in oil and natural gas revenues. However, the decreases over both periods were largely driven by a cumulative $7.5 million reduction in severance taxes at Hastings Field for a state-approved enhanced oil recovery project exemption.

General and administrative expenses increased $1.4 million on a sequential-quarter basis and $4.4 million from the prior-year third quarter level, primarily due to higher employee-related costs.

Cash interest expense decreased approximately $4 million in the third quarter of 2014 from the prior-year third quarter level as a reduction in the average interest rate to 5.2% from 6.2% between periods more than offset an approximate $344 million increase in average debt outstanding. The lower interest rate was primarily due to the Company’s April 2014 refinancing, whereby $1.25 billion of 5½% Notes were issued to refinance the Company’s $996 million in 8¼% Notes. Net interest expense increased approximately $10 million in the third quarter of 2014 from the prior-year third quarter level due to a reduction in capitalized interest of approximately $14 million between the periods. The decrease in

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capitalized interest between the third quarters of 2013 and 2014 was primarily the result of the completion of major projects in 2013, including the Riley Ridge gas processing facility and the tertiary flood at Bell Creek Field.

Denbury’s overall DD&A rate was $21.58 per BOE in the third quarter of 2014, compared to $19.08 per BOE in the prior-year third quarter. The higher per-BOE DD&A rate was primarily driven by higher finding and development costs, which were primarily attributable to the reserve additions at Bell Creek Field in late 2013 that resulted in the transfer of most of that field’s development costs from unevaluated properties to proved properties.

The Company recorded a noncash gain of $277 million in the third quarter of 2014 associated with changes in the fair values of the Company’s derivative contracts, compared to a noncash fair value expense of $125 million in the second quarter of 2014, and an $80 million noncash fair value expense in the prior-year third quarter. Total net payments on the settlement of oil and natural gas derivative contracts were $25 million in the third quarter of 2014 compared to $50 million in payments in the second quarter of 2014 and less than $1 million in payments in the prior-year third quarter. These payments lowered average net realized oil prices in the third quarter of 2014 by $3.86 per barrel and in the second quarter of 2014 by $7.72 per barrel.

2014 Capital Expenditure Estimates

Denbury’s full-year 2014 capital expenditure budget remains unchanged from the previously disclosed amount of $1.1 billion. The capital budget consists of $1.0 billion of tertiary, non-tertiary, and CO₂ supply and pipeline projects, plus approximately $100 million of estimated capitalized costs (including capitalized internal acquisition, exploration and development costs; capitalized interest; and pre-production start-up costs associated with new tertiary floods). Of this combined capital expenditure amount, $764 million (approximately 69%) has been spent through the first nine months of 2014. Based on current projections, the Company expects to fully fund 2014 capital expenditures and dividends with cash flow from operations.

Share Repurchase Update

No common stock repurchases were made under Denbury’s share repurchase program during the third quarter of 2014, leaving approximately $222 million of repurchases remaining authorized under the program at quarter-end.

Conference Call and Annual Analyst Day Presentation

Denbury management will host a conference call to review and discuss third quarter 2014 financial and operating results and financial and operating guidance for the remainder of 2014 today, Wednesday, November 5, 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. 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 292681.

Denbury will host its annual analyst day in Plano, Texas on Tuesday, November 18, 2014. Management’s presentation at the annual analyst day, including operating and financial guidance for 2015, is scheduled to begin at 8:00 A.M. (Central). A live audio webcast of management’s presentation will be available on the Company’s website. The slides for the analyst day presentation and a news release summarizing the key strategic themes of that presentation, including estimates for 2015 cash flow, production, capital expenditures, and dividend rate will be published to the Company’s website on Monday,

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November 17, 2014. The audio webcast and slide presentation will be archived on the Company’s website for at least 30 days.

Denbury is a growing, dividend-paying, domestic 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. 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.

# # #

This news release, other than historical financial information, contains forward-looking statements, including estimated 2014 production, capital expenditures and cash flow, that involve risks and uncertainties including risks and uncertainties detailed in Denbury's filings with the Securities and Exchange Commission, including Denbury's most recent report on Form 10-K. These risks and uncertainties are incorporated by this reference as though fully set forth herein. These statements are based on engineering, geological, commodity pricing, financial and operating assumptions that management believes are reasonable based on currently available information; however, management's assumptions and Denbury's future performance are both subject to a wide range of business risks, and there is no assurance that Denbury’s goals and performance objectives can or will be realized. Actual results may vary materially. In addition, any forward-looking statements represent Denbury’s estimates only as of today and should not be relied upon as representing its estimates as of any future date. Denbury assumes no obligation to update its forward-looking statements.

DENBURY CONTACTS:

Jack Collins, Executive Director, Finance and Investor Relations, 972.673.2028

Ross Campbell, Manager of Investor Relations, 972.673.2825

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Financial and Statistical Data Tables and Reconciliation Schedules

Following are unaudited financial highlights for the comparative three and nine month periods ended September 30, 2014 and 2013. All production volumes and dollars are expressed on a net revenue interest basis with gas volumes converted to equivalent barrels at 6:1.

DENBURY RESOURCES INC.

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

The following information is based on GAAP reported earnings, with additional required disclosures included in the Company's Form 10-Q:



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
In thousands, except per share data	2014			2013		2014			2013
Revenues and other income
Oil sales	$	615,745		$	659,674	$	1,876,524		$	1,855,006
Natural gas sales	6,260			7,129		26,356			23,638
CO₂ and helium sales and transportation fees	11,378			6,739		33,961			19,859
Interest income and other income	4,274			11,293		14,680			19,502
Total revenues and other income	637,657			684,835		1,951,521			1,918,005
Expenses
Lease operating expenses	155,198			180,967		488,827			542,067
Marketing and plant operating expenses	15,328			13,131		50,263			36,259
CO₂ and helium discovery and operating expenses	11,434			4,120		22,229			11,261
Taxes other than income	39,966			49,267		136,761			132,218
General and administrative expenses	40,366			35,969		123,011			111,240
Interest, net of amounts capitalized of $5,862, $19,768, $17,413, and $64,752, respectively	44,752			34,501		140,136			101,137
Depletion, depreciation, and amortization	146,560			125,595		435,854			365,400
Commodity derivatives expense (income)	(252,265		)	80,446		(825		)	46,874
Loss on early extinguishment of debt	—			—		113,908			44,651
Other expenses	—			1,474		—			14,292
Total expenses	201,339			525,470		1,510,164			1,405,399
Income before income taxes	436,318			159,365		441,357			512,606
Income tax provision
Current income taxes	214			16,019		532			23,367
Deferred income taxes	167,356			41,292		168,967			169,634
Net income	$	268,748		$	102,054	$	271,858		$	319,605

Net income per common share
Basic	$	0.77		$	0.28	$	0.78		$	0.87
Diluted	$	0.77		$	0.28	$	0.77		$	0.86

Dividends per common share	$	0.0625		$	—	$	0.1875		$	—

Weighted average common shares outstanding
Basic	348,454			366,088		348,993			368,101
Diluted	350,918			369,142		351,347			371,316

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DENBURY RESOURCES INC.

SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES (UNAUDITED)

Reconciliation of net income (loss) (GAAP measure) to adjusted net income (non-GAAP measure)⁽¹⁾:



	Three Months Ended									Nine Months Ended
	September 30,						June 30,			September 30,
In thousands	2014			2013			2014			2014			2013
Net income (loss) (GAAP measure)	$	268,748		$	102,054		$	(55,200	)	$	271,858		$	319,605
Noncash fair value adjustments on commodity derivatives	(277,179		)	79,784			124,599			(103,080		)	46,212
Interest income and other income – noncash fair value adjustment – contingent liability	—			(7,500		)	—			—			(7,500		)
Lease operating expenses – Delhi Field remediation	(9,906		)	28,000			—			(9,906		)	98,000
Loss on early extinguishment of debt	—			—			113,908			113,908			44,651
CO₂ and helium discovery and operating expenses – CO₂ exploration costs	—			303			—			—			835
Other expenses – helium contract-related charges	—			1,207			—			—			9,207
Other expenses – acquisition transaction costs	—			—			—			—			2,414
Estimated income taxes on above adjustments to net income (loss)	109,093			(39,190		)	(90,633		)	(350		)	(74,620		)
Adjusted net income (non-GAAP measure)	$	90,756		$	164,658		$	92,674		$	272,430		$	438,804


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

Reconciliation of cash flow from operations (GAAP measure) to adjusted cash flow from operations (non-GAAP measure)⁽¹⁾:



	Three Months Ended									Nine Months Ended
In thousands	September 30,						June 30,			September 30,
In thousands	2014			2013			2014			2014			2013
Net income (loss) (GAAP measure)	$	268,748		$	102,054		$	(55,200	)	$	271,858		$	319,605
Adjustments to reconcile to adjusted cash flow from operations
Depletion, depreciation, and amortization	146,560			125,595			148,164			435,854			365,400
Deferred income taxes	167,356			41,292			(28,564		)	168,967			169,634
Stock-based compensation	8,887			8,103			8,871			26,104			23,774
Noncash fair value adjustments on commodity derivatives	(277,179		)	79,784			124,599			(103,080		)	46,212
Loss on early extinguishment of debt	—			—			113,908			113,908			44,651
Other	1,820			(5,141		)	2,353			5,396			7,095
Adjusted cash flow from operations (non-GAAP measure)	316,192			351,687			314,131			919,007			976,371
Net change in assets and liabilities relating to operations	24,200			(46,222		)	15,716			(33,910		)	35,838
Cash flow from operations (GAAP measure)	$	340,392		$	305,465		$	329,847		$	885,097		$	1,012,209


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

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DENBURY RESOURCES INC.

SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES (UNAUDITED)

Reconciliation of commodity derivatives income (expense) (GAAP measure) to noncash fair value adjustments on commodity derivatives (non-GAAP measure)⁽¹⁾:



	Three Months Ended									Nine Months Ended
	September 30,						June 30,			September 30,
In thousands	2014			2013			2014			2014			2013
Payment on settlements of commodity derivatives	$	(24,914	)	$	(662	)	$	(50,172	)	$	(102,255	)	$	(662	)
Noncash fair value adjustments on commodity derivatives (non-GAAP measure)	277,179			(79,784		)	(124,599		)	103,080			(46,212		)
Commodity derivatives income (expense) (GAAP measure)	$	252,265		$	(80,446	)	$	(174,771	)	$	825		$	(46,874	)


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

OPERATING HIGHLIGHTS (UNAUDITED)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Production (daily – net of royalties)
Oil (barrels)	70,619			67,705			70,504			65,755
Gas (mcf)	19,147			22,957			22,671			24,451
BOE (6:1)	73,810			71,531			74,283			69,830
Unit sales price (excluding derivative settlements)
Oil (per barrel)	$	94.78		$	105.91		$	97.49		$	103.34
Gas (per mcf)	3.55			3.38			4.26			3.54
BOE (6:1)	91.60			101.32			93.83			98.55
Unit sales price (including derivative settlements)
Oil (per barrel)	$	90.92		$	105.80		$	92.22		$	103.30
Gas (per mcf)	3.61			3.38			4.13			3.54
BOE (6:1)	87.93			101.22			88.79			98.52
NYMEX differentials
Oil (per barrel)	$	(2.53	)	$	(0.03	)	$	(2.16	)	$	5.13
Gas (per mcf)	(0.40		)	(0.18		)	(0.16		)	(0.15		)

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DENBURY RESOURCES INC.

OPERATING HIGHLIGHTS (UNAUDITED)



	Three Months Ended		Nine Months Ended
	September 30,		September 30,
Average Daily Volumes (BOE/d) (6:1)	2014	2013	2014	2013
Tertiary oil production
Gulf Coast region
Mature properties
Brookhaven	1,767	2,224	1,820	2,289
Eucutta	2,224	2,504	2,185	2,593
Mallalieu	1,869	2,042	1,848	2,105
Other mature properties ⁽¹⁾	6,189	6,761	6,209	7,262
Total mature properties	12,049	13,531	12,062	14,249
Delhi	4,377	4,517	4,542	5,269
Hastings	4,917	3,699	4,766	3,888
Heidelberg	5,721	4,553	5,553	4,217
Oyster Bayou	4,605	3,213	4,361	2,664
Tinsley	8,310	7,951	8,419	8,132
Total Gulf Coast region	39,979	37,464	39,703	38,419
Rocky Mountain region
Bell Creek	1,648	49	1,108	16
Total Rocky Mountain region	1,648	49	1,108	16
Total tertiary oil production	41,627	37,513	40,811	38,435
Non-tertiary oil and gas production
Gulf Coast region
Mississippi	2,346	2,692	2,391	2,689
Texas	5,537	6,548	6,160	6,723
Other	1,083	1,087	1,056	1,116
Total Gulf Coast region	8,966	10,327	9,607	10,528
Rocky Mountain region
Cedar Creek Anticline	18,623	18,872	18,927	15,888
Other	4,594	4,819	4,938	4,979
Total Rocky Mountain region	23,217	23,691	23,865	20,867
Total non-tertiary production	32,183	34,018	33,472	31,395
Total production	73,810	71,531	74,283	69,830


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

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DENBURY RESOURCES INC.

PER-BOE DATA (UNAUDITED)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Oil and natural gas revenues	$	91.60		$	101.32		$	93.83		$	98.55
Payment on settlements of commodity derivatives	(3.67		)	(0.10		)	(5.04		)	(0.03		)
Lease operating expenses – excluding Delhi Field remediation	(24.32		)	(23.24		)	(24.59		)	(23.29		)
Lease operating expenses – Delhi Field remediation	1.46			(4.26		)	0.49			(5.14		)
Production and ad valorem taxes	(5.34		)	(7.00		)	(6.22		)	(6.43		)
Marketing expenses, net of third-party purchases, and plant operating expenses	(1.63		)	(1.39		)	(1.82		)	(1.45		)
Production netback	58.10			65.33			56.65			62.21
CO₂ and helium sales, net of operating and exploration expenses	—			0.39			0.57			0.45
General and administrative expenses	(5.94		)	(5.47		)	(6.07		)	(5.84		)
Interest expense, net	(6.59		)	(5.24		)	(6.91		)	(5.31		)
Other	1.00			(1.57		)	1.08			(0.29		)
Changes in assets and liabilities relating to operations	3.56			(7.02		)	(1.67		)	1.88
Cash flow from operations	50.13			46.42			43.65			53.10
DD&A	(21.58		)	(19.08		)	(21.49		)	(19.17		)
Deferred income taxes	(24.65		)	(6.28		)	(8.33		)	(8.89		)
Loss on early extinguishment of debt	—			—			(5.62		)	(2.34		)
Noncash fair value adjustments on commodity derivatives	40.82			(12.12		)	5.08			(2.42		)
Other noncash items	(5.14		)	6.57			0.12			(3.51		)
Net income	$	39.58		$	15.51		$	13.41		$	16.77

CAPITAL EXPENDITURE SUMMARY (UNAUDITED)



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
In thousands	2014		2013			2014		2013
Capital expenditures by project
Tertiary oil fields	$	156,414	$	121,240		$	442,810	$	428,373
Non-tertiary fields	63,727		36,567			186,708		136,796
Capitalized interest and internal costs ⁽¹⁾	21,735		31,675			67,437		89,200
Oil and natural gas capital expenditures	241,876		189,482			696,955		654,369
CO₂ pipelines	12,256		10,243			24,612		39,363
CO₂ sources ⁽²⁾	9,265		47,096			37,502		114,240
CO₂ capitalized interest and other	779		10,474			2,831		35,200
Capital expenditures, before acquisitions	264,176		257,295			761,900		843,172
Property acquisitions ⁽³⁾	1,683		(4,952		)	1,683		1,062,607
Capital expenditures, total	$	265,859	$	252,343		$	763,583	$	1,905,779


(1)	Includes capitalized internal acquisition, exploration and development costs, capitalized interest, and pre-production startup costs associated with new tertiary floods.


(2)	Includes capital expenditures related to the Riley Ridge gas processing facility.

(3)

Property acquisitions during the nine months ended September 30, 2013 include capital expenditures of approximately $1.1 billion related to acquisitions during that period that are not reflected as an Investing Activity on the Unaudited Condensed Consolidated Statements of Cash Flows due to the movement of proceeds through a qualified intermediary to facilitate like-kind-exchange treatment under federal income tax rules.

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DENBURY RESOURCES INC.

SELECTED BALANCE SHEET AND CASH FLOW DATA (UNAUDITED)



	September 30,		December 31,
In thousands	2014		2013
Cash and cash equivalents	$	19,436	$	12,187
Total assets	12,140,053		11,788,737

Borrowings under bank credit facility	$	410,000	$	340,000
Borrowings under senior subordinated notes (principal only)	2,852,734		2,600,080
Financing and capital leases	332,179		356,686
Total debt (principal only)	$	3,594,913	$	3,296,766

Total stockholders' equity	$	5,349,769	$	5,301,406



	Nine Months Ended
	September 30,
In thousands	2014			2013
Cash provided by (used in)
Operating activities	$	885,097		$	1,012,209
Investing activities	(788,923		)	(951,703		)
Financing activities	(88,925		)	(132,469		)

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Non-GAAP Measures

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 for the periods presented are those which reflect the noncash fair value adjustments on the Company’s commodity derivatives and a contingent liability, estimated Delhi Field remediation costs and insurance reimbursements, the cost of early debt extinguishment, the portion of CO₂ and helium discovery and operating expenses attributable to exploration costs, helium contract-related charges, and transaction-related expenses. 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 results and trends. 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. Management 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.

Noncash fair value adjustments on commodity derivatives is a non-GAAP measure and is different from "Commodity derivatives expense (income)" in the Consolidated Statements of Operations in that the noncash fair value adjustments on commodity derivatives represent only the net change between periods of the fair market values of open commodity derivative positions, and exclude the impact of cash settlements on commodity derivatives during the period. Management believes that noncash fair value adjustments on commodity derivatives is a useful supplemental disclosure to "Commodity derivatives expense (income)" because the GAAP measure also includes cash settlements on commodity derivatives during the period; the non-GAAP measure is widely used within the industry and by securities analysts, banks and credit rating agencies within the calculation of EBITDA and in adjusting net income to present those measures on a comparative basis across companies, as well as to assess compliance with certain debt covenants.

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