Exhibit

PLANO, TX – November 5, 2015 – Denbury Resources Inc. (NYSE: DNR) (“Denbury” or the “Company”) today announced adjusted net income⁽¹⁾ (a non-GAAP measure) of $63 million for the third quarter of 2015, or $0.18⁽¹⁾⁽²⁾ per diluted share. On a GAAP basis, the Company recorded a net loss of $2.2 billion, or $6.41 per diluted share. Adjusted net income⁽¹⁾ for the third quarter of 2015 differs from GAAP net income due to the exclusion of (1) a $1.8 billion ($1.1 billion after tax) write-down of oil and natural gas properties, (2) a $1.3 billion ($1.2 billion after tax) impairment of goodwill, (3) a $69 million ($43 million after tax) loss on noncash fair value adjustments on commodity derivatives⁽¹⁾(a non-GAAP measure), and (4) a $14 million lease operating expense reduction due to insurance and other expense reimbursements.



	Quarter Ended
(in millions, except per share and unit data)	Sept. 30, 2015	June 30, 2015	Sept. 30, 2014
Net income (loss)	$(2,244)	$(1,148)	$269
Adjusted net income⁽¹⁾ (non-GAAP measure)	63	47	91
Net income (loss) per diluted share	(6.41)	(3.28)	0.77
Adjusted net income per diluted share⁽¹⁾⁽²⁾ (non-GAAP measure)	0.18	0.13	0.26
Cash flows from operations	273	289	340
Adjusted cash flows from operations⁽¹⁾⁽³⁾ (non-GAAP measure)	243	252	316

Revenues	$300	$374	$633
Receipt (payment) on settlements of commodity derivatives	161	124	(25)
Revenues and commodity derivative settlements combined	$461	$498	$608

Average realized oil price per barrel (excluding derivative settlements)	$45.74	$56.92	$94.78
Average realized oil price per barrel (including derivative settlements)	$71.32	$76.30	$90.92

Total production (BOE/d)	71,410	73,716	73,810


⁽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⁾	Calculated using average diluted shares outstanding of 350.9 million and 351.1 million for the three months ended September 30, 2015 and June 30, 2015, respectively.


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

- 1 -

Sequentially, adjusted net income⁽¹⁾ increased $16 million for the third quarter of 2015 compared to second quarter of 2015 levels, primarily driven by lower operating costs and lower depletion, depreciation and amortization expense, offset in part by the impact of lower oil and natural gas revenues and commodity derivative settlements combined. Adjusted net income⁽¹⁾ for the third quarter of 2015 decreased $28 million from the prior-year third quarter, due to a decrease in oil revenues (including commodity derivative settlements) between the quarters, largely offset by reductions in all categories of expenses during the third quarter of 2015. Adjusted cash flows from operations⁽¹⁾⁽³⁾(a non-GAAP measure) decreased $9 million on a sequential-quarter basis and decreased $73 million from the level in the prior-year third quarter, primarily as a result of the same drivers of the changes in adjusted net income⁽¹⁾.

Phil Rykhoek, Denbury’s President and CEO, commented, “We are continuing to see the benefits from the work of our innovation and improvement teams and cost reduction efforts, which have helped mitigate the impact of lower oil prices. These efforts have resulted in the seventh consecutive quarterly drop in lease operating expenses, to a normalized level in the third quarter of $19.43 per barrel (“Bbl”) of oil equivalent (“BOE”), and a decrease of 26% from the fourth quarter of 2013 level. A major factor in our operating expense improvement is the continued reduction in our use of carbon dioxide (“CO₂”), which is down 11% sequentially and 31% from the first quarter of 2015 levels. Also, as a result of our cost reduction efforts and capital discipline, we have been able to reduce our estimated 2015 development capital budget by a total of $95 million. We reduced our 2015 capital estimate by $50 million a couple of months ago and, as of today, we are lowering it an additional $45 million. We now estimate our 2015 total capital spending at $475 million, comprised of $370 million in development capital spending and $105 million of other capital costs, including capitalized internal costs, capitalized interest and pre-production startup costs. Although we experienced a slight decrease in our production this quarter, primarily attributable to Tinsley and Cedar Creek Anticline (“CCA”) fields, a portion of this drop is temporary and is expected to come back online in the fourth quarter. Also, we currently estimate that we have approximately 1,100 BOE per day (“BOE/d”) of uneconomic production shut-in. Due largely to this shut-in production and the weather impacts at Thompson Field in the second and third quarters of 2015, we refined our 2015 production expectations earlier in the third quarter to indicate that we expect production will be in the lower half of our guidance range. The bottom line is that we are making decisions and taking actions that will improve our business every day, even if those decisions and actions may have some temporary impacts on production.

quarter, and the suspension of the dividend frees up $88 million in cash annually that we can judiciously deploy elsewhere. We have applied much of our free cash this year to reducing our bank debt, which is down to $210 million at the end of the third quarter, from $395 million at year-end 2014. We remain committed to living within cash flow for 2016 and prudently managing our bank debt, which means, among other things, that our development capital spending will likely be in the $300 million to $350 million range for 2016 based on current oil price projections. I am excited about our progress in this lower oil price environment and am confident that we are paving the way for a much stronger Denbury when oil prices recover.”

Denbury’s total production for the third quarter of 2015 averaged 71,410 BOE/d, which included 40,834 Bbls per day (“Bbls/d”) from tertiary properties and 30,576 BOE/d from non-tertiary properties. Total production during the third quarter of 2015 decreased 3% both sequentially and when compared to the third quarter of 2014, primarily due to natural production declines at the Company’s mature tertiary properties in the Gulf Coast region and CCA in the Rocky Mountain region, as well as a temporary production decline at Tinsley Field and a contractual reversionary interest assignment at Delhi Field, each of which is discussed in further detail below. In addition, the Company currently estimates that approximately 1,100 BOE/d of production (excluding Riley Ridge) is shut-in due to wells that are uneconomic to either produce or repair at this time. These decreases in production were partially offset by production increases at Oyster Bayou Field in the Gulf Coast region and Bell Creek Field in the Rocky Mountain region. Third quarter of 2015 production was 95% oil, compared to 96% oil in the same prior-year period.

Tertiary oil production during the third quarter of 2015 decreased 4%, or 1,750 Bbls/d, on a sequential-quarter basis and 2%, or 793 Bbls/d, from levels in the third quarter of 2014. On a sequential-quarter basis, the tertiary oil production decrease was primarily driven by facility processing constraints and impacts of warmer temperatures restricting CO₂ injection and recycling at Tinsley Field; however, current production from the field is increasing and fourth quarter production is expected to be higher than production in the third quarter of 2015. The sequential decrease was partially offset by a production increase at Bell Creek Field. The year-over-year quarterly production decrease was also impacted by the contractual reversionary assignment in Delhi Field occurring on November 1, 2014, which reduced third quarter of 2015 production by approximately 1,200 Bbls/d, partially offset by production growth at Oyster Bayou Field.

Oil and natural gas revenues, excluding the impact of derivative contracts, decreased 53% when comparing the third quarters of 2015 and 2014, primarily due to a 50% decline in realized commodity prices and a 3% decrease in production. Denbury’s average realized oil price, excluding derivative settlements, was $45.74 per Bbl in the third quarter of 2015, compared to $56.92 per Bbl in the second quarter of 2015 and $94.78 per Bbl in the prior-year third quarter. Including derivative settlements, Denbury’s average realized oil price was $71.32 per Bbl in the third quarter of 2015, compared to $76.30 in the second quarter of 2015 and $90.92 per Bbl in the prior-year third quarter. The oil price realized relative to NYMEX oil prices (the Company’s NYMEX oil price differential) in the third quarter of 2015 was $0.96 per Bbl below NYMEX prices, compared to a differential of $0.89 per Bbl below NYMEX in the second quarter of 2015 and $2.53 per Bbl below NYMEX in the third quarter of 2014.

The Company’s total lease operating expenses in the third quarter of 2015 averaged $17.34 per BOE, which includes insurance and other expense reimbursements recognized during the quarter totaling approximately $14 million, comprised of a reimbursement for a retroactive utility rate adjustment ($10 million) and an insurance reimbursement for previous well control costs ($4 million). Lease operating expenses, excluding these nonrecurring amounts, averaged $19.43 per BOE in the third quarter of 2015, a decrease of 1% from the $19.70 per-BOE average in the second quarter of 2015 and 20% from the $24.32 per-BOE average in the third quarter of 2014. These decreases in lease operating costs are primarily due to the Company’s cost reduction efforts throughout 2014 and 2015, as well as general market decreases in the prices of many of the components of these costs.

As a result of the significant decrease in commodity pricing from fourth quarter 2014 levels, the Company recognized full cost pool ceiling test write-downs of $1.8 billion, $1.7 billion and $0.2 billion during the three months ended September 30, 2015, June 30, 2015, and March 31, 2015, respectively. In determining these write-downs, the Company is required to use the average of rolling first-day-of-the-month oil and gas prices for the preceding 12 months, after adjustments for market differentials by field. The preceding 12-month price averaged $56.74 per Bbl for crude oil and $3.64 per thousand cubic feet (“Mcf”) for natural gas for the period ended September 30, 2015. The Company currently estimates that the full cost ceiling test write-down in the fourth quarter of 2015 will be in a range of similar magnitude to the write-down recorded in the third quarter of 2015 if oil and natural gas prices remain at or near late-October 2015 levels for the remainder of 2015, depending further, in part, upon changes relative to proved oil and natural gas reserve volumes, future capital expenditures and operating costs.

Based on the results of the Company’s goodwill impairment test performed for the third quarter of 2015, the Company recorded a goodwill impairment charge of $1.3 billion to fully impair the carrying value of the Company’s goodwill. Of the Company’s $1.3 billion goodwill balance, approximately $1.0 billion was associated with the Company’s 2010 merger with Encore Acquisition Company. The significant decline in the Company's enterprise value (market capitalization and fair value of debt) at a rate greater than the decline in NYMEX oil futures prices between June 30 and September 30, 2015, was a primary cause of the impairment.

Denbury’s overall depletion, depreciation, and amortization (“DD&A”) rate was $18.48 per BOE in the third quarter of 2015, compared to $21.58 per BOE in the prior-year third quarter and $22.05 per BOE in the second quarter of 2015, with the decreases primarily driven by a reduction in depletable costs associated with the Company’s reserves base resulting from the full cost pool ceiling test write-downs recognized during the first half of 2015. Based on full cost pool ceiling test write-downs recognized during the nine months ended September 30, 2015, the DD&A rate for the fourth quarter of 2015 is expected to decrease further from the third quarter of 2015 rate.

Receipts on settlements of oil and natural gas derivative contracts were $161 million in the third quarter of 2015, compared to receipts of $124 million in the second quarter of 2015 and payments of $25 million in the prior-year third quarter. These settlements resulted in an increase in average net realized oil prices of $25.58 per Bbl in the third quarter of 2015, an increase of $19.38 per Bbl in the second quarter of 2015, and a decrease of $3.86 per Bbl in the third quarter of 2014. Changes in the fair values of the

Denbury’s effective tax rate for the third quarter of 2015 was 24.6%, down from 38.4% in the prior-year third quarter primarily as a result of the impairment of goodwill during the quarter. As a significant portion of the $1.3 billion goodwill balance that was written off for financial reporting purposes did not have a related tax basis, there was no corresponding tax benefit realized related to the impairment. The Company’s estimated statutory rate remained at 38%, consistent with the prior-year third quarter.

In the second half of 2015, the Company has reduced its estimated 2015 development capital expenditure budget by $95 million, offset in part by higher capitalized interest, lowering its overall 2015 estimated capital spending budget to $475 million, down from the previously estimated total capital spending amount of $550 million. The capital budget consists of approximately $370 million of tertiary, non-tertiary, and CO₂ supply and pipeline projects, plus approximately $105 million of estimated capitalized costs (including capitalized internal acquisition, exploration and development costs; capitalized interest; and pre-production startup costs associated with new tertiary floods). Of this combined capital expenditure amount, approximately $313 million (66%) has been incurred through the first nine months of 2015.

In light of the continuing low oil price environment and its desire to maintain the Company’s financial strength and flexibility, on September 21, 2015, the Company’s Board of Directors suspended the Company’s quarterly cash dividend following payment of its third quarter dividend on September 29, 2015. Separately, the Company’s Board of Directors authorized the reinstatement of the ability to repurchase shares under the Company’s share repurchase program, which authorization had been suspended in November of 2014. During September and October of 2015, the Company repurchased 4.4 million shares of Denbury common stock for approximately $12 million. Approximately $210 million remains authorized

Denbury management will host a conference call to review and discuss third quarter 2015 financial and operating results, as well as financial and operating guidance for the remainder of 2015 and preliminary estimates of 2016 capital expenditure levels, today, Thursday, November 5, at 10:00 A.M. (Central). Additionally, Denbury has published presentation materials which will be referenced during the conference call. 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 webcast of the conference call and accompanying slide presentation, please visit the investor relations section of the Company’s website at www.denbury.com. The webcast will be archived on the website, and a telephonic replay will be accessible for at least one month after the call by dialing 800.475.6701 or 320.365.3844 and entering confirmation number 324019.

Denbury is an independent oil and natural gas company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions. The Company’s goal is to increase the value of its properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO₂ enhanced oil 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 2015 production and capital expenditures, estimated cash generated from operations in 2015, estimated 2016 capital expenditures, and other risks and uncertainties detailed in the Company’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, 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. In addition, any forward-looking statements represent the Company’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.



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
In thousands, except per share data	2015			2014			2015			2014
Revenues and other income
Oil sales	$	285,742		$	615,745		$	939,744		$	1,876,524
Natural gas sales	4,646			6,260			15,005			26,356
CO₂ and helium sales and transportation fees	9,144			11,378			23,268			33,961
Interest income and other income	4,068			4,274			9,926			14,680
Total revenues and other income	303,600			637,657			987,943			1,951,521
Expenses
Lease operating expenses	113,902			155,198			387,156			488,827
Marketing and plant operating expenses	14,458			15,328			40,358			50,263
CO₂ and helium discovery and operating expenses	1,017			11,434			2,909			22,229
Taxes other than income	25,607			39,966			85,841			136,761
General and administrative expenses	32,907			40,366			117,134			123,011
Interest, net of amounts capitalized of $8,081, $5,862, $25,228 and $17,413, respectively	39,225			44,752			119,187			140,136
Depletion, depreciation, and amortization	121,406			146,560			419,304			435,854
Commodity derivatives expense (income)	(92,028		)	(252,265		)	(126,178		)	(825		)
Loss on early extinguishment of debt	—			—			—			113,908
Write-down of oil and natural gas properties	1,760,600			—			3,612,600			—
Impairment of goodwill	1,261,512			—			1,261,512			—
Total expenses	3,278,606			201,339			5,919,823			1,510,164
Income (loss) before income taxes	(2,975,006		)	436,318			(4,931,880		)	441,357
Income tax provision (benefit)
Current income taxes	1,184			214			1,063			532
Deferred income taxes	(732,064		)	167,356			(1,432,572		)	168,967
Net income (loss)	$	(2,244,126	)	$	268,748		$	(3,500,371	)	$	271,858

Net income (loss) per common share
Basic	$	(6.41	)	$	0.77		$	(10.01	)	$	0.78
Diluted	$	(6.41	)	$	0.77		$	(10.01	)	$	0.77

Dividends declared per common share	$	0.0625		$	0.0625		$	0.1875		$	0.1875

Weighted average common shares outstanding
Basic	350,052			348,454			349,787			348,993
Diluted	350,052			350,918			349,787			351,347



	Three Months Ended									Nine Months Ended
	September 30,						June 30,			September 30,
In thousands	2015			2014			2015			2015			2014
Net income (loss) (GAAP measure)	$	(2,244,126	)	$	268,748		$	(1,148,499	)	$	(3,500,371	)	$	271,858
Noncash fair value adjustments on commodity derivatives	68,649			(277,179		)	173,077			307,115			(103,080		)
Lease operating expenses – nonrecurring amounts	(13,715		)	(9,906		)	—			(13,715		)	(9,906		)
Loss on early extinguishment of debt	—			—			—			—			113,908
Write-down of oil and natural gas properties	1,760,600			—			1,705,800			3,612,600			—
Impairment of goodwill	1,261,512			—			—			1,261,512			—
Estimated income taxes on above adjustments to net income (loss)	(769,497		)	109,093			(713,973		)	(1,563,874		)	(350		)
Valuation allowance on deferred taxes	—			—			30,500			30,500			—
Adjusted net income (non-GAAP measure)	$	63,423		$	90,756		$	46,905		$	133,767		$	272,430



	Three Months Ended									Nine Months Ended
In thousands	September 30,						June 30,			September 30,
In thousands	2015			2014			2015			2015			2014
Net income (loss) (GAAP measure)	$	(2,244,126	)	$	268,748		$	(1,148,499	)	$	(3,500,371	)	$	271,858
Adjustments to reconcile to adjusted cash flows from operations
Depletion, depreciation, and amortization	121,406			146,560			147,940			419,304			435,854
Deferred income taxes	(732,064		)	167,356			(634,472		)	(1,432,572		)	168,967
Stock-based compensation	7,670			8,887			7,118			22,637			26,104
Noncash fair value adjustments on commodity derivatives	68,649			(277,179		)	173,077			307,115			(103,080		)
Loss on early extinguishment of debt	—			—			—			—			113,908
Write-down of oil and natural gas properties	1,760,600			—			1,705,800			3,612,600			—
Impairment of goodwill	1,261,512			—			—			1,261,512			—
Other	(1,129		)	1,820			620			(647		)	5,396
Adjusted cash flows from operations (non-GAAP measure)	242,518			316,192			251,584			689,578			919,007
Net change in assets and liabilities relating to operations	30,158			24,200			37,373			9,819			(33,910		)
Cash flows from operations (GAAP measure)	$	272,676		$	340,392		$	288,957		$	699,397		$	885,097



	Three Months Ended									Nine Months Ended
	September 30,						June 30,			September 30,
In thousands	2015			2014			2015			2015			2014
Receipt (payment) on settlements of commodity derivatives	$	160,677		$	(24,914	)	$	124,151		$	433,293		$	(102,255	)
Noncash fair value adjustments on commodity derivatives (non-GAAP measure)	(68,649		)	277,179			(173,077		)	(307,115		)	103,080
Commodity derivatives income (expense) (GAAP measure)	$	92,028		$	252,265		$	(48,926	)	$	126,178		$	825



	Three Months Ended									Nine Months Ended
	September 30,						June 30,			September 30,
	2015			2014			2015			2015			2014
Production (daily – net of royalties)
Oil (barrels)	67,900			70,619			69,837			69,424			70,504
Gas (mcf)	21,066			19,147			23,273			22,357			22,671
BOE (6:1)	71,410			73,810			73,716			73,150			74,283
Unit sales price (excluding derivative settlements)
Oil (per barrel)	$	45.74		$	94.78		$	56.92		$	49.58		$	97.49
Gas (per mcf)	2.40			3.55			2.44			2.46			4.26
BOE (6:1)	44.20			91.60			54.69			47.81			93.83
Unit sales price (including derivative settlements)
Oil (per barrel)	$	71.32		$	90.92		$	76.30		$	72.31		$	92.22
Gas (per mcf)	2.87			3.61			2.89			2.89			4.13
BOE (6:1)	68.66			87.93			73.20			69.51			88.79
NYMEX differentials
Gulf Coast region
Oil (per barrel)	$	0.92		$	2.15		$	1.86		$	0.88		$	1.97
Gas (per mcf)	(0.22		)	(0.18		)	(0.10		)	(0.18		)	0.09
Rocky Mountain region
Oil (per barrel)	$	(4.73	)	$	(11.96	)	$	(6.48	)	$	(6.33	)	$	(10.52	)
Gas (per mcf)	(0.55		)	(0.66		)	(0.68		)	(0.52		)	(0.48		)
Total company
Oil (per barrel)	$	(0.96	)	$	(2.53	)	$	(0.89	)	$	(1.52	)	$	(2.16	)
Gas (per mcf)	(0.34		)	(0.40		)	(0.30		)	(0.30		)	(0.16		)



	Three Months Ended			Nine Months Ended
	September 30,		June 30,	September 30,
Average Daily Volumes (BOE/d) (6:1)	2015	2014	2015	2015	2014
Tertiary oil production
Gulf Coast region
Mature properties
Brookhaven	1,712	1,767	1,691	1,672	1,820
Eucutta	1,922	2,224	2,054	1,961	2,185
Mallalieu	1,427	1,869	1,537	1,512	1,848
Other mature properties ⁽¹⁾	5,885	6,189	5,888	5,828	6,209
Total mature properties	10,946	12,049	11,170	10,973	12,062
Delhi	3,676	4,377	3,623	3,617	4,542
Hastings	5,114	4,917	5,350	5,054	4,766
Heidelberg	5,600	5,721	5,885	5,836	5,553
Oyster Bayou	5,962	4,605	5,936	5,920	4,361
Tinsley	7,311	8,310	8,740	8,320	8,419
Total Gulf Coast region	38,609	39,979	40,704	39,720	39,703
Rocky Mountain region
Bell Creek	2,225	1,648	1,880	2,025	1,108
Total Rocky Mountain region	2,225	1,648	1,880	2,025	1,108
Total tertiary oil production	40,834	41,627	42,584	41,745	40,811
Non-tertiary oil and gas production
Gulf Coast region
Mississippi	1,592	2,346	1,400	1,584	2,391
Texas	6,508	5,537	6,304	6,434	6,160
Other	846	1,083	906	919	1,056
Total Gulf Coast region	8,946	8,966	8,610	8,937	9,607
Rocky Mountain region
Cedar Creek Anticline	17,515	18,623	18,089	18,038	18,927
Other	4,115	4,594	4,433	4,430	4,938
Total Rocky Mountain region	21,630	23,217	22,522	22,468	23,865
Total non-tertiary production	30,576	32,183	31,132	31,405	33,472
Total production	71,410	73,810	73,716	73,150	74,283



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
Oil and natural gas revenues	$	44.20		$	91.60		$	47.81		$	93.83
Receipt (payment) on settlements of commodity derivatives	24.46			(3.67		)	21.70			(5.04		)
Lease operating expenses – excluding nonrecurring amounts	(19.43		)	(24.32		)	(20.08		)	(24.59		)
Lease operating expenses – nonrecurring amounts	2.09			1.46			0.69			0.49
Production and ad valorem taxes	(3.19		)	(5.34		)	(3.69		)	(6.22		)
Marketing expenses, net of third-party purchases, and plant operating expenses	(1.91		)	(1.63		)	(1.75		)	(1.82		)
Production netback	46.22			58.10			44.68			56.65
CO₂ and helium sales, net of operating and exploration expenses	1.24			—			1.02			0.57
General and administrative expenses	(5.01		)	(5.94		)	(5.87		)	(6.07		)
Interest expense, net	(5.97		)	(6.59		)	(5.97		)	(6.91		)
Other	0.43			1.00			0.67			1.08
Changes in assets and liabilities relating to operations	4.59			3.56			0.49			(1.67		)
Cash flows from operations	41.50			50.13			35.02			43.65
DD&A	(18.48		)	(21.58		)	(21.00		)	(21.49		)
Write-down of oil and natural gas properties	(267.99		)	—			(180.90		)	—
Impairment of goodwill	(192.02		)	—			(63.17		)	—
Deferred income taxes	111.43			(24.65		)	71.74			(8.33		)
Loss on early extinguishment of debt	—			—			—			(5.62		)
Noncash fair value adjustments on commodity derivatives	(10.45		)	40.82			(15.38		)	5.08
Other noncash items	(5.57		)	(5.14		)	(1.59		)	0.12
Net income (loss)	$	(341.58	)	$	39.58		$	(175.28	)	$	13.41



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
In thousands	2015		2014		2015		2014
Capital expenditures by project
Tertiary oil fields	$	36,845	$	156,414	$	133,439	$	442,810
Non-tertiary fields	22,620		63,727		75,199		186,708
Capitalized interest and internal costs ⁽²⁾	23,736		21,735		72,235		67,437
Oil and natural gas capital expenditures	83,201		241,876		280,873		696,955
CO₂ pipelines	3,839		12,256		10,135		24,612
CO₂ sources ⁽³⁾	7,204		9,265		17,686		37,502
CO₂ capitalized interest and other	1,213		779		3,816		2,831
Capital expenditures, before acquisitions	95,457		264,176		312,510		761,900
Acquisitions of oil and natural gas properties	796		1,683		22,755		1,683
Capital expenditures, total	$	96,253	$	265,859	$	335,265	$	763,583



	September 30,		December 31,
In thousands	2015		2014
Cash and cash equivalents	$	12,212	$	23,153
Total assets	7,355,152		12,727,802

Borrowings under bank credit facility	$	210,000	$	395,000
Borrowings under senior subordinated notes (principal only)	2,852,250		2,852,735
Financing and capital leases	295,095		323,624
Total debt (principal only)	$	3,357,345	$	3,571,359

Total stockholders' equity	$	2,136,332	$	5,703,856

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 write-down of oil and natural gas properties, impairment of goodwill, noncash fair value adjustments on the Company’s commodity derivative contracts, nonrecurring lease operating expenses, the cost of early debt extinguishment, and a valuation allowance on deferred taxes. 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 flows from operations is a non-GAAP measure that represents cash flows provided by operations before changes in assets and liabilities, as summarized from the Company’s Consolidated Statements of Cash Flows. Adjusted cash flows from operations measures the cash flows 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 flows 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 represents only the net change between periods of the fair market values of open commodity derivative positions, and excludes the impact of 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 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 in calculating 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.



Operating Area		2015 Estimated Production (BOE/d)
Tertiary		42,100 – 43,700
Cedar Creek Anticline		18,000 – 18,800
Gulf Coast Non-Tertiary		8,300 – 8,700
Other Rockies Non-Tertiary		4,100 – 4,300
Total Production		72,500 – 75,500



	Nine Months Ended
	September 30,
In thousands	2015			2014
Cash provided by (used in)
Operating activities	$	699,397		$	885,097
Investing activities	(427,540		)	(788,923		)
Financing activities	(282,798		)	(88,925		)

Cash dividends paid	65,422			65,241


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


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


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