Exhibit

PLANO, TX – November 7, 2017 – Denbury Resources Inc. (NYSE: DNR) (“Denbury” or the “Company”) today announced net income of $0.4 million, or $0.00 per diluted share, for the third quarter of 2017. Excluding special items, the Company reported adjusted net income⁽¹⁾ (a non-GAAP measure) for the quarter of $14 million, or $0.04⁽¹⁾⁽²⁾ per diluted share. Adjusted net income⁽¹⁾ for the third quarter of 2017 differs from the quarter’s GAAP net income due to the exclusion of $25 million ($16 million after tax) of expense from noncash fair value adjustments on commodity derivatives⁽¹⁾(a non-GAAP measure) and $7 million in severance-related payments associated with the Company’s workforce reduction, offset in part by a $9 million tax benefit for enhanced oil recovery income tax credits and other tax adjustments, with the GAAP and non-GAAP measures reconciled in tables beginning on page 7.



	Quarter Ended
($ in millions, except per-share and unit data)	Sept. 30, 2017		June 30, 2017			Sept. 30, 2016
Net income (loss)	$	0	$	14		$	(25	)
Adjusted net income⁽¹⁾ (non-GAAP measure)	14		1			1
Net income (loss) per diluted share	0.00		0.04			(0.06		)
Adjusted net income per diluted share⁽¹⁾⁽²⁾ (non-GAAP measure)	0.04		0.00			0.00
Cash flows from operations	66		53			96
Adjusted cash flows from operations⁽¹⁾ (non-GAAP measure)	68		65			62

Revenues	$	266	$	257		$	246
Receipt (payment) on settlements of commodity derivatives	0		(12		)	(7		)
Revenues and commodity derivative settlements combined	$	266	$	245		$	239

Average realized oil price per barrel (excluding derivative settlements)	$	47.78	$	47.16		$	43.45
Average realized oil price per barrel (including derivative settlements)	47.80		44.92			42.12

Total continuing production (BOE/d)⁽³⁾	60,328		59,774			60,714


(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 weighted average diluted shares outstanding of 393.0 million, 391.8 million, and 390.2 million for the three months ended September 30, 2017, June 30, 2017 and September 30, 2016, respectively.


(3)	Total continuing production excludes production from the Williston Basin sold during the third quarter of 2016.

Chris Kendall, Denbury’s President and CEO, commented, “We made great progress on several fronts in the third quarter, reflecting both the quality of our assets and, more importantly, the dedication of our workforce to Denbury’s long-term success. Even with the impact of Hurricane Harvey, we arrested the production decline that began in early 2015. We expect production to further increase in the fourth quarter, positioning us nicely heading into 2018. We made significant improvements in our cost structure, both through a workforce reduction and other identified cost savings, and held our normalized LOE flat with the second quarter. Our capital discipline, combined with our low decline, low capital intensity asset base, delivered yet another quarter of investing within cash flow, and we expect cash flow and development capital to be nearly balanced for the full year. Finally, our bank group recently reaffirmed the $1.05 billion borrowing base of our bank credit facility, ensuring a continued strong liquidity cushion as we head into 2018.”

Denbury’s production averaged 60,328 barrels of oil equivalent (“BOE”) per day (“BOE/d”) during the third quarter of 2017, up 1% (554 BOE/d) from the second quarter of 2017. Denbury’s production for the current quarter was reduced by approximately 2,000 BOE/d due to Hurricane Harvey, while the acquisition of Salt Creek Field on June 30, 2017 added approximately 2,200 BOE/d. Due to conditions associated with Hurricane Harvey, the Company suspended operations and temporarily shut-in all production at its Houston area fields (including Hastings, Oyster Bayou, Conroe, Thompson, Webster and Manvel fields) for an approximate 10-day period, representing net production of approximately 16,000 BOE/d, and the only field that remained partially shut-in was Thompson Field. Thompson Field had net production just prior to the storm of approximately 1,000 BOE/d, nearly all of which has now been returned to production. Further production information is provided on page 11 of this press release.

Denbury’s average realized oil price per barrel (“Bbl”), excluding derivative settlements, was $47.78 in the third quarter of 2017, compared to $47.16 in the second quarter of 2017, and $43.45 in the prior-year third quarter. Including derivative settlements, Denbury’s average realized oil price per Bbl was $47.80 in the third quarter of 2017, compared to $44.92 in the second quarter of 2017, and $42.12 in the prior-year third quarter. The Company’s realized oil price in the third quarter of 2017 was $0.34 per Bbl below NYMEX oil prices, compared to $1.16 per Bbl below NYMEX in the second quarter of 2017, and $1.57 per Bbl below NYMEX in the third quarter of 2016, with the improvement in the price differential impacted by the improvement in LLS index prices relative to NYMEX, as well as continued improvement in Rocky Mountain region differentials during the third quarter of 2017. During the third quarter of 2017, the Company sold approximately 65% of its crude oil at prices based on, or partially tied to, the LLS index

Receipts on settlements of oil derivative contracts were $0.1 million in the third quarter of 2017, compared to payments of $12 million in the second quarter of 2017, and payments of $7 million in the third quarter of 2016. The prior-period settlements resulted in a decrease in average net realized prices of $2.24 per Bbl in the second quarter of 2017 and a decrease of $1.33 per Bbl in the third quarter of 2016.

The Company’s total lease operating expenses in the third quarter of 2017 were $118 million, an increase of $6 million, or 6%, on an absolute-dollar basis when compared to those in the second quarter of 2017, and an increase of $11 million, or 11%, when compared to the third quarter of 2016. The higher expense in the third quarter of 2017 was due primarily to the Company’s acquisition of a non-operated working interest in Salt Creek Field on June 30, 2017, and to a lesser degree associated with increases related to clean-up expenses for Hurricane Harvey and higher CO₂ expense, primarily due to costs associated with a CO₂ well workoverduring the third quarter of 2017. Offsetting these increases were lower expenses across various categories, a portion of which is due to the down-time associated with fields impacted by Hurricane Harvey. During the third quarter of 2017, the Company’s CO₂ use averaged 487 million cubic feet per day, an increase of 6% when compared to the third quarter of 2016 and a decrease of 20% when compared to the second quarter of 2017. The increase in CO₂ use when compared to prior year is primarily attributable to the Hastings redevelopment project, with the sequential decrease impacted by Hurricane Harvey in the third quarter of 2017, as well as a decrease in injected volumes at Grieve Field, as the field had reached its target operating pressure.

General and administrative expenses were $27 million in the third quarter of 2017, an increase of $1 million when compared to the second quarter of 2017 and an increase of $3 million when compared to the third quarter of 2016, with the increase during both periods attributable to severance-related payments associated with the August 2017 workforce reduction, partially offset by overall reductions in compensation-related expenses due to lower headcount.

Interest expense, net of capitalized interest, totaled $25 million in the third quarter of 2017, relatively unchanged from the third quarter of 2016. Interest expense in the third quarters of 2017 and 2016 exclude approximately $13 million of interest on the Company’s 9% Senior Secured Second Lien Notes due 2021, which was recorded as debt for financial reporting purposes and is therefore not reflected as interest expense. A schedule detailing the components of interest expense is included on page 13 of this press release.

Denbury’s effective tax rate for the three and nine months ended September 30, 2017 differed from the Company’s statutory rate of 38%, primarily due to the impact of recognizing a tax benefit of $9 million in the current quarter for enhanced oil recovery credits, which was offset in part by stock-based compensation shortfalls (tax deduction less than book expense) of $2 million and $6 million for the three and nine months ended September 30, 2017, respectively. With pre-tax income for the three months ended September 30, 2017 being close to break-even, the net tax benefit from these items had a significant impact on the current quarter’s effective tax rate.

As of September 30, 2017, the Company had a total of $495 million of borrowings outstanding under its Facility, compared to $490 million as of June 30, 2017 and $301 million as of December 31, 2016. The $194 million increase in borrowings over the nine-month period is primarily due to the Company’s capital expenditure level, which includes $91 million of oil and natural gas property acquisitions in the first nine months of 2017, $52 million of cash outflows for working capital changes, and repayments of other non-bank debt of $46 million. After consideration of $62 million of outstanding letters of credit, the Company had $493 million of borrowing base availability as of September 30, 2017. Assuming oil prices remain in the low-to-mid $50’s per Bbl for the remainder of 2017, and based on currently-projected cash flows and capital spending levels, the Company anticipates that its bank debt at the end of 2017 should be in the range of $450 to $475 million.

The Company’s 2017 capital budget, excluding acquisitions and capitalized interest, remains unchanged from the previously estimated amount of approximately $250 million. The capital budget consists of approximately $195 million of tertiary, non-tertiary, and CO₂ supply and pipeline projects, plus approximately $55 million of estimated capitalized costs (including capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs). Of this combined capital expenditure amount, approximately $181 million (72%) has been incurred through the third quarter of 2017. Prior to Hurricane Harvey, the Company was on track to meet the midpoint of its 60,000 to 62,000 BOE/d full-year production guidance range. Considering the previously mentioned and still anticipated

Denbury management will host a conference call to review and discuss third quarter 2017 financial and operating results, as well as financial and operating guidance for 2017, today, Tuesday, November 7, at 10:00 A.M. (Central). Additionally, Denbury has published presentation materials on its website which will be referenced during the conference call. Individuals who would like to participate should dial 800.230.1093 or 612.332.0226 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 426557.

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 2017 production, capital expenditures, bank debt levels 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,						June 30,			September 30,
In thousands, except per-share data	2017			2016			2017			2017			2016
Revenues and other income
Oil sales	$	256,621		$	237,053		$	248,317		$	768,912		$	666,441
Natural gas sales	2,409			2,877			2,563			7,176			7,960
CO₂ sales and transportation fees	6,590			6,253			6,555			18,533			19,147
Interest income and other income	939			7,802			3,749			8,576			10,429
Total revenues and other income	266,559			253,985			261,184			803,197			703,977
Expenses
Lease operating expenses	117,768			106,522			111,318			342,926			308,988
Marketing and plant operating expenses	11,816			14,452			13,877			39,758			40,645
CO₂ discovery and operating expenses	1,346			861			513			2,452			2,539
Taxes other than income	20,233			20,401			20,175			62,848			59,997
General and administrative expenses	27,273			24,643			25,789			81,303			81,089
Interest, net of amounts capitalized of $9,416, $6,875, $8,147, $22,217 and $18,944, respectively	24,546			24,778			24,061			75,785			103,007
Depletion, depreciation, and amortization	52,101			55,012			51,152			154,448			198,919
Commodity derivatives expense (income)	25,263			(21,224		)	(10,373		)	(9,712		)	99,811
Gain on debt extinguishment	—			(7,826		)	—			—			(115,095		)
Write-down of oil and natural gas properties	—			75,521			—			—			810,921
Other expenses	—			—			—			—			36,232
Total expenses	280,346			293,140			236,512			749,808			1,627,053
Income (loss) before income taxes	(13,787		)	(39,155		)	24,672			53,389			(923,076		)
Income tax provision (benefit)
Current income taxes	1,072			(1,046		)	(5,965		)	(18,828		)	(1,051		)
Deferred income taxes	(15,301		)	(13,519		)	16,238			35,846			(331,574		)
Net income (loss)	$	442		$	(24,590	)	$	14,399		$	36,371		$	(590,451	)

Net income (loss) per common share
Basic	$	—		$	(0.06	)	$	0.04		$	0.09		$	(1.60	)
Diluted	$	—		$	(0.06	)	$	0.04		$	0.09		$	(1.60	)

Weighted average common shares outstanding
Basic	392,013			388,572			389,904			390,448			368,863
Diluted	393,023			388,572			391,827			392,625			368,863

Adjusted net income is a non-GAAP measure provided as a supplement to present an alternative net income (loss) measure which excludes expense and income items (and their related tax effects) not directly related to the Company’s ongoing operations. Management believes that adjusted net income may be helpful to investors by eliminating the impact of noncash and/or special or unusual items not indicative of the Company’s performance from period to period, 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, as a substitute for, or more meaningful than, net income (loss) or any other measure reported in accordance with GAAP, but rather to provide additional information useful in evaluating the Company’s operational trends and performance.



	Three Months Ended
	September 30,												June 30,
	2017						2016						2017
In thousands, except per-share data	Amount			Per Diluted Share			Amount			Per Diluted Share			Amount			Per Diluted Share
Net income (loss) (GAAP measure)	$	442		$	0.00		$	(24,590	)	$	(0.06	)	$	14,399		$	0.04
Adjustments to reconcile to adjusted net income (non-GAAP measure)
Noncash fair value adjustments on commodity derivatives ⁽¹⁾	25,352			0.06			(28,519		)	(0.07		)	(22,140		)	(0.06		)
Write-down of oil and natural gas properties ⁽²⁾	—			—			75,521			0.19			—			—
Gain on debt extinguishment ⁽³⁾	—			—			(7,826		)	(0.02		)	—			—
Severance-related payments included in general and administrative expenses ⁽⁶⁾	6,807			0.02			—			—			—			—
Estimated income taxes on above adjustments to net income (loss) and other discrete tax items ⁽⁸⁾	(18,676		)	(0.04		)	(13,322		)	(0.04		)	8,609			0.02
Adjusted net income (non-GAAP measure)	$	13,925		$	0.04		$	1,264		$	0.00		$	868		$	0.00



	Nine Months Ended
	September 30,
	2017						2016
In thousands, except per-share data	Amount			Per Diluted Share			Amount			Per Diluted Share
Net income (loss) (GAAP measure)	$	36,371		$	0.09		$	(590,451	)	$	(1.60	)
Adjustments to reconcile to adjusted net income (non-GAAP measure)
Noncash fair value adjustments on commodity derivatives ⁽¹⁾	(48,330		)	(0.12		)	216,769			0.59
Write-down of oil and natural gas properties ⁽²⁾	—			—			810,921			2.19
Gain on debt extinguishment ⁽³⁾	—			—			(115,095		)	(0.31		)
Legal settlements included in other expenses ⁽⁴⁾	—			—			30,250			0.08
Write-off of debt issuance costs included in interest expense ⁽⁵⁾	—			—			5,553			0.02
Severance-related payments included in general and administrative expenses ⁽⁶⁾	6,807			0.02			9,315			0.03
Transaction costs and other ⁽⁷⁾	—			—			5,638			0.02
Estimated income taxes on above adjustments to net income (loss) and other discrete tax items ⁽⁸⁾	13,092			0.03			(351,932		)	(0.96		)
Adjusted net income (non-GAAP measure)	$	7,940		$	0.02		$	20,968		$	0.06

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 Unaudited Condensed 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 related factors, without regard to whether the earned or incurred item was collected or paid during that period.



	Three Months Ended									Nine Months Ended
In thousands	September 30,						June 30,			September 30,
In thousands	2017			2016			2017			2017			2016
Net income (loss) (GAAP measure)	$	442		$	(24,590	)	$	14,399		$	36,371		$	(590,451	)
Adjustments to reconcile to adjusted cash flows from operations
Depletion, depreciation, and amortization	52,101			55,012			51,152			154,448			198,919
Deferred income taxes	(15,301		)	(13,519		)	16,238			35,846			(331,574		)
Stock-based compensation	3,274			5,560			4,835			12,215			9,682
Noncash fair value adjustments on commodity derivatives	25,352			(28,519		)	(22,140		)	(48,330		)	216,769
Gain on debt extinguishment	—			(7,826		)	—			—			(115,095		)
Write-down of oil and natural gas properties	—			75,521			—			—			810,921
Other	2,351			(59		)	781			4,689			12,270
Adjusted cash flows from operations (non-GAAP measure) ⁽¹⁾	68,219			61,580			65,265			195,239			211,441
Net change in assets and liabilities relating to operations	(2,568		)	34,835			(12,319		)	(52,380		)	(52,082		)
Cash flows from operations (GAAP measure)	$	65,651		$	96,415		$	52,946		$	142,859		$	159,359

Noncash fair value adjustments on commodity derivatives is a non-GAAP measure and is different from “Commodity derivatives expense (income)” in the Unaudited Condensed 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 (loss) to present those measures on a comparative basis across companies, as well as to assess compliance with certain debt covenants.



	Three Months Ended									Nine Months Ended
	September 30,						June 30,			September 30,
In thousands	2017			2016			2017			2017			2016
Receipt (payment) on settlements of commodity derivatives	$	89		$	(7,295	)	$	(11,767	)	$	(38,618	)	$	116,958
Noncash fair value adjustments on commodity derivatives (non-GAAP measure)	(25,352		)	28,519			22,140			48,330			(216,769		)
Commodity derivatives income (expense) (GAAP measure)	$	(25,263	)	$	21,224		$	10,373		$	9,712		$	(99,811	)



	Three Months Ended									Nine Months Ended
	September 30,						June 30,			September 30,
	2017			2016			2017			2017			2016
Production (daily – net of royalties)
Oil (barrels)	58,376			59,297			57,867			58,182			62,451
Gas (mcf)	11,710			13,416			11,444			10,985			15,995
BOE (6:1)	60,328			61,533			59,774			60,013			65,117
Unit sales price (excluding derivative settlements)
Oil (per barrel)	$	47.78		$	43.45		$	47.16		$	48.41		$	38.95
Gas (per mcf)	2.24			2.33			2.46			2.39			1.82
BOE (6:1)	46.67			42.38			46.12			47.37			37.80
Unit sales price (including derivative settlements)
Oil (per barrel)	$	47.80		$	42.12		$	44.92		$	45.98		$	45.78
Gas (per mcf)	2.24			2.33			2.46			2.39			1.82
BOE (6:1)	46.69			41.09			43.96			45.01			44.35
NYMEX differentials
Gulf Coast region
Oil (per barrel)	$	0.01		$	(0.77	)	$	(0.78	)	$	(0.71	)	$	(1.55	)
Gas (per mcf)	(0.11		)	(0.28		)	(0.03		)	(0.03		)	(0.46		)
Rocky Mountain region
Oil (per barrel)	$	(0.98	)	$	(3.08	)	$	(1.96	)	$	(1.69	)	$	(4.29	)
Gas (per mcf)	(1.38		)	(0.72		)	(1.42		)	(1.25		)	(0.63		)
Total company
Oil (per barrel)	$	(0.34	)	$	(1.57	)	$	(1.16	)	$	(1.04	)	$	(2.51	)
Gas (per mcf)	(0.72		)	(0.47		)	(0.69		)	(0.67		)	(0.53		)



	Three Months Ended			Nine Months Ended
	September 30,		June 30,	September 30,
Average Daily Volumes (BOE/d) (6:1)	2017	2016	2017	2017	2016
Tertiary oil production
Gulf Coast region
Mature properties ⁽¹⁾	7,450	8,653	7,737	7,764	9,242
Delhi	4,619	4,262	4,965	4,857	4,077
Hastings	4,867	4,729	4,400	4,520	4,922
Heidelberg	4,927	5,000	4,996	4,885	5,197
Oyster Bayou	4,870	4,767	5,217	5,053	5,115
Tinsley	6,506	6,756	6,311	6,494	7,328
Total Gulf Coast region	33,239	34,167	33,626	33,573	35,881
Rocky Mountain region
Bell Creek	3,406	3,032	3,060	3,225	3,071
Salt Creek ⁽²⁾	2,228	—	23	759	—
Total Rocky Mountain region	5,634	3,032	3,083	3,984	3,071
Total tertiary oil production	38,873	37,199	36,709	37,557	38,952
Non-tertiary oil and gas production
Gulf Coast region
Mississippi	867	963	1,004	1,069	884
Texas	4,024	4,234	5,002	4,452	4,826
Other	515	538	460	490	515
Total Gulf Coast region	5,406	5,735	6,466	6,011	6,225
Rocky Mountain region
Cedar Creek Anticline	14,535	16,017	15,124	14,907	16,704
Other	1,514	1,763	1,475	1,538	1,898
Total Rocky Mountain region	16,049	17,780	16,599	16,445	18,602
Total non-tertiary production	21,455	23,515	23,065	22,456	24,827
Total continuing production	60,328	60,714	59,774	60,013	63,779
Property sales
2016 property divestitures ⁽³⁾	—	819	—	—	1,338
Total production	60,328	61,533	59,774	60,013	65,117



	Three Months Ended									Nine Months Ended
	September 30,						June 30,			September 30,
	2017			2016			2017			2017			2016
Oil and natural gas revenues	$	46.67		$	42.38		$	46.12		$	47.37		$	37.80
Receipt (payment) on settlements of commodity derivatives	0.02			(1.29		)	(2.16		)	(2.36		)	6.55
Lease operating expenses	(21.22		)	(18.82		)	(20.46		)	(20.93		)	(17.32		)
Production and ad valorem taxes	(3.32		)	(3.18		)	(3.36		)	(3.51		)	(2.93		)
Marketing expenses, net of third-party purchases, and plant operating expenses	(1.75		)	(1.99		)	(1.83		)	(1.82		)	(1.89		)
Production netback	20.40			17.10			18.31			18.75			22.21
CO₂ sales, net of operating and exploration expenses	0.95			0.95			1.12			0.98			0.93
General and administrative expenses	(4.91		)	(4.35		)	(4.74		)	(4.96		)	(4.54		)
Interest expense, net	(4.42		)	(4.38		)	(4.42		)	(4.63		)	(5.77		)
Other	0.27			1.56			1.72			1.78			(0.98		)
Changes in assets and liabilities relating to operations	(0.46		)	6.15			(2.26		)	(3.20		)	(2.92		)
Cash flows from operations	11.83			17.03			9.73			8.72			8.93
DD&A	(9.39		)	(9.72		)	(9.40		)	(9.43		)	(11.15		)
Write-down of oil and natural gas properties	—			(13.34		)	—			—			(45.45		)
Deferred income taxes	2.76			2.39			(2.99		)	(2.19		)	18.58
Gain on debt extinguishment	—			1.38			—			—			6.45
Noncash fair value adjustments on commodity derivatives	(4.57		)	5.04			4.07			2.95			(12.14		)
Other noncash items	(0.55		)	(7.12		)	1.24			2.17			1.69
Net income (loss)	$	0.08		$	(4.34	)	$	2.65		$	2.22		$	(33.09	)



	Three Months Ended						Nine Months Ended
	September 30,				June 30,		September 30,
In thousands	2017		2016		2017		2017		2016
Capital expenditures by project
Tertiary oil fields	$	34,029	$	26,494	$	43,561	$	98,797	$	90,392
Non-tertiary fields	8,251		8,366		14,332		41,023		19,142
Capitalized internal costs ⁽²⁾	11,015		9,729		13,071		37,732		35,516
Oil and natural gas capital expenditures	53,295		44,589		70,964		177,552		145,050
CO₂ pipelines, sources and other	2,718		676		518		3,246		828
Capital expenditures, before acquisitions and capitalized interest	56,013		45,265		71,482		180,798		145,878
Acquisitions of oil and natural gas properties	1,916		9,984		73,001		91,015		10,888
Capital expenditures, before capitalized interest	57,929		55,249		144,483		271,813		156,766
Capitalized interest	9,416		6,875		8,147		22,217		18,944
Capital expenditures, total	$	67,345	$	62,124	$	152,630	$	294,030	$	175,710



	Three Months Ended									Nine Months Ended
	September 30,						June 30,			September 30,
In thousands	2017			2016			2017			2017			2016
Cash interest ⁽¹⁾	$	45,110		$	42,718		$	43,352		$	130,962		$	130,511
Interest on 2021 Senior Secured Notes not reflected as interest for financial reporting purposes ⁽¹⁾	(12,604		)	(12,533		)	(12,588		)	(37,761		)	(19,569		)
Noncash interest expense ⁽²⁾	1,456			1,468			1,444			4,801			11,009
Less: capitalized interest	(9,416		)	(6,875		)	(8,147		)	(22,217		)	(18,944		)
Interest expense, net	$	24,546		$	24,778		$	24,061		$	75,785		$	103,007



	September 30,		December 31,
In thousands	2017		2016
Cash and cash equivalents	$	57	$	1,606
Total assets	4,440,929		4,274,578

Borrowings under senior secured bank credit facility	$	495,000	$	301,000
Borrowings under senior secured second lien notes (principal only) ⁽¹⁾	614,919		614,919
Borrowings under senior subordinated notes (principal only)	1,612,603		1,612,603
Financing and capital leases	229,800		251,389
Total debt (principal only)	$	2,952,322	$	2,779,911

Total stockholders’ equity	$	517,447	$	468,448



	Nine Months Ended
	September 30,
In thousands	2017			2016
Cash provided by (used in)
Operating activities	$	142,859		$	159,359
Investing activities	(294,008		)	(134,007		)
Financing activities	149,600			(24,891		)


(1)	The net change between periods of the fair market values of open commodity derivative positions, excluding the impact of settlements on commodity derivatives during the period.


(2)	Full cost pool ceiling test write-downs related to the Company’s oil and natural gas properties.


(3)	Gain on extinguishment related to the Company’s debt exchange during the three months ended June 30, 2016 and open-market debt repurchases during the three and nine months ended September 30, 2016.


(4)	Settlements related to previously outstanding litigation, the most significant of which pertaining to a $28 million payment to Evolution in connection with the settlement resolving all outstanding disputes and claims.


(5)	Write-off of debt issuance costs associated with the Company’s senior secured bank credit facility, related to the May 2016 redetermination which reduced the Company’s borrowing base, with the nine-month period further impacted by reductions in the Company’s lender commitments resulting from the February 2016 amendment.


(6)	Severance-related payments associated with the Company’s August-2017 and February-2016 workforce reductions.


(7)	Transaction costs related to the Company’s debt exchange and a loss on sublease during the nine months ended September 30, 2016.


(1)	Mature properties include Brookhaven, Cranfield, Eucutta, Little Creek, Lockhart Crossing, Mallalieu, Martinville, McComb and Soso fields.


(2)	Includes production related to the acquisition of a 23% non-operated working interest in Salt Creek Field in Wyoming, which closed on June 30, 2017.


(3)	Includes non-tertiary production in the Rocky Mountain region related to the sale of remaining non-core assets in the Williston Basin of North Dakota and Montana, which closed in the third quarter of 2016, and other minor property divestitures.


(2)	Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.


(1)	Cash interest is presented on an accrual basis, and includes interest which is paid semiannually on the Company’s 9% Senior Secured Second Lien Notes due 2021 issued in May 2016, most of which is accounted for as debt and therefore not reflected as interest for financial reporting purposes.


(1)	Excludes $204 million and $229 million, respectively, of future interest payable on the notes as of September 30, 2017 and December 31, 2016, accounted for as debt for financial reporting purposes.