UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

☑ Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended June 30, ~~2019~~2020

☐ Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from _______ to ________

Commission file number: 001-12935

DENBURY RESOURCES INC.

(Exact name of registrant as specified in its charter)



Delaware		20-0467835
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

5320 Legacy Drive,
Plano,	TX	75024
(Address of principal executive offices)		(Zip Code)



Registrant’s telephone number, including area code:	(972)	673-2000

Securities registered pursuant to Section 12(b) of the Act:



Title of Each Class:	Trading Symbol:	Name of Each Exchange on Which Registered:
Common Stock $.001 Par Value	~~DNR~~DNR*	New York Stock Exchange

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):



Large accelerated filer	☑	Accelerated filer	☐	Non-accelerated filer	☐	Smaller reporting company	☐	Emerging growth company	☐
				(Do not check if a smaller reporting company)

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑

The number of shares outstanding of the registrant’s Common Stock, $.001 par value, as of July 31, ~~2019,~~2020, was ~~469,661,433.~~507,063,311.

* On July 31, 2020, the New York Stock Exchange (“NYSE”) notified Denbury Resources Inc. (“Denbury”) that the NYSE would apply to the Securities and Exchange Commission (the “SEC”) to delist the common stock of Denbury. The delisting will be effective 10 days after a Form 25 is filed with the SEC by the NYSE. The deregistration of Denbury’s common stock under Section 12(b) of the Exchange Act will be effective 90 days, or such shorter period as the SEC may determine, after filing of the Form 25. Upon deregistration of Denbury’s common stock under Section 12(b) of the Exchange Act, its common stock will remain registered under Section 12(g) of the Exchange Act.

Denbury Resources Inc.

Table of Contents




		Page

	PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements
	Unaudited Condensed Consolidated Balance Sheets as of June 30, ~~2019~~2020 and December 31, ~~2018~~2019	3
	Unaudited Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, ~~2019~~2020 and ~~2018~~2019	4
	Unaudited Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, ~~2019~~2020 and ~~2018~~2019	5
	Unaudited Condensed Consolidated ~~Statement~~Statements of Changes in Stockholders’ Equity for the Three and Six Months Ended June 30, ~~2019~~2020 and ~~2018~~2019	6
	Notes to Unaudited Condensed Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2023
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	3744
Item 4.	Controls and Procedures	3946

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	4047
Item 1A.	Risk Factors	4147
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4252
Item 3.	Defaults Upon Senior Securities	4252
Item 4.	Mine Safety Disclosures	4252
Item 5.	Other Information	4252
Item 6.	Exhibits	4353
	Signatures	4455

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Denbury Resources Inc.

Unaudited Condensed Consolidated Balance Sheets

(In thousands, except par value and share data)


	June 30,			December 31,			June 30,			December 31,
	2019			2018			2020			2019
Assets
Current assets
Cash and cash equivalents	$	341		$	38,560		$	209,276		$	516
Accrued production receivable	135,697			125,788			77,344			139,407
Trade and other receivables, net	28,469			26,970			34,449			18,318
Derivative assets	24,447			93,080			47,655			11,936
Other current assets	14,989			11,896			20,724			10,434
Total current assets	203,943			296,294			389,448			180,611
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved properties	11,275,255			11,072,209			11,702,063			11,447,680
Unevaluated properties	941,336			996,700			645,847			872,910
CO₂ properties	1,198,657			1,196,795			1,198,981			1,198,846
Pipelines and plants	2,324,265			2,302,817			2,339,761			2,329,078
Other property and equipment	223,666			250,279			216,294			212,334
Less accumulated depletion, depreciation, amortization and impairment	(11,583,497		)	(11,500,190		)	(12,570,062		)	(11,688,020		)
Net property and equipment	4,379,682			4,318,610			3,532,884			4,372,828
Operating lease right-of-use assets	36,421			—			32,587			34,099
Derivative assets	9,488			4,195
Other assets	102,500			104,123			103,116			104,329
Total assets	$	4,732,034		$	4,723,222		$	4,058,035		$	4,691,867
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	180,283		$	198,380		$	160,694		$	183,832
Oil and gas production payable	63,034			61,288			40,652			62,869
Derivative liabilities	1,912			—			7,691			8,346
Current maturities of long-term debt (including future interest payable of $85,677 and $85,303, respectively – see Note 4)	101,829			105,125
Current maturities of long-term debt (including future interest payable of $119,454 and $86,054, respectively – see Note 4)							2,366,330			102,294
Operating lease liabilities	6,739			—			7,807			6,901
Total current liabilities	353,797			364,793			2,583,174			364,242
Long-term liabilities
Long-term debt, net of current portion (including future interest payable of $121,982 and $164,914, respectively – see Note 4)	2,466,127			2,664,211
Long-term debt, net of current portion (including future interest payable of $0 and $78,860, respectively – see Note 4)							145,922			2,232,570
Asset retirement obligations	181,491			174,470			177,030			177,108
Derivative liabilities	22			—
Deferred tax liabilities, net	362,303			309,758			306,186			410,230
Operating lease liabilities	45,391			—			38,584			41,932
Other liabilities	52,227			68,213			2,720			53,526
Total long-term liabilities	3,107,561			3,216,652			670,442			2,915,366
Commitments and contingencies (Note 7)
Commitments and contingencies (Note 9)
Stockholders’ equity
Preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding	—			—			—			—
Common stock, $.001 par value, 750,000,000 shares authorized; 464,166,479 and 462,355,725 shares issued, respectively	464			462
Common stock, $.001 par value, 750,000,000 shares authorized; 509,553,960 and 508,065,495 shares issued, respectively							510			508
Paid-in capital in excess of par	2,694,184			2,685,211			2,754,749			2,739,099
Accumulated deficit	(1,412,094		)	(1,533,112		)	(1,944,772		)	(1,321,314		)
Treasury stock, at cost, 2,474,904 and 1,941,749 shares, respectively	(11,878		)	(10,784		)
Treasury stock, at cost, 1,828,444 and 1,652,771 shares, respectively							(6,068		)	(6,034		)
Total stockholders’ equity	1,270,676			1,141,777			804,419			1,412,259
Total liabilities and stockholders’ equity	$	4,732,034		$	4,723,222		$	4,058,035		$	4,691,867

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Denbury Resources Inc.

Unaudited Condensed Consolidated Statements of Operations

(In thousands, except per share data)


	Three Months Ended June 30,					Six Months Ended June 30,					Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018		2019			2018		2020			2019			2020			2019
Revenues and other income
Oil, natural gas, and related product sales	$	330,421		$	375,565	$	624,998		$	715,586	$	109,387		$	330,421		$	339,011		$	624,998
CO₂sales and transportation fees	7,986			6,715		16,556			14,267		6,504			7,986			14,532			16,556
Purchased oil sales	2,591			346		2,806			1,403		1,490			2,591			5,211			2,806
Other income	2,367			4,437		4,457			9,041		494			2,367			1,322			4,457
Total revenues and other income	343,365			387,063		648,817			740,297		117,875			343,365			360,076			648,817
Expenses
Lease operating expenses	117,932			120,384		243,355			238,740		81,293			117,932			190,563			243,355
Transportation and marketing expenses	11,236			10,062		22,009			20,555		9,388			11,236			19,009			22,009
CO₂ discovery and operating expenses	581			500		1,137			962		885			581			1,637			1,137
Taxes other than income	25,517			27,234		49,302			54,553		10,372			25,517			30,058			49,302
Purchased oil expenses	2,564			289		2,777			1,162		1,450			2,564			5,111			2,777
General and administrative expenses	17,506			19,412		36,431			39,644		23,776			17,506			33,509			36,431
Interest, net of amounts capitalized of $8,238, $8,851, $18,772 and $17,303, respectively	20,416			16,208		37,814			33,447
Interest, net of amounts capitalized of $8,729, $8,238, $18,181 and $18,772, respectively											20,617			20,416			40,563			37,814
Depletion, depreciation, and amortization	58,264			52,944		115,561			105,395		55,414			58,264			152,276			115,561
Commodity derivatives expense (income)	(24,760		)	96,199		58,617			145,024		40,130			(24,760		)	(106,641		)	58,617
Gain on debt extinguishment	(100,346		)	—		(100,346		)	—		—			(100,346		)	(18,994		)	(100,346		)
Write-down of oil and natural gas properties											662,440			—			734,981			—
Other expenses	2,386			4,178		6,524			7,564		11,290			2,386			13,784			6,524
Total expenses	131,296			347,410		473,181			647,046		917,055			131,296			1,095,856			473,181
Income before income taxes	212,069			39,653		175,636			93,251
Income tax provision	65,377			9,431		54,618			23,451
Net income	$	146,692		$	30,222	$	121,018		$	69,800
Income (loss) before income taxes											(799,180		)	212,069			(735,780		)	175,636
Income tax provision (benefit)											(101,706		)	65,377			(112,322		)	54,618
Net income (loss)											$	(697,474	)	$	146,692		$	(623,458	)	$	121,018

Net income per common share
Net income (loss) per common share
Basic	$	0.32		$	0.07	$	0.27		$	0.17	$	(1.41	)	$	0.32		$	(1.26	)	$	0.27
Diluted	$	0.32		$	0.07	$	0.26		$	0.15	$	(1.41	)	$	0.32		$	(1.26	)	$	0.26

Weighted average common shares outstanding
Basic	452,612			433,467		452,169			413,217		495,245			452,612			494,752			452,169
Diluted	467,427			457,165		461,460			454,466		495,245			467,427			494,752			461,460

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Denbury Resources Inc.

Unaudited Condensed Consolidated Statements of Cash Flows

(In thousands)


	Six Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2020			2019
Cash flows from operating activities
Net income	$	121,018		$	69,800
Adjustments to reconcile net income to cash flows from operating activities
Net income (loss)							$	(623,458	)	$	121,018
Adjustments to reconcile net income (loss) to cash flows from operating activities
Depletion, depreciation, and amortization	115,561			105,395			152,276			115,561
Write-down of oil and natural gas properties							734,981			—
Deferred income taxes	52,545			25,237			(106,513		)	52,545
Stock-based compensation	6,865			5,152			3,540			6,865
Commodity derivatives expense (income)	58,617			145,024			(106,641		)	58,617
Receipt (payment) on settlements of commodity derivatives	6,657			(88,127		)
Receipt on settlements of commodity derivatives							70,267			6,657
Gain on debt extinguishment	(100,346		)	—			(18,994		)	(100,346		)
Debt issuance costs and discounts	2,901			2,268			9,921			2,901
Other, net	(57		)	(5,107		)	(1,642		)	(57		)
Changes in assets and liabilities, net of effects from acquisitions
Accrued production receivable	(9,909		)	(17,385		)	62,063			(9,909		)
Trade and other receivables	(271		)	(320		)	(16,162		)	(271		)
Other current and long-term assets	(3,389		)	(5,627		)	(4,552		)	(3,389		)
Accounts payable and accrued liabilities	(33,320		)	14,999			(60,295		)	(33,320		)
Oil and natural gas production payable	1,746			(4,501		)	(22,217		)	1,746
Other liabilities	(5,618		)	(1,182		)	237			(5,618		)
Net cash provided by operating activities	213,000			245,626			72,811			213,000

Cash flows from investing activities
Oil and natural gas capital expenditures	(148,254		)	(134,458		)	(79,897		)	(148,254		)
Pipelines and plants capital expenditures	(10,591		)	(7,882		)	(10,962		)	(10,591		)
Net proceeds from sales of oil and natural gas properties and equipment	431			2,077			40,971			431
Other	(725		)	5,365			(105		)	(725		)
Net cash used in investing activities	(159,139		)	(134,898		)	(49,993		)	(159,139		)

Cash flows from financing activities
Bank repayments	(281,000		)	(1,153,653		)	(226,000		)	(281,000		)
Bank borrowings	361,000			1,093,653			491,000			361,000
Interest payments treated as a reduction of debt	(42,558		)	(37,233		)	(42,506		)	(42,558		)
Cash paid in conjunction with debt repurchases							(14,171		)	—
Cash paid in conjunction with debt exchange	(120,007		)	—			—			(120,007		)
Costs of debt financing	(9,332		)	—			(299		)	(9,332		)
Pipeline financing and capital lease debt repayments	(7,273		)	(12,625		)	(7,015		)	(7,273		)
Other	12,899			(628		)	(9,230		)	12,899
Net cash used in financing activities	(86,271		)	(110,486		)
Net cash provided by (used in) financing activities							191,779			(86,271		)
Net increase (decrease) in cash, cash equivalents, and restricted cash	(32,410		)	242			214,597			(32,410		)
Cash, cash equivalents, and restricted cash at beginning of period	54,949			15,992			33,045			54,949
Cash, cash equivalents, and restricted cash at end of period	$	22,539		$	16,234		$	247,642		$	22,539

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

Table of Contents

Denbury Resources Inc.

Unaudited Condensed Consolidated Statements of Changes in Stockholders' Equity

(Dollar amounts in thousands)


	Common Stock ($.001 Par Value)			Paid-In Capital in Excess of Par		Retained Earnings (Accumulated Deficit)			Treasury Stock (at cost)							Common Stock ($.001 Par Value)					Paid-In Capital in Excess of Par		Retained Earnings (Accumulated Deficit)			Treasury Stock (at cost)
	Shares	Amount		Paid-In Capital in Excess of Par		Retained Earnings (Accumulated Deficit)			Shares	Amount			Total Equity			Shares		Amount			Paid-In Capital in Excess of Par		Retained Earnings (Accumulated Deficit)			Shares	Amount			Total Equity
Balance – December 31, 2018	462,355,725	$	462	$	2,685,211	$	(1,533,112	)	1,941,749	$	(10,784	)	$	1,141,777
Issued or purchased pursuant to stock compensation plans	1,331,050	2		—		—			—	—			2
Issued pursuant to directors’ compensation plan	41,487	—		—		—			—	—			—
Stock-based compensation	—	—		4,306		—			—	—			4,306
Tax withholding – stock compensation	—	—		—		—			531,494	(1,091		)	(1,091		)
Net loss	—	—		—		(25,674		)	—	—			(25,674		)
Balance – March 31, 2019	463,728,262	464		2,689,517		(1,558,786		)	2,473,243	(11,875		)	1,119,320
Balance – December 31, 2019																508,065,495		$	508		$	2,739,099	$	(1,321,314	)	1,652,771	$	(6,034	)	$	1,412,259
Issued or purchased pursuant to stock compensation plans	400,850	—		—		—			—	—			—			312,516		—			—		—			—	—			—
Issued pursuant to directors’ compensation plan	37,367	—		—		—			—	—			—			37,367		—			—		—			—	—			—
Stock-based compensation	—	—		4,667		—			—	—			4,667			—		—			3,204		—			—	—			3,204
Tax withholding – stock compensation	—	—		—		—			1,661	(3		)	(3		)	—		—			—		—			175,673	(34		)	(34		)
Net income	—	—		—		146,692			—	—			146,692			—		—			—		74,016			—	—			74,016
Balance – June 30, 2019	464,166,479	$	464	$	2,694,184	$	(1,412,094	)	2,474,904	$	(11,878	)	$	1,270,676
Balance – March 31, 2020																508,415,378		508			2,742,303		(1,247,298		)	1,828,444	(6,068		)	1,489,445
Canceled pursuant to stock compensation plans																(6,218,868	)	(6		)	6		—			—	—			—
Issued pursuant to notes conversion																7,357,450		8			11,453		—			—	—			11,461
Stock-based compensation																—		—			987		—			—	—			987
Net loss																—		—			—		(697,474		)	—	—			(697,474		)
Balance – June 30, 2020																509,553,960		$	510		$	2,754,749	$	(1,944,772	)	1,828,444	$	(6,068	)	$	804,419


	Common Stock ($.001 Par Value)			Paid-In Capital in Excess of Par		Retained Earnings (Accumulated Deficit)			Treasury Stock (at cost)							Common Stock ($.001 Par Value)			Paid-In Capital in Excess of Par		Retained Earnings (Accumulated Deficit)			Treasury Stock (at cost)
	Shares	Amount		Paid-In Capital in Excess of Par		Retained Earnings (Accumulated Deficit)			Shares	Amount			Total Equity			Shares	Amount		Paid-In Capital in Excess of Par		Retained Earnings (Accumulated Deficit)			Shares	Amount			Total Equity
Balance – December 31, 2017	402,549,346	$	403	$	2,507,828	$	(1,855,810	)	457,041	$	(4,256	)	$	648,165
Balance – December 31, 2018																462,355,725	$	462	$	2,685,211	$	(1,533,112	)	1,941,749	$	(10,784	)	$	1,141,777
Issued or purchased pursuant to stock compensation plans	378,595	—		—		—			—	—			—			1,331,050	2		—		—			—	—			2
Issued pursuant to directors’ compensation plan																41,487	—		—		—			—	—			—
Stock-based compensation																—	—		4,306		—			—	—			4,306
Tax withholding – stock compensation																—	—		—		—			531,494	(1,091		)	(1,091		)
Net loss																—	—		—		(25,674		)	—	—			(25,674		)
Balance – March 31, 2019																463,728,262	464		2,689,517		(1,558,786		)	2,473,243	(11,875		)	1,119,320
Issued or purchased pursuant to stock compensation plans																400,850	—		—		—			—	—			—
Issued pursuant to directors’ compensation plan																37,367	—		—		—			—	—			—
Stock-based compensation	—	—		3,303		—			—	—			3,303			—	—		4,667		—			—	—			4,667
Tax withholding – stock compensation	—	—		—		—			330,826	(828		)	(828		)	—	—		—		—			1,661	(3		)	(3		)
Net income	—	—		—		39,578			—	—			39,578			—	—		—		146,692			—	—			146,692
Balance – March 31, 2018	402,927,941	403		2,511,131		(1,816,232		)	787,867	(5,084		)	690,218
Issued or purchased pursuant to stock compensation plans	36,437	—		—		—			—	—			—
Issued pursuant to notes conversion	55,249,999	55		161,995		—			—	—			162,050
Stock-based compensation	—	—		3,226		—			—	—			3,226
Tax withholding – stock compensation	—	—		—		—			18,451	(71		)	(71		)
Net income	—	—		—		30,222			—	—			30,222
Balance – June 30, 2018	458,214,377	$	458	$	2,676,352	$	(1,786,010	)	806,318	$	(5,155	)	$	885,645
Balance – June 30, 2019																464,166,479	$	464	$	2,694,184	$	(1,412,094	)	2,474,904	$	(11,878	)	$	1,270,676

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

Table of Contents

Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 1. Basis of Presentation

Organization and Nature of Operations

Denbury Resources Inc. (“Denbury” or the “Company”), a Delaware corporation, is an independent oil and natural gas company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions. Our goal is to increase the value of our properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO₂ enhanced oil recovery operations.

Interim Financial Statements

The accompanying unaudited condensed consolidated financial statements of Denbury Resources Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, ~~2018~~2019 (the “Form 10-K”). Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company” or “Denbury,” refer to Denbury Resources Inc. and its subsidiaries.

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end, and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year. In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of June 30, ~~2019~~,2020, our consolidated results of operations for the three and six months endedJune 30, ~~2019~~2020 and ~~2018~~,2019, our consolidated cash flows for the six months ended June 30, ~~2019~~2020 and ~~2018~~,2019, and our consolidated statements of changes in stockholders’ equity for the three and six months ended June 30, ~~2019~~2020 and ~~2018.~~2019.

Industry Conditions, Liquidity, and Management’s Plans

In March 2020, the World Health Organization declared the ongoing COVID-19 coronavirus (“COVID-19”) outbreak a pandemic, and the President of the United States declared the COVID-19 pandemic a national emergency. The COVID-19 pandemic has caused a rapid and precipitous drop in the worldwide demand for oil, which worsened an already deteriorated oil market that resulted from the early-March 2020 failure by the group of oil producing nations known as OPEC+ to reach an agreement over proposed oil production cuts, which caused oil prices to reach historic low levels during April 2020. Although OPEC+ subsequently reached an agreement to curtail production, which has allowed oil prices to recover into the low $40s per barrel in July 2020, oil prices are expected to continue to remain at lower levels as a result of these events and the ongoing COVID-19 pandemic. Our operational and financial performance has been negatively impacted by actions taken to contain the impact of COVID-19, driving down domestic and global oil demand, and also affecting oil futures prices. Because the realized oil prices we have received since early March 2020 have been significantly reduced, our operating cash flow and liquidity have been adversely affected.

In response to the low oil price environment and during this period of uncertainty, in the first six months of 2020 we have implemented the following operational and financial measures:

Reduced budgeted 2020 capital spending by $80 million, or 44%, to approximately $95 million to $105 million;


•	Deferred the Cedar Creek Anticline CO₂ tertiary flood development project beyond 2020;

Implemented cost reduction measures including shutting down compressors or delaying well repairs and workovers that are uneconomic and reducing our workforce to better align with current and projected near-term needs;

Restructured approximately 50% of our three-way collars covering 14,500 barrels per day (“Bbls/d”) into fixed-price swaps for the second quarter through the fourth quarter of 2020 in order to increase downside protection. Our current hedge portfolio covers 35,500 Bbls/d for the second half of 2020, with over half of those contracts consisting of fixed-price swaps and the remainder consisting of three-way collars;

Evaluated production economics at each field and shut-in production beginning in late March 2020 that was uneconomic to produce or repair based on prevailing oil prices; and

Conducted a complete market-based review of strategic alternatives, including a comprehensive restructuring, to enhance our liquidity and strengthen our capital structure.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Collectively, the above factors, along with the materially adverse change in industry market conditions and our cash flow over the past several months, substantially diminished our ability to repay, refinance, or restructure our $2.1 billion of our then-outstanding long-term bond debt. After extensive, arm’s length negotiations, on July 28, 2020, we entered into a Restructuring Support Agreement (“RSA”) with bank lenders and certain holders of our second lien and convertible notes. The RSA contemplates a restructuring of the Company pursuant to a prepackaged joint plan of reorganization. See discussion under Entry into Restructuring Support Agreement and Voluntary Reorganization under Chapter 11 of the Bankruptcy Code below.

Entry into Restructuring Support Agreement and Voluntary Reorganization under Chapter 11 of the Bankruptcy Code

On July 28, 2020, Denbury and its subsidiaries (collectively, “Denbury”) entered into a Restructuring Support Agreement (the “RSA”) with lenders holding 100% of the revolving loans under our bank credit facility (“Bank Credit Agreement”) and debtholders holding approximately 67.1% of our second lien notes and approximately 73.1% of our convertible notes, which contemplated a restructuring of the Company pursuant to a prepackaged joint plan of reorganization (the “Plan”). On July 30, 2020 (the “Petition Date”), Denbury and its subsidiaries filed petitions for reorganization in a “prepackaged” voluntary bankruptcy (the “Chapter 11 Restructuring”) under chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”) (case no. 20-33801). The Chapter 11 Restructuring is being undertaken to deleverage the Company, relieving it of approximately $2.1 billion of bond debt by issuing equity in a reorganized entity to the holders of that debt. Denbury continues to operate its businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court, in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court. On July 31, 2020, the Bankruptcy Court entered orders approving certain customary “first day” relief to enable Denbury to operate in the ordinary course during the Chapter 11 Restructuring, including approval on an interim basis of post-petition financing under a debtor-in-possession (“DIP”) facility (the “DIP Facility”) and use of cash collateral of Denbury’s lenders and secured noteholders.

The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default under the Bank Credit Agreement, the indentures governing our senior secured second lien notes, convertible senior notes, and senior subordinated notes and the agreements governing our NEJD pipeline lease financing. On August 4, 2020, we entered into the DIP Facility, and $185 million of our outstanding loans and all of our approximately $95 million of outstanding letters of credit under Denbury’s pre-petition revolving Bank Credit Agreement were “rolled up” into the DIP Facility. Immediately thereafter, Denbury initiated a repayment of $150 million of amounts borrowed under the DIP Facility with cash on hand. On August 7, 2020, the beneficiary of the $41.3 million letter of credit issued as “financial assurances” under the NEJD pipeline lease financing drew the full amount of such letter of credit in accordance with its terms as a result of the Chapter 11 Restructuring, which resulted in Denbury borrowing an identical amount under the DIP Facility. The Plan contemplates that, upon emergence from the Chapter 11 Restructuring, the DIP Facility be replaced with a committed exit facility, and Denbury’s pre-petition bond debt will receive the treatment set forth in the Plan and be cancelled. Accordingly, we have classified all outstanding debt, excluding the noncurrent portions of our capital leases and pipeline financings which the Plan contemplates will be reinstated upon emergence, as a current liability on our condensed consolidated balance sheet as of June 30, 2020. See also Note 4, Long-Term Debt – Chapter 11 Restructuring and Effect of Automatic Stay.

As consideration for the entry into the RSA by the ad hoc committee of holders of Denbury’s second lien notes and the compromises therein, on July 29, 2020, Denbury paid in cash prior to the Petition Date accrued and unpaid interest under the second lien notes of $8.0 million in the aggregate, as set forth in the RSA. The RSA provides for certain milestones requiring, among other things, that Denbury (i) obtains entry of an order by the Bankruptcy Court approving the Disclosure Statement and confirming the Plan (the “Confirmation Order”) no later than September 6, 2020; (ii) obtains entry of an order by the Bankruptcy Court approving the DIP Facility on a final basis no later than the earlier of (a) the entry of the Confirmation Order or (b) 35 days after the Petition Date; and (iii) causes the Plan to become effective no later than 14 days after entry of the Confirmation Order. Denbury is currently soliciting votes to accept the Plan from holders of claims and interests entitled to vote.

Below is a summary of the treatment that the stakeholders of the Company would receive under the Plan following emergence from chapter 11:


•	Trade and Other Claims. The holders of Denbury’s other secured, priority and trade vendor claims would have such obligations reinstated, paid in full in cash, or receive such other treatment to render such claims unimpaired.


•	Holders of Bank Credit Agreement Claims. The holders of obligations under the Bank Credit Agreement would have such obligations paid in full in cash or receive such other treatment to render such claims unimpaired.

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Notes to Unaudited Condensed Consolidated Financial Statements


•	Holders of Second Lien Notes Claims. The holders of obligations under senior secured second lien notes would receive their pro rata share of 95% of the reorganized company’s equity interests, subject to certain dilution on account of warrants and the management incentive plan.


•	Holders of Convertible Notes Claims. The holders of obligations under convertible senior notes would receive their pro rata share of (a) 5% of the reorganized company’s equity interests, subject to certain dilution on account of warrants and the management incentive plan and (b) 100% of the series A warrants on the terms set forth in the Plan.


•	Holders of Subordinated Notes Claims. If the class of subordinated notes claims votes to accept the Plan, holders of obligations under senior subordinated notes would receive their pro rata share of 54.55% of the series B warrants on the terms set forth in the Plan, reflecting 3% of the reorganized company’s equity interests after giving effect to the exercise of the Series A warrants.


•	Equity Holders. If the classes of subordinated notes claims and equity interests both vote to accept the Plan, holders of existing equity interests would receive their pro rata share of 45.45% of the series B warrants on the terms set forth in the Plan, reflecting 2.5% of the reorganized company’s equity interests after giving effect to the exercise of the Series A warrants.

Going Concern

As discussed above, the filing of the Chapter 11 Restructuring on July 30, 2020 constituted an event of default under all of our outstanding debt agreements, resulting in the automatic and immediate acceleration of the Company’s debt outstanding, with the exception of our capital leases and our obligations under our Free State pipeline transportation agreement. At that date, the Company did not have sufficient cash on hand or available liquidity to repay such debt.

Our operations and ability to develop and execute our business plan are subject to risk and uncertainty associated with the Chapter 11 Restructuring. The outcome of the Chapter 11 Restructuring is subject to factors that are outside of the Company’s control, including actions of the Bankruptcy Court and the Company’s creditors. There can be no assurance that we will confirm and consummate the Plan as contemplated by the RSA or complete another plan of reorganization with respect to the Chapter 11 Restructuring. As a result, we have concluded that management’s plans do not alleviate substantial doubt about our ability to continue as a going concern.

The condensed consolidated financial statements included in this Quarterly Report on Form 10-Q have been prepared on a going concern basis of accounting, and do not reflect any adjustments relating to the recoverability and classification of recorded asset amounts or the amounts and classification of liabilities that might result if we are unable to continue as a going concern.

Reclassifications

Certain prior period amounts have been reclassified to conform to the current year presentation. On the Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2018, “Purchased oil sales” is a new line item and includes sales related to purchases of oil from third-parties, which were reclassified from “Other income,” “Purchased oil expenses” is a new line item and includes expenses related to purchases of oil from third-parties, which were reclassified from “Marketing and plant operating expenses” used in prior reports, and “Transportation and marketing expenses” is a new line item, previously captioned “Marketing and plant operating expenses,” but adjusted to exclude both expenses related to plant operating expenses, which were reclassified to “Other expenses,” and also purchases of oil from third-parties. Such reclassifications had no impact on our reported ~~total revenues, expenses,~~ net income (loss), current assets, total assets, current liabilities, total liabilities or stockholders’ equity.

Cash, Cash Equivalents, and Restricted Cash

We consider all highly liquid investments to be cash equivalents if they have maturities of three months or less at the date of purchase. Cash and cash equivalents potentially subject the Company to a concentration of credit risk as substantially all of its deposits held in financial institutions were in excess of the Federal Deposit Insurance Corporation insurance limits as of June 30, 2020. The Company maintains its cash and cash equivalents in the form of checking accounts with financial institutions that are also lenders under the Bank Credit Agreement. The Company has not experienced any losses on its deposits of cash and cash equivalents. The following table provides a reconciliation of cash, cash equivalents, and restricted cash as reported within the Unaudited Condensed Consolidated Balance Sheets to “Cash, cash equivalents, and restricted cash at end of period” as reported within the Unaudited Condensed Consolidated Statements of Cash Flows:


In thousands	June 30, 2019		December 31, 2018		June 30, 2020		December 31, 2019
Cash and cash equivalents	$	341	$	38,560	$	209,276	$	516
Restricted cash included in other assets	22,198		16,389		38,366		32,529
Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows	$	22,539	$	54,949	$	247,642	$	33,045

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Notes to Unaudited Condensed Consolidated Financial Statements

Amounts included in restricted cash included in “Other assets” in the accompanying Unaudited Condensed Consolidated Balance Sheets represent escrow accounts that are legally restricted for certain of our asset retirement obligations.

See ~~Table~~Entry into Restructuring Support Agreement and Voluntary Reorganization under Chapter 11 of ~~Contents~~the Bankruptcy Code

~~Denbury Resources Inc.~~

~~Notes~~ above for a discussion of cash used to ~~Unaudited Condensed Consolidated Financial Statements~~

~~Our prior-year quarterly report on Form 10-Q for the period ended~~repay outstanding borrowings subsequent to June 30, 2018, filed with the SEC on August 9, 2018, previously disclosed balances of certain U.S. Treasury Notes of $24.6 million and $25.4 million as of January 1, 2018 and June 30, 2018, respectively, that should have been excluded from “Cash, cash equivalents, and restricted cash” on the Consolidated Statements of Cash Flows. Accordingly, “Cash, cash equivalents, and restricted cash” as of January 1, 2018 and June 30, 2018, originally reported as $40.6 million and $41.6 million, respectively, should have been reported as $16.0 million and $16.2 million, respectively. In addition, changes in the U.S. Treasury Notes of $0.8 million during the six months ended June 30, 2018 should have been included in net cash used in investing activities. Accordingly, net cash used in investing activities for the six months ended June 30, 2018, originally reported as $134.1 million, should have been $134.9 million. These revisions had no impact on the Company’s financial condition or results of operations for the periods presented.2020.

Net Income (Loss) per Common Share

Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income (loss) per common share is calculated in the same manner, but includes the impact of potentially dilutive securities. Potentially dilutive securities consist of nonvested restricted stock, nonvested performance-based equity awards, and shares into which our convertible senior notes are convertible.

The following table sets forth the reconciliations of net income (loss) and weighted average shares used for purposes of calculating the basic and diluted net income (loss) per common share for the periods indicated:


	Three Months Ended				Six Months Ended				Three Months Ended					Six Months Ended
	June 30,				June 30,				June 30,					June 30,
In thousands	2019		2018		2019		2018		2020			2019		2020			2019
Numerator
Net income – basic	$	146,692	$	30,222	$	121,018	$	69,800
Net income (loss) – basic									$	(697,474	)	$	146,692	$	(623,458	)	$	121,018
Effect of potentially dilutive securities
Interest on convertible senior notes including amortization of discount, net of tax	548		130		548		539		—			548		—			548
Net income – diluted	$	147,240	$	30,352	$	121,566	$	70,339
Net income (loss) – diluted									$	(697,474	)	$	147,240	$	(623,458	)	$	121,566

Denominator
Weighted average common shares outstanding – basic	452,612		433,467		452,169		413,217		495,245			452,612		494,752			452,169
Effect of potentially dilutive securities
Restricted stock and performance-based equity awards	2,835		8,586		3,301		6,877		—			2,835		—			3,301
Convertible senior notes⁽¹⁾	11,980		15,112		5,990		34,372		—			11,980		—			5,990
Weighted average common shares outstanding – diluted	467,427		457,165		461,460		454,466		495,245			467,427		494,752			461,460

(1)

~~For the three and six months ended June 30, 2019, shares~~Shares shown under “convertible senior notes” represent the ~~prorated portion~~impact over the periods of the approximately 90.9 million shares of the Company’s common stock issuable upon full conversion of our convertible senior notes ~~(see Note 4,~~ ~~Long-Term Debt~~ – ~~2019 Note Exchanges~~).

which were issued on June 19, 2019.

Basic weighted average common shares exclude shares of nonvested restricted stock. As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income (loss) per common share (although time-vesting restricted stock is issued and outstanding upon grant). For purposes of calculating diluted weighted average common shares during the three and six months ended June 30, 2019, ~~and 2018,~~ the nonvested restricted stock and performance-based equity awards are included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, and for the shares underlying the convertible senior notes as if the convertible senior notes were converted at the beginning of ~~the 2018 and 2019 periods.~~2019.

810

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Notes to Unaudited Condensed Consolidated Financial Statements

The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss) per share, as their effect would have been antidilutive:


	Three Months Ended		Six Months Ended		Three Months Ended		Six Months Ended
	June 30,		June 30,		June 30,		June 30,
In thousands	2019	2018	2019	2018	2020	2019	2020	2019
Stock appreciation rights	2,026	2,827	2,059	2,891	1,493	2,026	1,510	2,059
Restricted stock and performance-based equity awards	4,998	179	4,790	305	6,589	4,998	10,837	4,790
Convertible senior notes					90,368	—	90,610	—

Oil and Natural Gas Properties

Unevaluated Costs. Under full cost accounting, we exclude certain unevaluated costs from the amortization base and full cost ceiling test pending the determination of whether proved reserves can be assigned to such properties. These costs are transferred to the full cost amortization base in the course of these properties being developed, tested and evaluated. At least annually, we test these assets for impairment based on an evaluation of management’s expectations of future pricing, evaluation of lease expiration terms, and planned project development activities. Given the significant declines in NYMEX oil prices to approximately $20 per Bbl in late March 2020 due to OPEC supply pressures and a reduction in worldwide oil demand amid the COVID-19 pandemic, as well as the uncertainty of future oil prices from demand destruction caused by the pandemic, we reassessed our development plans and recognized an impairment of $244.9 million of our unevaluated costs during the three months ended March 31, 2020, whereby these costs were transferred to the full cost amortization base.

Write-Down of Oil and Natural Gas Properties. The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as (1) the present value of estimated future net revenues from proved oil and natural gas reserves before future abandonment costs (discounted at 10%), based on the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects. Our future net revenues from proved oil and natural gas reserves are not reduced for development costs related to the cost of drilling for and developing CO₂ reserves nor those related to the cost of constructing CO₂ pipelines, as we do not have to incur additional costs to develop the proved oil and natural gas reserves. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO₂ costs related to CO₂ reserves and CO₂ pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes. The cost center ceiling test is prepared quarterly.

We recognized a full cost pool ceiling test write-down of $662.4 million and $72.5 million during the three months ended June 30, 2020 and March 31, 2020, respectively. The first-day-of-the-month oil prices for the preceding 12 months, after adjustments for market differentials by field, averaged $44.74 per Bbl and $55.17 per Bbl as of June 30, 2020 and March 31, 2020, respectively. In addition, the first-day-of-the-month natural gas prices for the preceding 12 months, after adjustments for market differentials by field, averaged $1.91 per MMBtu and $1.68 per MMBtu as of June 30, 2020 and March 31, 2020, respectively. If oil prices remain at or near early-August 2020 levels for the remainder of 2020, we currently expect that we would also record write-downs in subsequent quarters in 2020, as the 12-month average price used in determining the full cost ceiling value will continue to decline during each rolling quarterly period in 2020, subject to the date of the Company’s emergence from bankruptcy and potential impacts of fresh start accounting, if applicable.

Impairment Assessment of Long-Lived Assets

We test long-lived assets for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. These long-lived assets, which are not subject to our full cost pool ceiling test, are principally comprised of our capitalized CO₂ properties and pipelines. Given the significant declines in NYMEX oil prices to approximately $20 per Bbl in late March 2020 due to OPEC supply pressures and a reduction in worldwide oil demand amid the COVID-19 pandemic, we performed a long-lived asset impairment test for our two long-lived asset groups (Gulf Coast region and Rocky Mountain region) as of March 31, 2020.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

We perform our long-lived asset impairment test by comparing the net carrying costs of our two long-lived asset groups to the respective expected future undiscounted net cash flows that are supported by these long-lived assets which include production of our probable and possible oil and natural gas reserves. The portion of our capitalized CO₂ costs related to CO₂ reserves and CO₂ pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves is included in the full cost pool ceiling test as a reduction to future net revenues. The remaining net capitalized costs that are not included in the full cost pool ceiling test, and related intangible assets, are subject to long-lived asset impairment testing. These costs totaled approximately $1.3 billion as of March 31, 2020. If the undiscounted net cash flows are below the net carrying costs for an asset group, we must record an impairment loss by the amount, if any, that net carrying costs exceed the fair value of the long-lived asset group. The undiscounted net cash flows for our asset groups exceeded the net carrying costs; thus, step two of the impairment test was not required and 0 impairment was recorded.

Significant assumptions impacting expected future undiscounted net cash flows include projections of future oil and natural gas prices, projections of estimated quantities of oil and natural gas reserves, projections of future rates of production, timing and amount of future development and operating costs, projected availability and cost of CO₂, projected recovery factors of tertiary reserves and risk-adjustment factors applied to the cash flows. We performed a qualitative assessment as of June 30, 2020 and determined there were no material changes to our key cash flow assumptions and no triggering events since the analysis performed as of March 31, 2020; therefore, 0 impairment test was performed for the second quarter of 2020.

Recent Accounting Pronouncements

Recently ~~Adopted~~

~~Leases.~~ ~~Effective January 1, 2019, we adopted Accounting Standards Update (“ASU”) 2016-02,~~ ~~Leases~~ ~~(“ASU 2016-02”), and ASU 2018-01,~~ ~~Leases (Topic 842) – Land Easement Practical Expedient for Transition to Topic 842~~, using the modified retrospective method with an application date of January 1, 2019. ASU 2016-02 does not apply to mineral leases or leases that convey the right to explore for or use the land on which oil, natural gas, and similar natural resources are contained. We elected the practical expedients provided in the new ASUs that allow historical lease classification of existing leases, allow entities to recognize leases with terms of one year or less in their statement of operations, allow lease and non-lease components to be combined, and carry forward our accounting treatment for existing land easement agreements. The adoption of the new standards resulted in the recognition of $39.1 million of lease assets and $55.8 million of lease liabilities ($16.7 million of which related to previously-existing lease obligations) as of January 1, 2019, in our Unaudited Condensed Consolidated Balance Sheets, but did not materially impact our results of operations and had no impact on our cash flows. The additional lease assets and liabilities recorded on our balance sheet primarily related to our operating leases for office space, as the accounting for our financing leases and pipeline financings was relatively unchanged.

~~Not Yet~~ Adopted

Financial Instruments – Credit Losses. In June 2016, the ~~FASB~~Financial Accounting Standards Board (“FASB”) issued ASU 2016-13, Financial Instruments – Credit Losses (“ASU 2016-13”). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires the use of a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. Effective January 1, 2020, we adopted ASU 2016-13. The ~~amendments in~~implementation of this ASU are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, and early adoption is permitted. Entities must adopt the amendment using a modified retrospective approach to the first reporting period in which the guidance is effective. The adoption of ASU 2016-13 is currentlystandard did not ~~expected to~~ have a material ~~effect~~impact on our consolidated financial statements.

Fair Value Measurement. In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820) – Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurements (“ASU 2018-13”). ASU 2018-13 adds, modifies, or removes certain disclosure requirements for recurring and nonrecurring fair value measurements based on the FASB’s consideration of costs and benefits. Effective January 1, 2020, we adopted ASU 2018-13. The implementation of this standard did not have a material impact on our consolidated financial statements or footnote disclosures.

Not Yet Adopted

Income Taxes. In December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes (“ASU 2019-12”). The objective of ASU 2019-12 is to simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740 and to provide more consistent application to improve the comparability of financial statements. The amendments in this ASU are effective for fiscal years beginning after December 15, ~~2019, and interim periods within those fiscal years,~~2020, and early adoption is permitted. ~~Entities must adopt~~We are currently evaluating the amendments on changes in unrealized gains and losses for Level 3 fair value measurements, the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements, and the narrative description of measurement uncertainty prospectively, and all other amendments should be applied retrospectively to all periods presented. The adoption of ASU 2018-13 is currently not expected toimpact this guidance may have ~~a material effect~~ on our consolidated financial statements ~~but may require enhanced~~and related footnote disclosures.

Note 2. Divestiture

On March 4, 2020, we closed a farm-down transaction for the sale of half of our working interest positions in four southeast Texas oil fields for $40 million net cash and a carried interest in ten wells to be drilled by the purchaser. We did not record a gain or loss on the sale of the properties in accordance with the full cost method of accounting.

Note 2.3. Revenue Recognition

We record revenue in accordance with Financial Accounting Standards Board Codification (“FASC”) Topic 606, Revenue from Contracts with Customers. The core principle of FASC Topic 606 is that an entity should recognize revenue for the transfer of goods or services equal to the amount of consideration that it expects to be entitled to receive for those goods or services. Once

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

we have delivered the volume of commodity to the delivery point and the customer takes delivery and possession, we are entitled to payment and we invoice the customer for such delivered production. Payment under most oil and CO₂ contracts is made within a month following product delivery and for natural gas and NGL contracts is generally made within two months following delivery.

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~~Denbury Resources Inc.~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

Timing of revenue recognition may differ from the timing of invoicing to customers; however, as the right to consideration after delivery is unconditional based on only the passage of time before payment of the consideration is due, upon delivery we record a receivable in “Accrued production receivable” in our Unaudited Condensed Consolidated Balance Sheets, which was ~~$135.7~~$77.3 million and ~~$125.8~~$139.4 million as of June 30, ~~2019~~2020 and December 31, ~~2018,~~2019, respectively. The Company enters into purchase transactions with third parties and separate sale transactions with third parties in the Gulf Coast region. Revenues and expenses from these transactions are presented on a gross basis, as we act as a principal in the transaction by assuming control of the commodities purchased and the responsibility to deliver the commodities sold. Revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser.

Disaggregation of Revenue

The following table summarizes our revenues by product type for the three and six months ended June 30, ~~2019~~2020 and ~~2018:~~2019:

Three Months Ended Six Months Ended
June 30, June 30,
In thousands 2019 2018 2019 2018
Oil sales $ 328,571
$ 373,286
$ 620,536
$ 710,692
Natural gas sales 1,850
2,279
4,462
4,894
CO₂ sales and transportation fees
7,986
6,715
16,556
14,267
Purchased oil sales 2,591
346
2,806
1,403
Total revenues $ 340,998
$ 382,626
$ 644,360
$ 731,256

~~Note 3. Leases~~

We evaluate contracts for leasing arrangements at inception. We lease office space, equipment, and vehicles that have non-cancelable lease terms. Leases with a term of 12 months or less are not recorded on our balance sheet. The table below reflects our operating lease assets and liabilities, which primarily consists of our office leases, and finance lease assets and liabilities:

June 30,
In thousands 2019
Operating leases
Operating lease right-of-use assets $ 36,421

Operating lease liabilities - current $ 6,739
Operating lease liabilities - long-term 45,391
Total operating lease liabilities $ 52,130

Finance leases
Other property and equipment $ 1,736
Accumulated depreciation (1,465 )
Other property and equipment, net $ 271

Current maturities of long-term debt $ 233
Long-term debt, net of current portion 59
Total finance lease liabilities $ 292

The majority of our leases contain renewal options, typically exercisable at our sole discretion. We record right-of-use assets and liabilities based on the present value of lease payments over the initial lease term, unless the option to extend the lease is

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~~Denbury Resources Inc.~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

reasonably certain, and utilize our incremental borrowing rate based on information available at the lease commencement date. The following weighted average remaining lease terms and discount rates related to our outstanding leases:



	~~June 30,~~
	~~2019~~
~~Weighted Average Remaining Lease Term~~
~~Operating leases~~	~~6.2 years~~
~~Finance leases~~	~~1.3 years~~

~~Weighted Average Discount Rate~~
~~Operating leases~~	~~6.8~~	%
~~Finance leases~~	~~2.3~~	%

Lease costs for operating leases or leases with a term of 12 months or less are recognized on a straight-line basis over the lease term. For finance leases, interest on the lease liability and the amortization of the right-of-use asset are recognized separately, with the depreciable life reflective of the expected lease term. We have subleased part of the office space included in our operating leases for which we receive rental payments. The following table summarizes the components of lease costs and sublease income:

Three Months Ended Six Months Ended
In thousands Income Statement Presentation June 30, 2019 June 30, 2019
Operating lease cost General and administrative expenses $ 2,412
$ 4,827

Finance lease cost
Amortization of right-of-use assets Depletion, depreciation, and amortization $ 264
$ 1,134
Interest on lease liabilities Interest expense 8
38
Total finance lease cost $ 272
$ 1,172

Sublease income General and administrative expenses $ 1,331
$ 2,367

~~Our statement of cash flows included the following activity related to our operating and finance leases:~~

Six Months Ended
In thousands June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases $ 5,854
Operating cash flows from interest on finance leases 38
Financing cash flows from finance leases 1,217

Right-of-use assets obtained in exchange for lease obligations

Operating leases 294
Finance leases —



	Three Months Ended				Six Months Ended
	June 30,				June 30,
In thousands	2020		2019		2020		2019
Oil sales	$	108,538	$	328,571	$	337,115	$	620,536
Natural gas sales	849		1,850		1,896		4,462
CO₂ sales and transportation fees	6,504		7,986		14,532		16,556
Purchased oil sales	1,490		2,591		5,211		2,806
Total revenues	$	117,381	$	340,998	$	358,754	$	644,360

~~Table of Contents~~

~~Denbury Resources Inc.~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

~~The following table summarizes by year the maturities of our lease liabilities as of June 30, 2019:~~

Operating Finance
In thousands Leases Leases
2019 $ 5,063
$ 118
2020 9,874
178
2021 10,042
—
2022 10,259
—
2023 10,300
—
Thereafter 18,537
—
Total minimum lease payments 64,075
296
Less: Amount representing interest (11,945 ) (4 )
Present value of minimum lease payments $ 52,130
$ 292

~~The following table summarizes by year the remaining non-cancelable future payments under our leases, as accounted for under previous accounting guidance under FASC Topic 840,~~ ~~Leases, as of December 31, 2018:~~

Operating
In thousands Leases
2019 $ 10,690
2020 9,776
2021 10,007
2022 10,223
2023 10,262
Thereafter 18,169
Total minimum lease payments $ 69,127

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 4. Long-Term Debt

The table below reflects long-term debt ~~and capital lease obligations~~ outstanding as of the dates indicated:


	June 30,			December 31,			June 30,			December 31,
In thousands	2019			2018			2020			2019
Senior Secured Bank Credit Agreement	$	80,000		$	—		$	265,000		$	—
9% Senior Secured Second Lien Notes due 2021	614,919			614,919			584,709			614,919
9¼% Senior Secured Second Lien Notes due 2022	455,668			455,668			455,668			455,668
7¾% Senior Secured Second Lien Notes due 2024	528,026			—			531,821			531,821
7½% Senior Secured Second Lien Notes due 2024	24,638			450,000			20,641			20,641
6⅜% Convertible Senior Notes due 2024	245,548			—			225,663			245,548
6⅜% Senior Subordinated Notes due 2021	51,304			203,545			51,304			51,304
5½% Senior Subordinated Notes due 2022	94,784			314,662			58,426			58,426
4⅝% Senior Subordinated Notes due 2023	211,695			307,978			135,960			135,960
Pipeline financings	174,018			180,073			160,428			167,439
Capital lease obligations	292			5,362			157			—
Total debt principal balance	2,480,892			2,532,207			2,489,777			2,281,726
Debt discount⁽¹⁾	(109,072		)	—			(88,442		)	(101,767		)
Future interest payable⁽²⁾	207,659			250,218			119,454			164,914
Debt issuance costs	(11,523		)	(13,089		)	(8,537		)	(10,009		)
Total debt, net of debt issuance costs and discount	2,567,956			2,769,336			2,512,252			2,334,864
Less: current maturities of long-term debt⁽³⁾	(101,829		)	(105,125		)	(2,366,330		)	(102,294		)
Long-term debt and capital lease obligations	$	2,466,127		$	2,664,211
Long-term debt							$	145,922		$	2,232,570

(1)

Consists of discounts related to ~~the issuance during June 2019 of~~ our ~~new~~ 7¾% Senior Secured Second Lien Notes due 2024 ~~(the “7¾% Senior Secured Notes”)~~ and ~~new~~ 6⅜% Convertible Senior Notes due 2024 ~~(the “2024 Convertible Senior Notes”)~~ of ~~$29.4~~$24.4 million and ~~$79.6~~$64.0 million, respectively, ~~(see~~ ~~2019 Note Exchanges~~ ~~below)~~ as of June 30, ~~2019.~~

2020.


(2)	Future interest payable represents most of the interest due over the terms of our 9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”) and 9¼% Senior Secured Second Lien Notes due 2022 (the “2022 Senior Secured Notes”) and has been accounted for as debt in accordance with FASC 470-60, Troubled Debt Restructuring by Debtors.


(3)	Our current maturities of long-term debt as of June 30, ~~2019~~2020 include ~~$85.7~~$119.5 million of future interest payable related to the 2021 Senior Secured Notes and 2022 Senior Secured Notes that is due within the next twelve months. See Chapter 11 Restructuring and Effect of Automatic Stay below.

The ultimate parent company in our corporate structure, Denbury Resources Inc. (“DRI”), is the sole issuer of all of our outstanding senior secured, convertible senior, and senior subordinated notes. DRI has no independent assets or operations. Each of the subsidiary guarantors of such notes is 100% owned, directly or indirectly, by DRI, and the guarantees of the notes are full and unconditional and joint and several; any subsidiaries of DRI that are not subsidiary guarantors of such notes are minor subsidiaries.

~~Senior Secured Bank Credit Facility~~Chapter 11 Restructuring and Effect of Automatic Stay

~~In December 2014, we entered~~As discussed in Note 1, Basis of Presentation – Entry into ~~an Amended~~Restructuring Support Agreement and ~~Restated Credit Agreement with JPMorgan Chase Bank, N.A., as administrative agent,~~Voluntary Reorganization under Chapter 11 of the Bankruptcy Code, on July 30, 2020, Denbury filed for relief under chapter 11 of the Bankruptcy Code. Both the NEJD pipeline lease financing and other lenders party thereto (as amended, the “Bank Credit Agreement”), which has been amended periodically since that time. The Bank Credit Agreement is a senior secured revolving credit facility with a maturity date of December 9, 2021, provided that the maturity date may occur earlier (between February 2021 and August 2021) if the 2021 Senior Secured Notes due in May 2021 or 6⅜% Senior Subordinated Notes due in August 2021, respectively,Free State pipeline transportation agreement are not ~~repaid or refinanced by each of~~impaired and are expected to continue post-bankruptcy under their ~~respective maturity dates. As part~~existing terms and maintain their long-term nature. Therefore, the noncurrent portions of our ~~spring 2019 semiannual redetermination,~~pipeline financings remain classified as long-term debt in the ~~borrowing base~~condensed consolidated balance sheet as of June 30, 2020. Any efforts to enforce payment obligations related to the acceleration of the Company’s debt have been automatically stayed as a result of the filing of the Chapter 11 Restructuring, and ~~lender commitments~~the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code. Refer to Note 1, Basis of Presentation – Entry into Restructuring Support Agreement and Voluntary Reorganization under Chapter 11 of the Bankruptcy Code, for ~~our Bank Credit Agreement were reaffirmed at $615 million, with~~more information on the next such redetermination being scheduled for November 2019. If our outstanding debt under the Bank Credit Agreement were to ever exceed the borrowing base, we would be required to repay the excess amount over a period not to exceed six months. The weighted average interest rate on borrowingsChapter 11 Restructuring.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Senior Secured Bank Credit Facility

Since December 2014, the Company maintained a senior secured revolving credit facility with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto, which has been amended periodically since that time. The Bank Credit Agreement had a scheduled maturity date of December 9, 2021, provided that the maturity date may be accelerated to earlier dates in 2021 if certain defined liquidity ratios are not met, or if the 2021 Senior Secured Notes due in May 2021 or 6⅜% Senior Subordinated Notes due in August 2021 are not repaid or refinanced by each of their respective maturity dates. The borrowing base under the Bank Credit Agreement was ~~5.1% as~~evaluated semi-annually, generally around May 1 and November 1. In conjunction with the scheduled May 2020 redetermination on June 26, 2020, we entered into the Eighth Amendment to the Bank Credit Agreement (the “Eighth Amendment”) which among other things:

Reaffirmed the borrowing base under the Bank Credit Agreement at $615 million until the next scheduled or interim redetermination or other adjustment to the borrowing base in accordance with the terms of the Bank Credit Agreement;

Reduced (until the fall 2020 borrowing base redetermination date) the maximum availability under the Bank Credit Agreement to the sum of $275 million plus the total amount of outstanding letters of credit under the Bank Credit Agreement from time to time (not to exceed $100 million); and

Added dollar limits (until the fall 2020 borrowing base redetermination date) on our ability to use certain baskets in the negative covenants governing dispositions, hedge terminations, investments, restricted payments and redemptions of junior lien debt and unsecured debt.

Under the terms of the RSA, the lenders under the Company’s Bank Credit Agreement agreed to provide the Company and its subsidiaries with the DIP Facility, which is to be replaced with the committed exit facility upon emergence from the Chapter 11 Restructuring. Refer to Note 1, Basis of Presentation – Entry into Restructuring Support Agreement and Voluntary Reorganization under Chapter 11 of the Bankruptcy Code, for additional information.

On June 29, 2020, we elected to draw $200 million (the “Credit Draw”) under the Bank Credit Agreement. As of June 30, ~~2019. We incur a commitment fee~~2020, we had $265 million of ~~0.50% on the undrawn portion~~outstanding borrowings and approximately $95 million of ~~the aggregate lender commitments~~outstanding letters of credit under the Bank Credit Agreement.

The Bank Credit Agreement ~~contains~~contained certain financial performance covenants through the maturity of the facility, including the following:

A Consolidated Total Debt to Consolidated EBITDAX covenant, with such ratio not to exceed 5.25 to 1.0 through December 31, 2020 and 4.50 to 1.0 thereafter;

A consolidated senior secured debt to consolidated EBITDAX covenant, with such ratio not to exceed 2.5 to 1.0. Only debt under our Bank Credit Agreement is considered consolidated senior secured debt for purposes of this ratio;

A minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0; and

A requirement to maintain a current ratio (i.e., Consolidated Current Assets to Consolidated Current Liabilities) of 1.0 to 1.0.

AsFor purposes of ~~June 30, 2019, we were in compliance with all debt covenants under~~computing the current ratio per the Bank Credit ~~Agreement.~~ Agreement, Consolidated Current Assets exclude the current portion of derivative assets but include available borrowing capacity under the senior secured bank credit facility, and Consolidated Current Liabilities exclude the current portion of derivative liabilities as well as the current portions of long-term indebtedness outstanding.

The above description of our Bank Credit Agreement and defined terms are contained in the Bank Credit Agreement and the amendments thereto.

~~2019 Note Exchanges~~

During June 2019, we closed a series of debt exchanges to extend the maturities of our outstanding long-term debt and reduce our debt principal. As part of these transactions, we exchanged a total of $468.4 million aggregate principal amount of our then existing senior subordinated notes for $102.6 million aggregate principal amount of new 7¾% Senior Secured Notes, $245.5 million aggregate principal amount of new 2024 Convertible Senior Notes and $120.0 million of cash. The exchanged subordinated notes consisted of $152.2 million aggregate principal amount of our 6⅜% Senior Subordinated Notes due 2021, $219.9 million aggregate principal amount of our 5½% Senior Subordinated Notes due 2022 and $96.3 million aggregate principal amount of our 4⅝% Senior Subordinated Notes due 2023. In addition, we also exchanged $425.4 million of 7½% Senior Secured Second Lien Notes due 2024 (the “7½% Senior Secured Notes”) for $425.4 million aggregate principal amount of 7¾% Senior Secured Notes.

~~In accordance with FASC 470-50,~~ ~~Modifications and Extinguishments~~, the June 2019 exchange of our existing senior subordinated notes was accounted for as a debt extinguishment. Therefore, our new 7¾% Senior Secured Notes and new 2024 Convertible Senior Notes were recorded on our balance sheet at fair market value based upon initial trading prices following their issuance, resulting in a discount to their principal amount of $22.6 million and $79.9 million, respectively. These debt discounts will be amortized as interest expense over the terms of these notes. As a result, we recognized a noncash gain on debt extinguishment, net of transaction costs, totaling $100.3 million for the three and six months ended June 30, 2019, in our Unaudited Condensed Consolidated Statements of Operations.

Separately, the exchange of our existing senior secured second lien notes was accounted for as a modification of those notes. Therefore, no gain or loss was recognized, and previously deferred debt issuance costs of $6.9 million were treated as a discount to the principal amount of the new 7¾% Senior Secured Notes, which discount will be amortized as interest expense over the term of these notes.

~~7¾% Senior Secured Second Lien Notes due 2024~~

As part of the notes exchanges discussed above, in June 2019 we issued $528.0 million of 7¾% Senior Secured Notes in connection with exchanges with certain holders of the Company’s outstanding senior subordinated notes and existing 7½% Senior Secured Notes (see ~~2019 Note Exchanges~~ ~~above). The 7¾% Senior Secured Notes, which carry a stated interest rate of 7.75% per annum, were recorded at approximately 94% of their principal amount in accordance with FASC 470-50,~~ ~~Modifications and Extinguishments~~, which equates to an effective yield to maturity of approximately 9.39%. Interest on the 7¾% Senior Secured Notes is payable semiannually in arrears on February 15 and August 15 of each year, and mature on February 15, 2024. We may redeem the 7¾% Senior Secured Notes in whole or in part at our option beginning August 15, 2020, at a redemption price of 103.875% of the principal amount, and at declining redemption prices thereafter, as specified in the indenture governing the 7¾% Senior Secured Notes. Prior to August 15, 2020, we may at our option redeem up to an aggregate of 35% of the principal amount of the 7¾% Senior Secured Notes at a price of 107.75% of par with the proceeds of certain equity offerings. In addition, at any

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

~~time prior to August 15,~~Second Quarter 2020 ~~we may redeem the 7¾% Senior Secured Notes in whole or in part at a price equal to 100%~~Conversion of ~~the principal amount plus a “make-whole” premium and accrued and unpaid interest. The 7¾% Senior Secured Notes are not subject to any sinking fund requirements.~~

The 7¾% Senior Secured Notes are guaranteed jointly and severally by our subsidiaries representing substantially all of our assets, operations and income and are secured by second-priority liens on substantially all of the assets that secure the Bank Credit Agreement, which second-priority liens are contractually subordinated to liens that secure our Bank Credit Agreement and any future additional priority lien debt.

6⅜% Convertible Senior Notes due 2024

~~As part~~During the second quarter of ~~the notes exchanges discussed above, in June 2019 we issued $245.5~~2020, holders of $19.9 million aggregate principal amount outstanding of ~~2024~~our 6⅜% Convertible Senior Notes ~~in connection with exchanges with certain holders of the Company’s existing senior subordinated notes (see~~ ~~2019 Note Exchanges~~ ~~above). The~~due 2024 (the “2024 Convertible Senior ~~Notes, which carry a stated interest rate~~Notes”) converted their notes into shares of ~~6.375% per annum, were recorded~~Denbury common stock, at ~~approximately 67%~~the rates specified in the indenture for the notes, resulting in the issuance of ~~their principal amount in accordance with FASC 470-50,~~ ~~Modifications and Extinguishments~~, which equates to an effective yield to maturity of approximately 15.31%. Interest on the 2024 Convertible Senior Notes is payable semiannually in arrears on June 30 and December 30 of each year, beginning in December 2019, and mature on December 31, 2024. We do not have the right to redeem the 2024 Convertible Senior Notes prior to their maturity. The 2024 Convertible Senior Notes are convertible into7.4 million shares of our common stock ~~at any time, at~~upon conversion. The debt principal balance net of debt discounts totaling $13.9 million, was reclassified to “Paid-in capital in excess of par” and “Common stock” in our Unaudited Condensed Consolidated Balance Sheets upon the ~~option~~conversion of the ~~holders, at a rate of 370~~notes into shares of Denbury common ~~stock per $1,000 principal amount~~stock. As of June 30, 2020, there was $225.7 million 2024 Convertible Senior Notes ~~which is equivalent~~outstanding.

First Quarter 2020 Repurchases of Senior Secured Notes

During March 2020, we repurchased a total of $30.2 million aggregate principal amount of our 2021 Senior Secured Notes in open-market transactions for a total purchase price of $14.2 million, excluding accrued interest. In connection with these transactions, we recognized a $19.0 million gain on debt extinguishment, net of unamortized debt issuance costs and future interest payable written off.

Note 5. Income Taxes

On March 27, 2020, Congress enacted the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) to ~~up to approximately 90.9 million shares~~provide certain taxpayer relief as a result of the ~~Company’s common stock, subject~~COVID-19 pandemic. The CARES Act included several favorable provisions that impacted income taxes, primarily the modified rules on the deductibility of business interest expense for 2019 and 2020, a five-year carryback period for net operating losses generated after 2017 and before 2021, and the acceleration of refundable alternative minimum tax credits.

We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to ~~customary adjustments~~our ordinary income or loss to calculate our estimated tax liability or benefit. Our income taxes are based on an estimated statutory rate of approximately 25% in 2020 and 2019. As provided for under FASC 740-270-35-2, we determined the actual effective tax rate for the six months ended June 30, 2020 was the best estimate of our annual effective tax rate. Our effective tax rate for the six months ended June 30, 2020, differed from our estimated statutory rate, primarily due to the ~~conversion rate~~establishment of a full valuation allowance on our $85.0 million of enhanced oil recovery credits and ~~threshold price with respect~~research and development credits that currently are not expected to ~~among other things, stock dividends~~be utilized, partially offset by tax changes enacted by the CARES Act which resulted in the full release of a $24.5 million valuation allowance against a portion of our business interest expense deduction that we previously estimated would be disallowed.

Note 6. Stock Compensation

2020 Compensation Adjustments

In response to the ongoing significant economic and ~~distributions, mergers~~market uncertainty affecting the oil and reclassifications. The 2024 Convertible Senior Notes will be automatically converted into shares of common stock at this rate if the volume weighted average trading price of the Company’s common stock equals or exceeds the threshold price, which initially is $2.43 per share, for 10 trading days in any period of 15 consecutive trading days, subject to satisfaction of certain other conditions. Additionally,gas industry, the Company ~~may, based on a determination of~~and its Board of Directors (the “Board”) and Compensation Committee (the “Compensation Committee”) conducted a comprehensive review of our compensation programs across the organization. As a result of this review, the Board and Compensation Committee determined that ~~such changes are~~our historic compensation structure and performance metrics would not be effective in motivating and incentivizing our workforce in the ~~best interests~~current environment. With the advice of our independent compensation consultant and legal advisors, effective June 3, 2020, the Company and ~~subject~~the Board implemented a revised compensation structure for all of the Company’s employees (including its named executive officers) and non-employee directors. In connection with the revised compensation structure, the Company’s CEO voluntarily reduced his 2020 base annual salary by 20%, and the Company’s CEO and CFO voluntarily reduced 2020 targeted variable compensation by 35% and 20%, respectively. In addition, the Chairman of the Board reduced his 2020 chairman retainer by 20%.

Under part of the revised compensation structure, which applies to a group of 21 of the Company’s executives (including our named executive officers) and senior managers, all outstanding equity awards and 2020 targeted variable cash-based compensation for those individuals were canceled and replaced with a cash retention incentive. In total, $15.2 million in cash retention incentives were prepaid to those employees in June 2020, with an obligation to repay up to 100% of the compensation (on an after-tax basis) if certain ~~limitations, increase~~conditions are not satisfied. Our named executive officers’ cash retention incentive will be earned 50% based on their continued employment for a period of up to 12 months, and 50% based on achieving certain specified incentive metrics. I

Table of Contents

Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

n accordance with FASC Topic 718, Compensation – Stock Compensation, we accounted for the ~~conversion rate. Any such conversion rate increase would cause~~transaction involving equity compensation as an award modification and reclassified the awards from equity to liability awards. As a ~~proportional decrease in~~result of the ~~threshold price for mandatory conversions, and thereby would enable~~modification of the ~~Company~~awards, unrecognized compensation at the time of modification was determined to ~~require a mandatory conversion into common stock at a lower price~~be $18.7 million ($4.1 million of incremental compensation expense, of which $3.4 million was expensed during the second quarter of 2020), which was higher than the ~~initial~~$15.2 million cash payment, and was calculated as the greater of (i) grant date fair value of the previously-outstanding awards plus incremental compensation (defined as cash paid related to the cash retention incentive in excess of the modification date fair value of the previously-existing awards) or ~~then-prevailing threshold price.~~(ii) cash paid for the cash retention incentive for each award. The value will be recognized as total compensation expense for each award over the service period. We recognized $11.5 million of the $18.7 million as compensation expense in “General and administrative expenses” in our Unaudited Condensed Consolidated Statements of Operations during the second quarter of 2020, with the remaining $7.2 million amortized over the estimated remaining service period. The accounting for remaining share-based compensation awards will continue throughout the period covered by the Chapter 11 Restructuring.

Note 5.7. Commodity Derivative Contracts

We do not apply hedge accounting treatment to our oil and natural gas derivative contracts; therefore, the changes in the fair values of these instruments are recognized in income in the period of change. These fair value changes, along with the settlements of expired contracts, are shown under “Commodity derivatives expense (income)” in our Unaudited Condensed Consolidated Statements of Operations.

Historically, we have entered into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength and expectation of future commodity prices.

We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of June 30, ~~2019,~~2020, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

The following table summarizes our commodity derivative contracts as of June 30, ~~2019~~2020, none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic:


Months		Index Price	Volume (Barrels per day)	Contract Prices ($/Bbl)														Index Price	Volume (Barrels per day)	Contract Prices ($/Bbl)
				Range⁽¹⁾				Weighted Average Price												Range⁽¹⁾				Weighted Average Price
				Range⁽¹⁾				Swap		Sold Put		Floor			Ceiling					Range⁽¹⁾				Swap		Sold Put		Floor		Ceiling
Oil Contracts:	Oil Contracts:																Oil Contracts:
2019 Fixed-Price Swaps
July – Dec		Argus LLS	13,000	$	60.00	–	74.90	$	64.69	$	—	$	—		$	—
2019 Three-Way Collars⁽²⁾
2020 Fixed-Price Swaps																	2020 Fixed-Price Swaps
July – Dec		NYMEX	22,000	$	55.00	–	75.45	$	—	$	48.55	$	56.55		$	69.17		NYMEX	13,500	$	36.25	–	61.00	$	40.52	$	—	$	—	$	—
July – Dec		Argus LLS	5,500		62.00	–	86.00	—		54.73		63.09			79.93			Argus LLS	7,500		35.00	–	64.26	51.67		—		—		—
2020 Fixed-Price Swaps
Jan – Dec		NYMEX	2,000	$	60.00	–	61.00	$	60.59	$	—	$	—		$	—
Jan – Dec		Argus LLS	4,000		60.72	–	64.26	62.41		—		—			—
2020 Three-Way Collars⁽²⁾	2020 Three-Way Collars⁽²⁾																2020 Three-Way Collars⁽²⁾
Jan – June		NYMEX	12,000	$	55.00	–	82.65	$	—	$	48.89	$	58.49		$	65.57
Jan – June		Argus LLS	4,500		62.50	–	87.10	—		53.89		63.89			72.55
July – Dec		NYMEX	10,000		55.00	–	82.65	—		49.05		58.58			65.81			NYMEX	9,500	$	55.00	–	82.65	$	—	$	47.93	$	57.00	$	63.25
July – Dec		Argus LLS	2,500		64.00	–	87.10	—		54.40		64.40		��	76.59			Argus LLS	5,000		58.00	–	87.10	—		52.80		61.63		70.35


(1)	Ranges presented for fixed-price swaps represent the lowest and highest fixed prices of all open contracts for the period presented. For three-way collars, ranges represent the lowest floor price and highest ceiling price for all open contracts for the period presented.

(2)

A three-way collar is a costless collar contract combined with a sold put feature (at a lower price) with the same counterparty. The value received for the sold put is used to enhance the contracted floor and ceiling price of the related collar. At the contract settlement date, (1) if the index price is higher than the ceiling price, we pay the counterparty the difference between the index price and ceiling price for the contracted volumes, (2) if the index price is between the floor and ceiling price, no settlements occur, (3) if the index price is lower than the floor price but at or above the sold put price, the counterparty pays us the difference between the index price and the floor price for the contracted volumes and (4) if ~~the index price is lower~~oil prices average less than the sold put price, ~~the counterparty pays us~~our receipts on settlement would be limited to the difference between the floor price and the sold put price for the contracted volumes.

On July 31, 2020, the Bankruptcy Court entered an interim order authorizing Denbury to maintain its pre-petition hedge contracts and enter into new hedges in the ordinary course of business. See Note 1,Basis of Presentation – Entry into Restructuring Support Agreement and Voluntary Reorganization under Chapter 11 of the Bankruptcy Code.

Note 6.8. Fair Value Measurements

The FASC Fair Value Measurement topic defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (often referred to as the “exit price”). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the income approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

Level 1 – Quoted prices in active markets for identical assets or liabilities as of the reporting date.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded oil derivatives that are based on NYMEX ~~pricing~~ and ~~fixed-price swaps that are based on~~ regional pricing other than NYMEX (e.g., Light Louisiana Sweet). Our costless collars and the sold put features of our three-way collars are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying

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~~Denbury Resources Inc.~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

instruments, maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

•

Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. As of ~~June 30, 2019~~, instruments in this category include non-exchange-traded three-way collars that are based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The valuation models utilized for costless collars and three-way collars are consistent with the methodologies described above; however, the implied volatilities utilized in the valuation of Level 3 instruments are developed using a benchmark, which is

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. As of December 31, 2019, instruments in this category included non-exchange-traded three-way collars that were based on regional pricing other than NYMEX (e.g., Light Louisiana Sweet). The valuation models utilized for three-way collars were consistent with the methodologies described above; however, the implied volatilities utilized in the valuation of Level 3 instruments were developed using a benchmark, which was considered a significant unobservable input. An increase or decrease of 100 basis points in the implied volatility inputs utilized in our fair value measurement would result in a change of approximately $150 thousand in the fair value of these instruments as of June 30, 2019.

We adjust the valuations from the valuation model for nonperformance risk, using our estimate of the counterparty’s credit quality for asset positions and our credit quality for liability positions. We use multiple sources of third-party credit data in determining counterparty nonperformance risk, including credit default swaps.

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of the periods indicated:


	Fair Value Measurements Using:										Fair Value Measurements Using:
In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total			Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total
June 30, 2019
June 30, 2020
Assets
Oil derivative contracts – current	$	—	$	19,927		$	4,520	$	24,447		$	—	$	47,655		$	—		$	47,655
Oil derivative contracts – long-term	—		7,935			1,553		9,488
Total Assets	$	—	$	27,862		$	6,073	$	33,935		$	—	$	47,655		$	—		$	47,655

Liabilities
Oil derivative contracts – current	$	—	$	(1,912	)	$	—	$	(1,912	)	$	—	$	(7,691	)	$	—		$	(7,691	)
Oil derivative contracts – long-term	—		(22		)	—		(22		)
Total Liabilities	$	—	$	(1,934	)	$	—	$	(1,934	)	$	—	$	(7,691	)	$	—		$	(7,691	)

December 31, 2018
December 31, 2019
Assets
Oil derivative contracts – current	$	—	$	81,621		$	11,459	$	93,080		$	—	$	8,503		$	3,433		$	11,936
Oil derivative contracts – long-term	—		2,030			2,165		4,195
Total Assets	$	—	$	83,651		$	13,624	$	97,275		$	—	$	8,503		$	3,433		$	11,936

Liabilities
Oil derivative contracts – current											$	—	$	(6,522	)	$	(1,824	)	$	(8,346	)
Total Liabilities											$	—	$	(6,522	)	$	(1,824	)	$	(8,346	)

Since we do not apply hedge accounting for our commodity derivative contracts, any gains and losses on our assets and liabilities are included in “Commodity derivatives expense (income)” in the accompanying Unaudited Condensed Consolidated Statements of Operations.

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Notes to Unaudited Condensed Consolidated Financial Statements

Level 3 Fair Value Measurements

The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the three and six months ended June 30, ~~2019~~2020 and ~~2018:~~2019:


	Three Months Ended						Six Months Ended						Three Months Ended					Six Months Ended
	June 30,						June 30,						June 30,					June 30,
In thousands	2019			2018			2019			2018			2020		2019			2020			2019
Fair value of Level 3 instruments, beginning of period	$	3,686		$	—		$	13,624		$	—		$	—	$	3,686		$	1,609		$	13,624
Transfers out of Level 3													—		—			(1,609		)	—
Fair value gains (losses) on commodity derivatives	2,720			(1,168		)	(6,360		)	(1,168		)	—		2,720			—			(6,360		)
Receipts on settlements of commodity derivatives	(333		)	—			(1,191		)	—			—		(333		)	—			(1,191		)
Fair value of Level 3 instruments, end of period	$	6,073		$	(1,168	)	$	6,073		$	(1,168	)	$	—	$	6,073		$	—		$	6,073

The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets or liabilities still held at the reporting date	$	2,387		$	(1,168	)	$	(1,240	)	$	(1,168	)	$	—	$	2,387		$	—		$	(1,240	)

~~We utilize an income approach to value our~~Instruments previously categorized as Level 3 included non-exchange-traded three-way ~~collars. We obtain~~collars that were based on regional pricing other than NYMEX, whereby the implied volatilities utilized were developed using a benchmark, which was considered a significant unobservable input. The transfers between Level 3 and ~~ensure~~Level 2 during the ~~appropriateness of~~period generally relate to changes in the significant relevant observable and unobservable inputs ~~to the calculation, including contractual prices~~that are available for ~~the underlying instruments, maturity, forward prices for commodities, interest rates, volatility factors and credit worthiness, and~~ the fair value ~~estimate is prepared and reviewed on a quarterly basis. The following table details fair value inputs related to implied volatilities utilized in the valuation~~measurements of ~~our Level 3 oil derivative contracts:~~

Fair Value at
6/30/2019
(in thousands) Valuation Technique Unobservable Input Volatility Range
Oil derivative contracts $ 6,073
Discounted cash flow / Black-Scholes Volatility of Light Louisiana Sweet for settlement periods beginning after June 30, 2019 20.4% – 34.1%

such financial instruments.

Other Fair Value Measurements

The carrying value of our loans under our Bank Credit Agreement approximate fair value, as they are subject to short-term floating interest rates that approximate the rates available to us for those periods. We use a market approach to determine the fair value of our fixed-rate long-term debt using observable market data. The fair values of our senior secured second lien notes, convertible senior notes, and senior subordinated notes are based on quoted market prices, which are considered Level 1 measurements under the fair value hierarchy. The estimated fair value of the principal amount of our debt as of June 30, ~~2019~~2020 and December 31, ~~2018~~2019, excluding pipeline financing ~~and capital lease~~ obligations, was $~~1,935.6~~922.0 million and ~~$1,886.1~~$1,833.1 million,~~, respectively.~~ respectively, which decrease is primarily driven by a decrease in quoted market prices. We have other financial instruments consisting primarily of cash, cash equivalents, U.S. Treasury ~~Notes,~~notes, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.

Note 7.9. Commitments and Contingencies

Chapter 11 Proceedings

Refer to Note 1, Basis of Presentation – Entry into Restructuring Support Agreement and Voluntary Reorganization under Chapter 11 of the Bankruptcy Code, for more information on the Chapter 11 Restructuring.

Litigation

We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses. We are also subject to audits for various taxes (income, sales and use, and severance) in the various states in which we operate, and from time to time receive assessments for potential taxes that we may owe. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position, results of operations or cash flows, litigation is subject to inherent uncertainties. We accrue for losses from litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated.

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Notes to Unaudited Condensed Consolidated Financial Statements

Riley Ridge Helium Supply Contract Claim

As part of our 2010 and 2011 acquisitions of the Riley Ridge Unit and associated gas processing facility that was under construction, the Company assumed a 20-year helium supply contract under which we agreed to supply the helium separated from the full well stream by operation of the gas processing facility to a third-party purchaser, APMTG Helium, LLC (“APMTG”). The helium supply contract provides for the delivery of a minimum contracted quantity of helium, with liquidated damages payable if specified quantities of helium are not supplied in accordance with the terms of the contract. The liquidated damages ~~are specified in the contract at up to $8.0 million per contract year and~~ are capped at an aggregate of $46.0 million over the term of the contract.

As the gas processing facility has been shut-in since mid-2014 due to significant technical issues, we have not been able to supply helium under the helium supply contract. In a case filed in November 2014 in the Ninth Judicial District Court of Sublette County, Wyoming, APMTG claimed multiple years of liquidated damages for non-delivery of volumes of helium specified under the helium supply contract. The Company claimed that its contractual obligations were excused by virtue of events that fall within the force majeure provisions in the helium supply contract.

On March 11, 2019, the trial court entered a final judgment that a force majeure condition did exist, but the Company’s performance was excused by the force majeure provisions of the contract for only a 35-day period in 2014, and as a result the Company should pay APMTG liquidated damages and interest thereon for those time periods from contract commencement to the close of evidence (November 29, 2017) when the Company’s performance was not excused as provided in the contract. The Company has filed a notice of appeal of the trial court’s ruling to the Wyoming Supreme Court, the results of which cannot be predicted at this time.

. The Company’s position continues to be that its contractual obligations have been and continue to be excused by events that fall within the force majeure provisions inof the helium supply ~~contract.~~contract, so the Company has appealed the trial court’s ruling to the Wyoming Supreme Court. Briefing for the appeal by the Company and APMTG was completed on June 3, 2020, and oral arguments to be heard by the Wyoming Supreme Court are currently scheduled for August 13, 2020, after which the Wyoming Supreme Court will enter its judgment on the appeal. The timing and outcome of this appeal process is currently unpredictable, but at this time is anticipated to extend over the three or four months following the conclusion of oral arguments. The Company ~~intends~~expects to ~~continue~~enter into a stipulation with APMTG, to ~~vigorously defend its position and pursue all of its rights.~~be approved by the Bankruptcy Court, to lift the automatic stay with respect to this proceeding so that the appeal process may proceed as outlined above.

Absent reversal of the trial court’s ruling on appeal, the Company anticipates total liquidated damages would equal the $46.0 million aggregate cap under the helium supply contract ~~(including $14.2 million of liquidated damages for the contract years ending July 31, 2018 and July 31, 2019)~~ plus ~~$4.2~~$6.2 million of associated costs (through June 30, ~~2019)~~2020), for a total of ~~$50.2~~$52.2 million, included in ~~“Other~~“Accounts payable and accrued liabilities” in our Unaudited Condensed Consolidated Balance Sheets as of June 30, ~~2019.~~2020. The Company has a $32.8 million letter of credit posted as security in this case as part of the appeal process.

Note 8.10. Additional Balance Sheet Details

Trade and Other Receivables, Net



	June 30,		December 31,
In thousands	2020		2019
Trade accounts receivable, net	$	12,790	$	12,630
Federal income tax receivable, net	10,457		2,987
Commodity derivative settlement receivables	9,037		675
Other receivables	2,165		2,026
Total	$	34,449	$	18,318

Note 11. Subsequent ~~Event~~Events

Delhi Insurance Receivable

In late July 2020, we entered into agreements with certain of our insurance carriers, pursuant to which we expect to receive approximately $16 million as a reimbursement of previously-incurred costs and damages associated with the June 2013 release of well fluids within the Denbury-operated Delhi Field located in northern Louisiana. We expect to receive such insurance proceeds by the end of August 2020.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Houston Area Land Sale

On July ~~17, 2019,~~24, 2020, we completed the ~~Compensation Committee~~sale of a portion of certain non-producing surface acreage in the Houston area. The gross proceeds from the sale of this portion of the acreage under contract were approximately $14 million.

NYSE Delisting

On July 31, 2020, the New York Stock Exchange (the “NYSE”) notified us of its determination to commence proceedings to delist our ~~Board~~common stock from the NYSE, and as of ~~Directors made~~July 31, 2020 to indefinitely suspend trading of our annual grant of long-term incentive awards, consisting of 9,115,746 shares of restricted stock and 3,759,051 restricted stock units which are to be settled solely in cash, to certain employees under our 2004 Omnibus Stock and Incentive Plan. The closing stock price of Denbury’s common stock on ~~July 17, 2019 was $1.17 per share; however,~~ the ~~Compensation Committee utilized a~~NYSE. Suspension of trading in our common stock ~~price floor of $2.25 per share~~and delisting proceedings were undertaken by the NYSE in determining the total number of shares of restricted stock granted. In addition, the amount of cash for which the restricted stock units can be settled is capped at no more than two times the grant date valueaccordance with Section 802.01D of the ~~restricted stock units. The awards generally vest one-third per year over a three-year period.~~NYSE Listed Company Manual due to our filing of the Chapter 11 Restructuring on July 30, 2020.

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Denbury Resources Inc.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and Notes thereto included herein and our Consolidated Financial Statements and Notes thereto included in our Annual Report on Form 10-K for the year ended December 31, ~~2018~~2019 (the “Form 10-K”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K. Any terms used but not defined herein have the same meaning given to them in the Form 10-K. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Risk Factors under Item 1A of this Form 10-Q as well as Item 1A of the Form 10-K, along with Forward-Looking Information at the end of this section for information on the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

OVERVIEW

Denbury is an independent oil and natural gas company with operations focused in two key operating areas: the Gulf Coast and Rocky Mountain regions. Our goal is to increase the value of our properties through a combination of exploitation, drilling and proven engineering extraction practices, with the most significant emphasis relating to CO₂ enhanced oil recovery operations.

Oil Price Impact on Our Business. Our financial results are significantly impacted by changes in oil prices, as ~~97%~~98% of our production is oil. Changes in oil prices impact all aspects of our business; most notably our cash flows from operations, revenues, ~~and~~ capital allocation and budgeting ~~decisions. Excluding the impact of derivative settlements,~~decisions, and oil and natural gas reserves volumes. The table below outlines changes in our ~~average~~ realized oil ~~price was $59.39~~prices, before and after commodity hedging impacts, for our most recent comparative periods:



	Three Months Ended
	June 30, 2020		March 31, 2020		December 31, 2019		June 30, 2019
Average net realized prices
Oil price per Bbl - excluding impact of derivative settlements	$	24.39	$	45.96	$	56.58	$	62.22
Oil price per Bbl - including impact of derivative settlements	34.64		50.92		58.30		61.92

Recent Developments in Response to Oil Price Declines. In January and February 2020, NYMEX oil prices averaged in the mid-$50s per Bbl range before a precipitous decline in early March 2020 due to the combination of OPEC supply pressures and a reduction in worldwide oil demand amid the COVID-19 coronavirus (“COVID-19”) pandemic, resulting in NYMEX oil prices averaging approximately $30 per Bbl in March. NYMEX oil prices continued to decline in April 2020 to an average of $17 per Bbl, before increasing to an average of $29 per Bbl during ~~the first half of 2019, compared to $66.29~~May 2020, $38 per Bbl during ~~the first half of 2018. Including the impact of derivative settlements, our average realized oil price was $60.03~~June 2020, and $41 per Bbl during the first half of 2019, compared to $58.07 per Bbl in the first half of 2018. With our continued focus on improving the Company’s financial position and preserving liquidity, we have based our 2019 budget on a flat $50 oil price, and our 2019 capital spending has been budgeted in a range of $240 million to $260 million, excluding capitalized interest and acquisitions, which is roughly a 23% decrease from our 2018 capital spending levels. Based on recent oil price futures and our projections for the remainder of 2019, we estimate that our cash flows from operations will be significantly higher than our capital expenditures and result in Denbury generating significant excess cash flow during 2019. Also, we have hedged approximately 70% of our estimated second half 2019 production in order to provide a greater level of certainty in our 2019 cash flow. Based on our strong production performance during the first half of 2019 and expectations for the remainder of 2019, we currently anticipate that our 2019 production will average between 57,000 and 59,500 BOE/d, compared to our previous estimate of 56,000 and 60,000 BOE/d. Additional information concerning our 2019 budget and plans is included below under ~~Capital Resources and Liquidity – Overview~~.July 2020.

~~Operating Highlights.~~ ~~We recognized net income of $146.7 million, or $0.32 per diluted common share,~~The decrease in NYMEX oil prices during the second quarter of ~~2019,~~2020, as compared to ~~net income~~the first quarter of ~~$30.2 million, or $0.07 per diluted common share, during~~2020, significantly decreased our realized oil prices in the second quarter of ~~2018. The primary drivers~~2020 by almost half compared to those realized in the first quarter of 2020. In response to these ~~comparative period changes~~developments, in ~~our operating results were~~ the ~~following:~~first six months of 2020 we have implemented the following operational and financial measures:

~~Commodity derivatives expense decreased~~Reduced budgeted 2020 capital spending by ~~$121.0~~$80 million, ~~($24.8~~or 44%, to approximately $95 million ~~of income in the current-year period compared~~ to $96.2 million of expense in the prior-year period.) This decrease was primarily due to a change in noncash fair value adjustments of $67.8 million ($26.3 million of income in the current-year period compared to $41.4 million of expense in the prior-year period) and a $53.2 million decrease in payments on derivative contracts.$105 million;


•	~~Noncash gain on debt extinguishment, net of transaction costs, of $100.3 million in~~Deferred the ~~current-year period related to our June 2019 notes exchanges (see~~ Cedar Creek Anticline CO~~2019 Note Exchanges~~₂ ~~below).~~tertiary flood development project beyond 2020;

Evaluated production economics at each field and shut-in production beginning in late March 2020 that was uneconomic to produce or repair based on prevailing oil prices; and

•

~~Oil~~Conducted a complete market-based review of strategic alternatives, including a comprehensive restructuring, to enhance our liquidity and ~~natural gas revenues~~strengthen our capital structure. After extensive negotiations, we arrived at the transactions embodied in the ~~second quarter of 2019 decreased by~~restructuring support agreement (the “RSA”). See discussion under ~~$45.1 million, or~~ ~~12%, principally driven by a~~ 9%Chapter 11 Restructuring ~~decrease in realized oil prices.~~below.

We generated $148.6 million of cash flow from operating activities in the second quarter of 2019, relatively unchanged from the $154.0 million generated during the second quarter of 2018, but $84.2 million higher than the $64.4 million of cash flow generated in the first quarter of 2019.

~~2019 Note Exchanges.~~ During June 2019, we closed a series of debt exchanges to extend the maturities of our outstanding long-term debt and reduce our debt principal. As part of these transactions, we exchanged a total of $468.4 million aggregate principal amount of our then existing senior subordinated notes for $102.6 million aggregate principal amount of our new 7¾% Senior Secured Second Lien Notes due 2024 (the “7¾% Senior Secured Notes”), $245.5 million aggregate principal amount of our new 6⅜% Convertible Senior Notes due 2024 (the “2024 Convertible Senior Notes”) and $120.0 million of cash. The exchanged

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Denbury Resources Inc.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

~~subordinated notes consisted~~

Chapter 11 Restructuring. On July 28, 2020, Denbury and its subsidiaries (collectively, “Denbury”) entered into the RSA with lenders holding 100% of ~~$152.2 million aggregate principal amount~~the revolving loans under our bank credit facility (“Bank Credit Agreement”) and certain holders of ~~our 6⅜% Senior Subordinated Notes due 2021, $219.9 million aggregate principal amount~~a majority of ~~our 5½% Senior Subordinated Notes due 2022 and $96.3 million aggregate principal amount of our 4⅝% Senior Subordinated Notes due 2023. In addition, as part of creating a more liquid series of~~senior secured second lien notes and convertible senior notes to support a restructuring in accordance with the terms set forth in the Company’s chapter 11 plan of reorganization (the “Plan”). On July 30, 2020 (the “Petition Date”), Denbury and its subsidiaries filed petitions for reorganization in a “prepackaged” voluntary bankruptcy (the “Chapter 11 Restructuring”) under chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Chapter 11 Restructuring is being undertaken to deleverage the Company, relieving it of approximately $2.1 billion of bond debt by issuing equity in a reorganized entity to the holders of that debt. The Plan and the related disclosure statement were each filed with the Bankruptcy Court on July 30, 2020. We expect to continue operations in the normal course for the duration of the Chapter 11 Restructuring. On July 31, 2020, the Bankruptcy Court entered orders approving certain customary “first day” relief to enable Denbury to operate in the ordinary course during the Chapter 11 Restructuring, including approval on an interim basis of post-petition financing under a debtor-in-possession (“DIP”) facility (the “DIP Facility”) and use of cash collateral of Denbury’s lenders and secured noteholders. Denbury is currently soliciting votes to accept a proposed chapter 11 plan (the “Plan”) from holders of claims and interests entitled to vote. The hearing to confirm the Plan and the final hearing on approval of the DIP Facility and use of cash collateral is currently scheduled for September 2, 2020. For more information on the Chapter 11 Restructuring and related matters, refer to Note 1, Basis of Presentation – Entry into Restructuring Support Agreement and Voluntary Reorganization under Chapter 11 of the Bankruptcy Code, and Note 4, Long-Term Debt, to the condensed consolidated financial statements.

Comparative Financial Results and Highlights. We recognized a net loss of $697.5 million, or $1.41 per diluted common share, during the second quarter of 2020, compared to net income of $146.7 million, or $0.32 per diluted common share, during the second quarter of 2019. The primary drivers of our change in operating results were the following:

Oil and natural gas revenues decreased by $221.0 million (67%), with 51% of the decrease due to lower commodity prices and 16% of the decrease due to lower production, offset in ~~2024, we also exchanged $425.4~~part by an improvement in derivative commodity settlements of $47.2 million from the prior-year period;

A $662.4 million full cost pool ceiling test write-down as a result of the decline in NYMEX oil prices;

Commodity derivatives expense increased by $64.9 million ($40.1 million of ~~7½% Senior Secured Second Lien Notes due 2024 (the “7½% Senior Secured Notes”) for $425.4~~expense during the second quarter of 2020 compared to $24.8 million ~~aggregate principal amount~~ of ~~7¾% Senior Secured Notes.~~income during the second quarter of 2019), resulting from $112.1 million of incremental noncash fair value losses partially offset by a $47.2 million increase in cash receipts upon settlement between the second quarters of 2019 and 2020;

Reductions across numerous expense categories, the most significant being $36.6 million in lease operating expenses and $15.1 million in taxes other than income; and

In July 2019, we closed transactions to exchange an additional $4.0 million aggregate principal amount of 7½% Senior Secured Notes for $3.8 million aggregate principal amount of 7¾% Senior Secured Notes. The table below details the changes in our debt principal balances from March 31, 2019 to June 30, 2019, for those notes impacted by the June 2019 note exchanges discussed above, and includes the impact of the additional $4.0 million aggregate principal amount of 7½% Senior Secured Notes exchanged in July:

Principal Exchanged
In thousands March 31, 2019 (excluding cash) June 30, 2019
Notes Exchanged
6⅜% Senior Subordinated Notes due 2021 $ 203,545
$ (152,241 ) $ 51,304
5½% Senior Subordinated Notes due 2022 314,662
(219,878 ) 94,784
4⅝% Senior Subordinated Notes due 2023 307,978
(96,283 ) 211,695
7½% Senior Secured Second Lien Notes due 2024 450,000
(429,359 ) 20,641

New Notes Issued
7¾% Senior Secured Second Lien Notes due 2024 —
531,821
531,821
6⅜% Convertible Senior Notes due 2024
—
245,548
245,548
$ 1,276,185
$ (120,392 )
⁽¹⁾
$ 1,155,793


~~(1)~~	~~Primarily represents cash paid in the debt exchange transactions.~~

~~In accordance with Financial Accounting Standards Board Codification (“FASC”) 470-50,~~ ~~Modifications and Extinguishments~~, the June 2019 exchange of our existing senior subordinated notes was accounted for as a debt extinguishment. Therefore, our new 7¾% Senior Secured Notes and new 2024 Convertible Senior Notes were recorded on our balance sheet at fair market value based upon initial trading prices following their issuance, resulting in a discount to their principal amount of $22.6 million and $79.9 million, respectively. These debt discounts will be amortized as interest expense over the terms of these notes. As a result, we recognized a noncashA non-cash gain on debt extinguishment, net of transaction costs, ~~totaling~~of $100.3 million in the prior-year period related to our June 2019 notes exchanges.

Second Quarter 2020 Conversion of 6⅜% Convertible Senior Notes due 2024. During the second quarter of 2020, holders of $19.9 million aggregate principal amount outstanding of our 6⅜% Convertible Senior Notes due 2024 (the “2024 Convertible Senior Notes”) converted their notes into shares of Denbury common stock, at the rates specified in the indenture for the ~~three~~notes, resulting in the issuance of 7.4 million shares of our common stock upon conversion. The debt principal balance net of debt discounts totaling $13.9 million, was reclassified to “Paid-in capital in excess of par” and ~~six months ended June 30, 2019,~~“Common stock” in our Unaudited Condensed Consolidated ~~Statements~~Balance Sheets upon the conversion of ~~Operations.~~the notes into shares of Denbury common stock. As of June 30, 2020, there was $225.7 million 2024 Convertible Senior Notes outstanding.

~~Separately, the exchange~~First Quarter 2020 Repurchases of Senior Secured Notes. During March 2020, we repurchased a total of $30.2 million aggregate principal amount of our ~~existing~~9% Senior Secured Second Lien Notes due 2021 (the “2021 Senior Secured Notes”) in open-market transactions for a total purchase price of $14.2 million, excluding accrued interest. In connection with these transactions, we recognized a $19.0 million gain on debt extinguishment, net of unamortized debt issuance costs and future interest payable written off.

First Quarter 2020 Sale of Working Interests in Certain Texas Fields. On March 4, 2020, we closed a farm-down transaction for the sale of half of our nearly 100% working interest positions in four southeast Texas oil fields (consisting of Webster, Thompson, Manvel and East Hastings) for $40 million net cash and a carried interest in ten wells to be drilled by the purchaser (the “Gulf Coast Working Interests Sale”).

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Denbury Resources Inc.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Houston Area Land Sales. We have been actively marketing for sale non-producing surface acreage primarily around the Houston area. On July 24, 2020, we completed the sale of a portion of this acreage for gross proceeds of approximately $14 million. To date, we have closed acreage sales for total gross proceeds of approximately $34 million, and we currently have an additional $18 million under contract which is expected to close in the second half of 2020.

Suspension of Trading on the NYSE. Our common stock was traded on the New York Stock Exchange (the “NYSE”) under the symbol “DNR” until July 29, 2020. On July 31, 2020, the NYSE notified us of its determination to commence proceedings to delist our common stock from the NYSE, and as of July 31, 2020 to indefinitely suspend trading of our common stock on the NYSE. Suspension of trading in our common stock and delisting proceedings were undertaken by the NYSE in accordance with Section 802.01D of the NYSE Listed Company Manual due to our filing of the Chapter 11 Restructuring on July 30, 2020. Our common stock now trades on the OTC Pink Open Market under the symbol “DNRCQ”. We can provide no assurance that we are current in its reporting obligations or that the trading volume of our common stock will be sufficient to provide for an efficient trading market.

CAPITAL RESOURCES AND LIQUIDITY

Overview. Our primary sources of capital and liquidity are our cash flow from operations and cash on hand, which has been supplemented by proceeds from our March 2020 sale of working interests in four southeast Texas fields and periodically by sales of surface land with no active oil and natural gas operations. Our most significant cash outlays relate to our development capital expenditures, current period operating expenses, and our debt service obligations.

As discussed above, NYMEX oil prices have decreased significantly since the beginning of 2020, decreasing from nearly $60 per barrel in early January to around $25 per barrel in mid-May (although considerably lower during the month of April 2020), before rebounding to nearly $40 per Bbl at the end of June 2020. This decrease in the market prices for our production directly reduces our operating cash flow and indirectly impacts our other sources of potential liquidity, such as possibly lowering our borrowing capacity under our revolving credit facility, as our borrowing capacity and borrowing costs are generally related to the estimated value of our proved reserves.

In this low oil price environment, we have taken various steps to preserve our liquidity including (1) by reducing our 2020 budgeted development capital spending by 44% from initial levels and to less than half of 2019 levels, (2) by deferring the Cedar Creek Anticline CO₂ tertiary flood development project beyond 2020, (3) by continuing to focus on reducing our operating and overhead costs, (4) by restructuring certain of our three-way collars covering 14,500 Bbls/d into fixed-price swaps for the second through fourth quarters of 2020 to increase downside protection against current and potential further declines in oil prices, (5) by evaluating production economics and shutting in production beginning in late March that was uneconomic to produce or repair based on prevailing oil prices, and (6) by conducting a complete market-based review of strategic alternatives, including a comprehensive restructuring, to enhance our liquidity and strengthen our capital structure.

Chapter 11 Restructuring and Effect of Automatic Stay. On July 30, 2020, Denbury filed for relief under chapter 11 of the Bankruptcy Code in the United State Bankruptcy Court for the Southern District of Texas. The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default under the Bank Credit Agreement, the indentures governing the Company’s senior secured second lien notes, ~~was accounted for as a modification of those notes. Therefore, no gain or loss was recognized,~~convertible senior notes, and ~~previously deferred debt issuance costs of $6.9 million were treated as a discount to~~senior subordinated notes and the ~~principal amount~~agreements governing our NEJD pipeline lease financing. In conjunction with the negotiation of the ~~new 7¾% Senior Secured Notes, which discount will be amortized as~~RSA, the Company did not make the $7.8 million interest ~~expense over the term of these notes. Based~~payment due on ~~the combined debt discount of $109.4 million recorded in connection with the note exchanges, future interest expense reflected in~~ our ~~Unaudited Condensed Consolidated Statements of Operations will be higher than the actual cash interest payments on the 7¾~~6⅜% ~~Senior Secured Notes and 2024~~ Convertible Senior Notes ~~(see~~due 2024 on June 30, 2020, and the $3.1 million interest payment due on our 4⅝% Senior Subordinated Notes due 2023 on July 15, 2020. Any efforts to enforce payment obligations related to the acceleration of the Company’s debt have been automatically stayed as a result of the filing of the Chapter 11 Restructuring, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code. Refer to Note 1, ~~Results~~Basis of ~~Operations~~ –Presentation ~~Interest~~– Entry into Restructuring Support Agreement and ~~Financing Expenses~~Voluntary Reorganization under Chapter 11 of the Bankruptcy Code, to the condensed consolidated financial statements for ~~further discussion).~~more information on the Chapter 11 Restructuring.

~~July 2019 Citronelle Field Divestiture.~~We expect to continue operations in the normal course for the duration of the Chapter 11 Restructuring. On July ~~1, 2019, we closed~~31, 2020, the ~~sale of one of our mature Gulf Coast fields, Citronelle Field, which contributed 406 BOE/d~~Bankruptcy Court entered orders approving certain customary “first day” relief to ~~total Company production~~enable Denbury to operate in the ordinary course during the ~~second quarter~~Chapter 11 Restructuring, including approval on an interim basis of ~~2019, for $10 million. The sale had an effective date~~post-petition financing under a DIP Facility and use of ~~May 1, 2019.~~

~~Exploitation Drilling Update.~~ ~~During~~cash collateral of Denbury’s lenders and secured noteholders. Denbury is currently soliciting votes to accept the ~~second quarter~~Plan from holders of ~~2019, we tested our first horizontal well at Conroe Field, which achieved a high oil cut~~claims and ~~a peak production rate over 200 BOE/d. We currently plan~~interests entitled to ~~drill an additional well in~~vote. On July 31, 2020, ~~in an adjacent fault block that considers what we have learned from~~ the first well. We also tested the Cotton Valley interval at Tinsley Field during the second quarter, and while we were pleased with the 2.5 MMcf/d gas rate and high liquids yield, these test results, coupled with current commodity prices, would make a standalone development of the Lower Cotton Valley below our investmentBankruptcy Court entered orders designed to assist

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the Company in preserving certain of its tax attributes, including its net operating losses and tax credits, by establishing procedures and notice requirements prohibiting stockholders and potential stockholders with beneficial ownership or rights to acquire 4.5% or more of the Company’s issued and outstanding shares of common stock on June 30, 2020 from increasing or decreasing their ownership of the Company’s common stock without providing prior notice of the proposed transactions, which transfers then may require prior consent of the Bankruptcy Court. Any actions in violation of these procedures (including the notice requirements) are null and void ab initio and may be punished by contempt or other sanctions imposed by the Bankruptcy Court. For details of the procedures, see Exhibit 10(f) to this Form 10-Q, which is incorporated by reference herein. The final hearing on approval of the DIP Facility and use of cash collateral is currently scheduled for September 2, 2020.

Going Concern. As discussed above, the filing of the Chapter 11 Restructuring on July 30, 2020 constituted an event of default under all of our outstanding debt agreements, resulting in the automatic and immediate acceleration of the Company’s debt outstanding, with the exception of our capital leases and our obligations under our Free State pipeline transportation agreement. At that date, the Company did not have sufficient cash on hand or available liquidity to repay such debt.

The condensed consolidated financial statements as of June 30, 2020 included in this Quarterly Report on Form 10-Q have been prepared on a going concern basis of accounting, and do not reflect any adjustments relating to the recoverability and classification of recorded asset amounts or the amounts and classification of liabilities that might result if we are unable to continue as a going concern.

DIP Facility. Under the RSA, the lenders under the Company’s Bank Credit Agreement agreed to provide the Company and its subsidiaries with a senior secured super priority debtor-in-possession revolving credit facility in an aggregate principal amount of up to $615 million. The DIP Facility was approved on an interim basis by the Bankruptcy Court on July 31, 2020 and, on August 4, 2020, $185 million of our outstanding loans and all of our approximately $95 million of outstanding letters of credit under Denbury’s pre-petition revolving Bank Credit Agreement were “rolled up” into the DIP Facility. Immediately thereafter, Denbury initiated a repayment of $150 million of amounts borrowed under the DIP Facility with cash on hand. On August 7, 2020, the beneficiary of the $41.3 million letter of credit issued as “financial assurances” under the NEJD pipeline lease financing drew the full amount of such letter of credit in accordance with its terms as a result of the Chapter 11 Restructuring, which resulted in Denbury borrowing an identical amount under the DIP Facility. The Plan contemplates that, upon emergence from the Chapter 11 Restructuring, the DIP Facility be replaced with a committed exit facility. The proceeds of all or a portion of the DIP Facility may be used for, among other things, post-petition working capital, permitted investments, general corporate purposes, letters of credit, administrative costs and premiums, expenses and fees for the transactions contemplated by the Chapter 11 Restructuring, payment of court-approved adequate protection obligations, and other such purposes consistent with the DIP Facility.

Exit Financing. On July 28, 2020, prior to the commencement of the Chapter 11 Restructuring, the Company entered into an Exit Commitment Letter with the consenting lenders of the Company’s Bank Credit Agreement and/or their affiliates, which is subject to the satisfaction of certain customary conditions, including the approval of the Bankruptcy Court. As part of the RSA, the consenting lenders of the Company’s Bank Credit Agreement and/or their affiliates have agreed to provide, on a committed basis, the Company with the Exit Facility on the terms set forth in the exit term sheet attached to the RSA (the “Exit Facility Term Sheet”). The Exit Facility Term Sheet provides for, among other things, post-emergence financing in the form of a senior secured revolving credit facility in an aggregate principal amount of up to $615 million (the “Exit Facility”), subject to an initial borrowing base redetermination at the closing of the Exit Facility. Any loans drawn under the Exit Facility will be non-amortizing.

The effectiveness of the Exit Facility will be subject to customary closing conditions, including consummation of the Plan. The foregoing description of the Exit Facility Term Sheet does not purport to be complete and is qualified in its entirety by reference to the final, executed documents memorializing the Exit Facility, to be included in a supplement to the Plan to be filed with the Bankruptcy Court.

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threshold. We continue to work plans to test uphole intervals, which we believe to contain higher liquid content, and will then determine the best next steps, which could include self-development or potentially farming out the discovery to a third party. We continue to evaluate exploitation opportunities in additional horizons underlying the existing CO₂EOR flood at Tinsley Field, as well as within oil-bearing formations at Conroe Field. At Cedar Creek Anticline, we currently have plans to drill two additional Mission Canyon wells and a Charles B follow-up well in the second half of 2019.

~~CAPITAL RESOURCES AND LIQUIDITY~~

~~Overview.~~ Our primary sources of capital and liquidity are our cash flows from operations and availability of borrowing capacity under our senior secured bank credit facility. For the six months ended June 30, 2019, we generated cash flow from operations of $213.0 million, after giving effect to $50.8 million of cash outflows for working capital changes primarily related to payments during the first half of the year for ad valorem tax payments, accrued interest on our debt and accrued compensation. As of June 30, 2019, we had $80.0 million of outstanding borrowings on our $615 million senior secured bank credit facility, compared to no outstanding borrowings as of December 31, 2018 and March 31, 2019, leaving us with $480.5 million of borrowing base availability after consideration of $54.5 million of currently outstanding letters of credit. Based on our current 2019 projections using recent oil price futures, we expect to generate free cash flow sufficient to pay down the $80 million borrowed on our senior secured bank credit facility by the end of 2019, to the extent we choose to do so.

We have historically tried to limit our development capital spending to be roughly the same as, or less than, our cash flow from operations, and our 2019 cash flows from operations are currently expected to significantly exceed our planned $240 million to $260 million of development capital expenditures for the year.

As an additional source of potential liquidity, the Company has been engaged in two asset sale processes. In the first process, we have been actively marketing for sale surface land with no active oil and gas operations around our Conroe and Webster fields. During the second quarter of 2019, we entered into new contracts for $38 million, bringing the aggregate amount of land sold or under contract to $52 million as of June 30, 2019. During 2018, we completed approximately $5 million of land sales and currently have signed agreements for another $47 million, of which we expect to close $15 million in the second half of 2019, plus approximately $32 million under contract that provide for purchase price payments to begin by mid-2021, subject to a number of conditions. We remain focused on a strategy that we believe will ultimately yield the highest value for the remaining land, and we expect significant additional value of the remaining parcels not yet sold or under contract to be realized over the next two years. In the second process, in 2018 we began the process of portfolio optimization through the marketing of mature fields located in Mississippi and Louisiana and Citronelle Field in Alabama. In connection with this process, we completed the sale of Lockhart Crossing Field for net proceeds of approximately $4 million during the third quarter of 2018 and closed the sale of Citronelle Field for approximately $10 million during July 2019. The pace and outcome of any sales of the remaining assets cannot be predicted at this time, but their successful completion could provide additional liquidity for financial or operational uses.

Over the last several years, we have been keenly focused on reducing leverage and improving the Company’s financial condition. In total, we have reduced our outstanding debt principal by $1.1 billion between December 31, 2014 and June 30, 2019, primarily through debt exchanges, opportunistic open market debt repurchases, and the conversion in the second quarter of 2018 of all of our then outstanding convertible senior notes into common stock. Our leverage metrics have improved considerably over the past year, due primarily to our cost reduction efforts, improvement in oil prices and our overall reduction in debt. In conjunction with our continuing efforts to improve the Company’s balance sheet, we plan to assess, and may engage in, potential debt reduction and/or maturity extension transactions of various types, with a primary focus on our 2021 and 2022 debt maturities, balanced with maintaining liquidity.

Senior Secured Bank Credit Facility. In December 2014, we entered into ~~an Amended and Restated~~the Bank Credit Agreement, ~~with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (as amended, the “Bank Credit Agreement”),~~ which has been amended periodically since that time. Under the terms of the RSA, the lenders under the Company’s Bank Credit Agreement agreed to provide the Company and its subsidiaries with the DIP Facility, which is to be replaced with the committed exit facility upon emergence from the Chapter 11 Restructuring. Refer to Note 1, Basis of Presentation – Entry into Restructuring Support Agreement and Voluntary Reorganization under Chapter 11 of the Bankruptcy Code, for additional information.

In conjunction with the scheduled May 2020 redetermination on June 26, 2020, we entered into the Eighth Amendment to the Bank Credit Agreement (the “Eighth Amendment”) which among other things:

On June 29, 2020, we elected to draw $200 million (the “Credit Draw”) under the Bank Credit Agreement. As of June 30, 2020, we had $265.0 million of outstanding borrowings under our $275 million senior secured Bank Credit Agreement, leaving us with $10.0 million of available borrowing capacity, and $209.3 million of cash and cash equivalents on hand due to amounts drawn under the Bank Credit Agreement during the second quarter, compared to no outstanding borrowings as of December 31, 2019 and March 31, 2020 with nominal cash at those dates. In addition, we had $94.7 million outstanding letters of credit at June 30, 2020.

The Bank Credit Agreement is a senior secured revolving credit facility with a maturity date of December 9, 2021, provided that the maturity date may occur earlier (between February 2021 and August 2021) if the 9% Senior Secured Second Lien Notes due in May 2021 (the “2021 Senior Secured Notes”) or 6⅜% Senior Subordinated Notes due in August 2021, respectively, are not repaid or refinanced by each of their respective maturity dates. As part of our spring 2019 semiannual borrowing base redetermination, the borrowing base and lender commitments for our Bank Credit Agreement were reaffirmed at $615 million, with the next such redetermination scheduled for November 2019. The Bank Credit Agreement containscontained certain financial performance covenants through the maturity of the facility, including the following:

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A Consolidated Total Debt to Consolidated EBITDAX covenant, with such ratio not to exceed 5.25 to 1.0 through December 31, 2020 and 4.50 to 1.0 thereafter;

A minimum permitted ratio of consolidated EBITDAX to consolidated interest charges of 1.25 to 1.0; and

A requirement to maintain a current ratio (i.e., Consolidated Current Assets to Consolidated Current Liabilities) of 1.0 to 1.0.

For purposes of computing the current ratio per the Bank Credit Agreement, Consolidated Current Assets exclude the current portion of derivative assets but include available borrowing capacity under the senior secured bank credit facility, and Consolidated Current Liabilities exclude the current portion of derivative liabilities as well as the current portions of long-term indebtedness outstanding.

Under these financial performance covenant calculations, as of June 30, ~~2019,~~2020, our ratio of consolidated total debt to consolidated EBITDAX was ~~4.14~~5.08 to 1.0 (with a maximum permitted ratio of 5.25 to 1.0), our consolidated senior secured debt to consolidated EBITDAX was ~~0.13~~0.59 to 1.0 (with a maximum permitted ratio of 2.5 to 1.0), our ratio of consolidated EBITDAX to consolidated interest charges was ~~3.12~~2.40 to 1.0 (with a required ratio of not less than 1.25 to 1.0), and our current ratio was ~~2.64~~2.86 to 1.0 (with a required ratio of not less than 1.0 to 1.0). Based upon our currently forecasted levels of production and costs, hedges in place as of August 6, 2019, and current oil commodity futures prices, we currently anticipate continuing to be in compliance with our financial performance covenants during the foreseeable future.

The above description of our Bank Credit Agreement is qualified by the express language and defined terms contained in the Bank Credit Agreement and the amendments thereto, each of which are filed as exhibits to our periodic reports filed with the SEC.

~~2019 Note Exchanges.~~ ~~Through a series of exchange transactions completed on June 19, 2019 (see~~ ~~Overview~~ – ~~2019 Note Exchanges~~ above), we reduced our debt principal balance by $120 million and extended the maturities of $348.4 million aggregate principal amount of our existing debt by exchanging a portion of our 6⅜% Senior Subordinated Notes due 2021, 5½% Senior Subordinated Notes due 2022 and 4⅝% Senior Subordinated Notes due 2023 for 7¾% Senior Secured Notes, 2024 Convertible Senior Notes and cash. In addition to extending maturities of a portion of our existing debt, the exchange transactions could contribute to debt reduction of $245.5 million if all of the 2024 Convertible Senior Notes convert to Company common stock (based upon issuance of up to 90,852,760 shares at the current conversion rate of 370 shares of common stock per $1,000 principal amount for such notes).

~~Capital Spending~~. We currently anticipate that our full-year 2019 capital spending, excluding capitalized interest and acquisitions, will be approximately $240 million to $260 million. Although we currently have no plans to adjust our anticipated capital spending for 2019, we continually evaluate our expected cash flows and capital expenditures throughout the year and could adjust capital expenditures if our cash flows were to meaningfully change. Capitalized interest is currently estimated at between $30 million and $40 million for 2019. The 2019 capital budget, excluding capitalized interest and acquisitions, provides for approximate spending as follows:

~~$100 million allocated for tertiary oil field expenditures;~~

~~$70 million allocated for other areas, primarily non-tertiary oil field expenditures including exploitation;~~


•	~~$30 million to be spent on CO~~₂ ~~sources and pipelines; and~~

~~$50 million for other capital items such as capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.~~

Based upon our currently forecasted levels of production and costs, commodity hedges in place, and current oil commodity futures prices, we intend to fund our development capital spending with cash flow from operations. If prices were to decrease or changes in operating results were to cause a reduction in anticipated 2019 cash flows significantly below our currently forecasted operating cash flows, we would likely reduce our capital expenditures. If we reduce our capital spending due to lower cash flows, any sizeable reduction would likely lower our anticipated production levels in future years.

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Capital Spending. We currently anticipate that our full-year 2020 capital spending, excluding capitalized interest and acquisitions, will be approximately $95 million to $105 million. This 2020 capital expenditure amount of between $95 million to $105 million, which was revised on March 31, 2020, excluding capitalized interest and acquisitions, is an $80 million, or 44%, reduction from the late-February 2020 estimate of between $175 million and $185 million in response to the more than 50% decline in NYMEX WTI prices during March 2020 as a result of the COVID-19 pandemic, which worsened an already deteriorated oil market that resulted from the early-March 2020 failure by the group of oil producing nations known as OPEC+ to reach an agreement over proposed oil production cuts. Oil prices are expected to continue to be volatile as a result of these events and the ongoing COVID-19 outbreak, and as changes in oil inventories, oil demand and economic performance are reported. The 2020 capital budget, excluding capitalized interest and acquisitions, provides for approximate spending as follows:

$35 million allocated for tertiary oil field expenditures;

$25 million allocated for other areas, primarily non-tertiary oil field expenditures including exploitation;


•	$10 million to be spent on CO₂ sources and pipelines; and

$30 million for other capital items such as capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.

Capital Expenditure Summary. The following table reflects incurred capital expenditures (including accrued capital) for the six months ended June 30, ~~2019~~2020 and ~~2018:~~2019:


	Six Months Ended				Six Months Ended
	June 30,				June 30,
In thousands	2019		2018		2020		2019
Capital expenditure summary
Tertiary oil fields	$	54,786	$	64,086	$	19,920	$	54,786
Non-tertiary fields	36,554		32,739		13,248		36,554
Capitalized internal costs⁽¹⁾	24,214		22,747		18,344		24,214
Oil and natural gas capital expenditures	115,554		119,572		51,512		115,554
CO₂ pipelines, sources and other	22,465		9,648		8,532		22,465
Capital expenditures, before acquisitions and capitalized interest	138,019		129,220		60,044		138,019
Acquisitions of oil and natural gas properties	97		21		80		97
Capital expenditures, before capitalized interest	138,116		129,241		60,124		138,116
Capitalized interest	18,772		17,303		18,181		18,772
Capital expenditures, total	$	156,888	$	146,544	$	78,305	$	156,888


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

Off-Balance Sheet Arrangements. Our off-balance sheet arrangements include obligations for various development and exploratory expenditures that arise from our normal capital expenditure program or from other transactions common to our industry, none of which are recorded on our balance sheet. In addition, in order to recover our undeveloped proved reserves, we must also fund the associated future development costs estimated in our proved reserve reports.

Our commitments and obligations consist of those detailed as of December 31, ~~2018,~~2019, in our Form 10-K under Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Commitments and Obligations.

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RESULTS OF OPERATIONS

Our tertiary operations represent a significant portion of our overall operations and are our primary long-term strategic focus. The economics of a tertiary field and the related impact on our financial statements differ from a conventional oil and gas play, and we have outlined certain of these differences in our Form 10-K and other public disclosures. Our focus on these types of operations impacts certain trends in both current and long-term operating results. Please refer to Management’s Discussion and Analysis of Financial Condition and Results of Operations – Financial Overview of Tertiary Operations in our Form 10-K for further information regarding these matters.

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Operating Results Table

Certain of our operating results and statistics for the comparative three and six months ended June 30, ~~2019~~2020 and ~~2018~~2019 are included in the following table:


	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
In thousands, except per-share and unit data	2019			2018			2019			2018			2020			2019			2020			2019
Operating results
Net income	$	146,692		$	30,222		$	121,018		$	69,800
Net income per common share – basic	0.32			0.07			0.27			0.17
Net income per common share – diluted	0.32			0.07			0.26			0.15
Net income (loss)⁽¹⁾													$	(697,474	)	$	146,692		$	(623,458	)	$	121,018
Net income (loss) per common share – basic⁽¹⁾													(1.41		)	0.32			(1.26		)	0.27
Net income (loss) per common share – diluted⁽¹⁾													(1.41		)	0.32			(1.26		)	0.26
Net cash provided by operating activities	148,634			153,999			213,000			245,626			10,969			148,634			72,811			213,000
Average daily production volumes
Bbls/d	58,034			60,109			57,726			59,236			48,900			58,034			51,774			57,726
Mcf/d	10,111			11,314			10,467			11,607			7,737			10,111			7,818			10,467
BOE/d⁽¹⁾⁽²⁾	59,719			61,994			59,470			61,171			50,190			59,719			53,077			59,470
Operating revenues
Oil sales	$	328,571		$	373,286		$	620,536		$	710,692		$	108,538		$	328,571		$	337,115		$	620,536
Natural gas sales	1,850			2,279			4,462			4,894			849			1,850			1,896			4,462
Total oil and natural gas sales	$	330,421		$	375,565		$	624,998		$	715,586		$	109,387		$	330,421		$	339,011		$	624,998
Commodity derivative contracts⁽²⁾⁽³⁾
Receipt (payment) on settlements of commodity derivatives	$	(1,549	)	$	(54,770	)	$	6,657		$	(88,127	)	$	45,629		$	(1,549	)	$	70,267		$	6,657
Noncash fair value gains (losses) on commodity derivatives⁽³⁾⁽⁴⁾	26,309			(41,429		)	(65,274		)	(56,897		)	(85,759		)	26,309			36,374			(65,274		)
Commodity derivatives income (expense)	$	24,760		$	(96,199	)	$	(58,617	)	$	(145,024	)	$	(40,130	)	$	24,760		$	106,641		$	(58,617	)
Unit prices – excluding impact of derivative settlements
Oil price per Bbl	$	62.22		$	68.24		$	59.39		$	66.29		$	24.39		$	62.22		$	35.78		$	59.39
Natural gas price per Mcf	2.01			2.21			2.35			2.33			1.21			2.01			1.33			2.35
Unit prices – including impact of derivative settlements⁽²⁾⁽³⁾
Oil price per Bbl	$	61.92		$	58.23		$	60.03		$	58.07		$	34.64		$	61.92		$	43.23		$	60.03
Natural gas price per Mcf	2.01			2.21			2.35			2.33			1.21			2.01			1.33			2.35
Oil and natural gas operating expenses
Lease operating expenses	$	117,932		$	120,384		$	243,355		$	238,740		$	81,293		$	117,932		$	190,563		$	243,355
Transportation and marketing expenses	11,236			10,062			22,009			20,555			9,388			11,236			19,009			22,009
Production and ad valorem taxes	23,526			25,363			45,560			50,395			8,766			23,526			26,753			45,560
Oil and natural gas operating revenues and expenses per BOE
Oil and natural gas revenues	$	60.80		$	66.57		$	58.06		$	64.63		$	23.95		$	60.80		$	35.09		$	58.06
Lease operating expenses	21.70			21.34			22.61			21.56			17.80			21.70			19.73			22.61
Transportation and marketing expenses	2.07			1.78			2.04			1.86			2.06			2.07			1.97			2.04
Production and ad valorem taxes	4.33			4.50			4.23			4.55			1.92			4.33			2.77			4.23
CO₂ sources – revenues and expenses
CO₂ sales and transportation fees	$	7,986		$	6,715		$	16,556		$	14,267		$	6,504		$	7,986		$	14,532		$	16,556
CO₂ discovery and operating expenses	(581		)	(500		)	(1,137		)	(962		)	(885		)	(581		)	(1,637		)	(1,137		)
CO₂ revenue and expenses, net	$	7,405		$	6,215		$	15,419		$	13,305		$	5,619		$	7,405		$	12,895		$	15,419


(1)	Includes a pre-tax full cost pool ceiling test write-down of our oil and natural gas properties of $662.4 million and $735.0 million for the three and six months ended June 30, 2020, respectively.


(2)	Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of natural gas (“BOE”).


~~(2)~~	~~See also~~ ~~Commodity Derivative Contracts~~ ~~below and~~ ~~Item 3. Quantitative and Qualitative Disclosures about Market Risk~~ ~~for information concerning our derivative transactions.~~

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(3)	See also Commodity Derivative Contracts below and Item 3. Quantitative and Qualitative Disclosures about Market Risk for information concerning our derivative transactions.

(4)

Noncash fair value gains (losses) 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 gains (losses) on commodity derivatives represent only the net changes between periods of the fair market values of commodity derivative positions, and exclude the impact of settlements on commodity derivatives during the period, which were receipts on settlements of $45.6 million and $70.3 million for the three and six months ended June 30, 2020, respectively, compared to payments on settlements of $1.5 million for the three months ended June 30, 2019 and receipts on settlements of $6.7 million for the six months ended June 30, ~~2019, compared to payments on settlements of $54.8 million and $88.1 million for the three and six months ended June 30, 2018, respectively.~~2019. We believe that noncash fair value gains (losses) on commodity derivatives is a useful supplemental disclosure to “Commodity derivatives expense (income)” in order to differentiate noncash fair market value adjustments from receipts or payments upon settlements on commodity derivatives during the period. This supplemental disclosure 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. Noncash fair value gains (losses) on commodity derivatives is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for “Commodity derivatives expense (income)” in the Unaudited Condensed Consolidated Statements of Operations.

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

Production

Average daily production by area for each of the four quarters of ~~2018~~2019 and for the first and second quarters of ~~2019~~2020 is shown below:


	Average Daily Production (BOE/d)						Average Daily Production (BOE/d)
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	First Quarter	Second Quarter	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	First Quarter	Second Quarter
Operating Area	2018	2018	2018	2018	2019	2019	2019	2019	2019	2019	2020	2020
Tertiary oil production
Gulf Coast region
Delhi	4,169	4,391	4,383	4,526	4,474	4,486	4,474	4,486	4,256	4,085	3,813	3,529
Hastings	5,704	5,716	5,486	5,480	5,539	5,466	5,539	5,466	5,513	5,097	5,232	4,722
Heidelberg	4,445	4,330	4,376	4,269	3,987	4,082	3,987	4,082	4,297	4,409	4,371	4,366
Oyster Bayou	5,056	4,961	4,578	4,785	4,740	4,394	4,740	4,394	3,995	4,261	3,999	3,871
Tinsley	6,053	5,755	5,294	5,033	4,659	4,891	4,659	4,891	4,541	4,343	4,355	3,788
West Yellow Creek	57	142	240	375	436	586	436	586	728	807	775	695
Mature properties⁽¹⁾	6,726	6,725	6,612	6,748	6,479	6,448	6,479	6,448	6,415	6,347	6,386	5,249
Total Gulf Coast region	32,210	32,020	30,969	31,216	30,314	30,353	30,314	30,353	29,745	29,349	28,931	26,220
Rocky Mountain region
Bell Creek	4,050	4,010	3,970	4,421	4,650	5,951	4,650	5,951	4,686	5,618	5,731	5,715
Salt Creek	2,002	2,049	2,274	2,107	2,057	2,078	2,057	2,078	2,213	2,223	2,149	1,386
Other	—	—	6	20	52	41
Grieve							52	41	58	60	50	7
Total Rocky Mountain region	6,052	6,059	6,250	6,548	6,759	8,070	6,759	8,070	6,957	7,901	7,930	7,108
Total tertiary oil production	38,262	38,079	37,219	37,764	37,073	38,423	37,073	38,423	36,702	37,250	36,861	33,328
Non-tertiary oil and gas production
Gulf Coast region
Mississippi	875	901	1,038	1,023	1,034	1,025	1,034	1,025	873	952	748	713
Texas	4,386	4,947	4,533	4,319	4,345	4,243	3,298	3,224	3,165	3,212	3,419	3,087
Other	44	—	5	6	10	6	10	6	6	5	6	5
Total Gulf Coast region	5,305	5,848	5,576	5,348	5,389	5,274	4,342	4,255	4,044	4,169	4,173	3,805
Rocky Mountain region
Cedar Creek Anticline	14,437	15,742	14,208	14,961	14,987	14,311	14,987	14,311	13,354	13,730	13,046	11,988
Other	1,485	1,490	1,409	1,343	1,313	1,305	1,313	1,305	1,238	1,192	1,105	1,069
Total Rocky Mountain region	15,922	17,232	15,617	16,304	16,300	15,616	16,300	15,616	14,592	14,922	14,151	13,057
Total non-tertiary production	21,227	23,080	21,193	21,652	21,689	20,890	20,642	19,871	18,636	19,091	18,324	16,862
Total continuing production	59,489	61,159	58,412	59,416	58,762	59,313	57,715	58,294	55,338	56,341	55,185	50,190
Property sales
Citronelle⁽²⁾	387	388	416	451	456	406
Lockhart Crossing⁽³⁾	462	447	353	—	—	—
Gulf Coast Working Interests Sale⁽²⁾							1,047	1,019	1,103	1,170	780	—
Citronelle⁽³⁾							456	406	—	—	—	—
Total production	60,338	61,994	59,181	59,867	59,218	59,719	59,218	59,719	56,441	57,511	55,965	50,190


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


(2)	Includes non-tertiary production ~~from Citronelle Field sold~~related to the March 2020 sale of 50% of our working interests in ~~July 2019.~~Webster, Thompson, Manvel, and East Hastings fields.


(3)	Includes production from ~~Lockhart Crossing~~Citronelle Field sold in ~~the third quarter of 2018.~~July 2019.

Total continuing production during the second quarter of ~~2019~~2020 averaged ~~59,313~~50,190 BOE/d, including ~~38,423~~33,328 Bbls/d ~~or 65%,~~ from tertiary properties and ~~20,890~~16,862 BOE/d from non-tertiary properties. Total continuing production ~~excludes production from Citronelle Field sold in July 2019 and,~~ for ~~prior-year~~prior periods excludes production ~~from Lockhart Crossing Field sold in the third~~

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~~quarter of 2018.~~related to the Gulf Coast Working Interests Sale completed in early March 2020 and Citronelle Field sold in July 2019. This total continuing production level represents ~~an increase~~a decrease of ~~551~~4,995 BOE/d ~~(1%~~(9%) compared to total continuing production levels in the first quarter of ~~2019 primarily due to continued response from Bell Creek’s phase 5 development~~2020 and a decrease of ~~1,846~~8,104 BOE/d ~~(3%~~(14%) compared to second quarter of ~~2018~~2019 continuing production, ~~levels~~ primarily due to ~~lower~~production shut-in due to wells that were uneconomic to produce or repair during the quarter. We estimate the impact to second quarter 2020 production from ~~Tinsley Field~~the shut-in wells was approximately 4,300 BOE/d.

As a result of the significant decline in oil prices, we focused our efforts beginning late in the first quarter to optimize cash flow through evaluating production economics and ~~Cedar Creek Anticline, with~~began shutting in production beginning in late March 2020. Throughout the ~~decline at Cedar Creek Anticline due~~second quarter of 2020, we continued evaluations around expected oil prices and production costs and began to restore some of these wells to production during May 2020 as oil prices trended higher. As such, as of quarter-end, we estimate that approximately 1,700 BOE/d of production remained shut-in as of June 30, 2020 attributable to uneconomic wells. We plan to continue this routine evaluation to assess levels of uneconomic production based on our expectations for wellhead oil prices and variable production costs and will actively make decisions to either shut-in additional production or bring production back online as conditions warrant. Production could be further curtailed by future regulatory actions or limitations in ~~part to timing of drilling new exploitation wells.~~ storage and/or takeaway capacity.

Our production during the three ~~and~~months ended June 30, 2020 was 97% oil, consistent with our oil production during the same prior-year period; whereas, production during the six months ended June 30, ~~2019~~2020 was ~~97%~~98% oil, ~~consistent with~~slightly higher than our 97% oil production during the prior-year ~~periods. We currently expect our third quarter 2019 production will be lower than the second quarter due to an extended period of planned maintenance at our primary Rocky Mountain region CO~~₂ ~~source impacting Bell Creek Field production, seasonal temperature effects in the Gulf Coast region, and the July 1, 2019 sale of Citronelle Field.~~period.

Oil and Natural Gas Revenues

Our oil and natural gas revenues during the three and six months ended June 30, ~~2019~~2020 decreased ~~12%~~67% and ~~13%~~46%, respectively, compared to these revenues for the same periods in ~~2018.~~2019. The changes in our oil and natural gas revenues are due to changes in production quantities and realized commodity prices (excluding any impact of our commodity derivative contracts), as reflected in the following table:

Three Months Ended Six Months Ended
June 30, June 30,
2019 vs. 2018 2019 vs. 2018
In thousands Decrease in Revenues Percentage Decrease in Revenues Decrease in Revenues Percentage Decrease in Revenues
Change in oil and natural gas revenues due to:
Decrease in production $ (13,782 ) (4 )% $ (19,892 ) (3 )%
Decrease in realized commodity prices (31,362 ) (8 )% (70,696 ) (10 )%
Total decrease in oil and natural gas revenues $ (45,144 ) (12 )% $ (90,588 ) (13 )%

Excluding any impact of our commodity derivative contracts, our net realized commodity prices and NYMEX differentials were as follows during the first quarters, second quarters, and six months ended June 30, 2019 and 2018:

Three Months Ended Three Months Ended Six Months Ended
March 31, June 30, June 30,
2019 2018 2019 2018 2019 2018
Average net realized prices
Oil price per Bbl $ 56.50
$ 64.25
$ 62.22
$ 68.24
$ 59.39
$ 66.29
Natural gas price per Mcf 2.68
2.44
2.01
2.21
2.35
2.33
Price per BOE 55.27
62.61
60.80
66.57
58.06
64.63
Average NYMEX differentials

Gulf Coast region
Oil per Bbl $ 4.26
$ 2.05
$ 4.85
$ 1.12
$ 4.55
$ 1.59
Natural gas per Mcf (0.10 ) 0.10
0.10
0.04
0.00
0.07
Rocky Mountain region
Oil per Bbl $ (2.56 ) $ (0.06 ) $ (1.48 ) $ (0.84 ) $ (1.97 ) $ (0.39 )
Natural gas per Mcf (0.28 ) (0.92 ) (1.13 ) (1.25 ) (0.67 ) (1.08 )
Total Company
Oil per Bbl $ 1.63
$ 1.29
$ 2.35
$ 0.39
$ 2.01
$ 0.87
Natural gas per Mcf (0.20 ) (0.40 ) (0.50 ) (0.62 ) (0.34 ) (0.51 )



	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2020 vs. 2019					2020 vs. 2019
In thousands	Decrease in Revenues			Percentage Decrease in Revenues		Decrease in Revenues			Percentage Decrease in Revenues
Change in oil and natural gas revenues due to:
Decrease in production	$	(52,727	)	(16	)%	$	(64,104	)	(10	)%
Decrease in realized commodity prices	(168,307		)	(51	)%	(221,883		)	(36	)%
Total decrease in oil and natural gas revenues	$	(221,034	)	(67	)%	$	(285,987	)	(46	)%

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Excluding any impact of our commodity derivative contracts, our net realized commodity prices and NYMEX differentials were as follows during the three months ended March 31, 2020 and 2019 and the three and six months ended June 30, 2020 and 2019:



	Three Months Ended						Three Months Ended						Six Months Ended
	March 31,						June 30,						June 30,
	2020			2019			2020			2019			2020			2019
Average net realized prices
Oil price per Bbl	$	45.96		$	56.50		$	24.39		$	62.22		$	35.78		$	59.39
Natural gas price per Mcf	1.46			2.68			1.21			2.01			1.33			2.35
Price per BOE	45.09			55.27			23.95			60.80			35.09			58.06
Average NYMEX differentials
Gulf Coast region
Oil per Bbl	$	1.18		$	4.26		$	(3.59	)	$	4.85		$	(0.53	)	$	4.55
Natural gas per Mcf	(0.06		)	(0.10		)	(0.09		)	0.10			(0.07		)	0.00
Rocky Mountain region
Oil per Bbl	$	(2.78	)	$	(2.56	)	$	(4.68	)	$	(1.48	)	$	(3.25	)	$	(1.97	)
Natural gas per Mcf	(0.91		)	(0.28		)	(1.04		)	(1.13		)	(0.98		)	(0.67		)
Total Company
Oil per Bbl	$	(0.38	)	$	1.63		$	(4.03	)	$	2.35		$	(1.61	)	$	2.01
Natural gas per Mcf	(0.41		)	(0.20		)	(0.54		)	(0.50		)	(0.48		)	(0.34		)

Prices received in a regional market fluctuate frequently and can differ from NYMEX pricing due to a variety of reasons, including supply and/or demand factors, crude oil quality, and location differentials.

•

Gulf Coast Region. Our average NYMEX oil differential in the Gulf Coast region was a ~~positive $4.85 per Bbl and a positive $1.12~~negative $3.59 per Bbl during the second ~~quarters~~quarter of 2020, compared to a positive $4.85 per Bbl during the second quarter of 2019 and ~~2018, respectively, and~~ a positive ~~$4.26~~$1.18 per Bbl during the first quarter of ~~2019.~~2020. Generally, our Gulf Coast region differentials are positive to NYMEX and highly correlated to the changes in prices of Light Louisiana Sweet crude oil, ~~which have generally strengthened over~~though storage constraints and weak demand caused these differentials to weaken significantly during the ~~past year, although recent Gulf Coast region differentials have somewhat softened.~~second quarter of 2020.

•

Rocky Mountain Region. NYMEX oil differentials in the Rocky Mountain region averaged ~~$1.48~~$4.68 per Bbl and ~~$0.84~~$1.48 per Bbl below NYMEX during the second quarters of ~~2019~~2020 and ~~2018~~2019, respectively, and ~~$2.56~~$2.78 per Bbl below NYMEX during the first quarter of ~~2019.~~2020. Differentials in the Rocky Mountain region can fluctuate significantly on a month-to-month basis due to weather, refinery or transportation issues, and Canadian and U.S. crude oil price index volatility. Although our differentials in the Rocky Mountain region have weakened somewhat from a year ago, they have improved from the differentials we experienced in the fourth quarter of 2018 and first quarter of 2019.

Our realized differentials during three and six months ended June 30, 2020 reflect the rapid and precipitous drop in demand for oil caused by the COVID-19 pandemic, which in turn has caused oil prices to plummet since the first week of March 2020. These events have worsened a deteriorated oil market which followed the early-March 2020 failure by the group of oil producing nations known as OPEC+ to reach an agreement over proposed oil production cuts. Moreover, the uncertainty about the duration of the COVID-19 pandemic and its resulting economic consequences has caused storage constraints resulting from over-supply of produced oil and reduced refinery run rates, with these uncertainties expected to continue to significantly decrease our realized oil prices in the third quarter of 2020 and potentially longer. While our oil differentials have improved since May 2020, oil prices are expected to continue to be volatile as a result of these events, and as changes in oil inventories, oil demand and economic performance are reported.

CO₂ Revenues and Expenses

We sell approximately 20% to 25% of our produced CO₂ from Jackson Dome to third-party industrial users at various contracted prices primarily under long-term contracts. We recognize the revenue received on these CO₂ sales as “CO₂ sales and transportation

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fees” with the corresponding costs recognized as “CO₂ discovery and operating expenses” in our Unaudited Condensed Consolidated Statements of Operations.

Purchased Oil Revenues and Expenses

From time to time, we market third-party production for sale in exchange for a fee. We recognize the revenue received on these oil sales as “Purchased oil sales” and the expenses incurred to market and transport the oil as “Purchased oil expenses” in our Unaudited Condensed Consolidated Statements of Operations.

Commodity Derivative Contracts

The following table summarizes the impact our crude oil derivative contracts had on our operating results for the three and six months ended June 30, ~~2019~~2020 and ~~2018~~2019:


	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
In thousands	2019			2018			2019			2018			2020			2019			2020		2019
Receipt (payment) on settlements of commodity derivatives	$	(1,549	)	$	(54,770	)	$	6,657		$	(88,127	)	$	45,629		$	(1,549	)	$	70,267	$	6,657
Noncash fair value gains (losses) on commodity derivatives⁽¹⁾	26,309			(41,429		)	(65,274		)	(56,897		)	(85,759		)	26,309			36,374		(65,274		)
Total income (expense)	$	24,760		$	(96,199	)	$	(58,617	)	$	(145,024	)	$	(40,130	)	$	24,760		$	106,641	$	(58,617	)


(1)	Noncash fair value gains (losses) on commodity derivatives is a non-GAAP measure. See Operating Results Table above for a discussion of the reconciliation between noncash fair value gains (losses) on commodity derivatives to “Commodity derivatives expense (income)” in the Unaudited Condensed Consolidated Statements of Operations.

In order to provide a level of price protection to a portion of our oil production, we have hedged a portion of our estimated oil production through 2020 using both NYMEX and LLS fixed-price swaps and three-way collars. See Note 5,7, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements for additional details of our outstanding commodity derivative contracts as of June 30, ~~2019,~~2020, and Item 3, Quantitative and Qualitative Disclosures about Market Risk below for additional discussion. In addition, the following table summarizes our commodity derivative contracts as of August ~~6, 2019:~~7, 2020:

2H 2019 1H 2020 2H 2020
WTI NYMEX Volumes Hedged (Bbls/d) — 2,000 2,000
Fixed-Price Swaps
Swap Price⁽¹⁾
— $60.59 $60.59
Argus LLS Volumes Hedged (Bbls/d) 13,000 4,500 4,500
Fixed-Price Swaps
Swap Price⁽¹⁾
$64.69 $62.29 $62.29
WTI NYMEX Volumes Hedged (Bbls/d) 22,000 12,000 10,000
3-Way Collars
Sold Put Price / Floor / Ceiling Price⁽¹⁾⁽²⁾
$48.55 / $56.55 / $69.17 $48.89 / $58.49 / $65.57 $49.05 / $58.58 / $65.81
Argus LLS Volumes Hedged (Bbls/d) 5,500 6,000 4,000
3-Way Collars
Sold Put Price / Floor / Ceiling Price⁽¹⁾⁽²⁾
$54.73 / $63.09 / $79.93 $53.42 / $63.19 / $71.16 $53.50 / $63.16 / $72.99
Total Volumes Hedged (Bbls/d) 40,500 24,500 20,500

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		2H 2020
WTI NYMEX	Volumes Hedged (Bbls/d)	13,500
Fixed-Price Swaps	Swap Price⁽¹⁾	$40.52
Argus LLS	Volumes Hedged (Bbls/d)	7,500
Fixed-Price Swaps	Swap Price⁽¹⁾	$51.67
WTI NYMEX	Volumes Hedged (Bbls/d)	9,500
3-Way Collars	Sold Put Price / Floor / Ceiling Price⁽¹⁾⁽²⁾	$47.93 / $57.00 / $63.25
Argus LLS	Volumes Hedged (Bbls/d)	5,000
3-Way Collars	Sold Put Price / Floor / Ceiling Price⁽¹⁾⁽²⁾	$52.80 / $61.63 / $70.35
	Total Volumes Hedged (Bbls/d)	35,500


(1)	Averages are volume weighted.


(2)	If oil prices were to average less than the sold put price, receipts on settlement would be limited to the difference between the floor price and the sold put price.

On July 31, 2020, the Bankruptcy Court entered an interim order authorizing us to maintain our pre-petition hedge contracts and enter into new hedges in the ordinary course of business.

Based on current contracts in place and NYMEX oil futures prices as of August ~~6, 2019,~~7, 2020, which averaged approximately ~~$53~~$42 per Bbl, we currently expect that we would receive cash payments of approximately ~~$30~~$35 million ~~during the remainder of 2019~~ upon settlement of our July through December 2020 contracts. Of this estimated amount, the ~~2019 contracts,~~majority relates to our three-way collars, which settlements are

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currently limited to the ~~amount~~extent oil prices remain below the price of ~~which is~~our sold puts. The weighted average differences between the floor and sold put prices of our 2020 three-way collars are $9.07 per Bbl and $8.83 per Bbl for NYMEX and LLS hedges, respectively. Settlements with respect to our fixed-price swaps are dependent upon fluctuations in future ~~NYMEX~~ oil prices in relation to the prices of our ~~2019~~2020 fixed-price swaps which have weighted average prices of ~~$64.69 per Bbl for LLS hedges and weighted average ceiling prices of our 2019 three-way collars of $69.17~~$40.52 per Bbl and ~~$79.93~~$51.67 per Bbl for NYMEX and LLS hedges, respectively. Changes in commodity prices, expiration of contracts, and new commodity contracts entered into cause fluctuations in the estimated fair value of our oil derivative contracts. Because we do not utilize hedge accounting for our commodity derivative contracts, the period-to-period changes in the fair value of these contracts, as outlined above, are recognized in our statements of operations.

Production Expenses

Lease Operating Expenses


	Three Months Ended				Six Months Ended				Three Months Ended				Six Months Ended
	June 30,				June 30,				June 30,				June 30,
In thousands, except per-BOE data	2019		2018		2019		2018		2020		2019		2020		2019
Total lease operating expenses	$	117,932	$	120,384	$	243,355	$	238,740	$	81,293	$	117,932	$	190,563	$	243,355

Total lease operating expenses per BOE	$	21.70	$	21.34	$	22.61	$	21.56	$	17.80	$	21.70	$	19.73	$	22.61

Total lease operating expenses decreased ~~$2.5~~$36.6 million ~~(2%~~(31%) and $52.8 million (22%) on an absolute-dollar basis, ~~but~~or ~~increase~~d $~~0.36~~3.90 ~~(2%~~(18%) and $2.88 (13%) on a per-BOE basis, during the three and six months ended June 30, ~~2019,~~2020, respectively, compared to the same prior-year ~~period.~~periods. The ~~decrease~~decreases on an absolute-dollar basis ~~was~~were primarily due to lower expenses across all expense categories, with the largest decreases in workover expense, labor, power and fuel costs, and ~~lower~~ CO₂ ~~expense due~~purchase expense. In response to ~~a decrease~~the significant decline in oil prices in March 2020, we reduced our capital budget and transportation rates, partially offset by an increase in contract labor for repair & maintenance activities primarily at Cedar Creek Anticline (“CCA”), with the per-BOE change further impacted by the decline in total production between the second quarters of 2018implemented cost reduction measures which included shutting down compressors or delaying well repairs and ~~2019. Lease operating expenses for the six months ended June 30, 2019 increased $4.6 million (2%) on an absolute dollar basis, or $1.05 (5%) on a per-BOE basis, compared to levels in the same period~~ ~~in 2018, primarily due to an increase in contract labor primarily at CCA and higher CO~~₂expense due to an increase in injection volumes and new floods and expansion areas moving into the production stage, resulting in costs being expensed versus capitalized, partially offset by lower power and fuel costs.workovers that were uneconomic. Compared to the first quarter of ~~2019,~~2020, lease operating expenses ~~in the second quarter of 2019~~ decreased ~~$7.5~~$28.0 million ~~(6%~~(26%) on an absolute-dollar basis, or ~~$1.83 (8%~~$3.66 (17%) on a per-BOE basis, ~~primarily~~ due to lower CO₂workover expense ~~due to lower utilization of industrial-sourced CO~~₂ ~~in our Gulf Coast region~~ and ~~lower~~ power and fuel ~~costs.~~costs resulting from the measures previously discussed.

Currently, our CO₂ expense comprises approximately 20% to 25% of our typical tertiary lease operating expenses, and for the CO₂ reserves we already own, consists of CO₂ production expenses, and for the CO₂ reserves we do not own, consists of our purchase of CO₂ from royalty and working interest owners and industrial sources. During the second quarters of 2020 and 2019, approximately 46% and ~~2018, approximately~~ 56% ~~and 49%~~, respectively, of the CO₂ utilized in our CO₂ floods consisted of CO₂ owned and produced by us (our net revenue interest). The price we pay others for CO₂ varies by source and is generally indexed to oil prices. When combining the production cost of the CO₂ we own with what we pay third parties for CO₂, our average cost of CO₂ was approximately ~~$0.33~~$0.39 per Mcf during the second quarter of ~~2019~~2020, including taxes paid on CO₂ production but excluding depletion, depreciation and amortization of capital expended at our CO₂ source fields and industrial sources. This per-Mcf CO₂ cost during the second quarter of ~~2019~~2020 was ~~lower~~higher than the ~~$0.44~~$0.33 per Mcf comparable measure during the second quarter of ~~2018~~2019 and ~~$0.39~~$0.36 per Mcf comparable measure during the first quarter of ~~2019~~2020 due to a ~~lower~~higher utilization of industrial-sourced CO₂ in our Gulf Coast ~~region,~~operations, which has a higher average cost than our naturally-occurring CO₂ ~~sources.~~source.

Transportation and Marketing Expenses

Transportation and marketing expenses primarily consist of amounts incurred relating to the transportation, marketing, and processing of oil and natural gas production. Transportation and marketing expenses were ~~$11.2~~$9.4 million and ~~$10.1~~$11.2 million for the three months ended June 30, 2020 and 2019, respectively, and $19.0 million and $22.0 million for the six months ended June 30, 2020 and 2019, respectively.

Taxes Other Than Income

Taxes other than income includes production, ad valorem and franchise taxes. Taxes other than income decreased $15.1 million (59%) and $19.2 million (39%) during the three and six months ended June 30, 2020, respectively, compared to the same periods in 2019, due primarily to a decrease in production taxes resulting from lower oil and natural gas revenues.

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~~three months ended June 30, 2019 and 2018, respectively, and $22.0 million and $20.6 million for the six months ended June 30, 2019 and 2018, respectively.~~

~~Taxes Other Than Income~~

Taxes other than income includes production, ad valorem and franchise taxes. Taxes other than income decreased $1.7 million (6%) during the three months ended June 30, 2019, compared to the same prior-year period and decreased $5.3 million (10%) during the six months ended June 30, 2019, compared to the same period in 2018, due primarily to a decrease in production taxes resulting from lower oil and natural gas revenues.

General and Administrative Expenses (“G&A”)


	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
In thousands, except per-BOE data and employees	2019			2018			2019			2018			2020			2019			2020			2019
Gross cash compensation and administrative costs	$	53,919		$	57,484		$	108,620		$	114,522		$	55,196		$	53,919		$	95,632		$	108,620
Gross stock-based compensation	4,669			3,227			8,975			6,529			1,687			4,669			4,891			8,975
Operator labor and overhead recovery charges	(30,740		)	(32,187		)	(60,615		)	(63,324		)	(25,735		)	(30,740		)	(53,220		)	(60,615		)
Capitalized exploration and development costs	(10,342		)	(9,112		)	(20,549		)	(18,083		)	(7,372		)	(10,342		)	(13,794		)	(20,549		)
Net G&A expense	$	17,506		$	19,412		$	36,431		$	39,644		$	23,776		$	17,506		$	33,509		$	36,431

G&A per BOE
Net cash administrative costs	$	2.56		$	2.99		$	2.74		$	3.11		$	4.97		$	2.56		$	3.10		$	2.74
Net stock-based compensation	0.66			0.45			0.64			0.47			0.24			0.66			0.37			0.64
Net G&A expenses	$	3.22		$	3.44		$	3.38		$	3.58		$	5.21		$	3.22		$	3.47		$	3.38

Employees as of June 30(1)	846			880									686			846


(1)	Includes 32 furloughed employees as of June 30, 2020, 17 of whom were terminated during July 2020.

Our net G&A expenses on an absolute-dollar basis increased $6.3 million (36%) during the three months ended June 30, 2020 compared to the same period in 2019, primarily due to $2.4 million in severance-related costs during the second quarter of 2020 and an incremental $6.3 million in performance and bonus-related compensation expense compared to the prior-year period due primarily to the modifications to our compensation program as discussed in Note 6, Stock Compensation, to the condensed consolidated financial statements. In addition to these increases, G&A recoveries related to operator labor and overhead, and capitalized exploration and development costs increased net G&A expense by approximately $8.0 million as a result of reductions in employees, shut-in production and fewer producing wells in the current period; however, these costs were offset in part by lower overall employee compensation and related costs due to reduced employee headcount. On a per-BOE basis, net G&A expense increased nearly $2 (62%) due to the impact of higher expense and lower production, due in part to approximately 4,300 BOE/d that was shut-in during the second quarter of 2020. During the six months ended June 30, 2020, our net G&A expenses on an absolute-dollar basis decreased ~~$1.9 million (10%) and $3.2~~$2.9 million (8%), ~~or $0.22 (6%) and $0.20 (6%~~but increased $0.09 (3%) on a per-BOE basis, ~~during the three and six months ended June 30, 2019, respectively,~~ compared to the same ~~periods~~period in ~~2018,~~2019, primarily due to reduced employee headcount resulting from our ~~continued focus on cost~~December 2019 voluntary separation program and our May 2020 involuntary workforce reduction, ~~efforts~~with the per-BOE change impacted by declines in production between 2019 and ~~reduction~~2020.

On a sequential-quarter basis, net G&A expenses increased $14.0 million primarily due to an increase in ~~performance-based compensation.~~compensation-related expenses. This increase was primarily due to modifications in our compensation program during the second quarter which resulted in adjustments to the bonus program for 2020 as compared to no accrual for bonuses in the first quarter of 2020 (see further discussion in Note 6, Stock Compensation, to the condensed consolidated financial statements).

Our well operating agreements allow us, when we are the operator, to charge a well with a specified overhead rate during the drilling phase and also to charge a monthly fixed overhead rate for each producing well. In addition, salaries associated with field personnel are initially recorded as gross cash compensation and administrative costs and subsequently reclassified to lease operating expenses or capitalized to field development costs to the extent those individuals are dedicated to oil and gas production, exploration, and development activities.

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Denbury Resources Inc.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Interest and Financing Expenses


	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
In thousands, except per-BOE data and interest rates	2019			2018			2019			2018			2020			2019			2020			2019
Cash interest⁽¹⁾	$	48,371		$	45,542		$	96,319		$	92,145		$	45,263		$	48,371		$	91,089		$	96,319
Less: interest not reflected as expense for financial reporting purposes⁽¹⁾	(21,355		)	(21,614		)	(42,634		)	(43,663		)	(20,912		)	(21,355		)	(42,266		)	(42,634		)
Noncash interest expense	1,194			1,131			2,457			2,268			1,061			1,194			2,092			2,457
Amortization of debt discount⁽²⁾	444			—			444			—			3,934			444			7,829			444
Less: capitalized interest	(8,238		)	(8,851		)	(18,772		)	(17,303		)	(8,729		)	(8,238		)	(18,181		)	(18,772		)
Interest expense, net	$	20,416		$	16,208		$	37,814		$	33,447		$	20,617		$	20,416		$	40,563		$	37,814
Interest expense, net per BOE	$	3.76		$	2.87		$	3.51		$	3.02		$	4.51		$	3.76		$	4.20		$	3.51
Average debt principal outstanding⁽³⁾	$	2,559,822		$	2,550,450		$	2,550,278		$	2,646,049		$	2,185,029		$	2,559,822		$	2,186,322		$	2,550,278
Average cash interest rate⁽⁴⁾	7.6		%	7.1		%	7.6		%	7.0		%	8.3		%	7.6		%	8.3		%	7.6		%

(1)

Cash interest includes the portion of interest on certain debt instruments accounted for as a reduction of debt for GAAP financial reporting purposes in accordance with ~~FASC~~Financial Accounting Standards Board Codification (“FASC”) 470-60, Troubled Debt Restructuring by Debtors. The portion of interest treated as a reduction of debt relates to our 2021 Senior Secured Notes and 9¼% Senior Secured Second Lien Notes due 2022 (the “2022 Senior Secured Notes”)~~, and our previously outstanding 3½% Convertible Senior Notes due 2024 and 5% Convertible Senior Notes due 2023.~~. See below for further discussion.

(2)

Represents amortization of debt discounts of ~~$0.1~~$1.3 million and ~~$0.3~~$2.6 million related to the 7¾% Senior Secured Second Lien Notes ~~and~~due 2024 ~~Convertible~~(the “7¾% Senior ~~Notes, respectively, for~~Secured Notes”) during the three and six months ended June 30, ~~2019.~~2020, respectively, and $2.6 million and $5.2 million related to the 2024 Convertible Senior Notes during the three and six months ended June 30, 2020, respectively.


(3)	Excludes debt discounts related to our 7¾% Senior Secured Notes and 2024 Convertible Senior Notes.


(4)	Includes commitment fees but excludes debt issue costs and amortization of discount.

As reflected in the table above, cash interest expense during the three and six months ended June 30, ~~2019 increased $2.8~~2020 decreased $3.1 million (6%) and ~~$4.2~~$5.2 million (5%), respectively, when compared to the prior-year periods due primarily to ~~an increase~~a decrease in our ~~weighted-average~~average debt principal outstanding as a result of the June 2019 debt exchange transactions and debt repurchases completed in the second half of 2019 and first quarter of 2020. Meanwhile, net interest ~~rate.~~

~~Capitalized interest~~expense was relatively unchanged and increased $2.7 million (7%) during the three ~~months ended June 30, 2019~~ and ~~increased $1.5 million (8%) during the~~ six months ended June 30, ~~2019,~~2020, respectively, compared to the ~~same~~prior-year periods ~~in 2018, primarily~~ due to ~~an increase in~~ the ~~number~~amortization of ~~projects that qualify for interest capitalization.~~the debt discounts related to our 7¾% Senior Secured Notes and 2024 Convertible Senior Notes.

Future interest payable related to our 2021 Senior Secured Notes and 2022 Senior Secured Notes is accounted for in accordance with FASC 470-60, Troubled Debt Restructuring by Debtors, whereby most of the future interest was recorded as debt as of the transaction date, which will be reduced as semiannual interest payments are made. Future interest payable recorded as debt totaled ~~$207.7~~$119.5 million as of June 30, 2019. Therefore, interest expense reflected in our Unaudited Condensed Consolidated Statements of Operations will be approximately $86 million lower annually than the actual cash interest payments on our 2021 Senior Secured Notes and 2022 Senior Secured Notes.2020.

~~As more fully described in Note 4,~~ ~~Long-Term Debt, to the Unaudited Condensed Consolidated Financial Statements, the~~The June 2019 debt exchange transactions were accounted for in accordance with FASC 470-50, Modifications and Extinguishments, whereby our ~~new~~ 7¾% Senior Secured Notes and ~~new~~ 2024 Convertible Senior Notes were recorded on our balance sheet at discounts to their principal amounts of $29.6 million and $79.9 million, respectively. ~~These debt discounts will be amortized as interest expense over~~

In conjunction with the ~~terms~~negotiation of the ~~notes; therefore, future~~RSA, the Company did not make the $7.8 million interest ~~expense reflected in our Unaudited Condensed Consolidated Statements of Operations will be higher than the actual cash interest payments~~payment due on our ~~new 7¾% Senior Secured Notes and new~~ 2024 Convertible Senior Notes on June 30, 2020, and the $3.1 million interest payment due on our 4⅝% Senior Subordinated Notes due 2023 on July 15, 2020. However, as part of the RSA signed on July 28, 2020 by ~~approximately $8~~holders of our second lien notes, the Company paid them a total of $8.0 million in ~~2019, $16 million in 2020, $19 million in 2021, $21 million in 2022, $25 million in 2023~~accrued and ~~$21 million in 2024.~~unpaid interest on the second lien notes.

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Denbury Resources Inc.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Depletion, Depreciation, and Amortization (“DD&A”)


	Three Months Ended				Six Months Ended				Three Months Ended				Six Months Ended
	June 30,				June 30,				June 30,				June 30,
In thousands, except per-BOE data	2019		2018		2019		2018		2020		2019		2020		2019
Oil and natural gas properties	$	40,110	$	33,358	$	76,945	$	65,229	$	40,290	$	40,110	$	82,859	$	76,945
CO₂ properties, pipelines, plants and other property and equipment	18,154		19,586		38,616		40,166		15,124		18,154		32,049		38,616
Accelerated depreciation charge⁽¹⁾									—		—		37,368		—
Total DD&A	$	58,264	$	52,944	$	115,561	$	105,395	$	55,414	$	58,264	$	152,276	$	115,561

DD&A per BOE
Oil and natural gas properties	$	7.38	$	5.91	$	7.15	$	5.89	$	8.82	$	7.38	$	8.58	$	7.15
CO₂properties, pipelines, plants and other property and equipment	3.34		3.47		3.59		3.63		3.31		3.34		3.31		3.59
Accelerated depreciation charge⁽¹⁾									—		—		3.87		—
Total DD&A cost per BOE	$	10.72	$	9.38	$	10.74	$	9.52	$	12.13	$	10.72	$	15.76	$	10.74

Write-down of oil and natural gas properties									$	662,440	$	—	$	734,981	$	—


(1)	Represents an accelerated depreciation charge related to capitalized amounts associated with unevaluated properties that were transferred to the full cost pool.

The decrease in our depletion, depreciation, and amortization expense during the three months ended June 30, 2020, when compared to the same period in 2019, was primarily due to a decrease in CO₂ depletion as a result of lower CO₂ volumes from our CO₂ sources. The increase in our DD&A expense during the six months ended June 30, 2020, when compared to the same period in 2019, was primarily due to an accelerated depreciation charge of $37.4 million related to impaired unevaluated properties that were transferred to the full cost pool during the first quarter of 2020.

Full Cost Pool Ceiling Test

Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation. Under these rules, the full cost ceiling value is calculated using the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period. The first-day-of-the-month oil prices for the preceding 12 months, after adjustments for market differentials by field, averaged $44.74 per Bbl and $55.17 per Bbl as of June 30, 2020 and March 31, 2020, respectively. In addition, the first-day-of-the-month natural gas prices for the preceding 12 months, after adjustments for market differentials by field, averaged $1.91 per MMBtu and $1.68 per MMBtu as of June 30, 2020 and March 31, 2020, respectively. While representative oil prices at March 31, 2020 were roughly consistent with adjusted prices used to calculate the December 31, 2019 full cost ceiling value, the decline in NYMEX oil prices in late March 2020 due to OPEC supply pressures and a reduction in worldwide oil demand amid the COVID-19 pandemic contributed to the impairment and transfer of $244.9 million of our unevaluated costs to the full cost amortization base during the three months ended March 31, 2020. Primarily as a result of adding these additional costs to the amortization base, we recognized a full cost pool ceiling test write-down of $72.5 million during the three months ended March 31, 2020. In addition, as a result of the precipitous decline in NYMEX oil prices during the second quarter of 2020, we recognized an additional full cost pool ceiling test write-down of $662.4 million during the three months ended June 30, 2020. If oil prices remain at or near early-August 2020 levels in subsequent periods, we currently expect that we would also record write-downs in subsequent quarters in 2020, as the 12-month average price used in determining the full cost ceiling value will continue to decline during each rolling quarterly period in 2020, subject to the date of the Company’s emergence from bankruptcy and potential impacts of fresh start accounting, if applicable. The possibility and amount of any future write-down or impairment is difficult to predict, and will depend, in part, upon oil and natural gas prices, the incremental proved reserves that may be added each period, revisions to previous reserve estimates and future capital expenditures and operating costs.

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Denbury Resources Inc.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Impairment Assessment of Long-lived Assets

We test long-lived assets for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. These long-lived assets, which are not subject to our full cost pool ceiling test, are principally comprised of our capitalized CO₂properties ~~depletion~~and pipelines. Given the significant recent declines in NYMEX oil prices to approximately $20 per Bbl in late March 2020 due to OPEC supply pressures and a reduction in worldwide oil demand amid the COVID-19 pandemic, we performed a long-lived asset impairment test for our two long-lived asset groups (Gulf Coast region and Rocky Mountain region) as of March 31, 2020.

Significant assumptions impacting expected future undiscounted net cash flows include projections of future oil and natural gas prices (management’s assumption of 2020 oil prices at strip pricing, gradually increasing to a long-term oil price of $65 per Bbl beginning in 2026, and gas futures pricing were used for the March 31, 2020 analysis), projections of estimated quantities of oil and natural gas reserves, projections of future rates of production, timing and amount of future development and operating costs, projected availability and cost of CO₂, projected recovery factors of tertiary reserves and risk-adjustment factors applied to the cash flows. We performed a qualitative assessment as of June 30, 2020 and determined there were no material changes to our key cash flow assumptions and no triggering events since the analysis performed as of March 31, 2020; therefore, no impairment test was performed for the second quarter of 2020.

Other Expenses

Other expenses totaled $11.3 million and $13.8 million during the three and six months ended June 30, 2020, respectively, compared to $2.4 million and $6.5 million during the three and six months ended June 30, 2019, ~~when compared to the same periods in 2018, was~~respectively. Other expenses during 2020 are primarily ~~due to an increase in depletable costs resulting from increases in our capitalized costs and future development~~comprised of $7.9 million of professional fees associated with restructuring activities, $1.6 million of costs associated with the Delta-Tinsley CO₂ pipeline incident, and $1.0 million of costs associated with the APMTG Helium, LLC helium supply contract ruling. The 2019 amounts are primarily comprised of $1.3 million of expense related to an impairment of assets, $1.3 million of acquisition transaction costs, and $1.0 million of transaction costs related to our ~~reserves base.~~privately negotiated debt exchanges.

Income Taxes


	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
In thousands, except per-BOE amounts and tax rates	2019			2018			2019			2018			2020			2019			2020			2019
Current income tax expense (benefit)	$	3,354		$	(754	)	$	2,073		$	(1,786	)	$	598		$	3,354		$	(5,809	)	$	2,073
Deferred income tax expense	62,023			10,185			52,545			25,237
Total income tax expense	$	65,377		$	9,431		$	54,618		$	23,451
Average income tax expense per BOE	$	12.03		$	1.68		$	5.07		$	2.12
Deferred income tax expense (benefit)													(102,304		)	62,023			(106,513		)	52,545
Total income tax expense (benefit)													$	(101,706	)	$	65,377		$	(112,322	)	$	54,618
Average income tax expense (benefit) per BOE													$	(22.27	)	$	12.03		$	(11.63	)	$	5.07
Effective tax rate	30.8		%	23.8		%	31.1		%	25.1		%	12.7		%	30.8		%	15.3		%	31.1		%
Total net deferred tax liability	$	362,303		$	231,761								$	306,186		$	362,303

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Denbury Resources Inc.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. Our income taxes are based on an estimated statutory rate of approximately 25% in ~~2019~~2020 and ~~2018.~~2019. As provided for under FASC 740-270-35-2, we determined the actual effective tax rate for the six months ended June 30, 2020 was the best estimate of our annual effective tax rate. Our effective tax rate for the three and six months ended June 30, ~~2019~~2020 was ~~higher~~lower than our estimated statutory rate, primarily due to the establishment of a full valuation allowance ~~against~~on our enhanced oil recovery and research and development credits that currently are not expected to be utilized. We evaluated our deferred tax assets in light of all available evidence as of the balance sheet date, including our cumulative loss position in consideration of recorded book full cost pool ceiling test write-downs and accelerated depreciation charge, and the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) provisions. Based on our evaluation using all available evidence and in consideration of the weight of existing negative evidence, we concluded that a ~~portion~~full valuation allowance of $85.0 million on our ~~business interest expense deduction that~~$63.4 million of enhanced oil recovery credits and $21.6 million of research and development credits was required, as we ~~estimate will~~believe the tax benefit of the tax credits are more-likely-than-not to not be ~~disallowed.~~realized. This is an increase in the valuation allowance of $74.0 million during the quarter ended June 30, 2020 over the $11.0 million valuation allowance established in the quarter ended March 31, 2020. The ~~Tax Cuts and Jobs~~CARES Act ~~(“The Act”), which was enacted on December 22, 2017, revised~~signed into law in March 2020, among other provisions, modified the rules regarding the deductibility of business interest expense that were established by ~~limiting that deduction~~the Tax Cuts and Jobs Act of December 2017, increasing the limitation threshold from 30% to ~~30%~~50% of ~~adjusted taxable income~~Adjusted Taxable Income (as defined)~~, with disallowed amounts being carried forward~~ for 2019 and 2020. In addition, for the 2020 year, a taxpayer may elect to ~~future taxable years. Based on our evaluation, using information existing as~~use its 2019 Adjusted Taxable Income in lieu of ~~the balance sheet date, of the near-term ability~~its 2020 Adjusted Taxable Income. Due to ~~utilize the tax benefits associated with our 2019 disallowed business interest expense,~~these modifications, we ~~have established a valuation allowance through our annual estimated effective income tax rate for that portion of~~now expect to fully deduct our business interest expense ~~that is currently expected to exceed~~in 2018, 2019 and 2020 and fully released our previously recorded valuation allowance of $24.5 million during the ~~allowed limitation under The Act.~~three months ended March 31, 2020.

The current income tax ~~benefits~~benefit for the ~~three and~~ six months ended June 30, ~~2018, represent~~2020, represents amounts estimated to be receivable resulting from alternative minimum tax ~~credits and certain state tax obligations.~~

As of June 30, 2019, we had estimated amounts available for carry forward of $57.8 million of enhanced oil recovery credits related to our tertiary operations, $21.6 million of research and development credits, and $18.1 million of alternative minimum tax credits. ~~The alternative~~Alternative minimum tax credits of $10.5 million are ~~fully refundable by 2021 and are~~currently recorded as a receivable on the balance sheet.

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Denbury Resources Inc.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

~~sheet. The enhanced oil recovery credits and research and development credits do not begin to expire until 2024 and 2031, respectively.~~

Per-BOE Data

The following table summarizes our cash flow and results of operations on a per-BOE basis for the comparative periods. Each of the significant individual components is discussed above.


	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
Per-BOE data	2019			2018			2019			2018			2020			2019			2020			2019
Oil and natural gas revenues	$	60.80		$	66.57		$	58.06		$	64.63		$	23.95		$	60.80		$	35.09		$	58.06
Receipt (payment) on settlements of commodity derivatives	(0.28		)	(9.71		)	0.62			(7.96		)	9.99			(0.28		)	7.28			0.62
Lease operating expenses	(21.70		)	(21.34		)	(22.61		)	(21.56		)	(17.80		)	(21.70		)	(19.73		)	(22.61		)
Production and ad valorem taxes	(4.33		)	(4.50		)	(4.23		)	(4.55		)	(1.92		)	(4.33		)	(2.77		)	(4.23		)
Transportation and marketing expenses	(2.07		)	(1.78		)	(2.04		)	(1.86		)	(2.06		)	(2.07		)	(1.97		)	(2.04		)
Production netback	32.42			29.24			29.80			28.70			12.16			32.42			17.90			29.80
CO₂ sales, net of operating and exploration expenses	1.36			1.10			1.43			1.20			1.23			1.36			1.33			1.43
General and administrative expenses	(3.22		)	(3.44		)	(3.38		)	(3.58		)	(5.21		)	(3.22		)	(3.47		)	(3.38		)
Interest expense, net	(3.76		)	(2.87		)	(3.51		)	(3.02		)	(4.51		)	(3.76		)	(4.20		)	(3.51		)
Other	(0.19		)	(0.24		)	0.17			0.15			(1.71		)	(0.19		)	0.22			0.17
Changes in assets and liabilities relating to operations	0.74			3.51			(4.72		)	(1.27		)	0.44			0.74			(4.24		)	(4.72		)
Cash flows from operations	27.35			27.30			19.79			22.18			2.40			27.35			7.54			19.79
DD&A	(10.72		)	(9.38		)	(10.74		)	(9.52		)
DD&A – excluding accelerated depreciation charge													(12.13		)	(10.72		)	(11.89		)	(10.74		)
DD&A – accelerated depreciation charge⁽¹⁾													—			—			(3.87		)	—
Write-down of oil and natural gas properties													(145.04		)	—			(76.08		)	—
Deferred income taxes	(11.41		)	(1.81		)	(4.88		)	(2.28		)	22.40			(11.41		)	11.03			(4.88		)
Gain on extinguishment of debt	18.46			—			9.32			—			—			18.46			1.97			9.32
Noncash fair value gains (losses) on commodity derivatives⁽¹⁾	4.84			(7.34		)	(6.07		)	(5.14		)
Noncash fair value gains (losses) on commodity derivatives⁽²⁾													(18.78		)	4.84			3.76			(6.07		)
Other noncash items	(1.53		)	(3.41		)	3.82			1.06			(1.56		)	(1.53		)	3.00			3.82
Net income	$	26.99		$	5.36		$	11.24		$	6.30
Net income (loss)													$	(152.71	)	$	26.99		$	(64.54	)	$	11.24


(1)	Represents an accelerated depreciation charge related to impaired unevaluated properties that were transferred to the full cost pool.


(2)	Noncash fair value gains (losses) on commodity derivatives is a non-GAAP measure. See Operating Results Table above for a discussion of the reconciliation between noncash fair value gains (losses) on commodity derivatives to “Commodity derivatives expense (income)” in the Unaudited Condensed Consolidated Statements of Operations.

CRITICAL ACCOUNTING POLICIES

For additional discussion of our critical accounting policies, see Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Form 10-K. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in the notes to the Company’s Unaudited Condensed Consolidated Financial Statements contained in this Quarterly Report on Form 10-Q.

FORWARD-LOOKING INFORMATION

The data and/or statements contained in this Quarterly Report on Form 10-Q that are not historical facts, including, but not limited to, statements found in the section Management’s Discussion and Analysis of Financial Condition and Results of Operations, and information regarding the financial position, business strategy, production and reserve growth, possible or assumed future results of operations, and other plans and objectives for the future operations of Denbury, and general economic conditions are

Table of Contents

Denbury Resources Inc.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

forward-looking statements, as that term is defined in Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern,

~~Table of Contents~~

~~Denbury Resources Inc.~~

~~Management’s Discussion and Analysis of Financial Condition and Results of Operations~~

among other things, our ability to obtain Bankruptcy Court approval with respect to motions or other requests made to the Bankruptcy Court and the risks attendant to the bankruptcy process, our ability to confirm and consummate the Plan or an alternative restructuring transaction, the effects of the Chapter 11 Restructuring on our liquidity or results of operations or business prospects, the effects of the Chapter 11 Restructuring on our business and the interests of various constituents, the length of time that we will operate under chapter 11 protection, risks associated with third-party motions in the Chapter 11 Restructuring, the adequacy and restrictions of a DIP facility such as that contemplated by our lenders’ commitment letter, and the impact of all of these factors upon our ability to capitalize on the reorganization process and emerge as an entity equipped to operate as a going concern on a long-term basis, the extent and length of the drop in worldwide oil demand due to the COVID-19 coronavirus, financial forecasts, future hydrocarbon prices and their volatility, current or future liquidity sources or their adequacy to support our anticipated future activities, our ability to ~~further reduce our debt levels~~refinance or extend ~~debt~~the maturities of our long-term indebtedness which matures in 2021 and 2022, possible future write-downs of oil and natural gas reserves and the effect of these factors upon our ability to continue as a going concern, together with assumptions based on current and projected production levels, oil and gas prices and oilfield costs, current or future expectations or estimations of our cash flows or the impact of changes in commodity prices on cash flows, availability of capital, borrowing capacity, price and availability of advantageous commodity derivative contracts or the predicted cash flow benefits therefrom, forecasted capital expenditures, drilling activity or methods, including the timing and location thereof, the nature of any future asset purchases or sales or the timing or proceeds thereof, estimated timing of commencement of CO₂ flooding of particular fields or areas, including Cedar Creek Anticline (“CCA”), or the availability of capital for CCA pipeline construction, or its ultimate cost or date of completion, timing of CO₂ injections and initial production responses in tertiary flooding projects, development activities, finding costs, anticipated future cost savings, capital budgets, interpretation or prediction of formation details, production rates and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO₂ reserves and supply and their availability, potential reserves, barrels or percentages of recoverable original oil in place, levels of tariffs or other trade restrictions, the likelihood, timing and impact of increased interest rates, the impact of regulatory rulings or changes, ~~anticipated~~ outcomes of pending litigation, prospective legislation affecting the oil and gas industry, environmental regulations, mark-to-market values, competition, rates of return, estimated costs, changes in costs, future capital expenditures and overall economics, worldwide economic conditions, the likelihood and extent of an economic slowdown, and other variables surrounding operations and future plans. Such forward-looking statements generally are accompanied by words such as “plan,” “estimate,” “expect,” “predict,” “forecast,” “to our knowledge,” “anticipate,” “projected,” “preliminary,” “should,” “assume,” “believe,” “may” or other words that convey, or are intended to convey, the uncertainty of future events or outcomes. Such forward-looking information is based upon management’s current plans, expectations, estimates, and assumptions and is subject to a number of risks and uncertainties that could significantly and adversely affect current plans, anticipated actions, the timing of such actions and our financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by us or on our behalf. Among the factors that could cause actual results to differ materially are our ability to refinance our senior debt maturing in 2021 and the related impact on our ability to continue as a going concern, fluctuations in worldwide oil prices or in U.S. oil prices and consequently in the prices received or demand for our oil and natural gas; evolving political and military tensions in the Middle East; decisions as to production levels and/or pricing by OPEC or production levels by U.S. shale producers in future periods; levels of future capital expenditures; trade disputes and resulting tariffs or international economic sanctions; effects and maturity dates of our indebtedness; success of our risk management techniques; accuracy of our cost estimates; ~~availability or~~access to and terms of credit in the commercial banking or other debt markets; fluctuations in the prices of goods and services; the uncertainty of drilling results and reserve estimates; operating hazards and remediation costs; disruption of operations and damages from well incidents, hurricanes, tropical storms, forest fires, or other natural occurrences; acquisition risks; requirements for capital or its availability; conditions in the worldwide financial, trade and credit markets; general economic conditions; competition; government regulations, including changes in tax or environmental laws or regulations; and unexpected delays, as well as the risks and uncertainties inherent in oil and gas drilling and production activities or that are otherwise discussed in this quarterly report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in our other public reports, filings and public statements including, without limitation, the Company’s most recent Form 10-K.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

Debt and Interest Rate Sensitivity

~~We finance some of our acquisitions and other expenditures with fixed and variable rate debt. These debt agreements expose us to market risk related to changes in interest rates.~~ As of June 30, ~~2019~~,2020, we had ~~$80.0~~$2.1 billion of fixed-rate debt outstanding and $265.0 million of outstanding borrowings onunder our ~~senior secured bank credit facility.~~Bank Credit Agreement. At this level of variable-rate debt, an increase or decrease of 10% in interest rates would have an immaterial effect on our interest expense. ~~None of our existing debt has~~Our Bank Credit Agreement, senior secured second lien notes, convertible senior notes, and senior subordinated notes do not have any triggers or covenants regarding our debt ratings with rating agencies, although under the NEJD financing lease, in light of credit downgrades in February 2016, we were required to provide a $41.3 million letter of credit to the lessor, which we provided on March 4, 2016. The letter of credit may be drawn upon in the event we fail to make a payment due under the pipeline financing lease agreement or upon other specified defaults set out in the pipeline financing lease agreement (filed as Exhibit 99.1 to the Form 8-K filed with the SEC on June 5, 2008).agencies. The fair values of our senior secured second lien notes, convertible senior notes, and senior subordinated notes are based on quoted market prices. The following table presents the principal and fair values of our outstanding debt as of June 30, ~~2019.~~2020.


In thousands	2021		2022		2023		2024		Total		Fair Value		2021		2022		2023		2024		Total		Fair Value
Variable rate debt:
Senior Secured Bank Credit Facility (weighted average interest rate of 5.1% at June 30, 2019)	$	80,000	$	—	$	—	$	—	$	80,000	$	80,000
Senior Secured Bank Credit Facility (weighted average interest rate of 5.0% at June 30, 2020)													$	265,000	$	—	$	—	$	—	$	265,000	$	265,000
Fixed rate debt:
9% Senior Secured Second Lien Notes due 2021	614,919		—		—		—		614,919		605,695		584,709		—		—		—		584,709		228,323
9¼% Senior Secured Second Lien Notes due 2022	—		455,668		—		—		455,668		428,328		—		455,668		—		—		455,668		175,300
7¾% Senior Secured Second Lien Notes due 2024	—		—		—		528,026		528,026		438,262		—		—		—		531,821		531,821		200,938
7½% Senior Secured Second Lien Notes due 2024	—		—		—		24,638		24,638		19,464		—		—		—		20,641		20,641		8,050
6⅜% Convertible Senior Notes due 2024	—		—		—		245,548		245,548		161,273		—		—		—		225,663		225,663		33,367
6⅜% Senior Subordinated Notes due 2021	51,304		—		—		—		51,304		41,685		51,304		—		—		—		51,304		2,735
5½% Senior Subordinated Notes due 2022	—		94,784		—		—		94,784		54,501		—		58,426		—		—		58,426		3,635
4⅝% Senior Subordinated Notes due 2023	—		—		211,695		—		211,695		106,377		—		—		135,960		—		135,960		4,662

See Note 4, Long-Term Debt, to the Unaudited Condensed Consolidated Financial Statements for details regarding our long-term debt.

Commodity Derivative Contracts

We enter into oil derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength, and expectation of future commodity prices. In order to provide a level of price protection to a portion of our oil production, we have hedged a portion of our estimated oil production through 2020 using both NYMEX and LLS fixed-price swaps and three-way collars. Depending on market conditions, we may continue to add to our existing ~~2019 and~~ 2020 hedges. See also Note 5,7, Commodity Derivative Contracts, and Note 68, Fair Value Measurements, to the Unaudited Condensed Consolidated Financial Statements for additional information regarding our commodity derivative contracts.

All of the mark-to-market valuations used for our commodity derivatives are provided by external sources. We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification. All of our commodity derivative contracts are with parties that are lenders under our senior secured bank credit facility (or affiliates of such lenders). We have included an estimate of nonperformance risk in the fair value measurement of our commodity derivative contracts, which we have measured for nonperformance risk based upon credit default swaps or credit spreads.

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~~Denbury Resources Inc.~~

For accounting purposes, we do not apply hedge accounting treatment to our commodity derivative contracts. This means that any changes in the fair value of these commodity derivative contracts will be charged to earnings instead of charging the effective portion to other comprehensive income and the ineffective portion to earnings.

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At June 30, ~~2019,~~2020, our commodity derivative contracts were recorded at their fair value, which was a net asset of ~~$32.0~~$40.0 million, ~~a $26.3~~an $85.7 million ~~increase~~decrease from the ~~$5.7~~$125.7 million net asset recorded at March 31, ~~2019,~~2020, and a ~~$65.3~~$36.4 million ~~decrease~~increase from the ~~$97.3~~$3.6 million net asset recorded at December 31, ~~2018.~~2019. These changes are primarily related to the expiration or early termination of commodity derivative contracts during the three and six months ended June 30, ~~2019,~~2020, new commodity derivative contracts entered into during ~~2019~~2020 for future periods, and to the changes in oil futures prices between December 31, ~~2018~~2019 and June 30, ~~2019~~2020.

Commodity Derivative Sensitivity Analysis

Based on NYMEX and LLS crude oil futures prices as of June 30, ~~2019~~2020, and assuming both a 10% increase and decrease thereon, we would expect to receive ~~or make~~ payments on our crude oil derivative contracts outstanding at June 30, 2020 as shown in the following table:


	Receipt / (Payment)			Receipt / (Payment)
In thousands	Crude Oil Derivative Contracts			Crude Oil Derivative Contracts
Based on:
Futures prices as of June 30, 2019	$	31,057
Futures prices as of June 30, 2020				$	41,226
10% increase in prices	(14,698		)	25,750
10% decrease in prices	109,514			56,695

Our commodity derivative contracts are used as an economic hedge of our exposure to commodity price risk associated with anticipated future production. As a result, changes in receipts or payments of our commodity derivative contracts due to changes in commodity prices as reflected in the above table would be mostly offset by a corresponding increase or decrease in the cash receipts on sales of our oil production to which those commodity derivative contracts relate.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, ~~2019~~2020, to ensure that information that is required to be disclosed in the reports the Company files and submits under the Securities Exchange Act of 1934 is recorded, that it is processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and that information that is required to be disclosed under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

Evaluation of Changes in Internal Control over Financial Reporting. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we have determined that, during the second quarter of fiscal ~~2019~~2020, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

~~We are involved in various lawsuits, claims~~The information under Note 9, Commitments and ~~regulatory proceedings incidental~~Contingencies, to ~~our businesses. While we currently believe that~~ the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our business or finances, litigation is subject to inherent uncertainties. We accrue for losses from litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated.

~~Riley Ridge Helium Supply Contract Claim~~

As part of our 2010 and 2011 acquisitions of the Riley Ridge Unit and associated gas processing facility that was under construction, the Company assumed a 20-year helium supply contract under which we agreed to supply the helium separated from the full well stream by operation of the gas processing facility to a third-party purchaser, APMTG Helium, LLC (“APMTG”). The helium supply contract provides for the delivery of a minimum contracted quantity of helium, with liquidated damages payable if specified quantities of helium are not supplied in accordance with the terms of the contract. The liquidated damages are specified in the contract at up to $8.0 million per contract year and are capped at an aggregate of $46.0 million over the term of the contract.

The Company’s position continues to be that its contractual obligations have been and continue to be excused by events that fall within the force majeure provisions in the helium supply contract. The Company intends to continue to vigorously defend its position and pursue all of its rights.

Absent reversal of the trial court’s ruling on appeal, the Company anticipates total liquidated damages would equal the $46.0 million aggregate cap under the helium supply contract (including $14.2 million of liquidated damages for the contract years ending July 31, 2018 and July 31, 2019) plus $4.2 million of associated costs (through June 30, 2019), for a total of $50.2 million, included in “Other liabilities” in our Unaudited Condensed Consolidated ~~Balance Sheets as of June 30, 2019.~~

~~Environmental Protection Agency Matter Concerning Certain Fields~~

The Company previously entered into a series of tolling agreements with the Environmental Protection Agency (“EPA”), and has been in discussions with the agency over the past several years regarding the EPA’s contention that it has causes of action under the Clean Water Act (“CWA”) related to releases (principally between 2008 and 2013) of oil and produced water containing small amounts of oil in the Citronelle Field in southern Alabama and several fields in Mississippi. The EPA has taken the position that these releases were in violation of the CWA.

In April 2019, the discussions concluded and the parties reached agreement on a proposed Consent Decree among the Company, the United States, and the State of Mississippi resolving the allegations of CWA violations. The proposed Consent Decree was lodged in U.S. District Court in Mississippi for a 30-day public comment period and will become effective upon the District Court entering the Consent Decree as a judgment of the court. Once effective, the Consent Decree will require the Company to pay civil penalties totaling $3.5 million in the aggregate to the United States and the State of Mississippi, to implement enhancements to the Company’s mechanical integrity program designed to minimize the occurrence and impact of any future releases at the Mississippi fields, and to perform other relief such as enhanced training and reporting requirements with respect to the Mississippi fields.

~~Table of Contents~~Financial Statements is incorporated herein by reference.

~~Denbury Resources Inc.~~

Item 1A. Risk Factors

~~Please refer~~In addition to the risks identified below, carefully consider the risk factors under the caption “Risk Factors” under Part I, Item 1A of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, ~~2018. There~~2019, together with all of the other information included in this Quarterly Report on Form 10-Q.

We are subject to the risks and uncertainties associated with proceedings under chapter 11 of the Bankruptcy Code.

On July 30, 2020, Denbury and all of the Company’s wholly owned subsidiaries filed petitions for voluntary relief under chapter 11 of the United States Bankruptcy Code. On July 28, 2020, Denbury entered into the RSA with 100% of our revolving credit facility lenders and holders of 67.1% of our senior second lien notes and 73.1% of our convertible notes to support a restructuring in accordance with the terms set forth in our Plan. For the duration of our Chapter 11 Restructuring, our operations and our ability to develop and execute our business plan, as well as our continuation as a going concern thereafter, are subject to risks and uncertainties associated with bankruptcy, including the following:

our ability to execute, confirm and consummate the Plan as contemplated by the RSA with respect to the Chapter 11 Restructuring;

the sufficiency and restrictions of DIP financing we have ~~been~~obtained to allow us to emerge from bankruptcy and execute our business plan post-emergence;

our ability to maintain our relationships with our suppliers, service providers, employees and other third parties;

our ability to maintain other contracts that are critical to our operations;

our ability to execute our business plan in the current depressed commodity price environment;

our ability to retain key employees;

the impact of third parties seeking to obtain court approval to terminate contracts and other agreements with us;

whether third parties seek to obtain court approval to convert the Chapter 11 Restructuring to a chapter 7 proceeding; and

the actions and decisions of our creditors and other third parties who have interests in our Chapter 11 Restructuring that may be inconsistent with our plans.

Delays in our Chapter 11 Restructuring increase our costs associated with the bankruptcy process along with the risks of our being unable to reorganize our business and emerge from bankruptcy.

These risks and uncertainties could affect our business and operations in various ways. Pursuant to the Bankruptcy Code, we need the prior approval of the Bankruptcy Court for transactions outside the ordinary course of business, which may limit our ability to respond timely to certain events or take advantage of certain opportunities. We also need Bankruptcy Court confirmation of the Plan as contemplated by the RSA. We cannot accurately predict or quantify the ultimate impact that events that occur during our Chapter 11 Restructuring will have on our business, financial condition, results of operations and cash flows.

Even if the Plan is consummated, we will continue to face a number of risks, principally the degree to which oil prices remain at low levels, and if so, for what length of time, which is likely to depend on the extent and impact of the COVID-19 pandemic, plus our ability to reduce expenses, implement any strategic initiatives and generally maintain favorable relationships with and secure the confidence of our counterparties. Accordingly, we cannot give any assurance that the proposed financial restructuring will allow us to continue as a going concern.

If the RSA is terminated, our ability to confirm and consummate the Plan could be materially and adversely affected.

The RSA contains a number of termination events, upon the occurrence of which certain parties to the RSA may terminate the agreement. If the RSA is terminated as to all parties thereto, each of the parties thereto will be released from its obligations in accordance with the terms of the RSA. Such termination may result in the loss of support for the Plan by the parties to the RSA, which could adversely affect our ability to confirm and consummate the Plan. If the Plan is not consummated, there can be no ~~material~~

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assurance that the Chapter 11 Restructuring would not be converted to chapter 7 liquidation cases or that any new plan would be as favorable to holders of claims against the Company as contemplated by the RSA.

We may not be able to obtain confirmation of the Plan or may have to modify the terms of the Plan.

To emerge successfully from Bankruptcy Court protection as a viable entity, we must meet certain statutory requirements with respect to adequacy of disclosure with respect to a chapter 11 plan of reorganization, solicit and obtain the requisite acceptances of such a reorganization plan and fulfill other statutory conditions for confirmation of such a plan. However, even if the Plan contemplated by the RSA meets other requirements under the Bankruptcy Code, certain parties in interest may file objections to the plan in an effort to persuade the Bankruptcy Court that we have not satisfied the confirmation requirements under section 1129 of the Bankruptcy Code. Even if no objections are filed and the requisite acceptances of our Plan are received from creditors entitled to vote on the Plan, the Bankruptcy Court, which can exercise substantial discretion, may not confirm the Plan.

Further, changed circumstances may necessitate changes to the Plan. Any such modifications could result in less favorable treatment than the treatment currently anticipated to be included in the Plan based upon the agreed terms of the RSA. Such less favorable treatment could include a distribution of property of a lesser value than currently anticipated to be distributed to the class affected by the modification, or no distribution of property whatsoever. Changes to the Plan may also delay the confirmation of the Plan and our emergence from bankruptcy.

The precise requirements and evidentiary showing for confirming a plan, notwithstanding its rejection by one or more impaired classes of claims or equity interests, depends upon a number of factors, including the status and seniority of claims by various creditors or holders or equity interests in the rejecting class (i.e., secured claims or unsecured claims, subordinated or senior claims). If the Plan is not confirmed by the Bankruptcy Court, it is unclear whether we would be able to reorganize our business and what, if anything, holders of claims against us would ultimately receive with respect to their claims.

The Plan may not become effective.

The Plan may not become effective because it is subject to the satisfaction of certain conditions precedent (some of which are beyond our control). There can be no assurance that such conditions will be satisfied or waived and, therefore, that the Plan will become effective and that we will emerge from the Chapter 11 Restructuring as contemplated by the Plan. If the effective date of the Plan is delayed, we may not have sufficient cash available to operate our business. In that case, we may need new or additional post-petition financing, which may increase the cost of consummating the Plan. There is no assurance of the terms on which such financing may be available or if such financing will be available at all. If the transactions contemplated by the Plan are not completed, it may become necessary to amend the Plan, with accompanying expenses and material delays.

We have substantial liquidity needs and may not have sufficient liquidity for the time necessary to confirm a plan of reorganization.

We have incurred, and expect to continue to incur, significant costs in connection with the Chapter 11 Restructuring. With the Bankruptcy Court’s authorization to use cash collateral and approval of the DIP Facility, we believe that we will have sufficient liquidity, including cash on hand and funds generated from ongoing operations, to fund anticipated cash requirements through the Chapter 11 Restructuring. As such, we expect to pay vendor and royalty obligations on a go-forward basis in the ordinary course according to the terms of our current contracts and consistent with applicable court orders approving such payments. However, there can be no assurance that our current liquidity will be sufficient to allow us to satisfy our obligations related to the Chapter 11 Restructuring and those necessary for confirmation of the Plan. There is a risk that we could fail to consummate the exit financing contemplated by the RSA, or that it will not be sufficient to meet our liquidity needs.

As a result of the Chapter 11 Restructuring, our financial results may not reflect historical trends.

We expect that our historical financial performance likely will not be indicative of financial performance after the date of the bankruptcy filing. In addition, if we emerge from the Chapter 11 Restructuring, the amounts reported in subsequent periods may materially change due to revisions to our operating plans. Our June 30, 2020 Condensed Consolidated Financial Statements do not include any adjustments that might be necessary should we be unable to continue as a going concern. In addition, our unaudited Condensed Consolidated Financial Statements do not reflect any adjustments related to bankruptcy or liquidation accounting. We also may be required to adopt fresh start accounting, in which case our assets and liabilities will be recorded at fair value as of the

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fresh start reporting date, which may differ materially from the recorded values of assets and liabilities prior to seeking bankruptcy protection. Our financial results after the application of fresh start accounting are likely to be different from historical trends.

The pursuit of the Chapter 11 Restructuring will consume a substantial portion of the time and attention of our management, and we may face increased levels of employee attrition.

Our management will be required to spend a significant amount of time and effort focusing on the Chapter 11 Restructuring instead of focusing exclusively on our business operations. This may adversely affect the conduct of our business, and, as a result, our financial condition and results of operations, particularly if the Chapter 11 Restructuring are protracted.

During the duration of the Chapter 11 Restructuring, our employees will face considerable distraction and uncertainty and we may experience increased levels of employee attrition. A loss of key personnel or material erosion of employee morale could have a material adverse effect on our business and results of operations. The failure to retain or attract new members of our management team and other key personnel could impair our ability to execute our strategy and implement operational initiatives.

On the effective date of the Plan, the composition of our board of directors will change substantially.

Under the Plan, the composition of our board of directors will change substantially. Pursuant to the Plan, our new board of directors will be appointed by the certain consenting noteholders under the RSA or the ad hoc committee representing them in accordance with the governance term sheet attached to the RSA. Our Chief Executive Officer will be a member of the board of directors. Any new directors are likely to have different backgrounds, experiences and perspectives from those individuals who previously served on the board of directors and, thus, may have different views on the issues that will determine our strategic and operational direction and may differ materially from those of the past.

In certain instances, a chapter 11 case may be converted to a case under chapter 7 of the Bankruptcy Code.

Upon a showing of cause, the Bankruptcy Court may convert our Chapter 11 Restructuring to cases under chapter 7 of the Bankruptcy Code. In such event, a chapter 7 trustee would be appointed or elected to liquidate our assets and the assets of our subsidiaries for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that any such liquidation under chapter 7 would result in significantly smaller distributions being made to our creditors than those provided for in the RSA and plan of reorganization: assets would have to be sold or otherwise disposed of in a distressed fashion over a short period of time rather than in a controlled manner and as a going concern, and additional expenses and claims would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with a cessation of operations.

Certain claims will not be discharged and could have a material adverse effect on our financial condition and results of operations.

The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation. With few exceptions, all claims that arise prior to the filing of our Chapter 11 Restructuring or before confirmation of the Plan (a) would be subject to compromise and/or treatment under the Plan and/or (b) would be discharged in accordance with the terms of the Plan. In order to achieve our objective of a swift confirmation of the Plan, we determined to leave many classes of claims as unimpaired and thus such claims are not discharged under the Plan. Holders of such claims can still assert the claims against the reorganized entity and may have an adverse effect on our financial condition and results of operations.

Even if the Plan is consummated, we may not be able to achieve our stated goals and continue as a going concern.

Even if the Plan is consummated, we will continue to face a number of risks, including further deterioration in commodity prices or decreased market demand or increasing expenses. Accordingly, we cannot guarantee that the Plan or any other chapter 11 plan of reorganization will achieve our stated goals.

Furthermore, even if our debts are reduced or discharged through such plan, we may need to raise additional funds through public or private debt or equity financing to fund the Company’s operations and its capital needs. Our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited, if it is available at all. Therefore, adequate funds may not be available when needed, or in sufficient amounts or available on acceptable terms, if at all.

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Continued COVID-19 outbreaks and uncertainty about their length and depth, together with oil prices remaining at current levels, will significantly reduce our cash flow and liquidity.

The COVID-19 pandemic continues to spread and evolve, both in the United States and abroad. Its ultimate impact on our operational and financial performance will depend on future developments, including the duration and spread of the pandemic, the actions to contain the disease or mitigate its impact, related restrictions on business activity and travel, and continued lower levels of domestic and global oil demand. The COVID-19 pandemic may also intensify the risks described in the other risk factors ~~contained~~disclosed in our Annual Report on Form ~~10-K~~10‑K for the fiscal year ended December 31, ~~2018 other than as detailed below.~~2019.

Prices in the oil market have remained depressed since March 2020. Oil prices are expected to continue to be volatile as a result of the near-term production instability, ongoing COVID-19 outbreaks, changes in oil inventories, industry demand and global and national economic performance. NYMEX oil prices averaged approximately $22 per Bbl during the last 10 trading days of March 2020, continuing to decline to an average of $17 per Bbl in April 2020 before increasing to an average of $29 per Bbl during May 2020, $38 per Bbl during June 2020, and $41 per Bbl during July 2020.

As previously described in “Risk Factors” under Item 1A of our 2019 annual report on Form 10-K filed with the SEC on February 27, 2020, oil prices are the most important determinant of our operational and financial success. The reduction in our cash flows from operations since early March 2020, and the possibility of a continued reduction in cash flows for an indeterminant period of time, impairs our ability to develop our properties to support our oil production and pay oilfield operating expenses. Secondarily, this level of reduced cash flow may require us to shut-in uneconomic production.

Our ability to use our net operating loss carryforwards (“NOLs”) and tax credits may be limited. The Bankruptcy Court has entered an order that is designed to protect our NOLs.

As of June 30, 2020, we had tax-effected U.S. federal NOLs of $28.4 million, which carryforward indefinitely, enhanced oil recovery tax credits of $64.4 million that begin to expire in 2024, and research and development credits of $21.6 million that begin to expire in 2031, if not limited by triggering events prior to such time. Under the provisions of the Internal Revenue Code (“IRC”), changes in our ownership, in certain circumstances, will limit the amount of U.S. federal NOLs and tax credits that can be utilized annually in the future to offset taxable income. In particular, Sections 382 and 383 of the IRC impose limitations on a company’s ability to use NOLs and tax credits upon certain changes in such ownership. Calculations pursuant to Sections 382 and 383 of the IRC can be very complicated and no assurance can be given that upon further analysis, our ability to take advantage of our NOLs or tax credits may be limited to a greater extent than we currently anticipate. If we are limited in our ability to use our NOLs or tax credits in future years in which we have taxable income, we will pay more taxes than if we were able to utilize our NOLs and tax credits fully. We may experience ownership changes in the future as a result of subsequent shifts in our stock ownership that we cannot ~~meet the “price criteria” for continued listing~~predict or control that could result in further limitations being placed on our ability to utilize our federal NOLs and tax credits.

Trading in our common stock on the NYSE has been suspended, and our stock is currently traded on the ~~NYSE may delist~~OTC Pink Open Marketplace, which involves additional risks compared to being listed on a national securities exchange.

Trading in our common stock ~~which could have an adverse impact~~was suspended indefinitely on the ~~trading volume, liquidity and market price of~~NYSE on July 31, 2020. We will not be able to re-list our common stock oron a national securities exchange during the ~~trading prices~~pendency of ~~our 6⅜% Convertible Senior Notes due 2024.~~

~~If we do not maintain an average closing price of $1.00 or more for~~the Chapter 11 Restructuring, although our common stock ~~over any consecutive 30 trading-day period,~~has been trading on the NYSE may delist our common stock for a failure to maintain compliance with the NYSE price criteria listing standards. As of August 8, 2019, the average closing price of our common stock over the immediately preceding 30 consecutive trading-day period was $1.14, although on August 8, 2019 the closing priceOTC Pink Open Marketplace. The trading of our common stock on the NYSE was $1.08 per share. Despite NYSE rules and processes that provide a period of time to cure non-compliance with this NYSE standard (during which time the issuer’s common stock generally continues to be traded on the NYSE), there is no assurance that trading prices of our common stock or other steps we take would be successful in assuring our long-term listing on the NYSE. A delisting of our common stock fromOTC Pink Open Marketplace rather than the NYSE ~~would likely reduce~~may negatively impact the ~~liquidity and market~~trading price of our common stock ~~(along with~~and the ~~trading prices~~levels of liquidity available to our ~~6⅜% Convertible Senior Notes~~stockholders. Securities traded in the over-the-counter markets generally have significantly less liquidity than securities traded on a national securities exchange due ~~2024), reduce~~to factors such as the reduced number of investors ~~willing to hold or acquire~~that will consider investing in the securities, the reduced number of market makers in the securities, and the reduced number of securities analysts that follow such securities. As a result, holders of shares of our common stock may find it difficult to resell their shares at prices quoted in the market or at all. Furthermore, because of the limited market and ~~negatively impact~~generally low volume of trading in our ~~ability~~common stock that could occur, the share price of our common stock could be more likely to ~~raise equity financing.~~be affected by broad market fluctuations, general market conditions, fluctuations in our operating results, changes in the market’s perception of our business, and announcements made by us or third parties with interests in the Chapter 11 Restructuring.

Because our common stock trades on the OTC Pink Open Marketplace, in some cases, we may be subject to additional compliance requirements under applicable state laws in the issuance of our securities. The lack of liquidity in our common stock may also make it difficult for us to issue additional securities for financing or other purposes, or to otherwise arrange for any

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financing we may need in the future. Accordingly, we urge that extreme caution be exercised with respect to existing and future investments in our common stock.

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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

~~Issuer Purchases of Equity Securities~~None.

~~The following table summarizes purchases of our common stock during the~~ ~~second quarter~~ of ~~2019~~:

Month
Total Number of Shares Purchased⁽¹⁾
Average Price Paid per Share
Total Number of
Shares Purchased
as Part of Publicly
Announced Plans or Programs

Approximate Dollar
Value of Shares
that May Yet Be
Purchased Under the Plans or Programs
(in millions)⁽²⁾
April 2019 782
$ 2.29
—
$ 210.1
May 2019 533
1.60
—
210.1
June 2019 346
1.24
—
210.1
Total 1,661

—


~~(1)~~	~~Shares purchased during the second quarter of~~ ~~2019~~ ~~were made in connection with the surrender of shares by our employees to satisfy their tax withholding requirements related to the vesting of restricted and performance shares.~~

~~(2)~~

In October 2011, we commenced a common share repurchase program, which has been approved for up to an aggregate of $1.162 billion of Denbury common shares by the Company’s Board of Directors. This program has effectively been suspended and we do not anticipate repurchasing shares of our common stock in the near future. The program has no pre-established ending date and may be suspended or discontinued at any time. We are not obligated to repurchase any dollar amount or specific number of shares of our common stock under the program.

Item 3. Defaults Upon Senior Securities

~~None.~~See Part I, Item 1. Notes to the Condensed Consolidated Financial Statements – Note 1,Basis of Presentation – Entry into Restructuring Support Agreement and Voluntary Reorganization under Chapter 11 of the Bankruptcy Code and Industry Conditions, Liquidity, and Management’s Plans,and Going Concern, and Note 4,Long-Term Debt, which are incorporated in this item by reference.

Item 4. Mine Safety Disclosures

None.

Item 5. Other Information

None.

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Item 6. Exhibits



Exhibit No.		Exhibit
33(a)		~~Certificate of Amendment and~~ Second Restated Certificate of Incorporation of Denbury Resources Inc., filed with the Delaware Secretary of State on ~~May 22, 2019~~October 30, 2014 (incorporated by reference to Exhibit 3(a) of Form 10-Q filed by the Company on November 7, 2014, File No. 001-12935).
3(b)		Third Amended and Restated Bylaws of Denbury Resources Inc., as of March 26, 2020 (incorporated by reference to Exhibit 3.1 of Form 8-K filed by the Company on ~~May 28, 2019)~~March 31, 2020, File No. 001-12935).
4(a)*		Second Supplemental Indenture for 9% Senior Secured Second Lien Notes due 2021, dated as of ~~June 19, 2019,~~July 27, 2018, by and among ~~the Company, the Subsidiary Guarantors named therein,~~Denbury Resources Inc., certain of its subsidiaries, and Wilmington Trust, National Association, as Trustee and Collateral ~~Trustee, with respect to $528,026,000 aggregate principal amount of 7¾~~Trustee.
4(b)*		First Supplemental Indenture for 9¼% Senior Secured Second Lien Notes due ~~2024 (incorporated by reference to Exhibit 4.1 of Form 8-K filed by the Company on June 24, 2019).~~
~~4(b)~~		~~Form of Global Note representing the 7¾% Senior Secured Second Lien Notes due 2024 (incorporated by reference to Exhibit 4.2 of Form 8-K filed by the Company on June 24, 2019).~~
~~4(c)~~		~~Indenture,~~2022, dated as of ~~June 19, 2019,~~July 27, 2018, by and among ~~the Company, the Subsidiary Guarantors named therein,~~Denbury Resources Inc., certain of its subsidiaries, and Wilmington Trust, National Association, as Trustee ~~with respect to $245,548,000 aggregate principal amount of 6⅜% Convertible Senior Notes due 2024 (incorporated by reference to Exhibit 4.3 of Form 8-K filed by the Company on June 24, 2019).~~and Collateral Trustee.
~~4(d)~~4(c)*		~~Form of Global Note representing the~~Third Supplemental Indenture for 6⅜% ~~Convertible~~ Senior Subordinated Notes due ~~2024 (incorporated~~2021, dated as of July 27, 2018, by ~~reference to Exhibit 4.4~~and among Denbury Resources Inc., certain of ~~Form 8-K filed~~its subsidiaries, and Wilmington Trust, National Association, as Trustee.
4(d)*		Third Supplemental Indenture for 5½% Senior Subordinated Notes due 2022, dated as of July 27, 2018, by ~~the Company on June 24, 2019).~~and among Denbury Resources Inc., certain of its subsidiaries, and Wilmington Trust, National Association, as Trustee.
4(e)*		Third Supplemental Indenture for 4⅝% Senior Subordinated Notes due 2023, dated as of July 27, 2018, by and among Denbury Resources Inc., certain of its subsidiaries, and Wilmington Trust, National Association, as Trustee.
10(a)		~~Collateral Trust Joinder, dated~~Denbury Resources Inc. 2004 Omnibus Stock and Incentive Plan, as amended and restated effective as of ~~June 19, 2019, by and between Wilmington Trust, National Association, as Trustee, and Wilmington Trust, National Association, as Collateral Trustee~~March 26, 2020 (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on June ~~24, 2019)~~3, 2020, File No. 001-12935).
10(b)		~~Priority Confirmation Joinder,~~Eighth Amendment to Amended and Restated Credit Agreement, dated as of June ~~19, 2019,~~26, 2020, by and ~~between~~among Denbury Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as ~~Priority Lien~~Administrative Agent, and ~~Wilmington Trust, National Association, as Collateral Trustee~~the financial institutions party thereto (incorporated by reference to Exhibit ~~10.2 on~~10.1 of Form 8-K filed by the Company on June ~~24, 2019)~~30, 2020, File No. 001-12935).
10(c)		Restructuring Support Agreement, dated July 28, 2020 (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on July 29, 2020, File No. 001-12935).
10(d)		Exit Commitment Letter, dated July 28, 2020 (incorporated by reference to Exhibit 10.2 of Form 8-K filed by the Company on July 29, 2020, File No. 001-12935).
10(e)		Senior Secured Super Priority Debtor-in-Possession Credit Agreement, dated as of August 4, 2020, by and among Denbury Resources Inc., the subsidiary guarantors party thereto, the lenders party thereto and JPMorgan Chase Bank, N.A. (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on August 6, 2020, File No. 001-12935).
10(f)		Final Order (I) Approving Notification and Hearing Procedures for Certain Transfers of and Declarations of Worthlessness with Respect to Common Stock, and (II) Granting Related Relief [Docket No. 62] (incorporated by reference to Exhibit 4.1 of Form 8-K filed by the Company on August 6, 2020, File No. 001-12935).

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10(g)*		2020 Form of Incentive Bonus Agreement for Denbury Resources Inc.
31(a)*		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)*		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*		Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101101.INS		~~Interactive Data Files~~ Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH*		Inline XBRL Taxonomy Extension Schema Document
101.CAL*		Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*		Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*		Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE*		Inline XBRL Taxonomy Extension Presentation Linkbase Document
104		The cover page from the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, has been formatted in Inline XBRL.


*	Included herewith.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		DENBURY RESOURCES INC.

August ~~9, 2019~~11, 2020		/s/ Mark C. Allen
		Mark C. Allen Executive Vice President and Chief Financial Officer

August ~~9, 2019~~11, 2020		/s/ Alan Rhoades
		Alan Rhoades Vice President and Chief Accounting Officer

4455



	Operating			Finance
In thousands	Leases			Leases
2019	$	5,063		$	118
2020	9,874			178
2021	10,042			—
2022	10,259			—
2023	10,300			—
Thereafter	18,537			—
Total minimum lease payments	64,075			296
Less: Amount representing interest	(11,945		)	(4		)
Present value of minimum lease payments	$	52,130		$	292



	Fair Value at 6/30/2019 (in thousands)		Valuation Technique	Unobservable Input	Volatility Range
Oil derivative contracts	$	6,073	Discounted cash flow / Black-Scholes	Volatility of Light Louisiana Sweet for settlement periods beginning after June 30, 2019	20.4% – 34.1%



			Principal Exchanged
In thousands	March 31, 2019		(excluding cash)				June 30, 2019
Notes Exchanged
6⅜% Senior Subordinated Notes due 2021	$	203,545	$	(152,241	)		$	51,304
5½% Senior Subordinated Notes due 2022	314,662		(219,878		)		94,784
4⅝% Senior Subordinated Notes due 2023	307,978		(96,283		)		211,695
7½% Senior Secured Second Lien Notes due 2024	450,000		(429,359		)		20,641

New Notes Issued
7¾% Senior Secured Second Lien Notes due 2024	—		531,821				531,821
6⅜% Convertible Senior Notes due 2024	—		245,548				245,548
	$	1,276,185	$	(120,392	)	⁽¹⁾	$	1,155,793



		2H 2019	1H 2020	2H 2020
WTI NYMEX	Volumes Hedged (Bbls/d)	—	2,000	2,000
Fixed-Price Swaps	Swap Price⁽¹⁾	—	$60.59	$60.59
Argus LLS	Volumes Hedged (Bbls/d)	13,000	4,500	4,500
Fixed-Price Swaps	Swap Price⁽¹⁾	$64.69	$62.29	$62.29
WTI NYMEX	Volumes Hedged (Bbls/d)	22,000	12,000	10,000
3-Way Collars	Sold Put Price / Floor / Ceiling Price⁽¹⁾⁽²⁾	$48.55 / $56.55 / $69.17	$48.89 / $58.49 / $65.57	$49.05 / $58.58 / $65.81
Argus LLS	Volumes Hedged (Bbls/d)	5,500	6,000	4,000
3-Way Collars	Sold Put Price / Floor / Ceiling Price⁽¹⁾⁽²⁾	$54.73 / $63.09 / $79.93	$53.42 / $63.19 / $71.16	$53.50 / $63.16 / $72.99
	Total Volumes Hedged (Bbls/d)	40,500	24,500	20,500



Month	Total Number of Shares Purchased⁽¹⁾	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (in millions)⁽²⁾
April 2019	782	$	2.29	—	$	210.1
May 2019	533	1.60		—	210.1
June 2019	346	1.24		—	210.1
Total	1,661			—