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~~March 31, 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	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~~April 30, 2020, was 506,481,777.

EXPLANATORY NOTE

As previously disclosed in the Current Report on Form 8-K filed by Denbury Resources Inc. (the “Company” or “Denbury”) on May 7, 2020, the Company expected that the filing of this Quarterly Report on Form 10-Q for the quarter ended March 31, ~~2019, was 469,661,433.~~2020 (the “Report”), originally due on May 11, 2020, would be delayed due to disruptions caused by the COVID-19 coronavirus (“COVID-19”) pandemic. In particular, the ongoing COVID-19 pandemic’s effect on economic activity across the globe resulted in a rapid and precipitous drop in demand for oil, which in turn has caused oil prices to plummet since the first week of March 2020, negatively affecting the Company’s cash flow, liquidity and financial position. 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. These significant and rapid changes required complex accounting judgments and revisions of estimates upon which the Company’s financial statements are based, which required additional time for compilation, preparation, and review necessary to prepare the Company’s Quarterly Report.

The Company relied on Release No. 34-88465 issued by the Securities and Exchange Commission on March 25, 2020, pursuant to Section 36 of the Securities Exchange Act of 1934, as amended, to delay the filing of this Quarterly Report.

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~~March 31, 2020 and December 31, ~~2018~~2019	34
	Unaudited Condensed Consolidated Statements of Operations for the Three ~~and Six~~ Months Ended ~~June 30,~~March 31, 2020 and 2019 ~~and 2018~~	45
	Unaudited Condensed Consolidated Statements of Cash Flows for the ~~Six~~Three Months Ended ~~June 30,~~March 31, 2020 and 2019 ~~and 2018~~	56
	Unaudited Condensed Consolidated ~~Statement~~Statements of Changes in Stockholders’ Equity for the Three ~~and Six~~ Months Ended ~~June 30,~~March 31, 2020 and 2019 ~~and 2018~~	67
	Notes to Unaudited Condensed Consolidated Financial Statements	78
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	3739
Item 4.	Controls and Procedures	3941

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	4042
Item 1A.	Risk Factors	4142
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4245
Item 3.	Defaults Upon Senior Securities	4245
Item 4.	Mine Safety Disclosures	4245
Item 5.	Other Information	4245
Item 6.	Exhibits	4346
	Signatures	4447

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,			March 31,			December 31,
	2019			2018			2020			2019
Assets
Current assets
Cash and cash equivalents	$	341		$	38,560		$	6,917		$	516
Accrued production receivable	135,697			125,788			72,470			139,407
Trade and other receivables, net	28,469			26,970			41,497			18,318
Derivative assets	24,447			93,080			125,724			11,936
Other current assets	14,989			11,896			10,312			10,434
Total current assets	203,943			296,294			256,920			180,611
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved properties	11,275,255			11,072,209			11,683,339			11,447,680
Unevaluated properties	941,336			996,700			636,656			872,910
CO₂ properties	1,198,657			1,196,795			1,198,902			1,198,846
Pipelines and plants	2,324,265			2,302,817			2,335,198			2,329,078
Other property and equipment	223,666			250,279			217,066			212,334
Less accumulated depletion, depreciation, amortization and impairment	(11,583,497		)	(11,500,190		)	(11,854,989		)	(11,688,020		)
Net property and equipment	4,379,682			4,318,610			4,216,172			4,372,828
Operating lease right-of-use assets	36,421			—			32,886			34,099
Derivative assets	9,488			4,195
Other assets	102,500			104,123			101,113			104,329
Total assets	$	4,732,034		$	4,723,222		$	4,607,091		$	4,691,867
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	180,283		$	198,380		$	106,546		$	183,832
Oil and gas production payable	63,034			61,288			46,921			62,869
Derivative liabilities	1,912			—			—			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 $83,751 and $86,054, respectively – see Note 4)							98,212			102,294
Operating lease liabilities	6,739			—			7,044			6,901
Total current liabilities	353,797			364,793			258,723			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 $59,998 and $78,860, respectively – see Note 4)							2,185,984			2,232,570
Asset retirement obligations	181,491			174,470			173,214			177,108
Derivative liabilities	22			—
Deferred tax liabilities, net	362,303			309,758			406,021			410,230
Operating lease liabilities	45,391			—			40,112			41,932
Other liabilities	52,227			68,213			53,592			53,526
Total long-term liabilities	3,107,561			3,216,652			2,858,923			2,915,366
Commitments and contingencies (Note 7)
Commitments and contingencies (Note 8)
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; 508,415,378 and 508,065,495 shares issued, respectively							508			508
Paid-in capital in excess of par	2,694,184			2,685,211			2,742,303			2,739,099
Accumulated deficit	(1,412,094		)	(1,533,112		)	(1,247,298		)	(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			1,489,445			1,412,259
Total liabilities and stockholders’ equity	$	4,732,034		$	4,723,222		$	4,607,091		$	4,691,867

~~See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.~~

~~Table of Contents~~

~~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,
2019 2018 2019 2018
Revenues and other income
Oil, natural gas, and related product sales $ 330,421
$ 375,565
$ 624,998
$ 715,586
CO₂sales and transportation fees
7,986
6,715
16,556
14,267
Purchased oil sales 2,591
346
2,806
1,403
Other income 2,367
4,437
4,457
9,041
Total revenues and other income 343,365
387,063
648,817
740,297
Expenses

Lease operating expenses 117,932
120,384
243,355
238,740
Transportation and marketing expenses 11,236
10,062
22,009
20,555
CO₂ discovery and operating expenses
581
500
1,137
962
Taxes other than income 25,517
27,234
49,302
54,553
Purchased oil expenses 2,564
289
2,777
1,162
General and administrative expenses 17,506
19,412
36,431
39,644
Interest, net of amounts capitalized of $8,238, $8,851, $18,772 and $17,303, respectively 20,416
16,208
37,814
33,447
Depletion, depreciation, and amortization 58,264
52,944
115,561
105,395
Commodity derivatives expense (income) (24,760 ) 96,199
58,617
145,024
Gain on debt extinguishment (100,346 ) —
(100,346 ) —
Other expenses 2,386
4,178
6,524
7,564
Total expenses 131,296
347,410
473,181
647,046
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

Net income per common share

Basic $ 0.32
$ 0.07
$ 0.27
$ 0.17
Diluted $ 0.32
$ 0.07
$ 0.26
$ 0.15

Weighted average common shares outstanding

Basic 452,612
433,467
452,169
413,217
Diluted 467,427
457,165
461,460
454,466

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

Table of Contents

Denbury Resources Inc.

Unaudited Condensed Consolidated Statements of ~~Cash Flows~~Operations

(In ~~thousands)~~thousands, except per share data)

Six Months Ended June 30,
2019 2018
Cash flows from operating activities

Net income
$ 121,018
$ 69,800
Adjustments to reconcile net income to cash flows from operating activities

Depletion, depreciation, and amortization
115,561
105,395
Deferred income taxes
52,545
25,237
Stock-based compensation
6,865
5,152
Commodity derivatives expense (income)
58,617
145,024
Receipt (payment) on settlements of commodity derivatives
6,657
(88,127 )
Gain on debt extinguishment (100,346 ) —
Debt issuance costs and discounts
2,901
2,268
Other, net
(57 ) (5,107 )
Changes in assets and liabilities, net of effects from acquisitions

Accrued production receivable
(9,909 ) (17,385 )
Trade and other receivables
(271 ) (320 )
Other current and long-term assets
(3,389 ) (5,627 )
Accounts payable and accrued liabilities
(33,320 ) 14,999
Oil and natural gas production payable
1,746
(4,501 )
Other liabilities
(5,618 ) (1,182 )
Net cash provided by operating activities
213,000
245,626

Cash flows from investing activities

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

Cash flows from financing activities

Bank repayments
(281,000 ) (1,153,653 )
Bank borrowings
361,000
1,093,653
Interest payments treated as a reduction of debt (42,558 ) (37,233 )
Cash paid in conjunction with debt exchange (120,007 ) —
Costs of debt financing (9,332 ) —
Pipeline financing and capital lease debt repayments
(7,273 ) (12,625 )
Other
12,899
(628 )
Net cash used in financing activities
(86,271 ) (110,486 )
Net increase (decrease) in cash, cash equivalents, and restricted cash
(32,410 ) 242
Cash, cash equivalents, and restricted cash at beginning of period
54,949
15,992
Cash, cash equivalents, and restricted cash at end of period
$ 22,539
$ 16,234



	Three Months Ended March 31,
	2020			2019
Revenues and other income
Oil, natural gas, and related product sales	$	229,624		$	294,577
CO₂sales and transportation fees	8,028			8,570
Purchased oil sales	3,721			215
Other income	828			2,090
Total revenues and other income	242,201			305,452
Expenses
Lease operating expenses	109,270			125,423
Transportation and marketing expenses	9,621			10,773
CO₂ discovery and operating expenses	752			556
Taxes other than income	19,686			23,785
Purchased oil expenses	3,661			213
General and administrative expenses	9,733			18,925
Interest, net of amounts capitalized of $9,452 and $10,534, respectively	19,946			17,398
Depletion, depreciation, and amortization	96,862			57,297
Commodity derivatives expense (income)	(146,771		)	83,377
Gain on debt extinguishment	(18,994		)	—
Write-down of oil and natural gas properties	72,541			—
Other expenses	2,494			4,138
Total expenses	178,801			341,885
Income (loss) before income taxes	63,400			(36,433		)
Income tax benefit	(10,616		)	(10,759		)
Net income (loss)	$	74,016		$	(25,674	)

Net income (loss) per common share
Basic	$	0.15		$	(0.06	)
Diluted	$	0.14		$	(0.06	)

Weighted average common shares outstanding
Basic	494,259			451,720
Diluted	586,190			451,720

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

Table of Contents

Denbury Resources Inc.

Unaudited Condensed Consolidated Statements of Cash Flows

(In thousands)



	Three Months Ended March 31,
	2020			2019
Cash flows from operating activities
Net income (loss)	$	74,016		$	(25,674	)
Adjustments to reconcile net income (loss) to cash flows from operating activities
Depletion, depreciation, and amortization	96,862			57,297
Write-down of oil and natural gas properties	72,541			—
Deferred income taxes	(4,209		)	(9,478		)
Stock-based compensation	2,453			3,263
Commodity derivatives expense (income)	(146,771		)	83,377
Receipt on settlements of commodity derivatives	24,638			8,206
Gain on debt extinguishment	(18,994		)	—
Debt issuance costs and discounts	4,926			1,263
Other, net	(673		)	908
Changes in assets and liabilities, net of effects from acquisitions
Accrued production receivable	66,937			(21,591		)
Trade and other receivables	(22,914		)	1,024
Other current and long-term assets	2,539			(387		)
Accounts payable and accrued liabilities	(72,607		)	(35,966		)
Oil and natural gas production payable	(15,948		)	4,605
Other liabilities	(954		)	(2,481		)
Net cash provided by operating activities	61,842			64,366

Cash flows from investing activities
Oil and natural gas capital expenditures	(46,016		)	(86,986		)
Pipelines and plants capital expenditures	(6,294		)	(1,682		)
Net proceeds from sales of oil and natural gas properties and equipment	40,543			104
Other	(4,521		)	(3,237		)
Net cash used in investing activities	(16,288		)	(91,801		)

Cash flows from financing activities
Bank repayments	(161,000		)	(103,000		)
Bank borrowings	161,000			103,000
Interest payments treated as a reduction of debt	(18,211		)	—
Cash paid in conjunction with debt repurchases	(14,171		)	—
Pipeline financing and capital lease debt repayments	(3,690		)	(4,108		)
Other	(2,953		)	(1,099		)
Net cash used in financing activities	(39,025		)	(5,207		)
Net increase (decrease) in cash, cash equivalents, and restricted cash	6,529			(32,642		)
Cash, cash equivalents, and restricted cash at beginning of period	33,045			54,949
Cash, cash equivalents, and restricted cash at end of period	$	39,574		$	22,307

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


	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	—	—		3,303		—			—	—			3,303			—	—		4,306		—			—	—			4,306
Tax withholding – stock compensation	—	—		—		—			330,826	(828		)	(828		)	—	—		—		—			531,494	(1,091		)	(1,091		)
Net income	—	—		—		39,578			—	—			39,578
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
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

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., 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~~,March 31, 2020, our consolidated results of operations for the three ~~and six~~ months ended~~June 30,~~ March 31, 2020 and 2019, ~~and~~ ~~2018~~, our consolidated cash flows for the ~~six~~three months ended ~~June 30,~~March 31, 2020 and 2019, ~~and~~ ~~2018~~, and our consolidated statements of changes in stockholders’ equity for the three ~~and six~~ months ended ~~June 30,~~March 31, 2020 and 2019.

Risks and Uncertainties

In March 2020, the World Health Organization declared the ongoing 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. Although OPEC+ has subsequently reached an agreement to curtail production, it is estimated that the near-term impact on global oil demand is significantly greater than the magnitude of production curtailments, and storage centers in the United States and around the world could potentially reach maximum storage levels. Together, these events have caused oil prices to plummet since the first week of March 2020, which has continued, and is expected to significantly decrease our realized oil prices in the second quarter of 2020 and potentially beyond.

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. 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. The extent of the impact on our operational and financial performance is dependent upon future developments that drive domestic and global oil supply and demand, including the duration and spread of the pandemic, its severity, the actions to contain the disease or mitigate its impact, related restrictions on travel, and future levels of domestic and global oil production.

Industry Conditions, Liquidity, Management’s Plans, and Going Concern

As discussed above, COVID-19 has had a significant impact on oil prices, which directly impacts our business in many ways. The decrease in oil prices directly impacts the operating cash flow we are able to generate from our production, and if prices are too low, it may not be economic for us to produce certain of our properties. The decrease in oil prices may also impact our other sources of liquidity, potentially reducing our borrowing capacity under our bank credit facility. Our primary sources of capital and liquidity are our cash flows from operations and availability of borrowing capacity under our bank credit facility. As of May 13, 2020, our bank credit facility availability was $520.3 million, based on a $615 million borrowing base and $94.7 million of

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

letters of credit currently outstanding. Our most significant cash outlays relate to our development capital expenditures, current period operating expenses, and our debt service obligations.

Our senior secured bank credit facility and the indentures related to our senior secured second lien notes, senior convertible notes, and senior subordinated notes are subject to a variety of covenants. Throughout 2019 and ~~2018.~~the three months ended March 31, 2020, we were in compliance with all covenants under our senior secured bank credit facility, including maintenance financial covenants, as well as covenants within our long-term note indentures. However, declining industry conditions and reductions in our cash flows and liquidity over the past few months have made our ability to comply with the maximum permitted ratio of total net debt to consolidated EBITDAX maintenance financial covenant in our senior secured bank credit facility increasingly unlikely if these conditions continue, and we foresee the potential to be in violation of this covenant by the end of the second or third quarter of this year.

Our senior secured bank credit facility matures on December 9, 2021, provided that the maturity date may be accelerated to earlier dates in 2021 (February 12, 2021, May 14, 2021 or August 13, 2021) if certain defined liquidity ratios are not met, or if our 9% Senior Secured Second Lien Notes due May 15, 2021 (the “2021 Senior Secured Notes”) or our 6⅜% Senior Subordinated Notes due in August 2021 (the “2021 Senior Subordinated Notes”) are not repaid or refinanced by each of their respective maturity dates. Our maintenance financial covenants contained in our senior secured bank credit facility are described in Note 4, Long-Term Debt.

In this low oil price environment and period of uncertainty, 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 continuing to focus on reducing our operating and overhead costs, and (3) by restructuring certain of our three-way collars covering 14,500 barrels per day 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. As the ability to fund our full 2020 development capital budget with cash flow from operations and asset sale proceeds is dependent in part upon future commodity pricing, which we cannot predict nor control, we expect to fund any potential shortfall with incremental borrowings under our senior secured bank credit facility. There can be no assurances that we will be able to fund any potential shortfall with borrowings under our senior secured bank credit facility.

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,~~March 31, 2019, “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, current assets, total assets, current liabilities, total liabilities or stockholders’ equity.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Cash, Cash Equivalents, and Restricted Cash

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		March 31, 2020		December 31, 2019
Cash and cash equivalents	$	341	$	38,560	$	6,917	$	516
Restricted cash included in other assets	22,198		16,389		32,657		32,529
Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows	$	22,539	$	54,949	$	39,574	$	33,045

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.

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~~Notes to Unaudited Condensed Consolidated Financial Statements~~

Our prior-year quarterly report on Form 10-Q for the period ended 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.

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
	June 30,				June 30,				March 31,
In thousands	2019		2018		2019		2018		2020		2019
Numerator
Net income – basic	$	146,692	$	30,222	$	121,018	$	69,800
Net income (loss) – basic									$	74,016	$	(25,674	)
Effect of potentially dilutive securities
Interest on convertible senior notes including amortization of discount, net of tax	548		130		548		539		5,857		—
Net income – diluted	$	147,240	$	30,352	$	121,566	$	70,339
Net income (loss) – diluted									$	79,873	$	(25,674	)

Denominator
Weighted average common shares outstanding – basic	452,612		433,467		452,169		413,217		494,259		451,720
Effect of potentially dilutive securities
Restricted stock and performance-based equity awards	2,835		8,586		3,301		6,877		1,078		—
Convertible senior notes⁽¹⁾	11,980		15,112		5,990		34,372		90,853		—
Weighted average common shares outstanding – diluted	467,427		457,165		461,460		454,466		586,190		451,720

(1)

For the three ~~and six~~ months ended ~~June 30, 2019,~~March 31, 2020, shares shown under “convertible senior notes” represent the ~~prorated portion~~impact over the period 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,~~March 31, 2020, 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

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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.~~

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~~Denbury Resources Inc.~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

2020 period.

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
	June 30,		June 30,		March 31,
In thousands	2019	2018	2019	2018	2020	2019
Stock appreciation rights	2,026	2,827	2,059	2,891	1,528	2,091
Restricted stock and performance-based equity awards	4,998	179	4,790	305	14,007	8,350

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 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, as well as the uncertainty of future oil prices from demand destruction caused by the pandemic, we 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 $72.5 million during the three months ended March 31, 2020, with first-day-of-the-month prices for the preceding 12 months averaging $55.17 per Bbl for crude oil and $1.68 per MMBtu for natural gas, after adjustments for market differentials by field. If oil prices were to remain at or near early-May 2020 levels in subsequent periods, we currently expect that we would also record significant write-downs in subsequent quarters, 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.

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 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).

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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.

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

Reference Rate Reform. In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848) (“ASU 2020-04”). ASU 2020-04 provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions to ease financial reporting burdens related to the expected market transition from the London Interbank Offered Rate (“LIBOR”) or another reference rate to alternative reference rates. The amendments in this ASU are effective beginning on March 12, 2020, and an entity may elect to apply the amendments prospectively through December 31, 2022. We are currently evaluating the impact this guidance may have on our consolidated financial statements and related footnote disclosures.

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. The sale had an effective date of January 1, 2019. We did not record a gain or loss on the sale of the properties in accordance with the full cost method of accounting.

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Denbury Resources Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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 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~~$72.5 million and ~~$125.8~~$139.4 million as of ~~June 30, 2019~~March 31, 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~~March 31, 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
	March 31,
In thousands	2020		2019
Oil sales	$	228,577	$	291,965
Natural gas sales	1,047		2,612
CO₂ sales and transportation fees	8,028		8,570
Purchased oil sales	3,721		215
Total revenues	$	241,373	$	303,362

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~~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

1213

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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,			March 31,			December 31,
In thousands	2019			2018			2020			2019
Senior Secured Bank Credit Agreement	$	80,000		$	—		$	—		$	—
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			—			245,548			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			163,748			167,439
Capital lease obligations	292			5,362
Total debt principal balance	2,480,892			2,532,207			2,247,825			2,281,726
Debt discount⁽¹⁾	(109,072		)	—			(97,873		)	(101,767		)
Future interest payable⁽²⁾	207,659			250,218			143,749			164,914
Debt issuance costs	(11,523		)	(13,089		)	(9,505		)	(10,009		)
Total debt, net of debt issuance costs and discount	2,567,956			2,769,336			2,284,196			2,334,864
Less: current maturities of long-term debt⁽³⁾	(101,829		)	(105,125		)	(98,212		)	(102,294		)
Long-term debt and capital lease obligations	$	2,466,127		$	2,664,211
Long-term debt							$	2,185,984		$	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~~$25.7 million and ~~$79.6~~$72.2 million, respectively, ~~(see~~ ~~2019 Note Exchanges~~ ~~below)~~ as of ~~June 30, 2019.~~

March 31, 2020.


(2)	Future interest payable represents most of the interest due over the terms of our 9%2021 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~~March 31, 2020 include ~~$85.7~~$83.8 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.

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

In December 2014, we entered into an Amended and Restated 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. 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~~be accelerated to earlier ~~(between February~~dates in 2021 ~~and~~(February 12, 2021, May 14, 2021 or August 13, 2021) if certain defined liquidity ratios are not met, or if the 2021 Senior Secured Notes due in May 2021 or ~~6⅜%~~2021 Senior Subordinated Notes due in August 2021 ~~respectively,~~ are not repaid or refinanced by each of their respective maturity dates. The borrowing base under the Bank Credit Agreement is evaluated semi-annually, generally around May 1 and November 1. As ~~part~~ of ~~our~~May 13, 2020, the bank group has not yet completed the process for the spring ~~2019 semiannual~~ redetermination, and therefore the borrowing base and ~~lender commitments for our Bank Credit Agreement were reaffirmed~~commitment levels currently remain at $615 ~~million, with~~million. The Company currently anticipates that the bank group will complete the redetermination process over the next ~~such redetermination being scheduled for November 2019.~~several weeks, and it is currently uncertain if there will be any change to the borrowing base or banks’ commitment levels. 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~~We incur a commitment fee of 0.50% on ~~borrowings~~the undrawn portion of the aggregate lender commitments under the Bank Credit Agreement.

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Notes to Unaudited Condensed Consolidated Financial Statements

~~under the Bank Credit Agreement was 5.1% as of June 30, 2019. We incur a commitment fee of 0.50% on the undrawn portion of the aggregate lender commitments under the Bank Credit Agreement.~~

The Bank Credit Agreement contains 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.

For purposes of computing the current ratio per the Bank Credit Agreement, Consolidated Current Assets exclude the current portion of derivative assets but include borrowing base availability 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.

As of ~~June 30, 2019,~~March 31, 2020, we were in compliance with all debt covenants under the Bank Credit Agreement. However, declining industry conditions and reductions in our cash flows and liquidity over the past few months have made our ability to comply with the maximum permitted ratio of total net debt to consolidated EBITDAX maintenance financial covenant in our senior secured bank credit facility increasingly unlikely if these conditions continue, and we foresee the potential to be in violation of this covenant by the end of the second or third quarter of this year. 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~~2020 Repurchases of Senior Secured Notes

During ~~June 2019,~~March 2020, 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~~repurchased a total of ~~$468.4~~$30.2 million in aggregate principal amount of our ~~then existing senior subordinated notes for $102.6 million aggregate principal amount of new 7¾%~~2021 Senior Secured Notes ~~$245.5~~in open-market transactions for a total purchase price of $14.2 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.excluding accrued interest. 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 July 2019, we closed~~connection with these 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.~~

~~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~~$19.0 million 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~~unamortized 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~~and future 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, 2020, we may redeem the 7¾% Senior Secured Notes in whole or in part at a price equal to 100% 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 of the notes exchanges discussed above, in June 2019 we issued $245.5 million of 2024 Convertible Senior Notes in connection with exchanges with certain holders of the Company’s existing senior subordinated notes (see ~~2019 Note Exchanges~~ ~~above). The 2024 Convertible Senior Notes, which carry a stated interest rate of 6.375% per annum, were recorded at approximately 67% 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 into shares of our common stock at any time, at the option of the holders, at a rate of 370 shares of common stock per $1,000 principal amount of 2024 Convertible Senior Notes, which is equivalent to up to approximately 90.9 million shares of the Company’s common stock, subject to customary adjustments to the conversion rate and threshold price with respect to, among other things, stock dividends and distributions, mergers 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, the Company may, based on a determination of its Board of Directors that such changes are in the best interests of the Company, and subject to certain limitations, increase the conversion rate. Any such conversion rate increase would cause a proportional decrease in the threshold price for mandatory conversions, and thereby would enable the Company to require a mandatory conversion into common stock at a lower price than the initial or then-prevailing threshold price.written off.

Note 5. Income Taxes

On March 27, 2020, Congress enacted the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) to provide certain taxpayer relief as a result of the 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.

Note 5.6. 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

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Notes to Unaudited Condensed Consolidated Financial Statements

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,~~March 31, 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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~~Notes to Unaudited Condensed Consolidated Financial Statements~~

The following table summarizes our commodity derivative contracts as of ~~June 30, 2019~~March 31, 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
Apr – Dec																		NYMEX	13,500	$	36.25	–	61.00	$	40.52	$	—	$	—	$	—
Apr – Dec																		Argus LLS	7,500		35.00	–	64.26	51.67		—		—		—
2020 Three-Way Collars⁽²⁾																	2020 Three-Way Collars⁽²⁾
Apr – June																		NYMEX	11,500	$	55.00	–	82.65	$	—	$	47.95	$	57.18	$	63.44
Apr – June																		Argus LLS	7,000		58.00	–	87.10	—		52.93		62.09		69.54
July – Dec		NYMEX	22,000	$	55.00	–	75.45	$	—	$	48.55	$	56.55		$	69.17		NYMEX	9,500		55.00	–	82.65	—		47.93		57.00		63.25
July – Dec		Argus LLS	5,500		62.00	–	86.00	—		54.73		63.09			79.93			Argus LLS	5,000		58.00	–	87.10	—		52.80		61.63		70.35
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⁾
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
July – Dec		Argus LLS	2,500		64.00	–	87.10	—		54.40		64.40		��	76.59


(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.

Note 6.7. 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:

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Notes to Unaudited Condensed Consolidated Financial Statements

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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~~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

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
March 31, 2020
Assets
Oil derivative contracts – current	$	—	$	19,927		$	4,520	$	24,447		$	—	$	125,724		$	—		$	125,724
Oil derivative contracts – long-term	—		7,935			1,553		9,488
Total Assets											$	—	$	125,724		$	—		$	125,724

December 31, 2019
Assets
Oil derivative contracts – current											$	—	$	8,503		$	3,433		$	11,936
Total Assets	$	—	$	27,862		$	6,073	$	33,935		$	—	$	8,503		$	3,433		$	11,936

Liabilities
Oil derivative contracts – current	$	—	$	(1,912	)	$	—	$	(1,912	)	$	—	$	(6,522	)	$	(1,824	)	$	(8,346	)
Oil derivative contracts – long-term	—		(22		)	—		(22		)
Total Liabilities	$	—	$	(1,934	)	$	—	$	(1,934	)	$	—	$	(6,522	)	$	(1,824	)	$	(8,346	)

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

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~~March 31, 2020 and ~~2018:~~2019:


	Three Months Ended						Six Months Ended						Three Months Ended
	June 30,						June 30,						March 31,
In thousands	2019			2018			2019			2018			2020			2019
Fair value of Level 3 instruments, beginning of period	$	3,686		$	—		$	13,624		$	—		$	1,609		$	13,624
Fair value gains (losses) on commodity derivatives	2,720			(1,168		)	(6,360		)	(1,168		)
Transfers out of Level 3													(1,609		)	—
Fair value losses on commodity derivatives													—			(9,047		)
Receipts on settlements of commodity derivatives	(333		)	—			(1,191		)	—			��			(891		)
Fair value of Level 3 instruments, end of period	$	6,073		$	(1,168	)	$	6,073		$	(1,168	)	$	—		$	3,686

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	)
The amount of total losses for the period included in earnings attributable to the change in unrealized losses relating to assets or liabilities still held at the reporting date													$	—		$	(6,481	)

~~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~~March 31, 2020 and December 31, ~~2018~~2019, excluding pipeline financing ~~and capital lease~~ obligations, was $~~1,935.6~~490.4 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 7.8. Commitments and Contingencies

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

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Notes to Unaudited Condensed Consolidated Financial Statements

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 is currently expected to be completed in late May or early June, after which oral arguments are anticipated to be scheduled and heard prior to the Wyoming Supreme Court entering its judgment on the appeal. The ~~Company intends~~timing and outcome of this appeal process is currently unpredictable, but at this time is anticipated to ~~continue~~extend over the next six to ~~vigorously defend its position and pursue all of its rights.~~nine months.

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~~$5.7 million of associated costs (through ~~June 30, 2019)~~March 31, 2020), for a total of ~~$50.2~~$51.7 million, included in “Other liabilities” in our Unaudited Condensed Consolidated Balance Sheets as of ~~June 30, 2019.~~March 31, 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. Subsequent Event~~9. Additional Balance Sheet Details

~~On July 17, 2019, the Compensation Committee of our Board of Directors made our annual grant of long-term incentive awards, consisting of 9,115,746 shares of restricted stock~~Trade and ~~3,759,051 restricted stock units which are to be settled solely in cash, to certain employees under our 2004 Omnibus Stock~~Other Receivables, Net



	March 31,		December 31,
In thousands	2020		2019
Commodity derivative settlement receivables	$	15,396	$	675
Trade accounts receivable, net	13,504		12,630
Federal income tax receivable, net	11,054		2,987
Other receivables	1,543		2,026
Total	$	41,497	$	18,318

Accounts Payable 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 stock price floor of $2.25 per share 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 value of the restricted stock units. The awards generally vest one-third per year over a three-year period.Accrued Liabilities



	March 31,		December 31,
In thousands	2020		2019
Accounts payable	$	26,134	$	29,077
Accrued lease operating expenses	21,141		26,686
Accrued interest	16,176		25,253
Taxes payable	10,461		21,274
Accrued compensation	7,187		36,366
Accrued exploration and development costs	4,671		7,811
Other	20,776		37,365
Total	$	106,546	$	183,832

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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,~~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
	March 31, 2020		December 31, 2019		March 31, 2019
Average net realized prices
Oil price per Bbl - excluding impact of derivative settlements	$	45.96	$	56.58	$	56.50
Oil price per Bbl - including impact of derivative settlements	50.92		58.30		58.09

Recent Developments in Response to Oil Price Declines. In January and February 2020, NYMEX oil prices averaged in the mid-$50s per Bbl ~~during~~range before a precipitous decline in early March 2020 due to the ~~first half~~combination of ~~2019, compared to $66.29 per Bbl during~~OPEC supply pressures and a reduction in worldwide oil demand amid the ~~first half of 2018. Including the impact of derivative settlements, our average realized~~COVID-19 coronavirus (“COVID-19”) pandemic, resulting in NYMEX oil ~~price was $60.03 per Bbl during the first half of 2019, compared to $58.07~~prices averaging approximately $30 per Bbl in March. NYMEX oil prices continued to decline in April 2020 to an average of $17 per Bbl in response to uncertainty about the ~~first half~~duration of ~~2018. With~~the COVID-19 pandemic and storage constraints in the United States resulting from over-supply of produced oil, which are also expected to significantly decrease our ~~continued focus on improving the Company’s financial position and preserving liquidity, we have based our 2019 budget on a flat $50~~realized oil ~~price, and our 2019 capital spending has been budgeted~~prices 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~~.

~~Operating Highlights.~~ ~~We recognized net income of $146.7 million, or $0.32 per diluted common share, during~~ the second quarter of ~~2019, compared~~2020 and potentially longer. In response to ~~net income of $30.2 million, or $0.07 per diluted common share, during~~these developments, we have implemented the ~~second quarter of 2018. The primary drivers of these comparative period changes in our operating results were the following:~~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).~~


•	~~Oil and natural gas revenues in the second quarter of 2019 decreased by~~ ~~$45.1 million, or~~ ~~12%, principally driven by a~~ 9% ~~decrease in realized oil prices.~~tertiary flood development project beyond 2020;

Implemented cost reduction measures including shutting down compressors or delaying well repairs and workovers that are uneconomic and by reducing performance-based compensation for employees; and

~~We generated $148.6 million~~Restructured approximately 50% of ~~cash flow from operating activities~~our three-way collars covering 14,500 barrels per day (“Bbls/d”) into fixed-price swaps for the second quarter through fourth quarters of 2020 in order to increase downside protection. Our current hedge portfolio covers 39,500 Bbls/d for the second quarter of ~~2019, relatively unchanged from the $154.0 million generated during~~2020 and 35,500 Bbls/d for the second ~~quarter~~half of ~~2018, but $84.2 million higher than~~2020, with over half of those contracts consisting of fixed-price swaps and the ~~$64.4 million~~remainder consisting of ~~cash flow generated in the first quarter of 2019.~~three-way collars.

~~2019 Note Exchanges.~~ ~~During June 2019, we closed~~As a ~~series of debt exchanges to extend the maturities of our outstanding long-term debt and reduce our debt principal. As part~~result of these ~~transactions,~~measures and due to continued uncertainty with respect to (1) future oil prices, (2) the duration, spread and severity of the COVID-19 pandemic in future periods, along with the impact of mitigation steps taken in response to the pandemic, (3) limitations in storage and/or takeaway capacity, or (4) the potential for voluntary or regulatory production curtailment actions, we ~~exchanged a total~~have currently suspended our previously provided production and financial guidance for 2020, other than budgeted levels 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 exchangeddevelopment capital.

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Denbury Resources Inc.

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

~~subordinated notes consisted~~Comparative Financial Results and Highlights. We recognized net income of ~~$152.2~~$74.0 million, or $0.14 per diluted common share, during the first quarter of 2020, compared to a net loss of $25.7 million, or $0.06 per diluted common share, during the first quarter of 2019. The primary drivers of our change in operating results and per diluted share amounts were the following:

Oil and natural gas revenues decreased by $65.0 million (22%), with 18% of the decrease due to lower commodity prices and 4% of the decrease due to lower production, offset in part by an improvement in derivative commodity settlements of $16.4 million from the prior-year period;

Commodity derivatives expense improved by $230.1 million ($83.4 million of expense during the first quarter of 2019 compared to $146.8 million of income during the first quarter of 2020), resulting from a $213.7 million gain on noncash fair value changes and $16.4 million increase in cash receipts upon settlement between the first quarters of 2019 and 2020;


•	A $72.5 million full cost pool ceiling test write-down as a result of the impairment and transfer of $244.9 million of unevaluated costs to the full cost amortization base as a result of the decline in NYMEX oil prices, along with a $37.4 million accelerated depreciation charge related to impaired unevaluated properties (see Results of Operations – Depletion, Depreciation, and Amortization);


•	A noncash gain on debt extinguishment of $19.0 million in the first quarter of 2020 (see 2020 Repurchases of Senior Secured Notes below); and

Reductions across numerous expense categories, the most significant being $16.2 million in lease operating expenses, $9.2 million in general and administrative expenses, and $4.1 million in taxes other than income.

2020 Repurchases of Senior Secured Notes. During March 2020, we repurchased a total of $30.2 million in 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, as part of creating a more liquid series of secured second lien debt due in 2024, we also exchanged $425.4 million of 7½%9% Senior Secured Second Lien Notes due ~~2024~~2021 (the ~~“7½%~~“2021 Senior Secured ~~Notes”)~~Notes) in open-market transactions for ~~$425.4~~a total purchase price of $14.2 million, ~~aggregate principal amount of 7¾% Senior Secured Notes.~~

excluding accrued interest. In ~~July 2019, we closed~~connection with these 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 ~~noncash~~$19.0 million gain on debt extinguishment, net of ~~transaction~~unamortized debt issuance costs ~~totaling $100.3 million for the three~~ and ~~six months ended June 30, 2019, in our Unaudited Condensed Consolidated Statements of Operations.~~future interest payable written off.

~~Separately, the exchange~~Sale 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. Based on the combined debt discount of $109.4 million recordedWorking Interests 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% Senior Secured Notes and 2024 Convertible Senior Notes (see ~~Results of Operations~~ – ~~Interest and Financing Expenses~~ ~~for further discussion).~~

~~July 2019 Citronelle Field Divestiture.~~Certain Texas Fields. On ~~July 1, 2019,~~March 4, 2020, we closed the farm-down transaction for the sale of ~~one~~half of our ~~mature Gulf~~nearly 100% working interest portion 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 ~~fields, Citronelle Field, which contributed 406 BOE/d to total Company production during the second quarter of 2019, for $10 million.~~Working Interests Sale”). The sale had an effective date of ~~May~~January 1, 2019.

CAPITAL RESOURCES AND LIQUIDITY

~~Exploitation Drilling Update.~~Overview. ~~During~~Our primary sources of capital and liquidity are our cash flow from operations and availability of borrowing capacity under our senior secured bank credit facility, which has been supplemented most recently by the working interests sale in March 2020 and periodically by asset sale proceeds associated with 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.

For the three months ended March 31, 2020, we generated cash flow from operations of $61.8 million, while incurring capital expenditures of $38.8 million and capitalized interest of $9.5 million, resulting in approximately $35 million of cash flow in excess of capital expenditures (excluding $42.9 million of working capital changes, but including $21.4 million of interest payments treated as a repayment of debt in our financial statements).

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 and considerably lower during the month of April 2020. This decrease in the market prices for our production directly reduce our operating cash flow and indirectly impact 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 continuing to focus on reducing our operating and overhead costs, and (3) by restructuring certain of our three-way collars covering 14,500 Bbls/d into fixed-price swaps for the second ~~quarter~~through fourth quarters of ~~2019, we tested our first horizontal well at Conroe Field, which achieved a high~~2020 to increase downside protection against current and potential further declines in oil cut and a peak production rate over 200 BOE/d. We currently plan to drill an additional well in 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 investmentprices.

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Denbury Resources Inc.

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

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,~~Although we have ~~been actively marketing for sale surface land with~~ no ~~active oil and gas operations around~~significant maturities of debt in 2020, 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 millionsignificant maturities 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.~~include $584.7 million of 2021 Senior Secured Notes maturing on May 15, 2021 and $455.7 million of 9¼% Senior Secured Second Lien Notes due 2022 maturing on March 31, 2022 (the “2022 Senior Secured Notes”).

Senior Secured Bank Credit Facility. In December 2014, we entered into an Amended and Restated 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. 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~~be accelerated to earlier ~~(between February~~dates in 2021 ~~and August 2021)~~if certain defined liquidity ratios are not met, or if the 9%2021 Senior Secured ~~Second Lien~~ Notes due in May 2021 ~~(the “2021 Senior Secured Notes”)~~ or 6⅜% Senior Subordinated Notes due in August 2021 ~~respectively,~~(the “2021 Senior Subordinated Notes”) are not repaid or refinanced by each of their respective maturity ~~dates.~~ dates, as follows:

To February 12, 2021, if on that date the sum of the of the Company’s cash, cash equivalents and borrowing availability under the senior secured bank credit facility is less than 120% of the amount of the then outstanding 2021 Senior Secured Notes;

To May 14, 2021, if either (a) prior to that date the 2021 Senior Secured Notes have not been repaid or otherwise redeemed in full, or (b) on that date the sum of the Company’s cash, cash equivalents and borrowing availability under the senior secured bank credit facility is less than 120% of the amount of the then outstanding 2021 Senior Subordinated Notes; or

To August 13, 2021, if prior to that date the 2021 Senior Subordinated Notes have not been repaid or otherwise redeemed in full.

As ~~part~~ of March 31, 2020, we had no outstanding borrowings on our ~~spring~~$615 million senior secured bank credit facility, consistent with December 31, 2019, ~~semiannual~~leaving us with $520.3 million of borrowing base availability after consideration of $94.7 million of letters of credit currently outstanding. The borrowing base under the Bank Credit Agreement is evaluated semi-annually, generally around May 1 and November 1. As of May 15, 2020, the bank group has not yet completed the process for the spring redetermination, and therefore the borrowing base and ~~lender commitments for our Bank Credit Agreement were reaffirmed~~commitment levels currently remain at $615 ~~million, with~~million. The Company currently anticipates that the bank group will complete the redetermination process over the next ~~such redetermination scheduled for November 2019.~~several weeks, and it is currently uncertain if there will be any change to the borrowing base or banks’ commitment levels. The Bank Credit Agreement contains certain financial performance covenants through the maturity of the facility, including the following:

~~Table of Contents~~

~~Denbury Resources Inc.~~

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

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.

As of March 31, 2020, we were in compliance with all debt covenants under the Bank Credit Agreement. Under these financial performance covenant calculations, as of ~~June 30, 2019,~~March 31, 2020, our ratio of consolidated total debt to consolidated EBITDAX was ~~4.14~~3.88 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~~0.00 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~~3.04 to 1.0 (with a required ratio of not less than 1.25 to 1.0), and our current ratio was ~~2.64~~4.11 to 1.0 (with a required ratio of not less than 1.0 to 1.0). ~~Based upon~~However, declining industry conditions and reductions in our ~~currently forecasted levels~~cash flows and liquidity over the past few months have made our ability to comply with the maximum permitted ratio of ~~production~~total net debt to consolidated EBITDAX maintenance financial covenant in our senior secured bank credit facility increasingly unlikely if these conditions continue, and ~~costs, hedges in place as of August 6, 2019, and current oil commodity futures prices,~~ we ~~currently anticipate continuing~~foresee the potential to be in ~~compliance with our financial performance covenants during~~violation of this covenant by the ~~foreseeable future.~~end of the second or third quarter of this year.

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.

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Denbury Resources Inc.

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

Going Concern. Our senior secured bank credit facility and the indentures related to our senior secured second lien notes, senior convertible notes, and senior subordinated notes are subject to a variety of covenants. Throughout 2019 ~~Note Exchanges.~~ ~~Through a series~~and the three months ended March 31, 2020, we were in compliance with all covenants under our senior secured bank credit facility, including maintenance financial covenants, as well as covenants within our long-term note indentures. However, declining industry conditions and reductions in our cash flows and liquidity over the past few months have made our ability to comply with the maximum permitted ratio of ~~exchange transactions completed~~total net debt to consolidated EBITDAX maintenance financial covenant in our senior secured bank credit facility increasingly unlikely if these conditions continue, and we foresee the potential to be in violation of this covenant by the end of the second or third quarter of this year.

In this low oil price environment and period of uncertainty, 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 continuing to focus on ~~June 19, 2019 (see~~ ~~Overview~~ – ~~2019 Note Exchanges~~ ~~above),~~reducing our operating and overhead costs, and (3) 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. As the ability to fund our full 2020 development capital budget with cash flow from operations and asset sale proceeds is dependent in part upon future commodity pricing, which we ~~reduced~~cannot predict nor control, we expect to fund any potential shortfall with incremental borrowings under our ~~debt~~senior secured bank credit facility. There can be no assurances that we will be able to fund any potential shortfall with borrowings under our senior secured bank credit facility.

Collectively, the above factors, along with the materially adverse change in industry market conditions and our cash flow over the past few months, have substantially diminished our ability to repay, refinance, or restructure our $584.7 million outstanding 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~~have raised substantial doubt about our ability to ~~extending maturities~~continue as a going concern. Because the actions described above are not sufficient to significantly mitigate the substantial doubt about our ability to continue as a going concern over the next twelve months from the issuance of these financial statements, we have engaged advisors to assist with the evaluation of a ~~portion~~range of strategic alternatives and are engaged in discussions with our lenders and bondholders regarding a potential comprehensive restructuring of our ~~existing debt,~~indebtedness. There can be no assurances that the ~~exchange transactions could contribute~~Company will be able to ~~debt reduction~~successfully restructure its indebtedness, improve its financial position or complete any strategic transaction. The condensed consolidated financial statements included in this Quarterly Report on Form 10-Q have been prepared on a going concern basis of ~~$245.5 million~~accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The condensed consolidated financial statements do not reflect any adjustments that might result if ~~all of the 2024 Convertible Senior Notes convert~~we are unable 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).~~continue as a going concern.

Capital Spending. We currently anticipate that our full-year ~~2019~~2020 capital spending, excluding capitalized interest and acquisitions, will be approximately ~~$240~~$95 million to ~~$260~~$105 million. ~~Although we currently have no plans~~This 2020 capital expenditure amount of between $95 million to ~~adjust our anticipated capital spending for 2019, we continually evaluate our expected cash flows~~$105 million, which was revised on March 31, 2020, excluding capitalized interest and ~~capital expenditures throughout~~acquisitions, is an $80 million, or 44%, reduction from the ~~year and could adjust capital expenditures if our cash flows were to meaningfully change. Capitalized interest is currently estimated at~~late-February 2020 estimate of between ~~$30~~$175 million and ~~$40~~$185 million ~~for 2019.~~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, and continuing uncertainty about their combined economic impact, especially on oil demand and prices. Although OPEC+ has subsequently reached an agreement to curtail production, it is estimated that the near-term impact on global oil demand is significantly greater than the magnitude of production curtailments, and storage centers in the United States and around the world could potentially reach maximum storage levels. 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 ~~2019~~2020 capital budget, excluding capitalized interest and acquisitions, provides for approximate spending as follows:

$~~100~~35 million allocated for tertiary oil field expenditures;

$7025 million allocated for other areas, primarily non-tertiary oil field expenditures including exploitation;


•	$3010 million to be spent on CO₂ sources and pipelines; and

$5030 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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Denbury Resources Inc.

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

Capital Expenditure Summary. The following table reflects incurred capital expenditures (including accrued capital) for the ~~six~~three months ended ~~June 30, 2019~~March 31, 2020 and ~~2018:~~2019:


	Six Months Ended				Three Months Ended
	June 30,				March 31,
In thousands	2019		2018		2020		2019
Capital expenditure summary
Tertiary oil fields	$	54,786	$	64,086	$	14,726	$	26,028
Non-tertiary fields	36,554		32,739		10,954		21,674
Capitalized internal costs⁽¹⁾	24,214		22,747		8,881		11,890
Oil and natural gas capital expenditures	115,554		119,572		34,561		59,592
CO₂ pipelines, sources and other	22,465		9,648		4,224		1,571
Capital expenditures, before acquisitions and capitalized interest	138,019		129,220		38,785		61,163
Acquisitions of oil and natural gas properties	97		21		42		29
Capital expenditures, before capitalized interest	138,116		129,241		38,827		61,192
Capitalized interest	18,772		17,303		9,452		10,534
Capital expenditures, total	$	156,888	$	146,544	$	48,279	$	71,726


(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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Denbury Resources Inc.

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

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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Denbury Resources Inc.

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

Operating Results Table

Certain of our operating results and statistics for the comparative three ~~and six~~ months ended ~~June 30, 2019~~March 31, 2020 and ~~2018~~2019 are included in the following table:


	Three Months Ended						Six Months Ended						Three Months Ended
	June 30,						June 30,						March 31,
In thousands, except per-share and unit data	2019			2018			2019			2018			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⁾													$	74,016		$	(25,674	)
Net income (loss) per common share – basic⁽¹⁾													0.15			(0.06		)
Net income (loss) per common share – diluted⁽¹⁾													0.14			(0.06		)
Net cash provided by operating activities	148,634			153,999			213,000			245,626			61,842			64,366
Average daily production volumes
Bbls/d	58,034			60,109			57,726			59,236			54,649			57,414
Mcf/d	10,111			11,314			10,467			11,607			7,899			10,827
BOE/d⁽¹⁾⁽²⁾	59,719			61,994			59,470			61,171			55,965			59,218
Operating revenues
Oil sales	$	328,571		$	373,286		$	620,536		$	710,692		$	228,577		$	291,965
Natural gas sales	1,850			2,279			4,462			4,894			1,047			2,612
Total oil and natural gas sales	$	330,421		$	375,565		$	624,998		$	715,586		$	229,624		$	294,577
Commodity derivative contracts⁽²⁾⁽³⁾
Receipt (payment) on settlements of commodity derivatives	$	(1,549	)	$	(54,770	)	$	6,657		$	(88,127	)
Receipt on settlements of commodity derivatives													$	24,638		$	8,206
Noncash fair value gains (losses) on commodity derivatives⁽³⁾⁽⁴⁾	26,309			(41,429		)	(65,274		)	(56,897		)	122,133			(91,583		)
Commodity derivatives income (expense)	$	24,760		$	(96,199	)	$	(58,617	)	$	(145,024	)	$	146,771		$	(83,377	)
Unit prices – excluding impact of derivative settlements
Oil price per Bbl	$	62.22		$	68.24		$	59.39		$	66.29		$	45.96		$	56.50
Natural gas price per Mcf	2.01			2.21			2.35			2.33			1.46			2.68
Unit prices – including impact of derivative settlements⁽²⁾⁽³⁾
Oil price per Bbl	$	61.92		$	58.23		$	60.03		$	58.07		$	50.92		$	58.09
Natural gas price per Mcf	2.01			2.21			2.35			2.33			1.46			2.68
Oil and natural gas operating expenses
Lease operating expenses	$	117,932		$	120,384		$	243,355		$	238,740		$	109,270		$	125,423
Transportation and marketing expenses	11,236			10,062			22,009			20,555			9,621			10,773
Production and ad valorem taxes	23,526			25,363			45,560			50,395			17,987			22,034
Oil and natural gas operating revenues and expenses per BOE
Oil and natural gas revenues	$	60.80		$	66.57		$	58.06		$	64.63		$	45.09		$	55.27
Lease operating expenses	21.70			21.34			22.61			21.56			21.46			23.53
Transportation and marketing expenses	2.07			1.78			2.04			1.86			1.89			2.02
Production and ad valorem taxes	4.33			4.50			4.23			4.55			3.53			4.13
CO₂ sources – revenues and expenses
CO₂ sales and transportation fees	$	7,986		$	6,715		$	16,556		$	14,267		$	8,028		$	8,570
CO₂ discovery and operating expenses	(581		)	(500		)	(1,137		)	(962		)	(752		)	(556		)
CO₂ revenue and expenses, net	$	7,405		$	6,215		$	15,419		$	13,305		$	7,276		$	8,014


(1)	Includes a pre-tax full cost pool ceiling test write-down of our oil and natural gas properties of $72.5 million for the three months ended March 31, 2020.


(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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Denbury Resources Inc.

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


(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 ~~payments~~receipts on settlements of ~~$1.5~~$24.6 million and $8.2 million for the three months ended ~~June 30,~~March 31, 2020 and 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. 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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Denbury Resources Inc.

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~~quarter 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
Operating Area	2018	2018	2018	2018	2019	2019	2019	2019	2019	2019	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
Hastings	5,704	5,716	5,486	5,480	5,539	5,466	5,539	5,466	5,513	5,097	5,232
Heidelberg	4,445	4,330	4,376	4,269	3,987	4,082	3,987	4,082	4,297	4,409	4,371
Oyster Bayou	5,056	4,961	4,578	4,785	4,740	4,394	4,740	4,394	3,995	4,261	3,999
Tinsley	6,053	5,755	5,294	5,033	4,659	4,891	4,659	4,891	4,541	4,343	4,355
West Yellow Creek	57	142	240	375	436	586	436	586	728	807	775
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
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
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
Salt Creek	2,002	2,049	2,274	2,107	2,057	2,078	2,057	2,078	2,213	2,223	2,149
Other	—	—	6	20	52	41
Grieve							52	41	58	60	50
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
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
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
Texas	4,386	4,947	4,533	4,319	4,345	4,243	3,298	3,224	3,165	3,212	3,419
Other	44	—	5	6	10	6	10	6	6	5	6
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
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
Other	1,485	1,490	1,409	1,343	1,313	1,305	1,313	1,305	1,238	1,192	1,105
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
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
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
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


(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~~first quarter of ~~2019~~2020 averaged ~~59,313~~55,185 BOE/d, including ~~38,423~~36,861 Bbls/d ~~or 65%,~~ from tertiary properties and ~~20,890~~18,324 BOE/d from non-tertiary properties. Total continuing production excludes production ~~from Citronelle Field sold~~related to the Gulf Coast Working Interests Sale completed in ~~July 2019~~early March 2020 and, for prior-year periods, excludes production from ~~Lockhart Crossing Field sold in the third~~Citronelle

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Denbury Resources Inc.

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

~~quarter of 2018.~~Field sold in July 2019. This total continuing production level represents ~~an increase~~a decrease of ~~551~~1,156 BOE/d ~~(1%~~(2%) compared to total continuing production levels in the fourth quarter of 2019 and a decrease of 2,530 BOE/d (4%) compared to first quarter of 2019 ~~primarily due~~continuing production. The sequential and year-over-year decreases were most significantly attributable to ~~continued response from Bell Creek’s phase 5 development and a decrease of 1,846 BOE/d (3%) compared to second quarter of 2018 continuing~~ production ~~levels primarily due to lower production from Tinsley Field and Cedar Creek Anticline, with the decline~~declines at Cedar Creek Anticline, ~~due in part to timing of drilling new exploitation wells.~~partially offset by production increases from Bell Creek Field’s phase 5 development. Our production during the three ~~and six~~ months ended ~~June 30, 2019~~March 31, 2020 was ~~97%~~98% oil, ~~consistent with~~slightly higher than our 97% oil production during the prior-year ~~periods.~~period.

As a result of the significant decline in oil prices, we have focused our efforts to optimize cash flow through evaluating production economics and shutting in production where validated. Beginning in late March and accelerating through April 2020, we estimate that approximately 2,000 BOE/d of uneconomic production was shut-in during April as a result of those efforts. In May 2020, we continued evaluations around expected oil prices and production costs, and have shut-in additional production, bringing the total shut-in production to approximately 8,500 BOE/d. We ~~currently~~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. As a result of these actions, along with reduced capital and workover spend, we expect ~~our third~~production to decline from the first quarter ~~2019 production will be lower than~~to 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~~quarter. Production could be further curtailed by future regulatory actions or limitations in ~~the Gulf Coast region, and the July 1, 2019 sale of Citronelle Field.~~storage and/or takeaway capacity.

Oil and Natural Gas Revenues

Our oil and natural gas revenues during the three ~~and six~~ months ended ~~June 30, 2019~~March 31, 2020 decreased ~~12% and 13%, respectively,~~22% compared to these revenues for the same ~~periods~~period 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
	March 31,
	2020 vs. 2019
In thousands	Decrease in Revenues			Percentage Decrease in Revenues
Change in oil and natural gas revenues due to:
Decrease in production	$	(13,090	)	(4	)%
Decrease in realized commodity prices	(51,863		)	(18	)%
Total decrease in oil and natural gas revenues	$	(64,953	)	(22	)%

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Denbury Resources Inc.

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

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:



	Three Months Ended
	March 31,
	2020			2019
Average net realized prices
Oil price per Bbl	$	45.96		$	56.50
Natural gas price per Mcf	1.46			2.68
Price per BOE	45.09			55.27
Average NYMEX differentials
Gulf Coast region
Oil per Bbl	$	1.18		$	4.26
Natural gas per Mcf	(0.06		)	(0.10		)
Rocky Mountain region
Oil per Bbl	$	(2.78	)	$	(2.56	)
Natural gas per Mcf	(0.91		)	(0.28		)
Total Company
Oil per Bbl	$	(0.38	)	$	1.63
Natural gas per Mcf	(0.41		)	(0.20		)

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~~$1.18 per Bbl and ~~a positive $1.12 per Bbl during the second quarters of 2019 and 2018, respectively, and a positive~~ $4.26 per Bbl during the first quarters of 2020 and 2019, respectively, and a positive $0.90 per Bbl during the fourth quarter of 2019. 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~~weakened over the past year, although ~~recent~~ Gulf Coast region differentials ~~have somewhat softened.~~slightly increased between the fourth quarter of 2019 and first quarter of 2020.

•

Rocky Mountain Region. NYMEX oil differentials in the Rocky Mountain region averaged ~~$1.48~~$2.78 per Bbl ~~and $0.84 per Bbl below NYMEX during the second quarters of 2019 and~~ ~~2018, respectively,~~ and $2.56 per Bbl below NYMEX during the first quarters of 2020 and 2019, respectively, and $2.48 per Bbl below NYMEX during the fourth quarter of 2019. 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.

The discussion above does not 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, all of which currently are expected to significantly decrease our realized oil prices in the second quarter of 2020 and potentially longer. 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 15% to 20% 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 fees” with the corresponding costs recognized as “CO₂ discovery and operating expenses” in our Unaudited Condensed Consolidated Statements of Operations.

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Denbury Resources Inc.

Management’s Discussion and Analysis of Financial Condition and Results 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~~March 31, 2020 and ~~2018~~2019:


	Three Months Ended						Six Months Ended						Three Months Ended
	June 30,						June 30,						March 31,
In thousands	2019			2018			2019			2018			2020		2019
Receipt (payment) on settlements of commodity derivatives	$	(1,549	)	$	(54,770	)	$	6,657		$	(88,127	)
Receipt on settlements of commodity derivatives													$	24,638	$	8,206
Noncash fair value gains (losses) on commodity derivatives⁽¹⁾	26,309			(41,429		)	(65,274		)	(56,897		)	122,133		(91,583		)
Total income (expense)	$	24,760		$	(96,199	)	$	(58,617	)	$	(145,024	)	$	146,771	$	(83,377	)


(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 5,6, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements for additional details of our outstanding commodity derivative contracts as of ~~June 30, 2019,~~March 31, 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:~~May 14, 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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~~Management’s Discussion and Analysis of Financial Condition and Results of Operations~~



		2Q 2020	2H 2020
WTI NYMEX	Volumes Hedged (Bbls/d)	13,500	13,500
Fixed-Price Swaps	Swap Price⁽¹⁾	$40.52	$40.52
Argus LLS	Volumes Hedged (Bbls/d)	7,500	7,500
Fixed-Price Swaps	Swap Price⁽¹⁾	$51.67	$51.67
WTI NYMEX	Volumes Hedged (Bbls/d)	11,500	9,500
3-Way Collars	Sold Put Price / Floor / Ceiling Price⁽¹⁾⁽²⁾	$47.95 / $57.18 / $63.44	$47.93 / $57.00 / $63.25
Argus LLS	Volumes Hedged (Bbls/d)	7,000	5,000
3-Way Collars	Sold Put Price / Floor / Ceiling Price⁽¹⁾⁽²⁾	$52.93 / $62.09 / $69.54	$52.80 / $61.63 / $70.35
	Total Volumes Hedged (Bbls/d)	39,500	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.

Based on current contracts in place and NYMEX oil futures prices as of ~~August 6, 2019,~~May 14, 2020, which averaged approximately ~~$53~~$29 per Bbl, we currently expect that we would receive cash payments of approximately ~~$30~~$135 million ~~during the remainder of 2019~~ upon settlement of our April through December 2020 contracts. Of this estimated amount, the ~~2019 contracts, the~~majority relates to our fixed-price swaps, which settlement amount ~~of which~~ is 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~~$40.52 per Bbl and $51.67 per Bbl for NYMEX and LLS hedges, respectively. Settlements with respect

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to our 2020 three-way collars are currently limited to the extent oil prices remain below the price of our sold puts. The weighted average ~~ceiling~~differences between the floor and sold put prices of our ~~2019~~2020 three-way collars ~~of $69.17~~are $9.13 per Bbl and ~~$79.93~~$8.97 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
	June 30,				June 30,				March 31,
In thousands, except per-BOE data	2019		2018		2019		2018		2020		2019
Total lease operating expenses	$	117,932	$	120,384	$	243,355	$	238,740	$	109,270	$	125,423

Total lease operating expenses per BOE	$	21.70	$	21.34	$	22.61	$	21.56	$	21.46	$	23.53

Total lease operating expenses decreased ~~$2.5~~$16.2 million ~~(2%~~(13%) on an absolute-dollar basis, ~~but~~or ~~increase~~d $~~0.36~~2.07 ~~(2%~~(9%) on a per-BOE basis, during the three months ended ~~June 30, 2019,~~March 31, 2020, compared to the same prior-year period. The decrease on an absolute-dollar basis was primarily due to lower ~~power and fuel costs and lower~~expenses across nearly all expense categories, with the largest decreases in workover expense, CO₂ purchase expense, ~~due to a decrease in oil prices~~ 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 2018 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~~₂~~expense 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. Compared to the ~~first~~fourth quarter of 2019, lease operating expenses ~~in the second quarter of 2019~~ decreased ~~$7.5~~$6.7 million (6%) on an absolute-dollar basis ~~or $1.83 (8%~~primarily due to lower company and contract labor, but decreased $0.47 (2%) on a per-BOE basis ~~primarily~~ due to lower COproduction in the first quarter of 2020₂ ~~expense due to lower utilization of industrial-sourced CO~~₂ ~~in our Gulf Coast region and lower power and fuel costs.~~.

Currently, our CO₂ expense comprises approximately 20% 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~~first quarters of 2020 and 2019, approximately 52% 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~~$0.36 per Mcf during the ~~second~~first 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~~first quarter of ~~2019~~2020 was lower than the ~~$0.44~~$0.39 per Mcf comparable measure during the ~~second~~first quarter of ~~2018~~2019 ~~and $0.39~~due to a decrease in the costs of industrial-sourced CO₂ in the Rocky Mountain region, but higher than the $0.34 per Mcf comparable measure during the ~~first~~fourth quarter of 2019 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.

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~~$9.6 million and ~~$10.1~~$10.8 million for the three months ended March 31, 2020 and 2019, respectively.

Taxes Other Than Income

Taxes other than income includes production, ad valorem and franchise taxes. Taxes other than income decreased $4.1 million (17%) during the three months ended March 31, 2020, compared to the same prior-year period, 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
	June 30,						June 30,						March 31,
In thousands, except per-BOE data and employees	2019			2018			2019			2018			2020			2019
Gross cash compensation and administrative costs	$	53,919		$	57,484		$	108,620		$	114,522		$	40,436		$	54,701
Gross stock-based compensation	4,669			3,227			8,975			6,529			3,204			4,306
Operator labor and overhead recovery charges	(30,740		)	(32,187		)	(60,615		)	(63,324		)	(27,485		)	(29,875		)
Capitalized exploration and development costs	(10,342		)	(9,112		)	(20,549		)	(18,083		)	(6,422		)	(10,207		)
Net G&A expense	$	17,506		$	19,412		$	36,431		$	39,644		$	9,733		$	18,925

G&A per BOE
Net cash administrative costs	$	2.56		$	2.99		$	2.74		$	3.11		$	1.43		$	2.94
Net stock-based compensation	0.66			0.45			0.64			0.47			0.48			0.61
Net G&A expenses	$	3.22		$	3.44		$	3.38		$	3.58		$	1.91		$	3.55

Employees as of June 30	846			880
Employees as of March 31													718			843

Our net G&A expenses on an absolute-dollar basis decreased ~~$1.9~~$9.2 million ~~(10%) and $3.2 million (8%~~(49%), or ~~$0.22 (6%) and $0.20 (6%~~$1.64 (46%) on a per-BOE basis, during the three ~~and six~~ months ended ~~June 30, 2019, respectively,~~March 31, 2020 compared to the same ~~periods~~period in ~~2018,~~2019, primarily due to reduced employee headcount resulting from our ~~continued focus on cost reduction efforts~~December 2019 voluntary separation program and ~~reduction~~reductions in performance-based compensation.

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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~~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
	June 30,						June 30,						March 31,
In thousands, except per-BOE data and interest rates	2019			2018			2019			2018			2020			2019
Cash interest⁽¹⁾	$	48,371		$	45,542		$	96,319		$	92,145		$	45,826		$	47,948
Less: interest not reflected as expense for financial reporting purposes⁽¹⁾	(21,355		)	(21,614		)	(42,634		)	(43,663		)	(21,354		)	(21,279		)
Noncash interest expense	1,194			1,131			2,457			2,268			1,031			1,263
Amortization of debt discount⁽²⁾	444			—			444			—			3,895			—
Less: capitalized interest	(8,238		)	(8,851		)	(18,772		)	(17,303		)	(9,452		)	(10,534		)
Interest expense, net	$	20,416		$	16,208		$	37,814		$	33,447		$	19,946		$	17,398
Interest expense, net per BOE	$	3.76		$	2.87		$	3.51		$	3.02		$	3.92		$	3.26
Average debt principal outstanding⁽³⁾	$	2,559,822		$	2,550,450		$	2,550,278		$	2,646,049		$	2,187,615		$	2,540,628
Average cash interest rate⁽⁴⁾	7.6		%	7.1		%	7.6		%	7.0		%	8.4		%	7.5		%

(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 ~~9¼%~~and 2022 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.~~Notes. See below for further discussion.

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(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 due 2024 (the “7¾% Senior Secured Notes”) and ~~2024~~6⅜% Convertible Senior Notes ~~respectively, for~~due 2024 (the “2024 Convertible Senior Notes”) during the three ~~and six~~ months ended ~~June 30, 2019.~~March 31, 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~~March 31, 2020 decreased $2.1 million ~~(6%~~(4%) ~~and $4.2 million (5%), respectively,~~ when compared to the prior-year ~~periods~~period due primarily to ~~an increase~~a decrease in our ~~weighted-average interest rate.~~

~~Capitalized interest was relatively unchanged during~~average debt principal outstanding as a result of the ~~three months ended~~ June ~~30,~~2019 debt exchange transactions and debt repurchases completed in the second half of 2019 and first quarter of 2020. Meanwhile, net interest expense increased ~~$1.5~~$2.5 million ~~(8%~~(15%) ~~during the six months ended June 30, 2019, compared~~due to the ~~same periods~~amortization of the debt discounts related to our 7¾% Senior Secured Notes and 2024 Convertible Senior Notes and a decrease in ~~2018, primarily due to an increase~~capitalized interest as a result of a reduction in the number of projects that qualify for interest capitalization.

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~~$143.7 million as of ~~June 30, 2019.~~March 31, 2020. Therefore, interest expense reflected in our Unaudited Condensed Consolidated Statements of Operations will be approximately ~~$86~~$84 million lower annually than the actual cash interest payments on our 2021 Senior Secured Notes and 2022 Senior Secured Notes.

~~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 the terms of the notes; therefore, future interest expense reflected in our Unaudited Condensed Consolidated Statements of Operations will be higher than the actual cash interest payments on our ~~new~~ 7¾% Senior Secured Notes and ~~new~~ 2024 Convertible Senior Notes by approximately ~~$8 million in 2019,~~ $16 million in 2020, $19 million in 2021, $21 million in 2022, $25 million in 2023 and $21 million in 2024.

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



	Three Months Ended
	March 31,
In thousands, except per-BOE data	2020		2019
Oil and natural gas properties	$	42,569	$	36,835
CO₂ properties, pipelines, plants and other property and equipment	16,925		20,462
Accelerated depreciation charge⁽¹⁾	37,368		—
Total DD&A	$	96,862	$	57,297

DD&A per BOE
Oil and natural gas properties	$	8.36	$	6.91
CO₂properties, pipelines, plants and other property and equipment	3.32		3.84
Accelerated depreciation charge⁽¹⁾	7.34		—
Total DD&A cost per BOE	$	19.02	$	10.75

Write-down of oil and natural gas properties	$	72,541	$	—


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

The increase in our oil and natural gas properties depletion during the three months ended March 31, 2020, when compared to the same period in 2019, was primarily due to a decrease in proved oil and natural gas reserve volumes. In addition, we recorded accelerated depreciation of $37.4 million related to impaired unevaluated properties that were transferred to the full cost pool.

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

Three Months Ended Six Months Ended
June 30, June 30,
In thousands, except per-BOE data 2019 2018 2019 2018
Oil and natural gas properties $ 40,110
$ 33,358
$ 76,945
$ 65,229
CO₂ properties, pipelines, plants and other property and equipment
18,154
19,586
38,616
40,166
Total DD&A $ 58,264
$ 52,944
$ 115,561
$ 105,395

DD&A per BOE

Oil and natural gas properties $ 7.38
$ 5.91
$ 7.15
$ 5.89
CO₂properties, pipelines, plants and other property and equipment
3.34
3.47
3.59
3.63
Total DD&A cost per BOE $ 10.72
$ 9.38
$ 10.74
$ 9.52
Full Cost Pool Ceiling Test

~~The increase in our~~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 ~~properties depletion~~price for each month during a 12-month rolling period prior to the end of a particular reporting period. NYMEX prices decreased precipitously in the first quarter of 2020, ending the period at $20.48 per Bbl, with representative oil and natural gas prices used in estimating our March 31, 2020 reserves averaging $55.17 per Bbl for crude oil and $1.68 per MMBtu for natural gas, after adjustments for market differentials by field. While representative oil prices utilized 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 ~~and six~~ months ended ~~June 30, 2019, when compared~~March 31, 2020. Primarily as a result of adding these additional costs to the ~~same~~amortization base, we recognized a full cost pool ceiling test write-down of $72.5 million during the three months ended March 31, 2020. If oil prices were to remain at or near early-May 2020 levels in subsequent periods, we currently expect that we would also record significant write-downs in ~~2018, was primarily~~subsequent quarters, 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. 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.

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 recent declines in NYMEX oil prices to approximately $20 per Bbl in late March 2020 due to ~~an increase~~OPEC supply pressures and a reduction in ~~depletable~~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).

We perform our long-lived asset impairment test by comparing the net carrying costs ~~resulting from increases in~~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 CO₂costs 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 no impairment was recorded.

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, ~~associated with our~~projected availability and cost of CO₂, projected recovery factors of tertiary reserves ~~base.~~and risk-adjustment factors applied to the cash flows.

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Income Taxes

Three Months Ended Six Months Ended
June 30, June 30,
In thousands, except per-BOE amounts and tax rates 2019 2018 2019 2018
Current income tax expense (benefit) $ 3,354
$ (754 ) $ 2,073
$ (1,786 )
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
Effective tax rate 30.8 % 23.8 % 31.1 % 25.1 %
Total net deferred tax liability $ 362,303

$ 231,761



	Three Months Ended
	March 31,
In thousands, except per-BOE amounts and tax rates	2020			2019
Current income tax benefit	$	(6,407	)	$	(1,281	)
Deferred income tax benefit	(4,209		)	(9,478		)
Total income tax benefit	$	(10,616	)	$	(10,759	)
Average income tax benefit per BOE	$	(2.09	)	$	(2.02	)
Effective tax rate	(16.7		)%	29.5		%
Total net deferred tax liability	$	406,021		$	300,280

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. Our effective tax rate for the three ~~and six~~ months ended ~~June 30, 2019~~March 31, 2020 was ~~higher~~lower than our estimated statutory rate, primarily due to ~~establishment~~the full release of a valuation allowance against a portion of our business interest expense deduction that we ~~estimate will~~previously estimated would be ~~disallowed.~~disallowed, offset by the establishment of a valuation allowance on a portion of our enhanced oil recovery credits that currently are not expected to be utilized. The ~~Tax Cuts~~Coronavirus Aid, Relief, and ~~Jobs~~Economic Security Act ~~(“The~~(the “CARES 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.~~use its 2019 Adjusted Taxable Income in lieu of its 2020 Adjusted Taxable Income. Due to these modifications, we now expect to fully deduct our business interest expense in 2018, 2019 and 2020 and have fully released our previously recorded valuation allowance of $24.5 million during the three months ended March 31, 2020. We evaluated all of our deferred tax assets in consideration of the CARES Act provisions and the book full cost pool ceiling test write-down and accelerated depreciation charge recorded in the financial statements for the period ended March 31, 2020. Based on our evaluation, using information existing as of the balance sheet date, of the near-term ability to utilize the tax benefits associated with our ~~2019 disallowed business interest expense,~~enhanced oil recovery credits (expiring in 2024), we have established a valuation allowance ~~through our annual estimated effective income tax rate~~of $11.0 million for ~~that~~the portion of our ~~business interest expense~~enhanced oil recovery credits that is currently not expected to ~~exceed the allowed limitation under The Act.~~be realized.

The current income tax benefits for the three ~~and six~~ months ended ~~June 30, 2018,~~March 31, 2020 and 2019, represent amounts estimated to be receivable resulting from alternative minimum tax credits and certain state tax obligations.

As of ~~June 30, 2019,~~March 31, 2020, after adjusting our attribute balances due to the CARES Act, we had estimated amounts available for carry forward of ~~$57.8~~$54.2 million of enhanced oil recovery credits related to our tertiary operations, $21.6 million of research and development credits, and ~~$18.1~~$11.1 million of alternative minimum tax credits. The alternative minimum tax credits are ~~fully refundable by 2021 and are~~currently recorded as a receivable on the balance sheet. The enhanced oil recovery credits and research and development credits do not begin to expire until 2024 and 2031, respectively.

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~~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
	June 30,						June 30,						March 31,
Per-BOE data	2019			2018			2019			2018			2020			2019
Oil and natural gas revenues	$	60.80		$	66.57		$	58.06		$	64.63		$	45.09		$	55.27
Receipt (payment) on settlements of commodity derivatives	(0.28		)	(9.71		)	0.62			(7.96		)
Receipt on settlements of commodity derivatives													4.84			1.54
Lease operating expenses	(21.70		)	(21.34		)	(22.61		)	(21.56		)	(21.46		)	(23.53		)
Production and ad valorem taxes	(4.33		)	(4.50		)	(4.23		)	(4.55		)	(3.53		)	(4.13		)
Transportation and marketing expenses	(2.07		)	(1.78		)	(2.04		)	(1.86		)	(1.89		)	(2.02		)
Production netback	32.42			29.24			29.80			28.70			23.05			27.13
CO₂ sales, net of operating and exploration expenses	1.36			1.10			1.43			1.20			1.43			1.51
General and administrative expenses	(3.22		)	(3.44		)	(3.38		)	(3.58		)	(1.91		)	(3.55		)
Interest expense, net	(3.76		)	(2.87		)	(3.51		)	(3.02		)	(3.92		)	(3.26		)
Other	(0.19		)	(0.24		)	0.17			0.15			1.92			0.53
Changes in assets and liabilities relating to operations	0.74			3.51			(4.72		)	(1.27		)	(8.43		)	(10.28		)
Cash flows from operations	27.35			27.30			19.79			22.18			12.14			12.08
DD&A	(10.72		)	(9.38		)	(10.74		)	(9.52		)
DD&A – excluding accelerated depreciation charge													(11.68		)	(10.75		)
DD&A – accelerated depreciation charge⁽¹⁾													(7.34		)	—
Write-down of oil and natural gas properties													(14.24		)	—
Deferred income taxes	(11.41		)	(1.81		)	(4.88		)	(2.28		)	0.83			1.78
Gain on extinguishment of debt	18.46			—			9.32			—			3.73			—
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⁾													23.98			(17.18		)
Other noncash items	(1.53		)	(3.41		)	3.82			1.06			7.11			9.25
Net income	$	26.99		$	5.36		$	11.24		$	6.30
Net income (loss)													$	14.53		$	(4.82	)


(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 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,

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

among other things, 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, the extent and length of the drop in worldwide oil demand due to the COVID-19 coronavirus, 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 comply with the maximum permitted ratio of total net debt to consolidated EBITDAX maintenance financial covenant in our senior secured bank credit facility and the related impact on our ability to continue as a going concern, our ability to refinance our senior debt maturing in 2021 and the related impact on our ability to continue as a going concern, the outcome of any discussions with our lenders and bondholders regarding the terms of a potential restructuring of our indebtedness or recapitalization of the Company and any resulting dilution for our stockholders, 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~~,March 31, 2020, we had ~~$80.0 million~~$2.1 billion of fixed-rate long-term debt outstanding and no outstanding borrowings on our variable-rate senior secured bank credit facility. ~~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 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). 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.~~March 31, 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
Fixed rate debt:
9% Senior Secured Second Lien Notes due 2021	614,919		—		—		—		614,919		605,695		$	584,709	$	—	$	—	$	—	$	584,709	$	172,168
9¼% Senior Secured Second Lien Notes due 2022	—		455,668		—		—		455,668		428,328		—		455,668		—		—		455,668		112,819
7¾% Senior Secured Second Lien Notes due 2024	—		—		—		528,026		528,026		438,262		—		—		—		531,821		531,821		79,029
7½% Senior Secured Second Lien Notes due 2024	—		—		—		24,638		24,638		19,464		—		—		—		20,641		20,641		2,942
6⅜% Convertible Senior Notes due 2024	—		—		—		245,548		245,548		161,273		—		—		—		245,548		245,548		103,118
6⅜% Senior Subordinated Notes due 2021	51,304		—		—		—		51,304		41,685		51,304		—		—		—		51,304		8,053
5½% Senior Subordinated Notes due 2022	—		94,784		—		—		94,784		54,501		—		58,426		—		—		58,426		2,496
4⅝% Senior Subordinated Notes due 2023	—		—		211,695		—		211,695		106,377		—		—		135,960		—		135,960		9,778

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 5,6, Commodity Derivative Contracts, and Note 67, 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,~~March 31, 2020, our commodity derivative contracts were recorded at their fair value, which was a net asset of ~~$32.0~~$125.7 million, a ~~$26.3~~$122.1 million increase from the ~~$5.7 million net asset recorded at March 31, 2019, and a $65.3 million decrease 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,~~March 31, 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~~March 31, 2020.

Commodity Derivative Sensitivity Analysis

Based on NYMEX and LLS crude oil futures prices as of ~~June 30, 2019~~March 31, 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 March 31, 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 March 31, 2020				$	127,641
10% increase in prices	(14,698		)	110,749
10% decrease in prices	109,514			144,518

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~~March 31, 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~~first 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 and regulatory proceedings incidental 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.

~~Environmental Protection Agency Matter Concerning Certain Fields~~

March 31, 2020. The Company ~~previously entered into~~has a ~~series~~$32.8 million letter of ~~tolling agreements with the Environmental Protection Agency (“EPA”), and has been~~credit posted as security 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 violationthis case as part 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.

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appeal process.

Item 1A. Risk Factors

Please refer to Item 1A of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, ~~2018.~~2019. There have been no material changes to our risk factors contained in our Annual Report on Form 10-K for the fiscal year ended December 31, ~~2018~~2019, other than as detailed below.

~~If we cannot meet the “price criteria” for continued listing on the NYSE, the NYSE may delist~~The current outbreak of COVID-19 has adversely impacted our ~~common stock, which could~~business, financial condition, liquidity and results of operations and is likely to have ana continuing adverse impact onfor a significant period of time.

The COVID-19 pandemic has caused a rapid and precipitous drop in demand for oil, which in turn has caused oil prices to plummet since the ~~trading volume,~~first week of March 2020, negatively affecting the Company’s cash flow, liquidity and financial position. These events have worsened an already deteriorated oil market ~~price~~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. Moreover, the uncertainty about the duration of the COVID-19 pandemic has caused storage constraints in the United States resulting from over-supply of produced oil, which is expected to significantly decrease our ~~common stock, or~~realized oil prices in the ~~trading~~second quarter of 2020 and potentially beyond. Oil prices ~~of our 6⅜% Convertible Senior Notes due 2024.~~

~~If we do not maintain an average closing price of $1.00 or more for our common stock over any consecutive 30 trading-day period, the NYSE may delist our common stock for a failure~~are expected 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 price 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 continuescontinue to be ~~traded on~~volatile as a result of these events and the ~~NYSE), there is no assurance that trading~~ongoing COVID-19 outbreak, and as changes in oil inventories, oil demand and economic performance are reported. We cannot predict when oil 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 from the NYSE would likely reduce the liquidity~~will improve and market price of our common stock, (along with the trading prices of our 6⅜% Convertible Senior Notes due 2024), reduce the number of investors willing to hold or acquire our common stock, and negatively impact our ability to raise equity financing.stabilize.

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The current pandemic and uncertainty about its length and depth in future periods has caused the realized oil prices we have received since early March 2020 to be significantly reduced, adversely affecting our operating cash flow and liquidity. Although we have reduced our 2020 capital expenditures budget by 44%, our lower levels of cash flow could affect our borrowing capacity and have required us to shut-in production that has become uneconomic. These conditions have also increased the difficulty in repaying, refinancing or restructuring our long-term debt, which is necessary in order to maintain our continuing financial viability, as separately described in the other risk factors contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019.

The COVID-19 pandemic is rapidly evolving, and the ultimate impact of this pandemic is highly uncertain and subject to change. The extent of the impact of the COVID-19 pandemic on our operational and financial performance will depend on future developments, including the duration and spread of the pandemic, its severity, the actions to contain the disease or mitigate its impact, related restrictions on travel, and the duration, timing and severity of the impact on domestic and global oil demand. The COVID-19 pandemic may also intensify the risks described in the other risk factors disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019.

Oil prices remaining at current levels will significantly reduce our cash flow and liquidity to a degree that threatens our continued financial viability.

Beginning in the first week of March 2020, the simultaneous surplus in world oil market supply (Saudi Arabia oil production hikes following OPEC+ production cut disagreements) and significant reduction in demand (as the scope of the spread, severity and resulting containment efforts of the COVID-19 pandemic became clear) have caused oil prices to plummet. 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 slightly to an average of $24 per Bbl during the first 10 trading days of May 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 make budgeted property development expenditures to support our oil production, pay oilfield operating expenses, and pay interest on our outstanding debt. Secondarily, this level of reduced cash flow may affect our ability to borrow under our senior secured credit facility, could require us to shut-in uneconomic production, or further impair the carrying value of our oil and natural gas reserves.

Moreover, on a long-term basis, it is difficult to predict the impact of the COVID-19 pandemic on the level of future economic activity, which will affect future demand for oil, and consequently, our business.

We have engaged advisers to assist us in, among other things, analyzing various alternatives to address our liquidity and capital structure.

We have engaged advisors to assist us in, among other things, analyzing various alternatives to address our liquidity and capital structure. We may seek to extend our maturities and/or reduce the overall principal amount of our debt through exchange offers, other liability management, recapitalization and/or restructuring transactions. As part of the evaluation of alternatives, we also are engaged in discussions with our lenders and bondholders regarding a potential comprehensive restructuring of our indebtedness. Any comprehensive restructuring of our indebtedness and capital structure may require a substantial impairment or conversion of our indebtedness to equity, as well as impairment, losses or substantial dilution for our stockholders and other stakeholders, which may result in our stockholders receiving minimal, if any, recovery for their existing shares and may place our stockholders at significant risk of losing some or all of their investment.

The outcome of our restructuring discussions and other efforts to address our liquidity and capital structure is uncertain and could adversely affect our business, financial condition and results of operations.

Our potential inability to comply with the financial covenants in our senior secured bank credit facility or to repay, refinance or restructure our notes due in 2021 have raised substantial doubt about our ability to continue as a going concern.

Our senior secured bank credit facility is subject to a variety of covenants. Throughout 2019 and the three months ended March 31, 2020, we were in compliance with all covenants under our senior secured bank credit facility, including maintenance

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financial covenants. However, declining industry conditions and reductions in our cash flows and liquidity over the past few months have made our ability to comply with the maximum permitted ratio of total net debt to consolidated EBITDAX maintenance financial covenant in our senior secured bank credit facility increasingly unlikely if these conditions continue, and we foresee the potential to be in violation of this covenant by the end of the second or third quarter of this year. Additionally, these conditions have substantially diminished our ability to repay, refinance, or restructure our $584.7 million outstanding principal balance of 2021 Senior Secured Notes. Our ability to satisfy the maintenance financial covenants in our senior secured bank credit facility and refinance or repay our 2021 Senior Secured Notes have raised substantial doubt about our ability to continue as a going concern.

An inability to repay, refinance or restructure our 2021 Senior Secured Notes or our inability to comply with the required financial ratios or financial condition tests under our senior secured bank credit facility could result in the acceleration of all such indebtedness and cross-default our other debt. If that should occur, we would likely be unable to pay all such debt or to borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us. If the amounts outstanding under our senior secured bank credit facility or any of our other indebtedness were to be accelerated, our assets may not be sufficient to repay in full the amounts owed to the lenders or to our other debt holders.

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

Issuer Purchases of Equity Securities

The following table summarizes purchases of our common stock during the ~~second~~first quarter of ~~2019~~2020:

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

—



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⁾
January 2020	2,531	$	0.99	—	$	210.1
February 2020	1,553	0.91		—	210.1
March 2020	171,589	0.18		—	210.1
Total	175,673			—


(1)	Shares purchased during the ~~second~~first quarter of ~~2019~~2020 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. The last repurchases under this program took place in October 2015. 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.

Item 4. Mine Safety Disclosures

None.

Item 5. Other Information

None.

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Item 6. Exhibits



Exhibit No.		Exhibit
3		~~Certificate of Amendment~~Third Amended and ~~Second~~ Restated ~~Certificate of Incorporation~~Bylaws of Denbury Resources Inc., ~~filed with the Delaware Secretary~~as of ~~State on May 22, 2019~~March 26, 2020 (incorporated by reference to Exhibit 3.1 of Form 8-K filed by the Company on ~~May 28, 2019).~~
~~4(a)~~		Indenture, dated as of June 19, 2019, among the Company, the Subsidiary Guarantors named therein, and Wilmington Trust, National Association, as Trustee and Collateral Trustee, with respect to $528,026,000 aggregate principal amount of 7¾% 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, dated as of June 19, 2019, among the Company, the Subsidiary Guarantors named therein, 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).
~~4(d)~~		~~Form of Global Note representing the 6⅜% Convertible Senior Notes due 2024 (incorporated by reference to Exhibit 4.4 of Form 8-K filed by the Company on June 24, 2019)~~March 31, 2020, File No. 001-12935).
10(a)*		~~Collateral Trust Joinder, dated as~~2020 Form of ~~June 19, 2019, by~~TSR Performance Award-Cash under the 2004 Omnibus Stock and between Wilmington Trust, National Association, as Trustee, and Wilmington Trust, National Association, as Collateral Trustee (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on June 24, 2019).Incentive Plan for Denbury Resources Inc.
10(b)*		~~Priority Confirmation Joinder, dated as~~2020 Form of ~~June 19, 2019, by~~TSR Performance Award-Equity under the 2004 Omnibus Stock and between JPMorgan Chase Bank, N.A., as Priority Lien Agent, and Wilmington Trust, National Association, as Collateral Trustee (incorporated by reference to Exhibit 10.2 on Form 8-K filed by the Company on June 24, 2019).Incentive Plan 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 March 31, 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~~May 18, 2020		/s/ Mark C. Allen
		Mark C. Allen Executive Vice President and Chief Financial Officer

~~August 9, 2019~~May 18, 2020		/s/ Alan Rhoades
		Alan Rhoades Vice President and Chief Accounting Officer

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	Three Months Ended June 30,					Six Months Ended June 30,
	2019			2018		2019			2018
Revenues and other income
Oil, natural gas, and related product sales	$	330,421		$	375,565	$	624,998		$	715,586
CO₂sales and transportation fees	7,986			6,715		16,556			14,267
Purchased oil sales	2,591			346		2,806			1,403
Other income	2,367			4,437		4,457			9,041
Total revenues and other income	343,365			387,063		648,817			740,297
Expenses
Lease operating expenses	117,932			120,384		243,355			238,740
Transportation and marketing expenses	11,236			10,062		22,009			20,555
CO₂ discovery and operating expenses	581			500		1,137			962
Taxes other than income	25,517			27,234		49,302			54,553
Purchased oil expenses	2,564			289		2,777			1,162
General and administrative expenses	17,506			19,412		36,431			39,644
Interest, net of amounts capitalized of $8,238, $8,851, $18,772 and $17,303, respectively	20,416			16,208		37,814			33,447
Depletion, depreciation, and amortization	58,264			52,944		115,561			105,395
Commodity derivatives expense (income)	(24,760		)	96,199		58,617			145,024
Gain on debt extinguishment	(100,346		)	—		(100,346		)	—
Other expenses	2,386			4,178		6,524			7,564
Total expenses	131,296			347,410		473,181			647,046
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

Net income per common share
Basic	$	0.32		$	0.07	$	0.27		$	0.17
Diluted	$	0.32		$	0.07	$	0.26		$	0.15

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



	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