UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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

For the quarterly period ended June 30, ~~2020~~2021

☐ 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.

(State or other jurisdiction of incorporation or organization)

(I.R.S. Employer Identification No.)


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

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

(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):

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 ☑

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ☑ No ☐

The number of shares outstanding of the registrant’s Common Stock, $.001 par value, as of July 31, ~~2020,~~2021, was ~~507,063,311.~~

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

Denbury ~~Resources~~ Inc.

Table of Contents

Page

~~Page~~

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements

Unaudited Condensed Consolidated Balance Sheets ~~as of~~ ~~June 30, 2020 and December 31, 2019~~

Unaudited Condensed Consolidated Statements of Operations ~~for the~~ ~~Three and Six Months Ended June 30, 2020 and 2019~~

Unaudited Condensed Consolidated Statements of Cash Flows ~~for the~~ ~~Six Months Ended June 30, 2020 and 2019~~

Unaudited Condensed Consolidated Statements of Changes in Stockholders’ Equity ~~for the~~ ~~Three and Six Months Ended June 30, 2020 and 2019~~

Notes to Unaudited Condensed Consolidated Financial Statements

Item 2.

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

2317

Item 3.

Quantitative and Qualitative Disclosures about Market Risk

4433

Item 4.

Controls and Procedures

4635

PART II. OTHER INFORMATION

Unregistered Sales of Equity Securities and Use of Proceeds

5237

Item 3.

Defaults Upon Senior Securities

5237

Item 4.

Mine Safety Disclosures

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,				Successor
		2020			2019				June 30, 2021		December 31, 2020
Assets	Assets							Assets
Current assets								Current assets
Cash and cash equivalents		$	209,276		$	516		Cash and cash equivalents	$	13,565	$	518
Restricted cash								Restricted cash	0		1,000
Accrued production receivable		77,344			139,407			Accrued production receivable	140,302		91,421
Trade and other receivables, net		34,449			18,318			Trade and other receivables, net	24,740		19,682
Derivative assets		47,655			11,936			Derivative assets	0		187
Other current assets		20,724			10,434
Prepaids								Prepaids	12,454		14,038
Total current assets		389,448			180,611			Total current assets	191,061		126,846
Property and equipment								Property and equipment
Oil and natural gas properties (using full cost accounting)								Oil and natural gas properties (using full cost accounting)
Proved properties		11,702,063			11,447,680			Proved properties	949,128		851,208
Unevaluated properties		645,847			872,910			Unevaluated properties	103,088		85,304
CO₂ properties		1,198,981			1,198,846			CO2 properties	188,700		188,288
Pipelines and plants		2,339,761			2,329,078
Pipelines								Pipelines	143,633		133,485
Other property and equipment		216,294			212,334			Other property and equipment	97,699		86,610
Less accumulated depletion, depreciation, amortization and impairment		(12,570,062		)	(11,688,020		)	Less accumulated depletion, depreciation, amortization and impairment	(120,073)		(41,095)
Net property and equipment		3,532,884			4,372,828			Net property and equipment	1,362,175		1,303,800
Operating lease right-of-use assets		32,587			34,099			Operating lease right-of-use assets	19,000		20,342

Intangible assets, net								Intangible assets, net	92,814		97,362
Other assets		103,116			104,329			Other assets	85,044		86,408
Total assets		$	4,058,035		$	4,691,867		Total assets	$	1,750,094	$	1,634,758
Liabilities and Stockholders’ Equity	Liabilities and Stockholders’ Equity							Liabilities and Stockholders’ Equity
Current liabilities								Current liabilities
Accounts payable and accrued liabilities		$	160,694		$	183,832		Accounts payable and accrued liabilities	$	163,905	$	112,671
Oil and gas production payable		40,652			62,869			Oil and gas production payable	69,390		49,165
Derivative liabilities		7,691			8,346			Derivative liabilities	223,212		53,865
Current maturities of long-term debt (including future interest payable of $119,454 and $86,054, respectively – see Note 4)		2,366,330			102,294
Current maturities of long-term debt								Current maturities of long-term debt	34,498		68,008
Operating lease liabilities		7,807			6,901			Operating lease liabilities	2,596		1,350
Total current liabilities		2,583,174			364,242			Total current liabilities	493,601		285,059
Long-term liabilities								Long-term liabilities
Long-term debt, net of current portion (including future interest payable of $0 and $78,860, respectively – see Note 4)		145,922			2,232,570
Long-term debt, net of current portion								Long-term debt, net of current portion	35,000		70,000
Asset retirement obligations		177,030			177,108			Asset retirement obligations	226,615		179,338
Derivative liabilities								Derivative liabilities	22,164		5,087
Deferred tax liabilities, net		306,186			410,230			Deferred tax liabilities, net	1,187		1,274
Operating lease liabilities		38,584			41,932			Operating lease liabilities	18,157		19,460
Other liabilities		2,720			53,526			Other liabilities	26,172		20,872
Total long-term liabilities		670,442			2,915,366			Total long-term liabilities	329,295		296,031
Commitments and contingencies (Note 9)
Commitments and contingencies (Note 8)								Commitments and contingencies (Note 8)	0		0
Stockholders’ equity								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; 509,553,960 and 508,065,495 shares issued, respectively		510			508
Preferred stock, $.001 par value, 50,000,000 shares authorized, none issued and outstanding								Preferred stock, $.001 par value, 50,000,000 shares authorized, none issued and outstanding	0		0
Common stock, $.001 par value, 250,000,000 shares authorized; 50,017,491 and 49,999,999 shares issued, respectively								Common stock, $.001 par value, 250,000,000 shares authorized; 50,017,491 and 49,999,999 shares issued, respectively	50		50
Paid-in capital in excess of par		2,754,749			2,739,099			Paid-in capital in excess of par	1,125,143		1,104,276
Accumulated deficit		(1,944,772		)	(1,321,314		)	Accumulated deficit	(197,995)		(50,658)
Treasury stock, at cost, 1,828,444 and 1,652,771 shares, respectively		(6,068		)	(6,034		)
Total stockholders’ equity		804,419			1,412,259			Total stockholders’ equity	927,198		1,053,668
Total liabilities and stockholders’ equity		$	4,058,035		$	4,691,867		Total liabilities and stockholders’ equity	$	1,750,094	$	1,634,758

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~~per-share data)


	Successor		Predecessor		Successor		Predecessor
	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020

Revenues and other income
Oil, natural gas, and related product sales	$	282,708	$	109,387	$	518,153	$	339,011
CO2 sales and transportation fees	10,134		6,504		19,362		14,532
Oil marketing revenues	7,819		1,490		13,945		5,211
Other income	707		494		1,067		1,322
Total revenues and other income	301,368		117,875		552,527		360,076
Expenses
Lease operating expenses	110,225		81,293		192,195		190,563
Transportation and marketing expenses	8,522		9,388		16,319		19,009
CO2 operating and discovery expenses	1,531		885		2,524		1,637
Taxes other than income	22,382		10,372		41,345		30,058
Oil marketing expenses	7,738		1,450		13,823		5,111
General and administrative expenses	15,450		23,776		47,433		33,509
Interest, net of amounts capitalized of $1,168, $8,729, $2,251 and $18,181, respectively	1,252		20,617		2,788		40,563
Depletion, depreciation, and amortization	36,381		55,414		75,831		152,276
Commodity derivatives expense (income)	172,664		40,130		288,407		(106,641)
Gain on debt extinguishment	0		0		0		(18,994)
Write-down of oil and natural gas properties	0		662,440		14,377		734,981

Other expenses	3,214		11,290		5,360		13,784
Total expenses	379,359		917,055		700,402		1,095,856
Loss before income taxes	(77,991)		(799,180)		(147,875)		(735,780)
Income tax benefit	(296)		(101,706)		(538)		(112,322)
Net loss	$	(77,695)	$	(697,474)	$	(147,337)	$	(623,458)

Net loss per common share
Basic	$	(1.52)	$	(1.41)	$	(2.91)	$	(1.26)
Diluted	$	(1.52)	$	(1.41)	$	(2.91)	$	(1.26)

Weighted average common shares outstanding
Basic	50,999		495,245		50,661		494,752
Diluted	50,999		495,245		50,661		494,752

Three Months Ended June 30, Six Months Ended June 30,
2020 2019 2020 2019
Revenues and other income
Oil, natural gas, and related product sales $ 109,387
$ 330,421
$ 339,011
$ 624,998
CO₂sales and transportation fees
6,504
7,986
14,532
16,556
Purchased oil sales 1,490
2,591
5,211
2,806
Other income 494
2,367
1,322
4,457
Total revenues and other income 117,875
343,365
360,076
648,817
Expenses

Lease operating expenses 81,293
117,932
190,563
243,355
Transportation and marketing expenses 9,388
11,236
19,009
22,009
CO₂ discovery and operating expenses
885
581
1,637
1,137
Taxes other than income 10,372
25,517
30,058
49,302
Purchased oil expenses 1,450
2,564
5,111
2,777
General and administrative expenses 23,776
17,506
33,509
36,431
Interest, net of amounts capitalized of $8,729, $8,238, $18,181 and $18,772, respectively 20,617
20,416
40,563
37,814
Depletion, depreciation, and amortization 55,414
58,264
152,276
115,561
Commodity derivatives expense (income) 40,130
(24,760 ) (106,641 ) 58,617
Gain on debt extinguishment —
(100,346 ) (18,994 ) (100,346 )
Write-down of oil and natural gas properties 662,440
—
734,981
—
Other expenses 11,290
2,386
13,784
6,524
Total expenses 917,055
131,296
1,095,856
473,181
Income (loss) before income taxes (799,180 ) 212,069
(735,780 ) 175,636
Income tax provision (benefit) (101,706 ) 65,377
(112,322 ) 54,618
Net income (loss) $ (697,474 ) $ 146,692
$ (623,458 ) $ 121,018

Net income (loss) per common share

Basic $ (1.41 ) $ 0.32
$ (1.26 ) $ 0.27
Diluted $ (1.41 ) $ 0.32
$ (1.26 ) $ 0.26

Weighted average common shares outstanding

Basic 495,245
452,612
494,752
452,169
Diluted 495,245
467,427
494,752
461,460

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

Table of Contents

Denbury ~~Resources~~ Inc.

Unaudited Condensed Consolidated Statements of Cash Flows

(In thousands)


	Successor		Predecessor
	Six Months Ended June 30, 2021		Six Months Ended June 30, 2020

Cash flows from operating activities
Net loss	$	(147,337)	$	(623,458)
Adjustments to reconcile net loss to cash flows from operating activities

Depletion, depreciation, and amortization	75,831		152,276
Write-down of oil and natural gas properties	14,377		734,981
Deferred income taxes	(87)		(106,513)
Stock-based compensation	20,232		3,540
Commodity derivatives expense (income)	288,407		(106,641)
Receipt (payment) on settlements of commodity derivatives	(101,796)		70,267
Gain on debt extinguishment	0		(18,994)
Debt issuance costs and discounts	1,370		9,921
Other, net	744		(1,642)
Changes in assets and liabilities, net of effects from acquisitions
Accrued production receivable	(48,881)		62,063
Trade and other receivables	(5,578)		(16,162)
Other current and long-term assets	1,294		(4,552)
Accounts payable and accrued liabilities	27,292		(60,295)
Oil and natural gas production payable	20,224		(22,217)
Other liabilities	(2,554)		237
Net cash provided by operating activities	143,538		72,811

Cash flows from investing activities
Oil and natural gas capital expenditures	(53,411)		(79,897)
Acquisitions of oil and natural gas properties	(10,811)		0
Pipelines and plants capital expenditures	(4,851)		(10,962)
Net proceeds from sales of oil and natural gas properties and equipment	18,456		40,971
Other	(4,159)		(105)
Net cash used in investing activities	(54,776)		(49,993)

Cash flows from financing activities
Bank repayments	(485,000)		(226,000)
Bank borrowings	450,000		491,000
Interest payments treated as a reduction of debt	0		(42,506)
Cash paid in conjunction with debt repurchases	0		(14,171)


Pipeline financing and capital lease debt repayments	(33,510)		(7,015)
Other	(2,735)		(9,529)
Net cash provided by (used in) financing activities	(71,245)		191,779
Net increase in cash, cash equivalents, and restricted cash	17,517		214,597
Cash, cash equivalents, and restricted cash at beginning of period	42,248		33,045
Cash, cash equivalents, and restricted cash at end of period	$	59,765	$	247,642

Six Months Ended June 30,
2020 2019
Cash flows from operating activities

Net income (loss)
$ (623,458 ) $ 121,018
Adjustments to reconcile net income (loss) to cash flows from operating activities

Depletion, depreciation, and amortization
152,276
115,561
Write-down of oil and natural gas properties 734,981
—
Deferred income taxes
(106,513 ) 52,545
Stock-based compensation
3,540
6,865
Commodity derivatives expense (income)
(106,641 ) 58,617
Receipt on settlements of commodity derivatives
70,267
6,657
Gain on debt extinguishment (18,994 ) (100,346 )
Debt issuance costs and discounts
9,921
2,901
Other, net
(1,642 ) (57 )
Changes in assets and liabilities, net of effects from acquisitions

Accrued production receivable
62,063
(9,909 )
Trade and other receivables
(16,162 ) (271 )
Other current and long-term assets
(4,552 ) (3,389 )
Accounts payable and accrued liabilities
(60,295 ) (33,320 )
Oil and natural gas production payable
(22,217 ) 1,746
Other liabilities
237
(5,618 )
Net cash provided by operating activities
72,811
213,000

Cash flows from investing activities

Oil and natural gas capital expenditures
(79,897 ) (148,254 )
Pipelines and plants capital expenditures (10,962 ) (10,591 )
Net proceeds from sales of oil and natural gas properties and equipment 40,971
431
Other
(105 ) (725 )
Net cash used in investing activities
(49,993 ) (159,139 )

Cash flows from financing activities

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

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

Table of Contents

Denbury ~~Resources~~ Inc.

Unaudited Condensed Consolidated Statements of Changes in Stockholders' Equity

(Dollar amounts in thousands)


	Common Stock ($.001 Par Value)			Paid-In Capital in Excess of Par		Retained Earnings (Accumulated Deficit)		Treasury Stock (at cost)
	Shares	Amount						Shares	Amount		Total Equity
Balance – December 31, 2020 (Successor)	49,999,999	$	50	$	1,104,276	$	(50,658)	—	$	—	$	1,053,668
Stock-based compensation	—	—		19,172		—		—	—		19,172
Tax withholding for stock compensation plans	—	—		(1,467)		—		—	—		(1,467)
Issued pursuant to exercise of warrants	5,620	0		195		—		—	—		195
Net loss	—	—		—		(69,642)		—	—		(69,642)
Balance – March 31, 2021 (Successor)	50,005,619	50		1,122,176		(120,300)		—	—		1,001,926

Stock-based compensation	—	—		2,682		—		—	—		2,682
Tax withholding for stock compensation plans	—	—		(7)		—		—	—		(7)
Issued pursuant to exercise of warrants	11,872	0		292		—		—	—		292
Net loss	—	—		—		(77,695)		—	—		(77,695)
Balance – June 30, 2021 (Successor)	50,017,491	$	50	$	1,125,143	$	(197,995)	—	$	—	$	927,198


																			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						Shares	Amount		Total Equity
	Shares		Amount								Shares	Amount			Total Equity
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	312,516		—			—		—			—	—			—
Balance – December 31, 2019 (Predecessor)																		Balance – December 31, 2019 (Predecessor)	508,065,495	$	508	$	2,739,099	$	(1,321,314)	1,652,771	$	(6,034)	$	1,412,259
Issued pursuant to stock compensation plans																		Issued pursuant to stock compensation plans	312,516	—		—		—		—	—		—
Issued pursuant to directors’ compensation plan	37,367		—			—		—			—	—			—			Issued pursuant to directors’ compensation plan	37,367	—		—		—		—	—		—
Stock-based compensation	—		—			3,204		—			—	—			3,204			Stock-based compensation	—	—		3,204		—		—	—		3,204
Tax withholding – stock compensation	—		—			—		—			175,673	(34		)	(34		)
Tax withholding for stock compensation plans																		Tax withholding for stock compensation plans	—	—		—		—		175,673	(34)		(34)
Net income	—		—			—		74,016			—	—			74,016			Net income	—	—		—		74,016		—	—		74,016
Balance – March 31, 2020	508,415,378		508			2,742,303		(1,247,298		)	1,828,444	(6,068		)	1,489,445
Balance – March 31, 2020 (Predecessor)																		Balance – March 31, 2020 (Predecessor)	508,415,378	508		2,742,303		(1,247,298)		1,828,444	(6,068)		1,489,445
Canceled pursuant to stock compensation plans	(6,218,868	)	(6		)	6		—			—	—			—			Canceled pursuant to stock compensation plans	(6,218,868)	(6)		6		—		—	—		—
Issued pursuant to notes conversion	7,357,450		8			11,453		—			—	—			11,461			Issued pursuant to notes conversion	7,357,450	8		11,453		—		—	—		11,461
Stock-based compensation	—		—			987		—			—	—			987			Stock-based compensation	—	—		987		—		—	—		987
Net loss	—		—			—		(697,474		)	—	—			(697,474		)	Net loss	—	—		—		(697,474)		—	—		(697,474)
Balance – June 30, 2020	509,553,960		$	510		$	2,754,749	$	(1,944,772	)	1,828,444	$	(6,068	)	$	804,419
Balance – June 30, 2020 (Predecessor)																		Balance – June 30, 2020 (Predecessor)	509,553,960	510		2,754,749		(1,944,772)		1,828,444	(6,068)		804,419
Canceled pursuant to stock compensation plans																		Canceled pursuant to stock compensation plans	(95,016)	—		—		—		—	—		—
Issued pursuant to notes conversion																		Issued pursuant to notes conversion	14,800	—		40		—		—	—		40
Stock-based compensation																		Stock-based compensation	—	—		10,126		—		—	—		10,126
Tax withholding for stock compensation plans																		Tax withholding for stock compensation plans	—	—		—		—		567,189	(134)		(134)
Net loss																		Net loss	—	—		—		(809,120)		—	—		(809,120)
Cancellation of Predecessor equity																		Cancellation of Predecessor equity	(509,473,744)	(510)		(2,764,915)		2,753,892		(2,395,633)	6,202		(5,331)
Issuance of Successor equity																		Issuance of Successor equity	49,999,999	50		1,095,369		—		—	—		1,095,419
Balance – September 18, 2020 (Predecessor)																		Balance – September 18, 2020 (Predecessor)	49,999,999	$	50	$	1,095,369	$	—	—	$	—	$	1,095,419

Balance – September 19, 2020 (Successor)																		Balance – September 19, 2020 (Successor)	49,999,999	$	50	$	1,095,369	$	—	—	$	—	$	1,095,419
Net income																		Net income	—	—		—		2,758		—	—		2,758
Balance – September 30, 2020 (Successor)																		Balance – September 30, 2020 (Successor)	49,999,999	50		1,095,369		2,758		—	—		1,098,177
Stock-based compensation																		Stock-based compensation	—	—		8,907		—		—	—		8,907
Net loss																		Net loss	—	—		—		(53,416)		—	—		(53,416)
Balance – December 31, 2020 (Successor)																		Balance – December 31, 2020 (Successor)	49,999,999	$	50	$	1,104,276	$	(50,658)	—	$	—	$	1,053,668

Common Stock
($.001 Par Value)

Paid-In
Capital in
Excess of
Par

Retained
Earnings (Accumulated Deficit)

Treasury Stock
(at cost)

Shares Amount 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
Issued or purchased pursuant to stock compensation plans 400,850
—
—
—
—
—
—
Issued pursuant to directors’ compensation plan 37,367
—
—
—
—
—
—
Stock-based compensation —
—
4,667
—
—
—
4,667
Tax withholding – stock compensation —
—
—
—
1,661
(3 ) (3 )
Net income —
—
—
146,692
—
—
146,692
Balance – June 30, 2019 464,166,479
$ 464
$ 2,694,184
$ (1,412,094 ) 2,474,904
$ (11,878 ) $ 1,270,676

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Denbury ~~Resources~~ Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 1. Basis of Presentation

Organization and Nature of Operations

Denbury ~~Resources~~ Inc. (“~~Denbury”~~Denbury,” “Company” or the ~~“Company”~~“Successor”), a Delaware corporation, is an independent ~~oil and natural gas~~energy company with operations focused in ~~two key operating areas:~~ the Gulf Coast and Rocky Mountain regions. ~~Our goal~~The Company 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~~differentiated by its focus on CO₂ enhanced oil recovery (“EOR”) and the emerging carbon capture, use, and storage (“CCUS”) industry, supported by the Company’s CO2 EOR technical and operational expertise and its extensive CO2 pipeline infrastructure. The utilization of captured industrial-sourced CO2 in EOR significantly reduces the carbon footprint of the oil that Denbury produces, underpinning the Company’s goal to fully offset its Scope 1, 2, and 3 CO2 emissions within this decade, primarily through increasing the amount of captured industrial-sourced CO2 used in its operations.

Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code

On July 30, 2020, Denbury Resources Inc. (the “Predecessor”) and its subsidiaries filed petitions for reorganization in a “prepackaged” voluntary bankruptcy under chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”) under the caption “In re Denbury Resources Inc., et al., Case No. 20-33801”. On September 2, 2020, the Bankruptcy Court entered an order (the “Confirmation Order”) confirming the prepackaged joint plan of reorganization (the “Plan”) and approving the Disclosure Statement, and on September 18, 2020 (the “Emergence Date”), the Plan became effective in accordance with its terms and the Company emerged from Chapter 11 as the successor reporting company of Denbury Resources Inc. On April 23, 2021, the Bankruptcy Court entered a final decree closing the Chapter 11 case captioned “In re Denbury Resources Inc., et al., Case No. 20-33801”, so all of the Chapter 11 cases have been closed.

Upon emergence from bankruptcy, we met the criteria and were required to adopt fresh start accounting in accordance with Financial Accounting Standards Board Codification (“FASC”) Topic 852, Reorganizations. Fresh start accounting requires that new fair values be established for the Company’s assets, liabilities and equity as of the Emergence Date, and therefore certain values and operational results of the condensed consolidated financial statements subsequent to September 18, 2020 are not comparable to those in the Company’s condensed consolidated financial statements prior to, and including September 18, 2020. The Emergence Date fair values of the Successor’s assets and liabilities differ materially from their recorded values as reflected on the historical balance sheets of the Predecessor contained in periodic reports previously filed with the Securities and Exchange Commission. References to “Successor” relate to the financial position and results of operations of the Company subsequent to September 18, 2020, and references to “Predecessor” relate to the financial position and results of operations of the Company prior to, and including, September 18, 2020.

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, ~~2019~~2020 (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~~presentation of our consolidated financial position as of June 30, ~~2020,~~2021 (Successor); our consolidated results of operations for the three and six months ended June 30, 2021 (Successor) and June 30, 2020 ~~and 2019,~~(Predecessor); our consolidated cash flows for the six months ended June 30, 2021 (Successor) and June 30, 2020 ~~and 2019,~~(Predecessor); and our consolidated statements of changes in stockholders’ equity for the three and six months ended June 30, 2021 (Successor), for the period January 1, 2020 through September 18, 2020 (Predecessor), and ~~2019.~~

~~Industry Conditions, Liquidity,~~for the period September 19, 2020 through December 31, 2020 (Successor). Upon the adoption of fresh start accounting, the Company’s assets and ~~Management’s Plans~~

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

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

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


•	~~Deferred the Cedar Creek Anticline CO~~₂ ~~tertiary flood development project beyond 2020;~~

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

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

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

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

fresh start

Table of Contents

Denbury ~~Resources~~ Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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

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

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

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

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

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


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


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

~~Table of Contents~~

~~Denbury Resources Inc.~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~


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


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


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


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

~~Going Concern~~

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

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

~~The~~ condensed consolidated financial statements ~~included~~subsequent to September 18, 2020 are not comparable to those in ~~this Quarterly Report on Form 10-Q have been prepared on a going concern basis of accounting,~~its condensed consolidated financial statements prior to, and do not reflect any adjustments relating to the recoverability and classification of recorded asset amounts or the amounts and classification of liabilities that might result if we are unable to continue as a going concern.including September 18, 2020.

Reclassifications

Certain prior period amounts have been reclassified to conform to the current year presentation. Such reclassifications had no impact on our reported net income (loss), current assets, total assets, current liabilities, total liabilities or stockholders’ equity.

Cash, Cash Equivalents, and Restricted Cash

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


	Successor
In thousands	June 30, 2021		December 31, 2020
Cash and cash equivalents	$	13,565	$	518
Restricted cash, current	0		1,000
Restricted cash included in other assets	46,200		40,730
Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows	$	59,765	$	42,248

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

~~Table of Contents~~

~~Denbury Resources Inc.~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

~~Amounts included in restricted~~Restricted cash included in ~~“Other assets”~~other assets in the ~~accompanying Unaudited Condensed Consolidated Balance Sheets represent~~table above consists of escrow accounts that are legally restricted for certain of our asset retirement ~~obligations. See~~ ~~Entry into Restructuring Support Agreement~~obligations, and ~~Voluntary Reorganization under Chapter 11 of~~are included in “Other assets” in the ~~Bankruptcy Code~~ ~~above for a discussion of cash used to repay outstanding borrowings subsequent to June 30, 2020.~~accompanying Unaudited Condensed Consolidated Balance Sheets.

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 during the Successor periods consist of nonvested restricted stock units and outstanding series A and series B warrants, and during the Predecessor periods consisted of nonvested restricted stock, nonvested performance-based equity awards, and ~~shares into which our~~ convertible senior notes ~~are convertible~~. For the three and six months ended June 30, 2021 and 2020, there were no adjustments to net loss for purposes of calculating basic and diluted net loss per common share.

Table of Contents

Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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


	Successor	Predecessor	Successor	Predecessor
In thousands	Three Months Ended June 30, 2021	Three Months Ended June 30, 2020	Six Months Ended June 30, 2021	Six Months Ended June 30, 2020







Weighted average common shares outstanding – basic	50,999	495,245	50,661	494,752
Effect of potentially dilutive securities
Restricted stock units	0	0	0	0

Warrants	0	0	0	0
Restricted stock and performance-based equity awards	0	0	0	0
Convertible senior notes(1)	0	0	0	0
Weighted average common shares outstanding – diluted(2)	50,999	495,245	50,661	494,752

Three Months Ended Six Months Ended
June 30, June 30,
In thousands 2020 2019 2020 2019
Numerator
Net income (loss) – basic $ (697,474 ) $ 146,692
$ (623,458 ) $ 121,018
Effect of potentially dilutive securities

Interest on convertible senior notes including amortization of discount, net of tax —
548
—
548
Net income (loss) – diluted $ (697,474 ) $ 147,240
$ (623,458 ) $ 121,566

Denominator
Weighted average common shares outstanding – basic 495,245
452,612
494,752
452,169
Effect of potentially dilutive securities
Restricted stock and performance-based equity awards —
2,835
—
3,301
Convertible senior notes⁽¹⁾
—
11,980
—
5,990
Weighted average common shares outstanding – diluted 495,245
467,427
494,752
461,460

(1)In connection with the Company’s emergence from bankruptcy on September 18, 2020, all outstanding convertible senior notes were fully extinguished.

(2)If the Company had recognized net income, the weighted average diluted shares outstanding would have been 54.3 million and 587.1 million for the three months ended June 30, 2021 and 2020, respectively, and 52.7 million and 586.6 million for the six months ended June 30, 2021 and 2020, respectively.

Basic weighted average common shares ~~exclude shares of nonvested restricted stock. As these restricted shares vest, they will be included in~~during the ~~shares outstanding used to calculate basic net income (loss) per common share (although time-vesting restricted~~Successor periods includes 987,987 and 563,416 performance stock ~~is issued and outstanding upon grant). For purposes of calculating diluted weighted average common shares~~units during the three and six months ended June 30, ~~2019, the nonvested restricted stock and performance-based equity awards are included in the computation using the treasury stock method,~~2021, respectively, with ~~the deemed proceeds equal~~vesting parameters tied to the ~~average unrecognized compensation during~~Company’s common stock trading prices and which became fully vested on March 3, 2021. Although the ~~period, and~~performance measures for vesting of these awards have been achieved, the shares underlying these awards are not currently outstanding as actual delivery of the shares is not scheduled to occur until after the end of the performance period, December 4, 2023. Basic weighted average common shares during the Predecessor periods included time-vesting restricted stock that vested during the periods.

The following outstanding securities were excluded from the computation of diluted net loss per share, as their effect would have been antidilutive, as of the respective dates:


	Successor	Predecessor
In thousands	June 30, 2021	June 30, 2020
Restricted stock units	1,255	0
Warrants	5,503	0
Stock appreciation rights	0	1,493
Nonvested time-based restricted stock and performance-based equity awards	0	5,572
Convertible senior notes	0	83,495

For the Successor period, the Company’s restricted stock units and series A and series B warrants were antidilutive based on the Company’s net loss position for the period. At June 30, 2021, the Company had approximately 5.5 million warrants outstanding that can be exercised for shares of the Successor’s common stock, at an exercise price of $32.59 per share for the 2.6 million series A warrants and at an exercise price of $35.41 per share for the 2.9 million series B warrants. The series A warrants are exercisable until September 18, 2025, and the series B warrants are exercisable until September 18, 2023, at which time the warrants expire.The warrants were issued pursuant to the Plan to holders of the Predecessor’s convertible senior notes, ~~as if~~senior subordinated notes, and equity. As of June 30, 2021, 2,315 series A warrants and 20,927 series B warrants had been exercised. The warrants may be exercised for cash or on a cashless basis. If warrants are exercised on a cashless basis, the ~~convertible senior notes were converted at the beginning~~amount of ~~2019.~~dilution will be less than 5.5 million shares.

Table of Contents

Denbury ~~Resources~~ Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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

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

Oil and Natural Gas Properties

Unevaluated Costs. Under full cost accounting, we exclude certain unevaluated costs from the amortization base and full cost ceiling test pending the determination of whether proved reserves can be assigned to such properties. These costs are transferred to the full cost amortization base ~~in the course of~~as these properties ~~being~~are 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~~In the first quarter of 2020 Predecessor period, given the significant declines in NYMEX oil prices ~~to approximately $20 per Bbl~~ in ~~late~~ March ~~2020 due to OPEC supply pressures~~ and ~~a reduction in worldwide oil demand amid the COVID-19 pandemic, as well as the uncertainty of future oil prices from demand destruction caused by the pandemic,~~April 2020, we reassessed our development plans and ~~recognized an impairment of~~transferred $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. Upon emergence from bankruptcy, the Company adopted fresh start accounting which resulted in our oil and natural gas properties, including unevaluated properties, being recorded at their fair values at the Emergence Date.

Write-Down of Oil and Natural Gas Properties. ~~The~~Under full cost accounting, 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 CO2 capital 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 $14.4 million during the three months ended March 31, 2021, with first-day-of-the-month NYMEX oil prices for the preceding 12 months averaging $36.40 per Bbl, after adjustments for market differentials and transportation expenses by field. The write-down was primarily a result of the recent acquisition (see Note 2 – Acquisition and Divestiture) which was recorded based on a valuation that utilized NYMEX strip oil prices at the acquisition date, which were significantly higher than the average first-day-of-the-month NYMEX oil prices used to value the cost ceiling. We also recognized full cost pool ceiling test write-downs of $662.4 million and $72.5 million during the Predecessor three months ended June 30, 2020 and March 31, 2020, respectively. ~~The first-day-of-the-month oil prices for~~We did 0t record a ceiling test write-down during the ~~preceding 12~~three months ~~after adjustments for market differentials by field, averaged $44.74 per Bbl and $55.17 per Bbl as of~~ended June 30, 2020 and March 31, 2020, respectively. In addition, the first-day-of-the-month natural gas prices for the preceding 12 months, after adjustments for market differentials by field, averaged $1.91 per MMBtu and $1.68 per MMBtu as of June 30, 2020 and March 31, 2020, respectively. If oil prices remain at or near early-August 2020 levels for the remainder of 2020, we currently expect that we would also record write-downs in subsequent quarters in 2020, as the 12-month average price used in determining the full cost ceiling value will continue to decline during each rolling quarterly period in 2020, subject to the date of the Company’s emergence from bankruptcy and potential impacts of fresh start accounting, if applicable.

~~Impairment Assessment of Long-Lived Assets~~

We test long-lived assets for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. These long-lived assets, which are not subject to our full cost pool ceiling test, are principally comprised of our capitalized CO
₂ properties and pipelines. Given the significant declines in NYMEX oil prices to approximately $20 per Bbl in late March 2020 due to OPEC supply pressures and a reduction in worldwide oil demand amid the COVID-19 pandemic, we performed a long-lived asset impairment test for our two long-lived asset groups (Gulf Coast region and Rocky Mountain region) as of March 31, 2020.

~~Table of Contents~~

~~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 CO~~₂ ~~reserves and CO~~₂ pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves is included in the full cost pool ceiling test as a reduction to future net revenues. The remaining net capitalized costs that are not included in the full cost pool ceiling test, and related intangible assets, are subject to long-lived asset impairment testing. These costs totaled approximately $1.3 billion as of March 31, 2020. If the undiscounted net cash flows are below the net carrying costs for an asset group, we must record an impairment loss by the amount, if any, that net carrying costs exceed the fair value of the long-lived asset group. The undiscounted net cash flows for our asset groups exceeded the net carrying costs; thus, step two of the impairment test was not required and 0 impairment was recorded.

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

Recent Accounting Pronouncements

~~Financial Instruments – Credit Losses.~~ ~~In June 2016, the 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 implementation of this standard did not have a material 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.

Income Taxes. In December 2019, the ~~FASB~~Financial Accounting Standards Board (“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. Effective January 1, 2021, we adopted ASU 2019-02. The ~~amendments in~~implementation of this ~~ASU are effective for fiscal years beginning after December 15, 2020, and early adoption is permitted. We are currently evaluating the~~standard did not have a material impact ~~this guidance may have~~ on our consolidated financial statements and related footnote disclosures.

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 2. Acquisition and Divestiture

Acquisition of Wyoming CO2 EOR Fields

On March 3, 2021, we acquired a nearly 100% working interest (approximately 83% net revenue interest) in the Big Sand Draw and Beaver Creek EOR fields located in Wyoming from a subsidiary of Devon Energy Corporation for $10.7 million cash (before final closing adjustments), including surface facilities and a 46-mile CO2 transportation pipeline to the acquired fields. The acquisition agreement provides for us to make two contingent cash payments, one in January 2022 and one in January 2023, of $4 million each, conditioned on NYMEX WTI oil prices averaging at least $50 per Bbl during 2021 and 2022, respectively. The fair value of the contingent consideration on the acquisition date was $5.3 million, and as of June 30, 2021, the fair value of the contingent consideration recorded on our unaudited condensed consolidated balance sheets was $7.0 million. The $1.7 million increase from the March 2021 acquisition date fair value was the result of higher NYMEX WTI oil prices and was recorded to “Other expenses” in our Unaudited Condensed Consolidated Statements of Operations.

The fair values allocated to our assets acquired and liabilities assumed for the acquisition were based on significant inputs not observable in the market and considered level 3 inputs. The following table presents a summary of the fair value of assets acquired and liabilities assumed in the acquisition:


In thousands
Consideration:
Cash consideration	$	10,657

Less: Fair value of assets acquired and liabilities assumed:(1)
Proved oil and natural gas properties	59,852
Other property and equipment	1,685
Asset retirement obligations	(39,794)
Contingent consideration	(5,320)
Other liabilities	(5,766)
Fair value of net assets acquired	$	10,657

(1)Fair value of assets acquired and liabilities assumed is preliminary, pending final closing adjustments and further evaluation of reserves and liabilities assumed.

Divestiture of Hartzog Draw Deep Mineral Rights

On ~~March 4, 2020,~~June 30, 2021, we closed ~~a farm-down transaction for~~ the sale of ~~half~~undeveloped, unconventional deep mineral rights in Hartzog Draw Field in Wyoming. The cash proceeds of $18 million were recorded to “Proved properties” in our ~~working interest positions in four southeast Texas oil fields for $40 million net cash and a carried interest in ten wells to be drilled by the purchaser. We did not record a~~Unaudited Condensed Consolidated Balance Sheets. The proceeds reduced our full cost pool; therefore, 0 gain or loss was recorded on the transaction, and the sale ~~of the properties in accordance with the full cost method of accounting.~~had no impact on our production or reserves.

Note 3. Revenue Recognition

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

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~~Denbury Resources Inc.~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

we have delivered the volume of commodity to the delivery point and the customer takes delivery and possession, we are entitled to payment and we invoice the customer for such delivered production. Payment under most oil and CO₂ contracts is ~~made~~received within a month following product delivery and for natural gas and NGL contracts payment is generally ~~made~~received within two months following delivery. 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 $77.3 million and $139.4 million as~~Sheets. From time to time,

Table of ~~June 30, 2020 and December 31, 2019, respectively. The~~Contents

Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

the Company enters into marketing arrangements for the purchase ~~transactions with~~and sale of crude oil for third ~~parties and separate sale transactions with third parties in the Gulf Coast region.~~parties. 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, 2020 and 2019:~~type:


	Successor		Predecessor		Successor		Predecessor

In thousands	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
Oil sales	$	280,577	$	108,538	$	513,621	$	337,115
Natural gas sales	2,131		849		4,532		1,896
CO2 sales and transportation fees	10,134		6,504		19,362		14,532
Oil marketing revenues	7,819		1,490		13,945		5,211
Total revenues	$	300,661	$	117,381	$	551,460	$	358,754

CO₂ sales and transportation fees

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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 outstanding as of the dates indicated:


	Successor
In thousands	June 30, 2021		December 31, 2020
Senior Secured Bank Credit Agreement	$	35,000	$	70,000
Pipeline financings	34,498		68,008
Total debt principal balance	69,498		138,008
Less: current maturities of long-term debt	(34,498)		(68,008)
Long-term debt	$	35,000	$	70,000

June 30, December 31,
In thousands 2020 2019
Senior Secured Bank Credit Agreement $ 265,000
$ —
9% Senior Secured Second Lien Notes due 2021 584,709
614,919
9¼% Senior Secured Second Lien Notes due 2022 455,668
455,668
7¾% Senior Secured Second Lien Notes due 2024 531,821
531,821
7½% Senior Secured Second Lien Notes due 2024 20,641
20,641
6⅜% Convertible Senior Notes due 2024
225,663
245,548
6⅜% Senior Subordinated Notes due 2021 51,304
51,304
5½% Senior Subordinated Notes due 2022 58,426
58,426
4⅝% Senior Subordinated Notes due 2023 135,960
135,960
Pipeline financings 160,428
167,439
Capital lease obligations 157
—
Total debt principal balance 2,489,777
2,281,726
Debt discount⁽¹⁾
(88,442 ) (101,767 )
Future interest payable⁽²⁾
119,454
164,914
Debt issuance costs (8,537 ) (10,009 )
Total debt, net of debt issuance costs and discount 2,512,252
2,334,864
Less: current maturities of long-term debt⁽³⁾
(2,366,330 ) (102,294 )
Long-term debt $ 145,922
$ 2,232,570

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

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

The ultimate parent company in our corporate structure, Denbury Resources Inc. (“DRI”), is the sole issuer of all 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.

~~Chapter 11 Restructuring and Effect of Automatic Stay~~

~~As discussed in Note 1,~~ ~~Basis of Presentation~~ – ~~Entry into Restructuring Support Agreement and Voluntary Reorganization under Chapter 11 of the Bankruptcy Code,~~ on July 30, 2020, Denbury filed for relief under chapter 11 of the Bankruptcy Code. Both the NEJD pipeline lease financing and Free State pipeline transportation agreement are not impaired and are expected to continue post-bankruptcy under their existing terms and maintain their long-term nature. Therefore, the noncurrent portions of our pipeline financings remain classified as long-term debt in the condensed consolidated balance sheet as of June 30, 2020. Any efforts to enforce payment obligations related to the acceleration of the Company’s debt have been automatically stayed as a result of the filing of the Chapter 11 Restructuring, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code. Refer to Note 1, ~~Basis of Presentation~~ – ~~Entry into Restructuring Support Agreement and Voluntary Reorganization under Chapter 11 of the Bankruptcy Code, for more information on the Chapter 11 Restructuring.~~

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~~Denbury Resources Inc.~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

Senior Secured Bank Credit ~~Facility~~Agreement

~~Since December 2014,~~On the ~~Company maintained~~Emergence Date, we entered into a ~~senior secured revolving~~ credit ~~facility~~agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto ~~which has been amended periodically since that time.~~(the “Bank Credit Agreement”). The Bank Credit Agreement ~~had~~is a senior secured revolving credit facility with an initial borrowing base and lender commitments of $575 million. Availability under the Bank Credit Agreement is subject to a borrowing base, which is redetermined semiannually on or around May 1 and November 1 of each year, with our next scheduled maturity date of December 9, 2021, provided that the maturity date may be accelerated to earlier dates in 2021 if certain defined liquidity ratios are not met, or if the 2021 Senior Secured Notes due in May 2021 or 6⅜% Senior Subordinated Notes due in August 2021 are not repaid or refinanced by each of their respective maturity dates.redetermination around November 1, 2021. The borrowing base is adjusted at the lenders’ discretion and is based, in part, upon external factors over which we have no control. If our outstanding debt under the Bank Credit Agreement exceeds the then-effective borrowing base, we would be required to repay the excess amount over a period not to exceed six months. The Bank Credit Agreement matures on January 30, 2024. The weighted average interest rate on borrowings outstanding as of June 30, 2021 under the Bank Credit Agreement was ~~evaluated semi-annually, generally around May 1 and November 1. In conjunction with~~4.0%. The undrawn portion of the ~~scheduled May 2020 redetermination on June 26, 2020, we entered into the Eighth Amendment to the Bank Credit Agreement (the “Eighth Amendment”) which among other things:~~

The Bank Credit Agreement prohibits us from paying dividends on our common stock through September 17, 2021. Commencing on September 18, 2021, we may pay dividends on our common stock or ~~interim redetermination~~make other restricted payments in an amount not to exceed “Distributable Free Cash Flow”, but only if (1) no event of default or ~~other adjustment to the~~ borrowing base ~~in accordance with the terms of the Bank Credit Agreement;~~

~~Under the terms~~Table of ~~the RSA, the lenders under the Company’s~~Contents

Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

The Successor Bank Credit Agreement ~~agreed~~is secured by (1) our proved oil and natural gas properties, which are held through our restricted subsidiaries; (2) the pledge of equity interests of such subsidiaries; (3) a pledge of our commodity derivative agreements; (4) a pledge of deposit accounts, securities accounts and our commodity accounts; and (5) a security interest in substantially all other collateral that may be perfected by a Uniform Commercial Code filing, subject to ~~provide the Company and its subsidiaries with the DIP Facility, which is to be replaced with the committed exit facility upon emergence from the Chapter 11 Restructuring. Refer to Note 1,~~ ~~Basis of Presentation~~ – ~~Entry into Restructuring Support Agreement and Voluntary Reorganization under Chapter 11 of the Bankruptcy Code, for additional information.~~certain exceptions.

On June 29, 2020, we elected to draw $200 million (the “Credit Draw”) under the Bank Credit Agreement. As of June 30, 2020, we had $265 million of outstanding borrowings and approximately $95 million of outstanding letters of credit under the Bank Credit Agreement.

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

•A Consolidated Total Debt to Consolidated EBITDAX covenant (as defined in the Bank Credit Agreement), with such ratio not to exceed ~~5.25 to 1.0 through December 31, 2020~~3.5 times; 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;

For purposes of computing the current ratio per the Bank Credit Agreement, Consolidated Current Assets exclude the current portion of derivative assets but include available borrowing capacity under the ~~senior secured bank credit facility,~~Bank Credit Agreement, 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, 2021, we were in compliance with all debt covenants under the Bank Credit Agreement.

The above description of our Bank Credit Agreement is qualified by the express language and defined terms ~~are~~ contained in the Bank Credit ~~Agreement~~Agreement.

Pipeline Financing Transactions

During the first half of 2021, Denbury paid $35.0 million to Genesis Energy, L.P., half of the four quarterly installments totaling $70 million to be paid during 2021 in accordance with the October 2020 restructuring of the financing arrangements of our NEJD CO2 pipeline system. The third quarterly installment of $17.5 million was paid in July 2021, and the ~~amendments thereto.~~final quarterly payment of $17.5 million is payable on October 31, 2021.

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~~Denbury Resources Inc.~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

~~Second Quarter 2020 Conversion of 6⅜% Convertible Senior Notes due 2024~~

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

~~First Quarter 2020 Repurchases of Senior Secured Notes~~

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

Note 5. Income Taxes

On March 27, 2020, Congress enacted the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) to 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.

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 combined federal and state statutory rate of approximately 25% in ~~2020~~2021 and ~~2019. As provided for under FASC 740-270-35-2, we determined the actual~~2020. Our effective tax ~~rate~~rates for the three and six months ended June 30, ~~2020 was the best estimate of our annual effective tax rate. Our effective tax rate for the six months ended June 30, 2020,~~2021 (Successor) differed from our estimated statutory rate ~~primarily due to~~as the ~~establishment of~~deferred tax benefit generated from our operating losses were offset by a ~~full~~ valuation allowance onapplied to our ~~$85.0 million of enhanced oil recovery credits~~underlying federal and ~~research and development credits that currently are not expected to be utilized, partially offset by~~state deferred tax changes enacted by the CARES Act which resulted in the full release of a $24.5 million valuation allowance against a portion of our business interest expense deduction that we previously estimated would be disallowed.

~~Note 6. Stock Compensation~~

~~2020 Compensation Adjustments~~

In response to the ongoing significant economic and market uncertainty affecting the oil and gas industry, the Company and its Board of Directors (the “Board”) and Compensation Committee (the “Compensation Committee”) conducted a comprehensive review of our compensation programs across the organization. As a result of this review, the Board and Compensation Committee determined that our historic compensation structure and performance metrics would not be effective in motivating and incentivizing our workforce in the current environment. With the advice of our independent compensation consultant and legal advisors, effective June 3, 2020, the Company and the Board implemented a revised compensation structure for all of the Company’s employees (including its named executive officers) and non-employee directors. In connection with the revised compensation structure, the Company’s CEO voluntarily reduced his 2020 base annual salary by 20%, and the Company’s CEO and CFO voluntarily reduced 2020 targeted variable compensation by 35% and 20%, respectively. In addition, the Chairman of the Board reduced his 2020 chairman retainer by 20%.

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

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~~Denbury Resources Inc.~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

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

Note 7.6. 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 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 addition, our new senior secured bank credit facility entered into on the Emergence Date required that, by December 31, 2020, we have certain minimum commodity hedge levels in place covering anticipated crude oil production through July 31, 2022. The requirement is non-recurring, and we were in compliance with the hedging requirements as of December 31, 2020.

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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, ~~2020,~~2021, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.

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~~Denbury Resources Inc.~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

The following table summarizes our commodity derivative contracts as of June 30, ~~2020~~,2021, 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)
			Range(1)				Weighted Average Price
							Swap		Floor		Ceiling
Oil Contracts:
2021 Fixed-Price Swaps
July – Dec	NYMEX	29,000	$	38.68	–	56.00	$	43.86	$	—	$	—
2021 Collars
July – Dec	NYMEX	4,000	$	45.00	–	59.30	$	—	$	46.25	$	53.04
2022 Fixed-Price Swaps
Jan – June	NYMEX	15,500	$	42.65	–	58.15	$	49.01	$	—	$	—
July – Dec	NYMEX	9,000		50.13	–	60.35	56.35		—		—
2022 Collars
Jan – June	NYMEX	11,000	$	47.50	–	70.75	$	—	$	49.77	$	64.31
July – Dec	NYMEX	10,000		47.50	–	70.75	—		49.75		64.18

Months Index Price Volume (Barrels per day) Contract Prices ($/Bbl)
Range⁽¹⁾
Weighted Average Price
Swap Sold Put Floor Ceiling
Oil Contracts:
2020 Fixed-Price Swaps
July – Dec NYMEX 13,500 $ 36.25
– 61.00
$ 40.52
$ —
$ —
$ —
July – Dec Argus LLS 7,500 35.00
– 64.26
51.67
—
—
—
2020 Three-Way Collars⁽²⁾

July – Dec NYMEX 9,500 $ 55.00
– 82.65
$ —
$ 47.93
$ 57.00
$ 63.25
July – Dec Argus LLS 5,000 58.00
– 87.10
—
52.80
61.63
70.35

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

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

Note 8.7. 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:

•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 and 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 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

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Notes to Unaudited Condensed Consolidated Financial Statements

of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

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~~Denbury Resources Inc.~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

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:
In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
June 30, 2021





Liabilities
Oil derivative contracts – current	$	0	$	(223,212)	$	0	$	(223,212)
Oil derivative contracts – long-term	0		(22,164)		0		(22,164)
Total Liabilities	$	0	$	(245,376)	$	0	$	(245,376)

December 31, 2020
Assets
Oil derivative contracts – current	$	0	$	187	$	0	$	187
Total Assets	$	0	$	187	$	0	$	187

Liabilities
Oil derivative contracts – current	$	0	$	(53,865)	$	0	$	(53,865)
Oil derivative contracts – long-term	0		(5,087)		0		(5,087)
Total Liabilities	$	0	$	(58,952)	$	0	$	(58,952)

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
June 30, 2020
Assets
Oil derivative contracts – current $ —
$ 47,655
$ —
$ 47,655
Total Assets $ —
$ 47,655
$ —
$ 47,655

Liabilities
Oil derivative contracts – current $ —
$ (7,691 ) $ —
$ (7,691 )
Total Liabilities $ —
$ (7,691 ) $ —
$ (7,691 )

December 31, 2019

Assets

Oil derivative contracts – current $ —
$ 8,503
$ 3,433
$ 11,936
Total Assets $ —
$ 8,503
$ 3,433
$ 11,936

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

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

~~Table of Contents~~

~~Denbury Resources Inc.~~

~~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, 2020 and 2019:~~

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

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

Instruments previously categorized as Level 3 included non-exchange-traded three-way 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 Level 2 during the period generally relate to changes in the significant relevant observable and unobservable inputs that are available for the fair value measurements of 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, ~~2020~~2021 and December 31, ~~2019~~,2020, excluding pipeline financing obligations, was ~~$922.0~~$35.0 million and ~~$1,833.1 million, respectively, which decrease is primarily driven by a decrease in quoted market prices.~~$70.0 million. We have other financial instruments consisting primarily of cash, cash equivalents, U.S. Treasury notes, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 9.8. Commitments and Contingencies

Chapter 11 Proceedings

~~Refer to Note 1,~~ ~~Basis~~On July 30, 2020, Denbury Resources Inc. and each of ~~Presentation~~ – ~~Entry into Restructuring Support Agreement and Voluntary Reorganization~~its wholly-owned subsidiaries filed for relief under ~~Chapter~~chapter 11 of the Bankruptcy ~~Code~~Code. The chapter 11 cases were administered jointly under the caption “In re Denbury Resources Inc., et al., ~~for more information~~Case No. 20-33801”. On September 2, 2020, the Bankruptcy Court entered the Confirmation Order and on the Emergence Date, all of the conditions of the Plan were satisfied or waived and the Plan became effective and was implemented in accordance with its terms. On September 30, 2020, the Bankruptcy Court closed the chapter 11 cases of each of Denbury Inc.’s wholly-owned subsidiaries. On April 23, 2021, the Bankruptcy Court entered a final decree closing the Chapter 11 ~~Restructuring.~~case captioned “In re Denbury Resources Inc., et al., Case No. 20-33801”, so all of the Chapter 11 cases have been closed.

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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~~Denbury Resources Inc.~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

~~Riley Ridge Helium Supply Contract Claim~~

As part of our 2010 and 2011 acquisitions of the Riley Ridge Unit and associated gas processing facility that was under construction, the Company assumed a 20-year helium supply contract under which we agreed to supply the helium separated from the full well stream by operation of the gas processing facility to a third-party purchaser, APMTG Helium, LLC (“APMTG”). The helium supply contract provides for the delivery of a minimum contracted quantity of helium, with liquidated damages payable if specified quantities of helium are not supplied in accordance with the terms of the contract. The liquidated damages are 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). 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 of the helium supply contract, so the Company has appealed the trial court’s ruling to the Wyoming Supreme Court. Briefing for the appeal by the Company and APMTG was completed on June 3, 2020, and oral arguments to be heard by the Wyoming Supreme Court are currently scheduled for August 13, 2020, after which the Wyoming Supreme Court will enter its judgment on the appeal. The timing and outcome of this appeal process is currently unpredictable, but at this time is anticipated to extend over the three or four months following the conclusion of oral arguments. The Company expects to enter into a stipulation with APMTG, to be approved by the Bankruptcy Court, to lift the automatic stay with respect to this proceeding so that the appeal process may proceed as outlined above.

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

Note ~~10.~~9. Additional Balance Sheet Details

Trade and Other Receivables, Net

Other receivables(1)

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

(1)Primarily consists of a currently estimated $9.9 million benefit under the Company’s power agreements for reduced power usage during the winter storms in February 2021.

Accounts Payable and Accrued Liabilities

~~Note 11. Subsequent Events~~


	Successor
In thousands	June 30, 2021		December 31, 2020
Accounts payable	$	27,166	$	18,629
Accrued derivative settlements	26,121		3,908
Accrued lease operating expenses	24,802		21,294
Accrued compensation	21,428		7,512
Accrued exploration and development costs	12,361		1,861
Taxes payable	10,180		17,221
Accrued general and administrative expenses	4,432		21,825
Other	37,415		20,421
Total	$	163,905	$	112,671

~~Delhi Insurance Receivable~~

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

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Denbury ~~Resources Inc.~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

~~Houston Area Land Sale~~

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

On July 31, 2020, the New York Stock Exchange (the “NYSE”) notified us of its determination to commence proceedings to delist our common stock from the NYSE, and as of July 31, 2020 to indefinitely suspend trading of our common stock on the NYSE. Suspension of trading in our common stock and delisting proceedings were undertaken by the NYSE in accordance with Section 802.01D of the NYSE Listed Company Manual due to our filing of the Chapter 11 Restructuring on July 30, 2020.

~~Table of Contents~~

~~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, ~~2019~~2020 (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.

As a result of the Company’s emergence from bankruptcy and adoption of fresh start accounting on September 18, 2020 (the “Emergence Date”), certain values and operational results of the condensed consolidated financial statements subsequent to September 18, 2020 are not comparable to those in the Company’s condensed consolidated financial statements prior to, and including September 18, 2020. The Emergence Date fair values of the Successor’s assets and liabilities differ materially from their recorded values as reflected on the historical balance sheets of the Predecessor contained in periodic reports previously filed with the Securities and Exchange Commission. References to “Successor” relate to the financial position and results of operations of the Company subsequent to September 18, 2020, and references to “Predecessor” relate to the financial position and results of operations of the Company prior to, and including, September 18, 2020.

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.

Denbury is an independent ~~oil and natural gas~~energy company with operations focused in ~~two key operating areas:~~ the Gulf Coast and Rocky Mountain regions. ~~Our goal~~The Company 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~~differentiated by its focus on CO₂ enhanced oil recovery (“EOR”) and the emerging carbon capture, use, and storage (“CCUS”) industry, supported by the Company’s CO2 EOR technical and operational expertise and its extensive CO2 pipeline infrastructure. The utilization of captured industrial-sourced CO2 in EOR significantly reduces the carbon footprint of the oil that Denbury produces, underpinning the Company’s goal to fully offset its Scope 1, 2, and 3 CO2 emissions within this decade, primarily through increasing the amount of captured industrial-sourced CO2 used in its operations.

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

~~Recent Developments in Response to Oil Price Declines.~~ In January and February 2020, NYMEX oil prices averaged in the mid-$50s per Bbl range before a precipitous decline in early March 2020 due to the combination of OPEC supply pressures and a reduction in worldwide oil demand amid the COVID-19 coronavirus (“COVID-19”) pandemic, resulting in NYMEX oil prices averaging approximately $30 per Bbl in March. NYMEX oil prices continued to decline in April 2020 to an average of $17 per Bbl, before increasing to an average of $29 per Bbl during May 2020, $38 per Bbl during June 2020, and $41 per Bbl during July 2020.

The decrease in NYMEX oil prices during the second quarter of 2020, as compared to the first quarter of 2020, significantly decreased our realized oil prices in the second quarter of 2020 by almost half compared to those realized in the first quarter of 2020. In response to these developments, in the first six months of 2020 we have implemented the following operational and financial measures:

~~Deferred the Cedar Creek Anticline CO~~₂ ~~tertiary flood development project beyond 2020;~~

Conducted a complete market-based review of strategic alternatives, including a comprehensive restructuring, to enhance our liquidity and strengthen our capital structure. After extensive negotiations, we arrived at the transactions embodied in the restructuring support agreement (the “RSA”). See discussion under ~~Chapter 11 Restructuring~~ ~~below.~~

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Denbury ~~Resources~~ Inc.

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

items and sales volumes, along with changes in our realized oil prices, before and after commodity derivative impacts, for our most recent comparative periods:


	Successor						Predecessor
	Three Months Ended						Three Months Ended June 30, 2020
In thousands, except per-unit data	June 30, 2021		March 31, 2021		December 31, 2020
Oil, natural gas, and related product sales	$	282,708	$	235,445	$	178,787	$	109,387
Receipt (payment) on settlements of commodity derivatives	(63,343)		(38,453)		14,429		45,629
Oil, natural gas, and related product sales and commodity settlements, combined	$	219,365	$	196,992	$	193,216	$	155,016

Average daily sales (BOE/d)	49,133		47,357		48,805		50,190

Average net realized prices
Oil price per Bbl - excluding impact of derivative settlements	$	64.70	$	56.28	$	40.63	$	24.39
Oil price per Bbl - including impact of derivative settlements	50.10		47.00		43.94		34.64

~~Chapter 11 Restructuring.~~
~~On July 28,~~

NYMEX WTI oil prices strengthened from the mid-$40s per Bbl range in December 2020 Denbury and its subsidiaries (collectively, “Denbury”) entered into the RSA with lenders holding 100% of the revolving loans under our bank credit facility (“Bank Credit Agreement”) and certain holders of a majority of senior secured second lien notes and convertible senior notes to support a restructuring in accordance with the terms set forth in the Company’s chapter 11 plan of reorganization (the “Plan”). On July 30, 2020 (the “Petition Date”), Denbury and its subsidiaries filed petitions for reorganization in a “prepackaged” voluntary bankruptcy (the “Chapter 11 Restructuring”) under chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Chapter 11 Restructuring is being undertaken to deleverage the Company, relieving itan average of approximately $2.1 billion of bond debt by issuing equity in a reorganized entity to the holders of that debt. The Plan and the related disclosure statement were each filed with the Bankruptcy Court on July 30, 2020. We expect to continue operations in the normal course for the duration of the Chapter 11 Restructuring. On July 31, 2020, the Bankruptcy Court entered orders approving certain customary “first day” relief to enable Denbury to operate in the ordinary course$66 per Bbl during the ~~Chapter 11 Restructuring, including approval on an interim basis~~second quarter of ~~post-petition financing under a debtor-in-possession (“DIP”) facility (the “DIP Facility”) and use~~2021, reaching highs of cash collateral of Denbury’s lenders and secured noteholders. Denbury is currently soliciting votes to accept a proposed chapter 11 plan (the “Plan”) from holders of claims and interests entitled to vote. The hearing to confirm the Plan and the final hearing on approval of the DIP Facility and use of cash collateral is currently scheduled for September 2, 2020. For more information on the Chapter 11 Restructuring and related matters, refer to Note 1, over $74 per Bbl in June 2021.

~~Basis of Presentation~~ – ~~Entry into Restructuring Support Agreement and Voluntary Reorganization under Chapter 11 of the Bankruptcy Code, and Note 4,~~ ~~Long-Term Debt, to the condensed consolidated financial statements.~~

~~Comparative~~Second Quarter 2021 Financial Results and Highlights. We recognized a net loss of $77.7 million, or $1.52 per diluted common share, during the second quarter of 2021, compared to a net loss of $697.5 million, or $1.41 per diluted common share, during the second quarter of ~~2020, compared to net income~~2020. The principal determinant of ~~$146.7 million, or $0.32 per diluted common share, during the~~our comparative second quarter ~~of 2019. The primary drivers of our change in operating~~ results ~~were~~between 2020 and 2021 was the ~~following:~~

•Oil and natural gas revenues increased $173.3 million (158%), primarily due to an increase in ~~NYMEX oil~~commodity prices;

•Commodity derivatives expense increased by ~~$64.9~~$132.5 million ~~($40.1~~consisting of a $109.0 million decrease in cash receipts upon contract settlements ($63.3 million in payments during the second quarter of 2021 compared to $45.6 million in receipts upon settlements during the second quarter of 2020) and a $23.5 million increase in the loss on noncash fair value changes;

•A $28.9 million increase in lease operating expense, across nearly all expense categories, consisting of increases of $8.4 million in workovers, $4.4 million in CO2 expense, $3.7 million in power and fuel, and approximately $7.1 million due to the Wind River Basin acquisition in March 2021;

•A $19.4 million reduction in net interest expense resulting from the full extinguishment of senior secured second lien notes, convertible senior notes, and senior subordinated notes pursuant to the terms of the prepackaged joint plan of reorganization completed in September 2020;

•A reduction in depletion, depreciation, and amortization expense of $19.0 million as a result of lower depletable costs due to the step down in book value resulting from fresh start accounting on the Emergence Date; and

•An $8.3 million decrease in general and administrative expense in the second quarter of 2021, primarily due to higher expense in the prior-year period as a result of modifications in our compensation program during the second quarter of 2020 ~~compared~~which resulted in adjustments to ~~$24.8 million of income~~the bonus program for 2020, as well as certain severance-related costs recorded during the second quarter of ~~2019), resulting from $112.1~~2020.

June 2021 Divestiture of Hartzog Draw Deep Mineral Rights. On June 30, 2021, we closed the sale of undeveloped, unconventional deep mineral rights in Hartzog Draw Field in Wyoming. The cash proceeds of $18 million ~~of incremental noncash fair value losses partially offset by a $47.2 million increase in cash receipts upon settlement between the second quarters of 2019 and 2020;~~

~~Second Quarter 2020 Conversion of 6⅜% Convertible Senior Notes due 2024.~~ During the second quarter of 2020, holders of $19.9 million aggregate principal amount outstanding of our 6⅜% Convertible Senior Notes due 2024 (the “2024 Convertible Senior Notes”) converted their notes into shares of Denbury common stock, at the rates specified in the indenture for the notes, resulting in the issuance of 7.4 million shares of our common stock upon conversion. The debt principal balance net of debt discounts totaling $13.9 million, was reclassified to “Paid-in capital in excess of par” and “Common stock”“Proved properties” in our Unaudited Condensed Consolidated Balance ~~Sheets upon~~Sheets. The proceeds reduced our full cost pool; therefore, no gain or loss was recorded on the ~~conversion of the notes into shares of Denbury common stock. As of June 30, 2020, there was $225.7 million 2024 Convertible Senior Notes outstanding.~~

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

~~First Quarter 2020 Sale of Working Interests in Certain Texas Fields.~~ ~~On March 4, 2020, we closed a farm-down transaction for~~ the sale ~~of half of~~had no impact on our nearly 100% working interest positions in four southeast Texas oil fields (consisting of Webster, Thompson, Manvel and East Hastings) for $40 million net cash and a carried interest in ten wells to be drilled by the purchaser (the “Gulf Coast Working Interests Sale”).production or reserves.

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Denbury ~~Resources~~ Inc.

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

~~Houston Area Land Sales~~March 2021 Acquisition of Wyoming CO2 EOR Fields. On March 3, 2021, we acquired a nearly 100% working interest (approximately 83% net revenue interest) in the Big Sand Draw and Beaver Creek EOR fields (collectively “Wind River Basin”) located in Wyoming from a subsidiary of Devon Energy Corporation for $10.7 million cash (before final closing adjustments), including surface facilities and a 46-mile CO2 transportation pipeline to the acquired fields. The acquisition agreement provides for us to make two contingent cash payments, one in January 2022 and one in January 2023, of $4 million each, conditioned on NYMEX WTI oil prices averaging at least $50 per Bbl during 2021 and 2022, respectively. As of June 30, 2021, the contingent consideration was recorded on our unaudited condensed consolidated balance sheets at its fair value of $7.0 million, a $1.7 million increase from the March 2021 acquisition date fair value. This $1.7 million increase was the result of higher NYMEX WTI oil prices and was recorded to “Other expenses” in our Unaudited Condensed Consolidated Statements of Operations. Wind River Basin sales averaged approximately 2,750 BOE/d during the second quarter of 2021 and utilize 100% industrial-sourced CO2.

Carbon Capture, Use and Storage. CCUS is a process that captures CO2 from industrial sources and reuses it or stores the CO2 in geologic formations in order to prevent its release into the atmosphere. We utilize CO2 from industrial sources in our EOR operations, and our extensive CO2 pipeline infrastructure and operations, particularly in the Gulf Coast, are strategically located in close proximity to large sources of industrial emissions. We believe that the assets and technical expertise required for CCUS are highly aligned with our existing CO2 EOR operations, providing us with a significant advantage and opportunity to participate in the emerging CCUS industry, as the building of a permanent carbon sequestration business requires both time and capital to build assets such as those we own and have been ~~actively marketing~~operating for ~~sale non-producing surface acreage primarily around~~years. During the ~~Houston area.~~ first half of 2021, approximately 34% of the COOn July 24, 2020, we completed the sale of a portion of this acreage for gross proceeds of approximately $14 million. To date, we have closed acreage sales for total gross proceeds of approximately $34 million,2 utilized in our oil and gas operations was industrial-sourced CO2, and we ~~currently have an additional $18 million under contract which is expected to close~~anticipate this percentage could increase in the ~~second half~~future as supportive U.S. government policy and public pressure on industrial CO2 emitters will provide strong incentives for these entities to capture their CO2 emissions. In an effort to proactively pursue these new CCUS opportunities, we are engaged in discussions with existing and potential third-party industrial CO2 emitters regarding transportation and storage solutions, while also identifying potential future sequestration sites and landowners of ~~2020.~~

~~Suspension of Trading on~~those locations. While EOR is the ~~NYSE~~. Our common stock was traded on the New York Stock Exchange (the “NYSE”) under the symbol “DNR” until July 29, 2020. On July 31, 2020, the NYSE notified us of its determination to commence proceedings to delistonly CCUS operation reflected in our ~~common stock from the NYSE,~~current and ~~as of July 31, 2020 to indefinitely suspend trading~~historical financial and operational results, and development of our ~~common stock on the NYSE. Suspension of trading~~permanent carbon sequestration business is likely to take several years, we believe Denbury is well positioned to leverage our existing CO2 pipeline infrastructure and EOR expertise to be a leader in our common stock and delisting proceedings were undertaken by the NYSE in accordance with Section 802.01D of the NYSE Listed Company Manual due to our filing of the Chapter 11 Restructuring on July 30, 2020. Our common stock now trades on the OTC Pink Open Market under the symbol “DNRCQ”. We can provide no assurance that we are current in its reporting obligations or that the trading volume of our common stock will be sufficient to provide for an efficient trading market.this industry.

CAPITAL RESOURCES AND LIQUIDITY

Overview. Our primary sources of capital and liquidity are our cash ~~flow~~flows from operations and ~~cash on hand, which has been supplemented by proceeds from~~availability under our ~~March 2020 sale of working interests in four southeast Texas fields and periodically by sales of surface land with no active oil and natural gas operations.~~senior secured bank credit facility. Our most significant cash capital outlays in 2021 relate to our $250 million to $270 million of budgeted development capital expenditures and $70 million of pipeline financing obligations associated with the NEJD pipeline. Based on our current ~~period operating expenses,~~2021 full-year projections using recent oil price futures, we currently expect that our cash flow from operations in 2021 will more than cover our budgeted development capital expenditures and also cover a significant portion of our ~~debt service~~pipeline financing obligations. In addition, we have sold certain non-producing assets that will further supplement our cash flow from operations.

As ~~discussed above, NYMEX~~of June 30, 2021, we had $35 million of outstanding borrowings on our $575 million senior secured bank credit facility, leaving us with $517.7 million of borrowing base availability after consideration of $22.3 million of outstanding letters of credit. Our borrowing base availability, coupled with unrestricted cash of $13.6 million, provides us total liquidity of $531.3 million as of June 30, 2021, which is more than adequate to meet our currently planned operating and capital needs.

2021 Plans and Capital Budget. Considering the current oil ~~prices have decreased significantly since~~price environment and strategic importance of the ~~beginning~~EOR CO2 flood at Cedar Creek Anticline (“CCA”), we announced in February 2021 our plans to move forward with development of ~~2020, decreasing~~this significant long-term project. We expect to spend approximately $150 million in 2021 on this CCA development, consisting of approximately $100 million dedicated to the 105-mile extension of the Greencore CO2 pipeline from ~~nearly $60 per barrel~~Bell Creek to CCA, with the remainder dedicated to facilities, well work and field development at CCA. Based on our current plans, most of the capital spend for the pipeline extension to CCA will occur in ~~early January to around $25 per barrel in mid-May (although considerably lower during~~ the ~~month~~second half of ~~April 2020), before rebounding to nearly $40 per Bbl at~~2021, with completion of the pipeline expected by the end of ~~June 2020. This decrease~~2021, first CO2 injection planned during the first half of 2022, and first tertiary production expected in the ~~market prices for~~second half of 2023. We currently anticipate that our production directly reduces our operating cash flow and indirectly impacts our other sources of potential liquidity, such as possibly lowering our borrowing capacity under our revolving credit facility, as our borrowing capacity and borrowing costs are generally related to the estimated value of our proved reserves.

~~In this low oil price environment, we have taken various steps to preserve our liquidity including (1) by reducing our 2020 budgeted~~full-year 2021 development capital spending, ~~by 44% from initial levels~~excluding capitalized interest and ~~to less than half of 2019 levels, (2) by deferring the Cedar Creek Anticline CO~~₂ tertiary flood development project beyond 2020, (3) by continuing to focus on reducing our operating and overhead costs, (4) by restructuring certain of our three-way collars covering 14,500 Bbls/d into fixed-price swaps for the second through fourth quarters of 2020 to increase downside protection against current and potential further declines in oil prices, (5) by evaluating production economics and shutting in production beginning in late March that was uneconomic to produce or repair based on prevailing oil prices, and (6) by conducting a complete market-based review of strategic alternatives, including a comprehensive restructuring, to enhance our liquidity and strengthen our capital structure.

~~Chapter 11 Restructuring and Effect of Automatic Stay.~~ On July 30, 2020, Denbury filed for relief under chapter 11 of the Bankruptcy Code in the United State Bankruptcy Court for the Southern District of Texas. The commencement of a voluntary proceeding in bankruptcy constituted an immediate event of default under the Bank Credit Agreement, the indentures governing the Company’s senior secured second lien notes, convertible senior notes, and senior subordinated notes and the agreements governing our NEJD pipeline lease financing. In conjunction with the negotiation of the RSA, the Company did not make the $7.8 million interest payment due on our 6⅜% Convertible Senior Notes due 2024 on June 30, 2020, and the $3.1 million interest payment due on our 4⅝% Senior Subordinated Notes due 2023 on July 15, 2020. Any efforts to enforce payment obligations related to the acceleration of the Company’s debt have been automatically stayed as a result of the filing of the Chapter 11 Restructuring, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code. Refer to Note 1, ~~Basis of Presentation~~ – ~~Entry into Restructuring Support Agreement and Voluntary Reorganization under Chapter 11 of the Bankruptcy Code,~~ ~~to the condensed consolidated financial statements for more information on the Chapter 11 Restructuring.~~

We expect to continue operations in the normal course for the duration of the Chapter 11 Restructuring. On July 31, 2020, the Bankruptcy Court entered orders approving certain customary “first day” relief to enable Denbury to operate in the ordinary course during the Chapter 11 Restructuring, including approval on an interim basis of post-petition financing under a DIP Facility and use of cash collateral of Denbury’s lenders and secured noteholders. Denbury is currently soliciting votes to accept the Plan from holders of claims and interests entitled to vote. On July 31, 2020, the Bankruptcy Court entered orders designed to assist

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Denbury ~~Resources~~ Inc.

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

acquisitions, will be in a range of $250 million to $270 million. Our current 2021 capital budget, excluding capitalized interest and acquisitions, at the $260 million midpoint level is as follows:

•$100 million for the Company in preserving certain of its tax attributes, including its net operating losses and tax credits, by establishing procedures and notice requirements prohibiting stockholders and potential stockholders with beneficial ownership or rights to acquire 4.5% or more105-mile extension of the ~~Company’s issued~~Greencore CO2 pipeline to CCA;

•$50 million for CCA tertiary well work, facilities, and ~~outstanding shares of common stock on~~field development;

•$50 million allocated for other tertiary oil field development;

•$35 million allocated for non-tertiary oil field development; and

•$25 million for other capital items such as capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.

We currently anticipate 2021 average daily sales volumes to be between 47,500 BOE/d and 51,500 BOE/d, including the Big Sand Draw and Beaver Creek working interests acquisition which closed in early March 2021.

Capital Expenditure Summary. The following table reflects incurred capital expenditures (including accrued capital) for the six months ended June 30, ~~2020 from increasing or decreasing their ownership~~2021 and 2020:


	Six Months Ended
	June 30,
In thousands	2021		2020
Capital expenditure summary
CCA tertiary development	$	10,260	$	2,151
Other tertiary oil fields	20,774		17,769
Non-tertiary fields	19,523		13,248
Capitalized internal costs(1)	14,785		18,344
Oil and natural gas capital expenditures	65,342		51,512
CCA CO2 pipeline	8,839		8,374
Other CO2 pipelines, sources and other	—		158
Development capital expenditures	74,181		60,044
Acquisitions of oil and natural gas properties(2)	10,811		80
Capital expenditures, before capitalized interest	84,992		60,124
Capitalized interest	2,251		18,181
Capital expenditures, total	$	87,243	$	78,305

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

(2)Primarily consists of the Company’s common stock without providing prior notice of the proposed transactions, which transfers then may require prior consent of the Bankruptcy Court. Any actions in violation of these procedures (including the notice requirements) are null and void ab initio and may be punished by contempt or other sanctions imposed by the Bankruptcy Court. For details of the procedures, see Exhibit 10(f) to this Form 10-Q, which is incorporated by reference herein. The final hearing on approval of the DIP Facility and use of cash collateral is currently scheduled for September 2, 2020.

~~Going Concern.~~ ~~As discussed above, the filing of the Chapter 11 Restructuring on July 30, 2020 constituted an event of default under all of our outstanding debt agreements, resulting~~working interest positions in the automatic and immediate acceleration of the Company’s debt outstanding, with the exception of our capital leases and our obligations under our Free State pipeline transportation agreement. At that date, the Company did not have sufficient cashWind River Basin enhanced oil recovery fields acquired on ~~hand or available liquidity to repay such debt.~~March 3, 2021.

Our operations and ability to develop and execute our business plan are subject to risk and uncertainty associated with the Chapter 11 Restructuring. The outcome of the Chapter 11 Restructuring is subject to factors that are outside of the Company’s control, including actions of the Bankruptcy CourtBased on current oil prices and the Company’s ~~creditors. There can be no assurance~~hedge positions, we expect that weour 2021 cash flows from operations will ~~confirm and consummate the Plan as contemplated by the RSA or complete another plan~~exceed our budgeted level of reorganization with respect to the Chapter 11 Restructuring. As a result, we have concluded that management’s plans do not alleviate substantial doubt about our ability to continue as a going concern.

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

planned development capital expenditures.

~~DIP Facility.~~

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

~~Exit Financing.~~ On July 28, 2020, prior to the commencement of the Chapter 11 Restructuring, the Company entered into an Exit Commitment Letter with the consenting lenders of the Company’s Bank Credit Agreement and/or their affiliates, which is subject to the satisfaction of certain customary conditions, including the approval of the Bankruptcy Court. As part of the RSA, the consenting lenders of the Company’s Bank Credit Agreement and/or their affiliates have agreed to provide, on a committed basis, the Company with the Exit Facility on the terms set forth in the exit term sheet attached to the RSA (the “Exit Facility Term Sheet”). The Exit Facility Term Sheet provides for, among other things, post-emergence financing in the form of a senior secured revolving credit facility ~~in an aggregate principal amount~~with a maturity date of ~~up to $615 million (the “Exit Facility”), subject to an initial~~January 30, 2024. As part of our spring 2021 semiannual borrowing base redetermination, the borrowing base and lender commitments for our Bank Credit Agreement were reaffirmed at $575 million, with our next scheduled redetermination around November 2021. The borrowing base is adjusted at the ~~closing of the Exit Facility. Any loans drawn~~lenders’ discretion and is based, in part, upon external factors over which we have no control. If our outstanding debt under the ~~Exit Facility will~~Bank Credit Agreement exceeds the then-effective borrowing base, we would be ~~non-amortizing.~~required to repay the excess amount over a

The effectiveness of the Exit Facility will be subject to customary closing conditions, including consummation of the Plan. The foregoing description of the Exit Facility Term Sheet does not purport to be complete and is qualified in its entirety by reference to the final, executed documents memorializing the Exit Facility, to be included in a supplement to the Plan to be filed with the Bankruptcy Court.20

Table of Contents

Denbury ~~Resources~~ Inc.

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

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

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

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

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

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

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

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

~~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.~~time.

Under these financial performance covenant calculations, as of June 30, ~~2020,~~2021, our ratio of consolidated total debt to consolidated EBITDAX was ~~5.08~~0.18 to 1.0 (with a maximum permitted ratio of ~~5.25~~3.5 to 1.0), our consolidated senior secured debt to consolidated EBITDAX was 0.59 to 1.0 (with a maximum permitted ratio of 2.5 to 1.0), our ratio of consolidated EBITDAX to consolidated interest charges was 2.40 to 1.0 (with a required ratio of not less than 1.25 to 1.0), and our current ratio was ~~2.86~~3.00 to 1.0 (with a required ratio of not less than 1.0 to 1.0). Based upon our currently forecasted levels of production and costs, hedges in place as of August 4, 2021, and current oil commodity derivative futures prices, we currently anticipate continuing to be in compliance with our financial performance covenants during the foreseeable future.

The above description of our Bank Credit Agreement is qualified by the express language and defined terms contained in the Bank Credit Agreement, ~~and the amendments thereto, each of~~ which ~~are filed as exhibits~~is an exhibit to our ~~periodic reports~~Form 8-K Report filed with the ~~SEC.~~SEC on September 18, 2020.

Commitments and Obligations. We have numerous contractual commitments in the ordinary course of business including debt service requirements, operating and finance leases, purchase obligations, and asset retirement obligations. Our operating leases primarily consist of our office leases. Our purchase obligations represent future cash commitments primarily for purchase contracts for CO2 captured from industrial sources, CO2 processing fees, transportation agreements and well-related costs.

~~Table~~Our commitments and obligations consist of ~~Contents~~those detailed as of December 31, 2020, in our Form 10-K under

~~Denbury Resources Inc.~~

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

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

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

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


•	~~$10 million to be spent on CO~~₂ ~~sources and pipelines; and~~

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

~~Capital Expenditure Summary.~~ ~~The following table reflects incurred capital expenditures (including accrued capital) for~~During the six months ended June 30, ~~2020~~2021, our long-term asset retirement obligations increased by $47.3 million, primarily related to our acquisition of working interest positions in Wyoming CO2 EOR fields (see Note 2, Acquisition and ~~2019:~~Divestiture).

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


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

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

~~Our commitments and obligations consist of those detailed as of December 31, 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~~.

Table of Contents

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~~Certain of our ~~overall operations~~financial and operating results and statistics for the comparative three and six months ended June 30, 2021 and 2020 are ~~our primary long-term strategic focus. The economics~~included in the following table:


	Successor		Predecessor		Successor		Predecessor
In thousands, except per-share and unit data	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
Financial results
Net loss(1)	$	(77,695)	$	(697,474)	$	(147,337)	$	(623,458)
Net loss per common share – basic(1)	(1.52)		(1.41)		(2.91)		(1.26)
Net loss per common share – diluted(1)	(1.52)		(1.41)		(2.91)		(1.26)
Net cash provided by operating activities	90,882		10,969		143,538		72,811
Average daily sales volumes
Bbls/d	47,653		48,900		46,834		51,774
Mcf/d	8,882		7,737		8,494		7,818
BOE/d(2)	49,133		50,190		48,250		53,077
Oil and natural gas sales
Oil sales	$	280,577	$	108,538	$	513,621	$	337,115
Natural gas sales	2,131		849		4,532		1,896
Total oil and natural gas sales	$	282,708	$	109,387	$	518,153	$	339,011
Commodity derivative contracts(3)
Receipt (payment) on settlements of commodity derivatives	$	(63,343)	$	45,629	$	(101,796)	$	70,267
Noncash fair value gains (losses) on commodity derivatives	(109,321)		(85,759)		(186,611)		36,374
Commodity derivatives income (expense)	$	(172,664)	$	(40,130)	$	(288,407)	$	106,641
Unit prices – excluding impact of derivative settlements
Oil price per Bbl	$	64.70	$	24.39	$	60.59	$	35.78
Natural gas price per Mcf	2.64		1.21		2.95		1.33
Unit prices – including impact of derivative settlements(3)
Oil price per Bbl	$	50.10	$	34.64	$	48.58	$	43.23
Natural gas price per Mcf	2.64		1.21		2.95		1.33
Oil and natural gas operating expenses
Lease operating expenses	$	110,225	$	81,293	$	192,195	$	190,563
Transportation and marketing expenses	8,522		9,388		16,319		19,009
Production and ad valorem taxes	21,836		8,766		39,731		26,753
Oil and natural gas operating revenues and expenses per BOE
Oil and natural gas revenues	$	63.23	$	23.95	$	59.33	$	35.09
Lease operating expenses	24.65		17.80		22.01		19.73
Transportation and marketing expenses	1.91		2.06		1.87		1.97
Production and ad valorem taxes	4.88		1.92		4.55		2.77
CO2 – revenues and expenses
CO2 sales and transportation fees	$	10,134	$	6,504	$	19,362	$	14,532
CO2 operating and discovery expenses	(1,531)		(885)		(2,524)		(1,637)
CO2 revenue and expenses, net	$	8,603	$	5,619	$	16,838	$	12,895

(1)Includes a pre-tax full cost pool ceiling test write-down of ~~a tertiary field~~$14.4 million during the first quarter of 2021, as compared to write-downs of $662.4 million and $735.0 million for the ~~related impact on our financial statements differ from a conventional~~three and six months ended June 30, 2020, respectively.

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

(3)~~Management’s Discussion and Analysis of Financial Condition and Results of Operations~~See also Commodity Derivative Contracts –below and ~~Financial Overview of Tertiary Operations~~Item 3. Quantitative and Qualitative Disclosures about Market Risk infor information concerning our ~~Form 10-K for further information regarding these matters.~~derivative transactions.

2922

Table of Contents

Denbury ~~Resources~~ Inc.

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

~~Operating Results Table~~

Sales Volumes

~~Certain~~

Average daily sales volumes by area for each of the four quarters of 2020 and for the first and second quarters of 2021 is shown below:


	Average Daily Sales Volumes (BOE/d)
	First Quarter	Second Quarter	First Quarter	Second Quarter	Third Quarter	Fourth Quarter
Operating Area	2021	2021	2020	2020	2020	2020
Tertiary oil sales
Gulf Coast region
Delhi	2,925	2,931	3,813	3,529	3,208	3,132
Hastings	4,226	4,487	5,232	4,722	4,473	4,598
Heidelberg	4,054	3,942	4,371	4,366	4,256	4,198
Oyster Bayou	3,554	3,791	3,999	3,871	3,526	3,880
Tinsley	3,424	3,455	4,355	3,788	4,042	3,654
Other(1)	6,098	6,074	7,161	5,944	6,271	6,332
Total Gulf Coast region	24,281	24,680	28,931	26,220	25,776	25,794
Rocky Mountain region
Bell Creek	4,614	4,394	5,731	5,715	5,551	5,079
Other(2)	2,573	4,378	2,199	1,393	2,167	2,007
Total Rocky Mountain region	7,187	8,772	7,930	7,108	7,718	7,086
Total tertiary oil sales	31,468	33,452	36,861	33,328	33,494	32,880
Non-tertiary oil and gas sales
Gulf Coast region
Total Gulf Coast region	3,621	3,415	4,173	3,805	3,728	3,523
Rocky Mountain region
Cedar Creek Anticline	11,150	10,918	13,046	11,988	11,485	11,433
Other(2)	1,118	1,348	1,105	1,069	979	969
Total Rocky Mountain region	12,268	12,266	14,151	13,057	12,464	12,402
Total non-tertiary sales	15,889	15,681	18,324	16,862	16,192	15,925
Total continuing sales	47,357	49,133	55,185	50,190	49,686	48,805
Property sales
Gulf Coast Working Interests Sale(3)	—	—	780	—	—	—
Total sales	47,357	49,133	55,965	50,190	49,686	48,805

(1)Includes our mature properties (Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb and Soso fields) and West Yellow Creek Field.

(2)Includes sales volumes related to our working interest positions in the Big Sand Draw and Beaver Creek fields acquired on March 3, 2021.

(3)Includes non-tertiary sales related to the March 2020 sale of 50% of our ~~operating results~~working interests in Webster, Thompson, Manvel, and ~~statistics for~~East Hastings fields (the “Gulf Coast Working Interests Sale”).

Total sales volumes during the ~~comparative three~~second quarter of 2021 averaged 49,133 BOE/d, including 33,452 Bbls/d from tertiary properties and ~~six months ended June 30, 2020 and~~ ~~2019~~ ~~are included~~15,681 BOE/d from non-tertiary properties. This sales volume represents an increase of 1,776 BOE/d (4%) compared to sales levels in the ~~following table:~~first quarter of 2021 and a decrease of 1,057 BOE/d (2%) compared to second quarter of 2020. The increase on a sequential-quarter basis was primarily attributable to our Wind River Basin acquisition in March 2021 and sales from these properties during the most recent quarter.

Three Months Ended Six Months Ended
June 30, June 30,
In thousands, except per-share and unit data 2020 2019 2020 2019
Operating results
Net income (loss)⁽¹⁾
$ (697,474 ) $ 146,692
$ (623,458 ) $ 121,018
Net income (loss) per common share – basic⁽¹⁾
(1.41 ) 0.32
(1.26 ) 0.27
Net income (loss) per common share – diluted⁽¹⁾
(1.41 ) 0.32
(1.26 ) 0.26
Net cash provided by operating activities 10,969
148,634
72,811
213,000
Average daily production volumes

Bbls/d 48,900
58,034
51,774
57,726
Mcf/d 7,737
10,111
7,818
10,467
BOE/d⁽²⁾
50,190
59,719
53,077
59,470
Operating revenues

Oil sales $ 108,538
$ 328,571
$ 337,115
$ 620,536
Natural gas sales 849
1,850
1,896
4,462
Total oil and natural gas sales $ 109,387
$ 330,421
$ 339,011
$ 624,998
Commodity derivative contracts⁽³⁾

Receipt (payment) on settlements of commodity derivatives $ 45,629
$ (1,549 ) $ 70,267
$ 6,657
Noncash fair value gains (losses) on commodity derivatives⁽⁴⁾
(85,759 ) 26,309
36,374
(65,274 )
Commodity derivatives income (expense) $ (40,130 ) $ 24,760
$ 106,641
$ (58,617 )
Unit prices – excluding impact of derivative settlements

Oil price per Bbl $ 24.39
$ 62.22
$ 35.78
$ 59.39
Natural gas price per Mcf 1.21
2.01
1.33
2.35
Unit prices – including impact of derivative settlements⁽³⁾

Oil price per Bbl $ 34.64
$ 61.92
$ 43.23
$ 60.03
Natural gas price per Mcf 1.21
2.01
1.33
2.35
Oil and natural gas operating expenses

Lease operating expenses $ 81,293
$ 117,932
$ 190,563
$ 243,355
Transportation and marketing expenses 9,388
11,236
19,009
22,009
Production and ad valorem taxes 8,766
23,526
26,753
45,560
Oil and natural gas operating revenues and expenses per BOE

Oil and natural gas revenues $ 23.95
$ 60.80
$ 35.09
$ 58.06
Lease operating expenses 17.80
21.70
19.73
22.61
Transportation and marketing expenses 2.06
2.07
1.97
2.04
Production and ad valorem taxes 1.92
4.33
2.77
4.23
CO₂ sources – revenues and expenses

CO₂ sales and transportation fees
$ 6,504
$ 7,986
$ 14,532
$ 16,556
CO₂ discovery and operating expenses
(885 ) (581 ) (1,637 ) (1,137 )
CO₂ revenue and expenses, net
$ 5,619
$ 7,405
$ 12,895
$ 15,419
23


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


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

Table of Contents

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 receipts on settlements of $45.6 million and $70.3 million for the three and six months ended June 30, 2020, respectively,The year-over-year decline was primarily impacted by (1) the carryover impact of exceptionally low levels of capital investment in 2020, significantly below levels required to hold production flat, (2) decreases at CCA due to the net profits interest of a third party, whereby increased oil prices have resulted in increased profitability and thus, lower reported sales volumes net to Denbury of approximately 625 BOE/d when compared to payments on settlements of $1.5 million for the three months ended June 30, 2019 and receipts on settlements of $6.7 million for the six months ended June 30, 2019. 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.

~~Table of Contents~~

~~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~~ ~~2019~~ ~~and for the~~ ~~first and second quarters~~ of ~~2020~~ ~~is shown below:~~

Average Daily Production (BOE/d)

First
Quarter

Second
Quarter

Third
Quarter

Fourth
Quarter

First
Quarter

Second
Quarter
Operating Area 2019 2019
2019
2019 2020
2020
Tertiary oil production
Gulf Coast region
Delhi 4,474
4,486

4,256

4,085
3,813
3,529
Hastings 5,539
5,466

5,513

5,097
5,232
4,722
Heidelberg 3,987
4,082

4,297

4,409
4,371
4,366
Oyster Bayou 4,740
4,394

3,995

4,261
3,999
3,871
Tinsley 4,659
4,891

4,541

4,343
4,355
3,788
West Yellow Creek 436
586
728
807
775
695
Mature properties⁽¹⁾
6,479
6,448
6,415
6,347
6,386
5,249
Total Gulf Coast region 30,314

30,353

29,745

29,349

28,931
26,220
Rocky Mountain region

Bell Creek 4,650
5,951

4,686

5,618
5,731
5,715
Salt Creek 2,057
2,078
2,213
2,223
2,149
1,386
Grieve 52
41
58
60
50
7
Total Rocky Mountain region 6,759
8,070

6,957

7,901
7,930
7,108
Total tertiary oil production 37,073
38,423

36,702

37,250
36,861
33,328
Non-tertiary oil and gas production

Gulf Coast region

Mississippi 1,034
1,025
873
952
748
713
Texas 3,298
3,224
3,165
3,212
3,419
3,087
Other 10
6
6
5
6
5
Total Gulf Coast region 4,342
4,255

4,044

4,169
4,173

3,805
Rocky Mountain region

Cedar Creek Anticline 14,987
14,311

13,354

13,730
13,046

11,988
Other 1,313
1,305

1,238

1,192
1,105

1,069
Total Rocky Mountain region 16,300
15,616

14,592

14,922
14,151

13,057
Total non-tertiary production 20,642
19,871

18,636

19,091

18,324

16,862
Total continuing production 57,715
58,294

55,338

56,341
55,185

50,190
Property sales

Gulf Coast Working Interests Sale⁽²⁾
1,047
1,019
1,103
1,170
780
—
Citronelle⁽³⁾
456
406
—
—
—
—
Total production 59,218
59,719
56,441
57,511
55,965
50,190


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


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


~~(3)~~	~~Includes production from Citronelle Field sold in July 2019.~~

~~Total continuing production during the~~ ~~second quarter~~ of ~~2020~~ ~~averaged 50,190 BOE/d, including 33,328 Bbls/d from tertiary properties and 16,862 BOE/d from non-tertiary properties. Total continuing production for prior periods excludes production~~

~~Table of Contents~~

~~Denbury Resources Inc.~~

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

related to the Gulf Coast Working Interests Sale completed in early March 2020 and Citronelle Field sold in July 2019. This total continuing production level represents a decrease of 4,995 BOE/d (9%) compared to total continuing production levels in the first quarter of 2020 and a decrease of 8,104 BOE/d (14%) compared to second quarter of 2019 continuing production, primarily due to production shut-in due to wells that were uneconomic to produce or repair during the quarter. We estimate the impact to second quarter 2020 production from the shut-in wells was approximately 4,300 BOE/d.

As a result of the significant decline in oil prices, we focused our efforts beginning late in the first quarter to optimize cash flow through evaluating production economics and began shutting in production beginning in late March 2020. Throughout the second quarter of 2020, ~~we continued evaluations around expected oil prices~~ and ~~production costs~~(3) declines at Delhi Field due to lower CO2 purchases between late-February and ~~began to restore some of these wells to production during May~~late-October 2020 as a result of the Delta-Tinsley pipeline being down for repair. The year-over-year decline in sales volumes was partially offset by sales increases from our Wind River Basin enhanced oil prices trended higher. As such, as of quarter-end, we estimate that approximately 1,700 BOE/d of production remained shut-in as of June 30, 2020 attributable to uneconomic wells. We plan to continue this routine evaluation to assess levels of uneconomic production basedrecovery fields acquired on our expectations for wellhead oil prices and variable production costs and will actively make decisions to either shut-in additional production or bring production back online as conditions warrant. Production could be further curtailed by future regulatory actions or limitations in storage and/or takeaway capacity.March 3, 2021.

Our ~~production~~sales volumes during the three and six months ended June 30, ~~2020 was~~2021 were 97% oil, consistent with our 97% and 98% oil ~~production~~sales during the same prior-year ~~period; whereas, production during the six months ended June 30, 2020 was 98% oil, slightly higher than our 97% oil production during the prior-year period.~~periods.

Oil and Natural Gas Revenues

Our oil and natural gas revenues during the three and six months ended June 30, ~~2020 decreased 67%~~2021 increased 158% and ~~46%~~53%, respectively, compared to these revenues for the same periods in ~~2019.~~2020. The changes in our oil and natural gas revenues are due primarily to ~~changes in production quantities and~~higher realized commodity prices (excluding any impact of our commodity derivative contracts), offset somewhat by changes in sales volumes, as reflected in the following table:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2021 vs. 2020				2021 vs. 2020
In thousands	Increase (Decrease) in Revenues		Percentage Increase (Decrease) in Revenues		Increase (Decrease) in Revenues		Percentage Increase (Decrease) in Revenues
Change in oil and natural gas revenues due to:
Decrease in sales volumes	$	(2,303)	(2)	%	$	(32,528)	(10)	%
Increase in realized commodity prices	175,624		160	%	211,670		63	%
Total increase in oil and natural gas revenues	$	173,321	158	%	$	179,142	53	%

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

~~Table of Contents~~

~~Denbury Resources Inc.~~

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

Excluding any impact of our commodity derivative contracts, our average net realized commodity prices and NYMEX differentials were as follows during the three months ended March 31, ~~2020~~2021 and ~~2019~~2020 and the three and six months ended June 30, ~~2020~~2021 and ~~2019:~~2020:


	Three Months Ended				Three Months Ended					Six Months Ended
	March 31,				June 30,				June 30,
	2021		2020		2021		2020			2021		2020
Average net realized prices
Oil price per Bbl	$	56.28	$	45.96	$	64.70	$	24.39		$	60.59	$	35.78
Natural gas price per Mcf	3.29		1.46		2.64		1.21			2.95		1.33
Price per BOE	55.24		45.09		63.23		23.95			59.33		35.09
Average NYMEX differentials
Gulf Coast region
Oil per Bbl	$	(1.37)	$	1.18	$	(1.13)	$	(3.59)		$	(1.23)	$	(0.53)
Natural gas per Mcf	0.68		(0.06)		(0.11)		(0.09)			0.30		(0.07)
Rocky Mountain region
Oil per Bbl	$	(1.80)	$	(2.78)	$	(1.59)	$	(4.68)		$	(1.54)	$	(3.25)
Natural gas per Mcf	0.49		(0.91)		(0.47)		(1.04)			(0.04)		(0.98)
Total Company
Oil per Bbl	$	(1.54)	$	(0.38)	$	(1.32)	$	(4.03)		$	(1.36)	$	(1.61)
Natural gas per Mcf	0.58		(0.41)		(0.33)		(0.54)			0.11		(0.48)

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Denbury Inc.

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

Three Months Ended Three Months Ended Six Months Ended
March 31, June 30, June 30,
2020 2019 2020 2019 2020 2019
Average net realized prices
Oil price per Bbl $ 45.96
$ 56.50
$ 24.39
$ 62.22
$ 35.78
$ 59.39
Natural gas price per Mcf 1.46
2.68
1.21
2.01
1.33
2.35
Price per BOE 45.09
55.27
23.95
60.80
35.09
58.06
Average NYMEX differentials

Gulf Coast region
Oil per Bbl $ 1.18
$ 4.26
$ (3.59 ) $ 4.85
$ (0.53 ) $ 4.55
Natural gas per Mcf (0.06 ) (0.10 ) (0.09 ) 0.10
(0.07 ) 0.00
Rocky Mountain region
Oil per Bbl $ (2.78 ) $ (2.56 ) $ (4.68 ) $ (1.48 ) $ (3.25 ) $ (1.97 )
Natural gas per Mcf (0.91 ) (0.28 ) (1.04 ) (1.13 ) (0.98 ) (0.67 )
Total Company
Oil per Bbl $ (0.38 ) $ 1.63
$ (4.03 ) $ 2.35
$ (1.61 ) $ 2.01
Natural gas per Mcf (0.41 ) (0.20 ) (0.54 ) (0.50 ) (0.48 ) (0.34 )

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

•

~~Gulf Coast Region~~. Our average NYMEX oil differential in the Gulf Coast region was a negative $3.59 per Bbl during the second quarter of 2020, compared to a positive $4.85 per Bbl during the second quarter of 2019 and a positive $1.18 per Bbl during the first quarter of 2020. Generally, our Gulf Coast region differentials are positive to NYMEX and highly correlated to the changes in prices of Light Louisiana Sweet crude oil, though

•Gulf Coast Region. Our average NYMEX oil differential in the Gulf Coast region was a negative $1.13 per Bbl during the second quarter of 2021, compared to a negative $3.59 per Bbl during the second quarter of 2020 and a negative $1.37 per Bbl during the first quarter of 2021. For both the first quarter of 2020 and for many years prior, our Gulf Coast region differentials were positive to NYMEX due to historically higher prices received for Gulf Coast crudes, such as Light Louisiana Sweet crude oil. As a result of the market disruptions, storage constraints and weak demand ~~caused these differentials to weaken significantly during the second quarter of 2020.~~

•

~~Rocky Mountain Region. NYMEX oil differentials in the Rocky Mountain region averaged $4.68 per Bbl and $1.48 per Bbl below NYMEX during the second quarters of 2020 and~~ ~~2019~~, respectively, and $2.78 per Bbl below NYMEX during the first quarter of 2020. Differentials in the Rocky Mountain region can fluctuate significantly on a month-to-month basis due to weather, refinery or transportation issues, and Canadian and U.S. crude oil price index volatility.

~~Our realized differentials during three and six months ended June 30, 2020 reflect the rapid and precipitous drop in demand for oil~~ caused by the COVID-19 coronavirus (“COVID-19”) pandemic, ~~which in turn has caused oil prices to plummet since~~these differentials weakened significantly during the first week of March 2020. These events have worsened a deteriorated oil market which followed the early-March 2020 failure by the group of oil producing nations known as OPEC+ to reach an agreement over proposed oil production cuts. Moreover, the uncertainty about the duration of the COVID-19 pandemic and its resulting economic consequences has caused storage constraints resulting from over-supply of produced oil and reduced refinery run rates, with these uncertainties expected to continue to significantly decrease our realized oil prices in the thirdsecond quarter of 2020 and ~~potentially longer. While our~~have remained lower than historical values since April 2020.

•Rocky Mountain Region. NYMEX oil differentials ~~have improved since May~~in the Rocky Mountain region averaged $1.59 per Bbl and $4.68 per Bbl below NYMEX during the second quarters of 2021 and 2020, respectively, and $1.80 per Bbl below NYMEX during the first quarter of 2021. Differentials in the Rocky Mountain region tend to fluctuate with regional supply and demand trends and can fluctuate significantly on a month-to-month basis due to weather, refinery or transportation issues, and Canadian and U.S. crude 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.~~price index volatility.

CO₂ Revenues and Expenses

We sell ~~approximately 20% to 25% of our produced~~ CO₂ produced 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

~~Table of Contents~~

~~Denbury Resources Inc.~~

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

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

~~Purchased~~ Oil Marketing 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~~“Oil marketing sales” and the expenses incurred to market and transport the oil as ~~“Purchased oil~~“Oil marketing 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, 2021 and 2020:


	Successor		Predecessor		Successor		Predecessor

In thousands	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
Receipt (payment) on settlements of commodity derivatives	$	(63,343)	$	45,629	$	(101,796)	$	70,267
Noncash fair value gains (losses) on commodity derivatives	(109,321)		(85,759)		(186,611)		36,374
Total income (expense)	$	(172,664)	$	(40,130)	$	(288,407)	$	106,641

Changes in our commodity derivatives expense were primarily related to the expiration of commodity derivative contracts, new commodity derivative contracts entered into for future periods, and to the changes in oil futures prices between the second quarters of 2020 and ~~2019~~:2021. The period-to-period changes reflect the very large fluctuations in oil prices between March 2020 ($30.45 per barrel), when worldwide financial markets were first beginning to absorb the potential impact of a global pandemic, and June 2021 oil prices ($71.35 per barrel) as prospects for increased economic activity and oil demand showed improvement.

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


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

In order to provide a level of price protection to a portion of our oil production, we have hedged a portion of our estimated oil production through ~~2020~~2022 using ~~both~~ NYMEX ~~and LLS~~ fixed-price swaps and ~~three-way~~costless collars. See Note 7,6, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements for additional details of our outstanding commodity

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Denbury Inc.

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

derivative contracts as of June 30, ~~2020,~~2021, 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 ~~7, 2020:~~4, 2021:


		2H 2021	1H 2022	2H 2022
WTI NYMEX	Volumes Hedged (Bbls/d)	29,000	15,500	9,000
Fixed-Price Swaps	Swap Price(1)	$43.86	$49.01	$56.35
WTI NYMEX	Volumes Hedged (Bbls/d)	4,000	11,000	10,000
Collars	Floor / Ceiling Price(1)	$46.25 / $53.04	$49.77 / $64.31	$49.75 / $64.18
	Total Volumes Hedged (Bbls/d)	33,000	26,500	19,000



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


~~(1)~~	~~Averages are volume weighted.~~


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

(1)Averages are volume weighted.

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

Based on current contracts in place and NYMEX oil futures prices as of August ~~7, 2020,~~4, 2021, which averaged approximately ~~$42~~$68 per Bbl, we currently expect that we would ~~receive~~make cash payments of approximately ~~$35~~$145 million upon settlement of our July through December ~~2020 contracts. Of this estimated~~2021 contracts, the amount ~~the majority relates to our three-way collars,~~of which ~~settlements are~~

~~Table of Contents~~

~~Denbury Resources Inc.~~

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

currently limited to the extent oil prices remain below the price of our sold puts. The weighted average differences between the floor and sold put prices of our 2020 three-way collars are $9.07 per Bbl and $8.83 per Bbl for NYMEX and LLS hedges, respectively. Settlements with respect to our fixed-price swaps areis primarily dependent upon fluctuations in future NYMEX oil prices in relation to the prices of our ~~2020~~2021 fixed-price swaps which have a weighted average ~~prices~~NYMEX oil price of ~~$40.52~~$43.69 per ~~Bbl and $51.67 per Bbl for NYMEX and LLS hedges, respectively.~~Bbl. 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


	Successor		Predecessor		Successor		Predecessor

In thousands, except per-BOE data	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
Total lease operating expenses	$	110,225	$	81,293	$	192,195	$	190,563

Total lease operating expenses per BOE	$	24.65	$	17.80	$	22.01	$	19.73

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

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

Total lease operating expenses ~~decreased $36.6~~increased $28.9 million ~~(31%~~(36%) and ~~$52.8~~$1.6 million ~~(22%~~(1%) on an absolute-dollar basis, or~~$3.90(18%~~ $6.85 (38%) and ~~$2.88 (13%~~$2.28 (12%) on a per-BOE basis, during the three and six months ended June 30, ~~2020,~~2021, respectively, compared to the same prior-year periods. The ~~decreases~~increase during the second quarter of 2021 on an absolute-dollar basis ~~were~~compared to the same period in 2020 was primarily due to ~~lower~~(a) higher expenses across nearly all expense categories as our costs are correlated to varying degrees with changes in oil prices, with the largest ~~decreases~~increases attributable to workovers ($8.4 million), CO2 expense ($4.4 million), and power and fuel ($3.7 million) and (b) 2020 period reduced spending and shut-in production in response to significantly lower oil prices in the second quarter of 2020. Lease operating expenses during the three months ended June 30, 2021 were further impacted by $7.1 million of expense related to the Wind River Basin acquisition in March 2021, as these properties have higher operating costs than our other fields. Lease operating expenses for the six months ended June 30, 2021 were relatively flat with the same prior-year period as increased expenses resulting from our Wind River Basin acquisition in March 2021 and increases in workover and CO2expense ~~labor,~~were largely offset by a $11.1 million reduction in power and fuel costs. The significant reduction in power and fuel costs was associated with the severe winter storm in February 2021 which created widespread power outages in Texas and CO₂ ~~purchase expense. In response~~disrupted the Company’s operations. Under certain of the Company’s power agreements the Company is compensated for its reduced power usage, which resulted in a benefit to the ~~significant decline~~Company of approximately $16.3 million; as of June 30, 2021, $9.9 million of these savings were included in ~~oil prices~~“Trade and other receivables, net” and $3.7 million included in ~~March 2020, we reduced~~“Other assets” in our ~~capital budget and implemented cost reduction measures which included shutting down compressors or delaying well repairs and workovers that were uneconomic.~~Unaudited Condensed Consolidated Balance Sheets. Compared to the first quarter of ~~2020,~~2021, lease operating expenses ~~decreased $28.0~~in the most recent quarter increased $28.3 million ~~(26%~~(34%) on an absolute-dollar basis ~~or $3.66 (17%~~and $5.42 (28%) on a per-BOE basis, due primarily to ~~lower workover expense and power and fuel costs resulting from~~ the ~~measures previously discussed~~.

~~Currently, our CO~~₂ ~~expense comprises approximately 20% to 25% of our typical tertiary lease operating expenses, and for the CO~~₂ ~~reserves we already own, consists of CO~~₂ ~~production expenses, and for the CO~~₂ ~~reserves we do not own, consists of our purchase of CO~~₂ ~~from royalty and working interest owners and industrial sources. During the second quarters of 2020 and 2019, approximately 46% and 56%, respectively, of the CO~~₂ ~~utilized in our CO~~₂ ~~floods consisted of CO~~₂ ~~owned and produced by us (our net revenue interest). The price we pay others for CO~~₂ ~~varies by source and is generally indexed to oil prices. When combining the production cost of the CO~~₂ ~~we own with what we pay third parties for CO~~₂~~, our average cost of CO~~₂ ~~was approximately $0.39 per Mcf during the~~ ~~second~~first quarter of ~~2020, including taxes paid on CO~~₂ ~~production but excluding depletion, depreciation and amortization of capital expended at our CO~~₂ ~~source fields and industrial sources. This per-Mcf CO~~₂ ~~cost during~~ 2021 utility benefit mentioned above, the second quarter of ~~2020 was higher than the $0.33 per Mcf comparable measure during the~~ ~~second quarter~~ of ~~2019~~ ~~and $0.36 per Mcf comparable measure during the first~~2021 reflecting a full quarter of ~~2020 due to a higher utilization~~operating expenses for the Wind River Basin properties acquired in March 2021, as well as increases in workover and CO2 expense.

Table of ~~industrial-sourced CO~~₂ ~~in our Gulf Coast operations, which has a higher average cost than our naturally-occurring CO~~₂ ~~source.~~Contents

Denbury Inc.

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

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 ~~$9.4~~$8.5 million and ~~$11.2~~$9.4 million for the three months ended June 30, ~~2020~~2021 and ~~2019,~~2020, respectively, and ~~$19.0~~$16.3 million and ~~$22.0~~$19.0 million for the six months ended June 30, 2021 and 2020, ~~and 2019,~~ respectively. The decreases between periods were primarily due to lower sales volumes.

Taxes Other Than Income

Taxes other than income includes production, ad valorem and franchise taxes. Taxes other than income ~~decreased $15.1~~increased $12.0 million ~~(59%~~(116%) and ~~$19.2~~$11.3 million ~~(39%~~(38%) during the three and six months ended June 30, ~~2020,~~2021, respectively, compared to the same prior-year periods, ~~in 2019,~~ due primarily to ~~a decrease~~an increase in production taxes resulting from ~~lower~~higher oil and natural gas revenues.

General and Administrative Expenses (“G&A”)


	Successor		Predecessor		Successor		Predecessor

In thousands, except per-BOE data and employees	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
Cash administrative costs	$	12,898	$	22,689	$	27,201	$	29,969
Stock-based compensation	2,552		1,087		20,232		3,540
G&A expense	$	15,450	$	23,776	$	47,433	$	33,509

G&A per BOE
Cash administrative costs	$	2.89	$	4.97	$	3.11	$	3.10
Stock-based compensation	0.57		0.24		2.32		0.37
G&A expenses	$	3.46	$	5.21	$	5.43	$	3.47

Employees as of period end	690		686

Our G&A expense on an absolute-dollar basis was $15.5 million during the three months ended June 30, 2021, a decrease of $8.3 million (35%) from the same prior-year period, primarily due to modifications in our compensation program during the second quarter of 2020 which resulted in adjustments to the bonus program for 2020, as well as certain severance-related costs recorded during the second quarter of 2020. During the six months ended June 30, 2021, our G&A expense increased $13.9 million (42%) primarily due to $15.3 million of stock-based compensation expense in the first quarter of 2021 resulting from the full vesting of performance-based equity awards with vesting parameters tied to the Company’s common stock trading prices. The shares underlying these awards are not currently outstanding as actual delivery of the shares is not scheduled to occur until after the end of the performance period, December 4, 2023.

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Denbury ~~Resources~~ Inc.

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

Interest and Financing Expenses

~~General and Administrative Expenses (“G&A”)~~

Three Months Ended Six Months Ended
June 30, June 30,
In thousands, except per-BOE data and employees 2020 2019 2020 2019
Gross cash compensation and administrative costs $ 55,196
$ 53,919
$ 95,632
$ 108,620
Gross stock-based compensation 1,687
4,669
4,891
8,975
Operator labor and overhead recovery charges (25,735 ) (30,740 ) (53,220 ) (60,615 )
Capitalized exploration and development costs (7,372 ) (10,342 ) (13,794 ) (20,549 )
Net G&A expense $ 23,776
$ 17,506
$ 33,509
$ 36,431

G&A per BOE

Net cash administrative costs $ 4.97
$ 2.56
$ 3.10
$ 2.74
Net stock-based compensation 0.24
0.66
0.37
0.64
Net G&A expenses $ 5.21
$ 3.22
$ 3.47
$ 3.38

Employees as of June 30⁽¹⁾
686
846


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


	Successor			Predecessor			Successor			Predecessor
In thousands, except per-BOE data and interest rates	Three Months Ended June 30, 2021			Three Months Ended June 30, 2020			Six Months Ended June 30, 2021			Six Months Ended June 30, 2020
Cash interest(1)	$	1,735		$	45,263		$	3,669		$	91,089
Less: interest not reflected as expense for financial reporting purposes(1)	—			(20,912)			—			(42,266)
Noncash interest expense	685			1,061			1,370			2,092
Amortization of debt discount(2)	—			3,934			—			7,829
Less: capitalized interest	(1,168)			(8,729)			(2,251)			(18,181)
Interest expense, net	$	1,252		$	20,617		$	2,788		$	40,563
Interest expense, net per BOE	$	0.28		$	4.51		$	0.32		$	4.20
Average debt principal outstanding(3)	$	107,542		$	2,185,029		$	121,392		$	2,186,322
Average cash interest rate(4)	6.5		%	8.3		%	6.0		%	8.3		%

~~Our net G&A expenses~~

(1)Cash interest during the Predecessor period includes the portion of interest on ~~an absolute-dollar basis increased $6.3 million (36%~~certain debt instruments accounted for as a reduction of debt for GAAP financial reporting purposes in accordance with FASC 470-60, Troubled Debt Restructuring by Debtors. The portion of interest treated as a reduction of debt related to the Predecessor’s 9% Senior Secured Second Lien Notes due 2021 (the “2021 Notes”) and 9¼% Senior Secured Second Lien Notes due 2022 (the “2022 Notes”). Amounts related to the 2021 Notes and 2022 Notes remaining in future interest payable were written-off on July 30, 2020 (the “Petition Date”).

(2)Represents amortization of debt discounts during the Predecessor period related to the 7¾% Senior Secured Second Lien Notes due 2024 (the “7¾% Senior Secured Notes”) and 6⅜% Convertible Senior Notes due 2024 (the “2024 Convertible Senior Notes”). Remaining debt discounts were written-off on the Petition Date.

(3)Excludes debt discounts related to the Predecessor’s 7¾% Senior Secured Notes and 2024 Convertible Senior Notes.

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

Cash interest during the three ~~months ended June 30, 2020 compared to the same period in 2019, primarily due to $2.4 million in severance-related costs during the second quarter of 2020~~ and an incremental $6.3 million in performance and bonus-related compensation expense compared to the prior-year period due primarily to the modifications to our compensation program as discussed in Note 6, ~~Stock Compensation~~, to the condensed consolidated financial statements. In addition to these increases, G&A recoveries related to operator labor and overhead, and capitalized exploration and development costs increased net G&A expense by approximately $8.0 million as a result of reductions in employees, shut-in production and fewer producing wells in the current period; however, these costs were offset in part by lower overall employee compensation and related costs due to reduced employee headcount. On a per-BOE basis, net G&A expense increased nearly $2 (62%) due to the impact of higher expense and lower production, due in part to approximately 4,300 BOE/d that was shut-in during the second quarter of 2020. During the six months ended June 30, ~~2020, our net G&A expenses on an absolute-dollar basis~~2021 decreased ~~$2.9~~$43.5 million ~~(8%~~(96%) and $87.4 million (96%), ~~but increased $0.09 (3%) on a per-BOE basis,~~respectively, when compared to the same ~~period in 2019,~~prior-year periods. The decreases between periods were primarily due to ~~reduced employee headcount resulting from our December 2019 voluntary separation program and our May 2020 involuntary workforce reduction,~~a decrease in the average debt principal outstanding, with the ~~per-BOE change impacted by declines in production between 2019~~Successor periods reflecting the full extinguishment of all outstanding obligations under our previously outstanding senior secured second lien notes, convertible senior notes, and ~~2020.~~

On a sequential-quarter basis, net G&A expenses increased $14.0 million primarily due to an increase in compensation-related expenses. This increase was primarily due to modifications in our compensation program duringsenior subordinated notes on the ~~second quarter which resulted in adjustments~~Emergence Date, pursuant to the ~~bonus program for 2020 as compared to no accrual for bonuses~~terms of the prepackaged joint plan of reorganization, relieving us of approximately $2.1 billion of debt by issuing equity and/or warrants in the ~~first quarter of 2020 (see further discussion in Note 6,~~ ~~Stock Compensation~~,Successor period to the ~~condensed consolidated financial statements).~~holders of that debt.

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.28

Table of Contents

Denbury ~~Resources~~ Inc.

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

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

~~Interest and Financing Expenses~~


	Successor		Predecessor		Successor		Predecessor

In thousands, except per-BOE data	Three Months Ended June 30, 2021		Three Months Ended June 30, 2020		Six Months Ended June 30, 2021		Six Months Ended June 30, 2020
Oil and natural gas properties	$	28,550	$	40,290	$	60,565	$	82,859
CO2 properties, pipelines, plants and other property and equipment	7,831		15,124		15,266		32,049
Accelerated depreciation charge(1)	—		—		—		37,368
Total DD&A	$	36,381	$	55,414	$	75,831	$	152,276

DD&A per BOE
Oil and natural gas properties	$	6.39	$	8.82	$	6.94	$	8.58
CO2 properties, pipelines, plants and other property and equipment	1.75		3.31		1.74		3.31
Accelerated depreciation charge(1)	—		—		—		3.87
Total DD&A cost per BOE	$	8.14	$	12.13	$	8.68	$	15.76

Write-down of oil and natural gas properties	$	—	$	662,440	$	14,377	$	734,981

Three Months Ended Six Months Ended
June 30, June 30,
In thousands, except per-BOE data and interest rates 2020 2019 2020 2019
Cash interest⁽¹⁾
$ 45,263
$ 48,371
$ 91,089
$ 96,319
Less: interest not reflected as expense for financial reporting purposes⁽¹⁾
(20,912 ) (21,355 ) (42,266 ) (42,634 )
Noncash interest expense 1,061
1,194
2,092
2,457
Amortization of debt discount⁽²⁾
3,934
444
7,829
444
Less: capitalized interest (8,729 ) (8,238 ) (18,181 ) (18,772 )
Interest expense, net $ 20,617
$ 20,416
$ 40,563
$ 37,814
Interest expense, net per BOE $ 4.51
$ 3.76
$ 4.20
$ 3.51
Average debt principal outstanding⁽³⁾
$ 2,185,029
$ 2,559,822
$ 2,186,322
$ 2,550,278
Average cash interest rate⁽⁴⁾
8.3 % 7.6 % 8.3 % 7.6 %
(1)Represents an accelerated depreciation charge related to capitalized amounts associated with unevaluated properties that were transferred to the full cost pool.

~~(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 Financial Accounting Standards Board Codification (“FASC”) 470-60, ~~Troubled Debt Restructuring by Debtors~~. The portion of interest treated as a reduction of debt relates to our 2021 Senior Secured Notes and 9¼% Senior Secured Second Lien Notes due 2022 (the “2022 Senior Secured Notes”). See below for further discussion.


~~(2)~~	Represents amortization of debt discounts of $1.3 million and $2.6 million related to the 7¾% Senior Secured Second Lien Notes due 2024 (the “7¾% Senior Secured Notes”) during the three and six months ended June 30, 2020, respectively, and $2.6 million and $5.2 million related to the 2024 Convertible Senior Notes during the three and six months ended June 30, 2020, respectively.


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


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

~~As reflected~~The decreases in ~~the table above, cash interest~~DD&A expense during the three and six months ended June 30, 2020 decreased $3.1 million (6%) and $5.2 million (5%), respectively, when compared to the prior-year periods due primarily to a decrease in our average debt principal outstanding as a result of the June 2019 debt exchange transactions and debt repurchases completed in the second half of 2019 and first quarter of 2020. Meanwhile, net interest expense was relatively unchanged and increased $2.7 million (7%) during the three and six months ended June 30, 2020, respectively, compared to the prior-year periods due to the amortization of the debt discounts related to our 7¾% Senior Secured Notes and 2024 Convertible Senior Notes.

~~Future interest payable related to our~~ 2021, ~~Senior Secured Notes and 2022 Senior Secured Notes is accounted for in accordance with FASC 470-60,~~ ~~Troubled Debt Restructuring by Debtors~~, whereby most of the future interest was recorded as debt as of the transaction date, which will be reduced as semiannual interest payments are made. Future interest payable recorded as debt totaled $119.5 million as of June 30, 2020.

~~The June 2019 debt exchange transactions were accounted for in accordance with FASC 470-50,~~ ~~Modifications and Extinguishments, whereby our 7¾% Senior Secured Notes and 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.~~

In conjunction with the negotiation of the RSA, the Company did not make the $7.8 million interest payment due on our 2024 Convertible Senior Notes on June 30, 2020, and the $3.1 million interest payment due on our 4⅝% Senior Subordinated Notes due 2023 on July 15, 2020. However, as part of the RSA signed on July 28, 2020 by holders of our second lien notes, the Company paid them a total of $8.0 million in accrued and unpaid interest on the second lien notes.

~~Table of Contents~~

~~Denbury Resources Inc.~~

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

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

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

DD&A per BOE

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

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


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

~~The decrease in our depletion, depreciation, and amortization expense during the three months ended June 30, 2020,~~ when compared to the same ~~period~~periods in ~~2019, was~~2020, were primarily due to ~~a decrease in CO~~₂ ~~depletion as a result of~~ lower CO₂ ~~volumes from our CO~~₂ ~~sources. The increase in our DD&A expense during the six months ended June 30, 2020, when compared~~depletable costs due to the ~~same period~~step down in ~~2019, was primarily due to an~~book value resulting from fresh start accounting as of September 18, 2020, with the year-over-year decrease further impacted by accelerated depreciation ~~charge~~ of $37.4 million in the first quarter of 2020 related to ~~impaired~~ unevaluated properties that were transferred to the full cost ~~pool during the first quarter of 2020.~~pool.

Full Cost Pool Ceiling Test Write-Downs

Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation. Under these rules, the full cost ceiling value is calculated using the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period. The first-day-of-the-month oil prices for the preceding 12 months, after adjustments for market differentials by field, averaged $44.74 per Bbl and $55.17 per Bbl as of June 30, 2020 and March 31, 2020, respectively. In addition, the first-day-of-the-month natural gas prices for the preceding 12 months, after adjustments for market differentials by field, averaged $1.91 per MMBtu and $1.68 per MMBtu as of June 30, 2020 and March 31, 2020, respectively. While representative oil prices at March 31, 2020 were roughly consistent with adjusted prices used to calculate the December 31, 2019 full cost ceiling value, the decline in NYMEX oil prices in late March 2020 due to OPEC supply pressures and a reduction in worldwide oil demand amid the COVID-19 pandemic contributed to the impairment and transfer of $244.9 million of our unevaluated costs to the full cost amortization base during the three months ended March 31, 2020. Primarily as a result of adding these additional costs to the amortization base, weWe recognized a full cost pool ceiling test write-down of ~~$72.5~~$14.4 million during the three months ended March 31, ~~2020. In addition, as~~2021, with first-day-of-the-month NYMEX oil prices for the preceding 12 months averaging $36.40 per Bbl, after adjustments for market differentials and transportation expenses by field. The write-down was primarily a result of the ~~precipitous decline in~~recent acquisition (see Overview – March 2021 Acquisition of Wyoming CO2 EOR Fields) which was recorded based on a valuation that utilized NYMEX strip oil prices at the acquisition date, which were significantly higher than the average first-day-of-the-month NYMEX oil prices ~~during~~used to value the ~~second quarter of 2020, we~~cost ceiling. We also recognized ~~an additional~~ full cost pool ceiling test ~~write-down~~write-downs of $662.4 million and $72.5 million during the Predecessor three months ended June 30, 2020 and March 31, 2020, respectively. We did not record a ceiling test write-down during the three months ended June 30, 2020. If oil prices remain at or near early-August 2020 levels in subsequent periods, we currently expect that we would also record write-downs in subsequent quarters in 2020, as the 12-month average price used in determining the full cost ceiling value will continue to decline during each rolling quarterly period in 2020, subject to the date of the Company’s emergence from bankruptcy and potential impacts of fresh start accounting, if applicable. The possibility and amount of any future write-down or impairment is difficult to predict, and will depend, in part, upon oil and natural gas prices, the incremental proved reserves that may be added each period, revisions to previous reserve estimates and future capital expenditures and operating costs.

2021.

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Table of Contents

Denbury ~~Resources~~ Inc.

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

~~Impairment Assessment of Long-lived Assets~~

We test long-lived assets for impairment whenever events or changes in circumstances indicate that their carrying value may not be recoverable. These long-lived assets, which are not subject to our full cost pool ceiling test, are principally comprised of our capitalized 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) as of March 31, 2020.

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

~~Other Expenses~~

Other expenses totaled $11.3 million and $13.8 million during the three and six months ended June 30, 2020, respectively, compared to $2.4 million and $6.5 million during the three and six months ended June 30, 2019, respectively. Other expenses during 2020 are primarily comprised of $7.9 million of professional fees associated with restructuring activities, $1.6 million of costs associated with the Delta-Tinsley CO₂ pipeline incident, and $1.0 million of costs associated with the APMTG Helium, LLC helium supply contract ruling. The 2019 amounts are primarily comprised of $1.3 million of expense related to an impairment of assets, $1.3 million of acquisition transaction costs, and $1.0 million of transaction costs related to our privately negotiated debt exchanges.

Income Taxes


	Successor			Predecessor			Successor			Predecessor

In thousands, except per-BOE amounts and tax rates	Three Months Ended June 30, 2021			Three Months Ended June 30, 2020			Six Months Ended June 30, 2021			Six Months Ended June 30, 2020
Current income tax expense (benefit)	$	(260)		$	598		$	(451)		$	(5,809)
Deferred income tax benefit	(36)			(102,304)			(87)			(106,513)
Total income tax benefit	$	(296)		$	(101,706)		$	(538)		$	(112,322)
Average income tax benefit per BOE	$	(0.07)		$	(22.27)		$	(0.06)		$	(11.63)
Effective tax rate	0.4		%	12.7		%	0.4		%	15.3		%
Total net deferred tax liability	$	1,187		$	306,186

Three Months Ended Six Months Ended
June 30, June 30,
In thousands, except per-BOE amounts and tax rates 2020 2019 2020 2019
Current income tax expense (benefit) $ 598
$ 3,354
$ (5,809 ) $ 2,073
Deferred income tax expense (benefit) (102,304 ) 62,023
(106,513 ) 52,545
Total income tax expense (benefit) $ (101,706 ) $ 65,377
$ (112,322 ) $ 54,618
Average income tax expense (benefit) per BOE $ (22.27 ) $ 12.03
$ (11.63 ) $ 5.07
Effective tax rate 12.7 % 30.8 % 15.3 % 31.1 %
Total net deferred tax liability $ 306,186

$ 362,303

~~Table of Contents~~

~~Denbury Resources Inc.~~

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

We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. Our income taxes are based on an estimated combined federal and state statutory rate of approximately 25% in ~~2020~~2021 and ~~2019. As provided for under FASC 740-270-35-2, we determined the actual effective tax rate for the six months ended June 30, 2020 was the best estimate of our annual effective tax rate.~~2020. Our effective tax ~~rate~~rates for the Successor three and six months ended June 30, ~~2020 was~~2021 were significantly lower than our estimated statutory rate, primarily due to our overall deferred tax asset position and the ~~establishment~~valuation allowance offsetting those assets. As we had a pre-tax loss for the second quarter of 2021 and first half of 2021, the income tax benefit resulting from these losses is fully offset by the change in valuation allowance, resulting in essentially no tax provision.

The tax basis of our assets, primarily our oil and gas properties, is in excess of their carrying value, as adjusted in fresh start accounting; therefore, we are currently in a ~~full~~net deferred tax asset position. Based on all available evidence, both positive and negative, we continue to record a valuation allowance on our ~~enhanced oil recovery and research and development credits that currently are not expected to be utilized. We evaluated~~underlying deferred tax assets as of June 30, 2021, as we believe our deferred tax assets ~~in light~~are not more-likely-than-not to be realized. We intend to maintain the valuation allowances on our deferred tax assets until there is sufficient evidence to support the reversal of all ~~available evidence as~~or some portion of the ~~balance sheet date, including our cumulative loss position in consideration of recorded book full cost pool ceiling test write-downs and accelerated depreciation charge,~~allowances, which will largely be determined based on oil prices and the ~~Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) provisions. Based~~Company’s ability to generate positive pre-tax income. A $1.2 million state deferred tax liability is recorded on ~~our evaluation using all available evidence and in consideration of~~ the weight of existing negative evidence, we concluded that a full valuation allowance of $85.0 million on our $63.4 million of enhanced oil recovery credits and $21.6 million of research and development credits was required, as we believe the tax benefit of the tax credits are more-likely-than-not to not be realized. This is an increase in the valuation allowance of $74.0 million during the quarter ended June 30, 2020 over the $11.0 million valuation allowance established in the quarter ended March 31, 2020. The CARES Act signed into law in March 2020, among other provisions, modified the rules regarding the deductibility of business interest expense that were established by the Tax Cuts and Jobs Act of December 2017, increasing the limitation threshold from 30% to 50% of Adjusted Taxable Income (as defined) for 2019 and 2020. In addition, for the 2020 year, a taxpayer may elect to 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 fully released our previously recorded valuation allowance of $24.5 million during the three months ended March 31, 2020.Successor balance sheet.

The current income tax ~~benefit~~benefits for the Predecessor six months ended June 30, 2020, ~~represents~~represent amounts estimated to be receivable resulting from alternative minimum tax credits. ~~Alternative~~

As of June 30, 2021, we had $0.6 million of alternative minimum tax credits, ~~of $10.5 million~~which under the Tax Cut and Jobs Act will be refunded in 2021 and are ~~currently~~ recorded as a receivable on the balance sheet. Our state net operating loss carryforwards expire in various years, starting in 2025.

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Table of Contents

Denbury ~~Resources~~ Inc.

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

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
	June 30,		June 30,
Per-BOE data	2021			2020		2021		2020
Oil and natural gas revenues	$	63.23		$	23.95	$	59.33	$	35.09
Receipt (payment) on settlements of commodity derivatives	(14.17)			9.99		(11.65)		7.28
Lease operating expenses	(24.65)			(17.80)		(22.01)		(19.73)
Production and ad valorem taxes	(4.88)			(1.92)		(4.55)		(2.77)
Transportation and marketing expenses	(1.91)			(2.06)		(1.87)		(1.97)
Production netback	17.62			12.16		19.25		17.90
CO2 sales, net of operating and discovery expenses	1.93			1.23		1.93		1.33
General and administrative expenses(1)	(3.46)			(5.21)		(5.43)		(3.47)
Interest expense, net	(0.28)			(4.51)		(0.32)		(4.20)

Stock compensation and other	0.12			(1.71)		1.95		0.22
Changes in assets and liabilities relating to operations	4.40			0.44		(0.94)		(4.24)
Cash flows from operations	20.33			2.40		16.44		7.54
DD&A – excluding accelerated depreciation charge	(8.14)			(12.13)		(8.68)		(11.89)
DD&A – accelerated depreciation charge(2)	—			—		—		(3.87)
Write-down of oil and natural gas properties	—			(145.04)		(1.65)		(76.08)
Deferred income taxes	0.01			22.40		0.01		11.03
Gain on extinguishment of debt	—			—		—		1.97
Noncash fair value gains (losses) on commodity derivatives	(24.45)			(18.78)		(21.37)		3.76

Other noncash items	(5.13)			(1.56)		(1.62)		3.00
Net loss	$	(17.38)		$	(152.71)	$	(16.87)	$	(64.54)

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

(1)General and administrative expenses include $15.3 million of performance stock-based compensation related to the full vesting of outstanding performance awards during the six months ended June 30, 2021, resulting in a significant non-recurring expense, which if excluded, would have caused these expenses to average $3.68 per BOE.

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


~~(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 cash flows, and other plans and objectives for the future operations of Denbury, ~~and~~projections or assumptions as to general economic conditions, ~~are~~predictions as to the nature and economics of a carbon capture, use and storage industry (“CCUS”), and anticipated effects of COVID-19 on U.S. and global oil

Table of Contents

Denbury ~~Resources~~ Inc.

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

demand 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, among other things, ~~our ability to obtain Bankruptcy Court approval with respect to motions or other requests made to~~ the ~~Bankruptcy Court~~level and ~~the risks attendant to the bankruptcy process, our ability to confirm and consummate the Plan or an alternative restructuring transaction, the effects~~sustainability of the Chapter 11 Restructuring on our liquidity or results of operations or business prospects, the effects of the Chapter 11 Restructuring on our business and the interests of various constituents, the length of time that we will operate under chapter 11 protection, risks associated with third-party motions in the Chapter 11 Restructuring, the adequacy and restrictions of a DIP facility such as that contemplated by our lenders’ commitment letter, and the impact of all of these factors upon our ability to capitalize on the reorganization process and emerge as an entity equipped to operate as a going concern on a long-term basis, the extent and length of the droprecent recovery in worldwide oil ~~demand due to the~~prices from their COVID-19 coronavirus caused downturn, financial forecasts, future hydrocarbon prices and their volatility, current or future liquidity sources or their adequacy to support our anticipated future activities, ~~our ability~~statements or predictions related to ~~refinance~~the scope, timing and economic aspects of the carbon capture, use and storage industry or ~~extend the maturities~~results of ~~our long-term indebtedness which matures in 2021 and 2022,~~negotiations of CCUS arrangements, 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, production, 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, outcomes of pending litigation, prospective legislation affecting the oil and gas industry, environmental regulations, mark-to-market values, competition, rates of return, estimated costs, changes in costs, future capital expenditures and overall economics, worldwide economic conditions, ~~the likelihood and extent of an economic slowdown,~~ and other variables surrounding operations and future plans. Such forward-looking statements generally are accompanied by words such as “plan,” “estimate,” “expect,” “predict,” “forecast,” “to our knowledge,” “anticipate,” “projected,” “preliminary,” “should,” “assume,” “believe,” “may” or other words that convey, or are intended to convey, the uncertainty of future events or outcomes. Such forward-looking information is based upon management’s current plans, expectations, estimates, and assumptions and is subject to a number of risks and uncertainties that could significantly and adversely affect current plans, anticipated actions, the timing of such actions and our financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by us or on our behalf. Among the factors that could cause actual results to differ materially are ~~our ability to refinance our senior debt maturing in 2021 and the related impact on our ability to continue as a going concern,~~ fluctuations in worldwide oil prices or in U.S. oil prices and consequently in the prices received or demand for our oil ~~and natural gas; evolving political and military tensions in the Middle East;~~produced; decisions as to production levels and/or pricing by ~~OPEC~~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; 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 cybersecurity breaches, or from well incidents, hurricanes, tropical storms, floods, 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

As of June 30, ~~2020,~~2021, we had ~~$2.1 billion of fixed-rate debt outstanding and $265.0~~$35.0 million of outstanding borrowings under our Bank Credit Agreement. At this level of variable-rate debt, an increase or decrease of 10% in interest rates would have an immaterial effect on our interest expense. Our Bank Credit Agreement ~~senior secured second lien notes, convertible senior notes, and senior subordinated notes do~~does not have any triggers or covenants regarding our debt ratings with rating agencies. ~~The fair values of our senior secured second lien notes, convertible senior notes, and senior subordinated notes are based on quoted market prices.~~ The following table presents the principal and fair values of our outstanding debt as of June 30, ~~2020.~~2021:


In thousands	2021		2022		2023		2024		Total		Fair Value
Variable rate debt:
Senior Secured Bank Credit Facility (weighted average interest rate of 4.0% at June 30, 2021)	$	—	$	—	$	—	$	35,000	$	35,000	$	35,000

In thousands 2021 2022 2023 2024 Total Fair Value
Variable rate debt:
Senior Secured Bank Credit Facility (weighted average interest rate of 5.0% at June 30, 2020) $ 265,000
$ —
$ —
$ —
$ 265,000
$ 265,000
Fixed rate debt:

9% Senior Secured Second Lien Notes due 2021 584,709
—
—
—
584,709
228,323
9¼% Senior Secured Second Lien Notes due 2022 —
455,668
—
—
455,668
175,300
7¾% Senior Secured Second Lien Notes due 2024 —
—
—
531,821
531,821
200,938
7½% Senior Secured Second Lien Notes due 2024 —
—
—
20,641
20,641
8,050
6⅜% Convertible Senior Notes due 2024 —
—
—
225,663
225,663
33,367
6⅜% Senior Subordinated Notes due 2021
51,304
—
—
—
51,304
2,735
5½% Senior Subordinated Notes due 2022 —
58,426
—
—
58,426
3,635
4⅝% Senior Subordinated Notes due 2023
—
—
135,960
—
135,960
4,662

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

Commodity Derivative Contracts

We enter into oil derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength, and expectation of future commodity prices. In addition, our new senior secured bank credit facility entered into on the Emergence Date required that, by December 31, 2020, we have certain minimum commodity hedge levels in place covering anticipated crude oil production through July 31, 2022. The requirement is non-recurring, and we were in compliance with the hedging requirements as of December 31, 2020. 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~~2022 using ~~both~~ NYMEX ~~and LLS~~ fixed-price swaps and ~~three-way~~costless collars. Depending on market conditions, we may continue to add to our existing ~~2020~~2021 and 2022 hedges. See also Note 7,6, Commodity Derivative Contracts, and Note 87, 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.

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, ~~2020,~~2021, our commodity derivative contracts were recorded at their fair value, which was a net ~~asset~~liability of ~~$40.0~~$245.4 million, ~~an $85.7~~a $109.3 million ~~decrease~~increase from the ~~$125.7~~$136.1 million net ~~asset~~liability recorded at March 31, ~~2020,~~2021, and a ~~$36.4~~$186.6 million increase from the ~~$3.6~~$58.8 million net ~~asset~~liability recorded at December 31, ~~2019.~~2020. These changes are primarily related to the expiration ~~or early termination~~ of commodity derivative contracts during the three and six months ended June 30, ~~2020,~~2021, new commodity derivative contracts entered into during ~~2020~~2021 for future periods, and to the changes in oil futures prices ~~between~~ from period to period.

~~December 31, 2019~~ ~~and~~ ~~June 30, 2020~~.

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Commodity Derivative Sensitivity Analysis

Based on NYMEX ~~and LLS~~ crude oil futures prices as of June 30, ~~2020~~,2021, and assuming both a 10% increase and decrease thereon, we would expect to ~~receive~~make payments on our crude oil derivative contracts outstanding at June 30, ~~2020~~2021 as shown in the following table:


	Receipt / (Payment)
In thousands	Crude Oil Derivative Contracts
Based on:
Futures prices as of June 30, 2021	$	(234,002)
10% increase in prices	(326,894)
10% decrease in prices	(152,780)

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

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

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, ~~2020~~,2021, to ensure that information that is required to be disclosed in the reports the Company files and submits under the Securities Exchange Act of 1934 is recorded, that it is processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and that information that is required to be disclosed under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

Evaluation of Changes in Internal Control over Financial Reporting. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we have determined that, during the second quarter of fiscal ~~2020~~,2021, 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

The information under Note 9,8, Commitments and Contingencies, to the Unaudited Condensed Consolidated Financial Statements is incorporated herein by reference.

Item 1A. Risk Factors

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

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

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

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

~~the sufficiency and restrictions of DIP financing we~~2020. There have ~~obtained to allow us to emerge from bankruptcy and execute our business plan post-emergence;~~

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

~~our ability to maintain other contracts that are critical~~been no material changes to our ~~operations;~~

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

~~our ability to retain key employees;~~

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

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

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

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

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

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

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

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

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~~Denbury Resources Inc.~~

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

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

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

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

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

~~The Plan may not become effective.~~

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

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

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

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

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

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~~Denbury Resources Inc.~~

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

As previously described in “Risk Factors” under Item 1A of our 2019 annual report on Form 10-K filed with the SEC on February 27, 2020, oil prices are the most important determinant of our operational and financial success. The reduction in our cash flows from operations since early March 2020, and the possibility of a continued reduction in cash flows for an indeterminant period of time, impairs our ability to develop our properties to support our oil production and pay oilfield operating expenses. Secondarily, this level of reduced cash flow may require us to shut-in uneconomic production.36

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

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

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

Trading in our common stock was suspended indefinitely on the NYSE on July 31, 2020. We will not be able to re-list our common stock on a national securities exchange during the pendency of the Chapter 11 Restructuring, although our common stock has been trading on the OTC Pink Open Marketplace. The trading of our common stock on the OTC Pink Open Marketplace rather than the NYSE may negatively impact the trading price of our common stock and the levels of liquidity available to our stockholders. Securities traded in the over-the-counter markets generally have significantly less liquidity than securities traded on a national securities exchange due to factors such as the reduced number of investors that will consider investing in the securities, the reduced number of market makers in the securities, and the reduced number of securities analysts that follow such securities. As a result, holders of shares of our common stock may find it difficult to resell their shares at prices quoted in the market or at all. Furthermore, because of the limited market and generally low volume of trading in our common stock that could occur, the share price of our common stock could be more likely to be affected by broad market fluctuations, general market conditions, fluctuations in our operating results, changes in the market’s perception of our business, and announcements made by us or third parties with interests in the Chapter 11 Restructuring.

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

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

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

None.

Item 3. Defaults Upon Senior Securities

None.

~~See Part I, Item 1. Notes to the Condensed Consolidated Financial Statements – Note 1~~,~~Basis of Presentation~~ – ~~Entry into Restructuring Support Agreement and Voluntary Reorganization under Chapter 11 of the Bankruptcy Code~~ ~~and~~ ~~Industry Conditions, Liquidity, and Management’s Plans~~,~~and~~ ~~Going Concern, and Note 4~~,~~Long-Term Debt,~~ ~~which are incorporated in this item by reference.~~

Item 4. Mine Safety Disclosures

None.

Item 5. Other Information

None.

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Item 6. Exhibits



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

~~Table of Contents~~

~~Denbury Resources Inc.~~



10(g)*	~~2020 Form of Incentive Bonus Agreement for Denbury Resources Inc.~~
31(a)*	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)*		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32**		Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*		Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH*		Inline XBRL Taxonomy Extension Schema Document
101.CAL*		Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*		Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*		Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE*		Inline XBRL Taxonomy Extension Presentation Linkbase Document
104		The cover page from the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, ~~2020,~~2021, has been formatted in Inline XBRL.


*	~~Included herewith.~~

* Included herewith.

** Furnished herewith in accordance with Item 601(b)(32) of Regulation S-K.

5438

Table of Contents

Denbury ~~Resources~~ Inc.

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 INC.

August 5, 2021		~~DENBURY RESOURCES INC.~~

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

August ~~11, 2020~~5, 2021		/s/ ~~Alan Rhoades~~Nicole Jennings
		~~Alan Rhoades~~ Nicole Jennings Vice President and Chief Accounting Officer

5539



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



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

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

Weighted average common shares outstanding
Basic	495,245			452,612			494,752			452,169
Diluted	495,245			467,427			494,752			461,460



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


~~(1)~~	Shares shown under “convertible senior notes” represent the impact over the periods of the approximately 90.9 million shares of the Company’s common stock issuable upon full conversion of our convertible senior notes which were issued on June 19, 2019.


~~(1)~~	~~Consists of discounts related to our 7¾% Senior Secured Second Lien Notes due 2024 and 6⅜% Convertible Senior Notes due 2024 of $24.4 million and $64.0 million, respectively, as of June 30, 2020.~~


~~(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.



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



	Average Daily Production (BOE/d)
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	First Quarter	Second Quarter
Operating Area	2019	2019	2019	2019	2020	2020
Tertiary oil production
Gulf Coast region
Delhi	4,474	4,486	4,256	4,085	3,813	3,529
Hastings	5,539	5,466	5,513	5,097	5,232	4,722
Heidelberg	3,987	4,082	4,297	4,409	4,371	4,366
Oyster Bayou	4,740	4,394	3,995	4,261	3,999	3,871
Tinsley	4,659	4,891	4,541	4,343	4,355	3,788
West Yellow Creek	436	586	728	807	775	695
Mature properties⁽¹⁾	6,479	6,448	6,415	6,347	6,386	5,249
Total Gulf Coast region	30,314	30,353	29,745	29,349	28,931	26,220
Rocky Mountain region
Bell Creek	4,650	5,951	4,686	5,618	5,731	5,715
Salt Creek	2,057	2,078	2,213	2,223	2,149	1,386
Grieve	52	41	58	60	50	7
Total Rocky Mountain region	6,759	8,070	6,957	7,901	7,930	7,108
Total tertiary oil production	37,073	38,423	36,702	37,250	36,861	33,328
Non-tertiary oil and gas production
Gulf Coast region
Mississippi	1,034	1,025	873	952	748	713
Texas	3,298	3,224	3,165	3,212	3,419	3,087
Other	10	6	6	5	6	5
Total Gulf Coast region	4,342	4,255	4,044	4,169	4,173	3,805
Rocky Mountain region
Cedar Creek Anticline	14,987	14,311	13,354	13,730	13,046	11,988
Other	1,313	1,305	1,238	1,192	1,105	1,069
Total Rocky Mountain region	16,300	15,616	14,592	14,922	14,151	13,057
Total non-tertiary production	20,642	19,871	18,636	19,091	18,324	16,862
Total continuing production	57,715	58,294	55,338	56,341	55,185	50,190
Property sales
Gulf Coast Working Interests Sale⁽²⁾	1,047	1,019	1,103	1,170	780	—
Citronelle⁽³⁾	456	406	—	—	—	—
Total production	59,218	59,719	56,441	57,511	55,965	50,190