~~Denbury Inc.~~

~~Unaudited Condensed Consolidated Balance Sheets (continued)~~

~~(In thousands, except par value and share data)~~

Successor Predecessor
September 30, 2020 December 31, 2019
Liabilities and Stockholders’ Equity
Current liabilities

Accounts payable and accrued liabilities $ 166,385
$ 183,832
Oil and gas production payable 45,013
62,869
Derivative liabilities 5,739
8,346
Current maturities of long-term debt (including future interest payable of $0 and $86,054, respectively – see Note 6) 73,511
102,294
Operating lease liabilities 763
6,901
Total current liabilities 291,411
364,242
Long-term liabilities

Long-term debt, net of current portion (including future interest payable of $0 and $78,860, respectively – see Note 6) 102,456
2,232,570
Asset retirement obligations 158,757
177,108
Derivative liabilities 584
0
Deferred tax liabilities, net 3,836
410,230
Operating lease liabilities 463
41,932
Other liabilities 22,186
53,526
Total long-term liabilities 288,282
2,915,366
Commitments and contingencies (Note 12)
Stockholders’ equity
Predecessor preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding —
0
Predecessor common stock, $.001 par value, 750,000,000 shares authorized; 508,065,495 shares issued —
508
Predecessor paid-in capital in excess of par —
2,739,099
Predecessor treasury stock, at cost, 1,652,771 shares —
(6,034 )
Successor preferred stock, $.001 par value, 50,000,000 shares authorized, none issued and outstanding 0
—
Successor common stock, $.001 par value, 250,000,000 shares authorized; 49,999,999 shares issued 50
—
Successor paid-in-capital in excess of par 1,095,369
—
Retained earnings (accumulated deficit) 2,758
(1,321,314 )
Total stockholders’ equity
1,098,177
1,412,259
Total liabilities and stockholders’ equity $ 1,677,870
$ 4,691,867

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

~~Table of Contents~~

Denbury 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

Successor Predecessor
Period from Sept. 19, 2020 through Period from July 1, 2020 through Three Months Ended
Sept. 30, 2020 Sept. 18, 2020 Sept. 30, 2019
Revenues and other income
Oil, natural gas, and related product sales $ 22,321
$ 153,090
$ 293,192
CO₂sales and transportation fees
967
6,517
8,976
Oil marketing sales 151
3,332
5,468
Other income 94
7,097
7,817
Total revenues and other income 23,533
170,036
315,453
Expenses

Lease operating expenses 11,484
59,708
117,850
Transportation and marketing expenses 1,344
8,155
10,067
CO₂ operating and discovery expenses
242
955
879
Taxes other than income 2,073
13,473
22,010
Oil marketing expenses 139
3,288
5,436
General and administrative expenses 1,735
15,013
18,266
Interest, net of amounts capitalized of $183, $4,704 and $8,773, respectively 334
7,704
22,858
Depletion, depreciation, and amortization 5,283
36,317
55,064
Commodity derivatives expense (income) (4,035 ) 4,609
(43,155 )
Gain on debt extinguishment 0
0
(5,874 )
Write-down of oil and natural gas properties 0
261,677
0
Reorganization items, net 0
849,980
0
Other expenses 2,164
22,084
2,140
Total expenses 20,763
1,282,963
205,541
Income (loss) before income taxes 2,770
(1,112,927 ) 109,912
Income tax provision (benefit) 12
(303,807 ) 37,050
Net income (loss) $ 2,758
$ (809,120 ) $ 72,862

Net income (loss) per common share

Basic $ 0.06
$ (1.63 ) $ 0.16
Diluted $ 0.06
$ (1.63 ) $ 0.14

Weighted average common shares outstanding

Basic 50,000
497,398
455,487
Diluted 50,000
497,398
547,205

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

Table of Contents

~~Denbury Inc.~~

~~Unaudited Condensed Consolidated Statements of Operations~~

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

Successor Predecessor
Period from Sept. 19, 2020 through Period from Jan. 1, 2020 through Nine Months Ended
Sept. 30, 2020 Sept. 18, 2020 Sept. 30, 2019
Revenues and other income
Oil, natural gas, and related product sales $ 22,321
$ 492,101
$ 918,190
CO₂sales and transportation fees
967
21,049
25,532
Oil marketing sales 151
8,543
8,274
Other income 94
8,419
12,274
Total revenues and other income 23,533
530,112
964,270
Expenses

Lease operating expenses 11,484
250,271
361,205
Transportation and marketing expenses 1,344
27,164
32,076
CO₂ operating and discovery expenses
242
2,592
2,016
Taxes other than income 2,073
43,531
71,312
Oil marketing expenses 139
8,399
8,213
General and administrative expenses 1,735
48,522
54,697
Interest, net of amounts capitalized of $183, $22,885 and $27,545, respectively 334
48,267
60,672
Depletion, depreciation, and amortization 5,283
188,593
170,625
Commodity derivatives expense (income) (4,035 ) (102,032 ) 15,462
Gain on debt extinguishment 0
(18,994 ) (106,220 )
Write-down of oil and natural gas properties 0
996,658
0
Reorganization items, net 0
849,980
0
Other expenses 2,164
35,868
8,664
Total expenses 20,763
2,378,819
678,722
Income (loss) before income taxes 2,770
(1,848,707 ) 285,548
Income tax provision (benefit) 12
(416,129 ) 91,668
Net income (loss) $ 2,758
$ (1,432,578 ) $ 193,880

Net income (loss) per common share
Basic $ 0.06
$ (2.89 ) $ 0.43
Diluted $ 0.06
$ (2.89 ) $ 0.41

Weighted average common shares outstanding

Basic 50,000
495,560
453,287
Diluted 50,000
495,560
490,054

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

~~Table of Contents~~

Denbury 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

Successor Predecessor
Period from Sept. 19, 2020 through Period from Jan. 1, 2020 through Nine Months Ended
Sept. 30, 2020 Sept. 18, 2020 Sept. 30, 2019
Cash flows from operating activities

Net income (loss)
$ 2,758
$ (1,432,578 ) $ 193,880
Adjustments to reconcile net income (loss) to cash flows from operating activities

Noncash reorganization items, net 0
810,909
0
Depletion, depreciation, and amortization
5,283
188,593
170,625
Write-down of oil and natural gas properties 0
996,658
0
Deferred income taxes
6
(408,869 ) 90,454
Stock-based compensation
0
4,111
9,866
Commodity derivatives expense (income)
(4,035 ) (102,032 ) 15,462
Receipt on settlements of commodity derivatives
6,660
81,396
14,714
Gain on debt extinguishment 0
(18,994 ) (106,220 )
Debt issuance costs and discounts
114
11,571
7,607
Other, net
589
439
(6,862 )
Changes in assets and liabilities, net of effects from acquisitions

Accrued production receivable
38,537
26,575
(1,428 )
Trade and other receivables
1,366
(22,343 ) (147 )
Other current and long-term assets
705
743
27
Accounts payable and accrued liabilities
(7,980 ) (16,102 ) (33,167 )
Oil and natural gas production payable
(11,064 ) (6,792 ) (1,819 )
Other liabilities
(29 ) 123
(9,414 )
Net cash provided by operating activities
32,910
113,408
343,578

Cash flows from investing activities

Oil and natural gas capital expenditures
(2,125 ) (99,582 ) (204,904 )
Pipelines and plants capital expenditures (6 ) (11,601 ) (25,965 )
Net proceeds from sales of oil and natural gas properties and equipment 880
41,322
10,494
Other
(309 ) 12,747
5,797
Net cash used in investing activities
(1,560 ) (57,114 ) (214,578 )

Cash flows from financing activities

Bank repayments
(55,000 ) (551,000 ) (641,000 )
Bank borrowings
0
691,000
691,000
Interest payments treated as a reduction of debt 0
(46,417 ) (59,808 )
Cash paid in conjunction with debt repurchases 0
(14,171 ) 0
Cash paid in conjunction with debt exchange 0
0
(125,268 )
Costs of debt financing 0
(12,482 ) (11,017 )
Pipeline financing and capital lease debt repayments
(54 ) (51,792 ) (10,279 )
Other
0
(9,363 ) 5,470
Net cash provided by (used in) financing activities
(55,054 ) 5,775
(150,902 )
Net increase (decrease) in cash, cash equivalents, and restricted cash
(23,704 ) 62,069
(21,902 )
Cash, cash equivalents, and restricted cash at beginning of period
95,114
33,045
54,949
Cash, cash equivalents, and restricted cash at end of period
$ 71,410
$ 95,114
$ 33,047

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

Table of Contents

Denbury 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 (Predecessor)	508,065,495		$	508		$	2,739,099		$	(1,321,314	)	1,652,771		$	(6,034	)	$	1,412,259		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	312,516		—			—			—			—		—			—			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 for stock compensation plans	—		—			—			—			175,673		(34		)	(34		)	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 (Predecessor)	508,415,378		508			2,742,303			(1,247,298		)	1,828,444		(6,068		)	1,489,445			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 (Predecessor)	509,553,960		510			2,754,749			(1,944,772		)	1,828,444		(6,068		)	804,419			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	(95,016	)	—			—			—			—		—			—			Canceled pursuant to stock compensation plans	(95,016)	—		—		—		—	—		—
Issued pursuant to notes conversion	14,800		—			40			—			—		—			40			Issued pursuant to notes conversion	14,800	—		40		—		—	—		40
Stock-based compensation	—		—			10,126			—			—		—			10,126			Stock-based compensation	—	—		10,126		—		—	—		10,126
Tax withholding for stock compensation plans	—		—			—			—			567,189		(134		)	(134		)	Tax withholding for stock compensation plans	—	—		—		—		567,189	(134)		(134)
Net loss	—		—			—			(809,120		)	—		—			(809,120		)	Net loss	—	—		—		(809,120)		—	—		(809,120)
Cancellation of Predecessor equity	(509,473,744	)	(510		)	(2,764,915		)	2,753,892			(2,395,633	)	6,202			(5,331		)	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	49,999,999		50			1,095,369			—			—		—			1,095,419			Issuance of Successor equity	49,999,999	50		1,095,369		—		—	—		1,095,419
Balance – September 18, 2020 (Predecessor)	49,999,999		$	50		$	1,095,369		$	—		—		$	—		$	1,095,419		Balance – September 18, 2020 (Predecessor)	49,999,999	$	50	$	1,095,369	$	—	—	$	—	$	1,095,419


Balance – September 19, 2020 (Successor)	49,999,999		$	50		$	1,095,369		$	—		—		$	—		$	1,095,419		Balance – September 19, 2020 (Successor)	49,999,999	$	50	$	1,095,369	$	—	—	$	—	$	1,095,419
Net income	—		—			—			2,758			—		—			2,758			Net income	—	—		—		2,758		—	—		2,758
Balance – September 30, 2020 (Successor)	49,999,999		$	50		$	1,095,369		$	2,758		0		$	0		$	1,098,177		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

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

Table of Contents

~~Denbury 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, 2018 (Predecessor) 462,355,725
$ 462
$ 2,685,211
$ (1,533,112 ) 1,941,749
$ (10,784 ) $ 1,141,777
Issued 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 for stock compensation plans —
—
—
—
531,494
(1,091 ) (1,091 )
Net loss —
—
—
(25,674 ) —
—
(25,674 )
Balance – March 31, 2019 (Predecessor) 463,728,262
464
2,689,517
(1,558,786 ) 2,473,243
(11,875 ) 1,119,320
Issued pursuant to stock compensation plans 400,850
—
—
—
—
—
—
Issued pursuant to directors’ compensation plan 37,367
—
—
—
—
—
—
Stock-based compensation —
—
4,667
—
—
—
4,667
Tax withholding for stock compensation plans —
—
—
—
1,661
(3 ) (3 )
Net income —
—
—
146,692
—
—
146,692
Balance – June 30, 2019 (Predecessor) 464,166,479
464
2,694,184
(1,412,094 ) 2,474,904
(11,878 ) 1,270,676
Issued pursuant to stock compensation plans 9,046,748
9
(9 ) —
—
—
—
Stock-based compensation —
—
3,983
—
—
—
3,983
Tax withholding for stock compensation plans —
—
—
—
1,145,881
(1,401 ) (1,401 )
Net income —
—
—
72,862
—
—
72,862
Balance – September 30, 2019 (Predecessor) 473,213,227
$ 473
$ 2,698,158
$ (1,339,232 ) 3,620,785
$ (13,279 ) $ 1,346,120

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

~~Table of Contents~~

Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 1. Basis of Presentation

Organization and Nature of Operations

Denbury Inc. (“Denbury,” “Company” or the “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.

~~As further described in~~ Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code

~~below, Denbury Inc. became the successor reporting company of~~On July 30, 2020, Denbury Resources Inc. (the “Predecessor”) upon the Predecessor’s emergence from bankruptcy on September 18, 2020. 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. On September 18, 2020, Denbury filed the Third Restated Certificate of Incorporation with the Delaware Secretary of State to effect a change of the Company’s corporate name from Denbury Resources Inc. to Denbury Inc., and on September 21, 2020, the Successor’s new common stock commenced trading on the New York Stock Exchange under the ticker symbol DEN.

~~Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code~~

On July 28, 2020, Denbury Resources Inc. and its subsidiaries entered into a Restructuring Support Agreement (the “RSA”) with lenders holding 100% of the revolving loans under our pre-petition revolving bank credit facility and debtholders holding approximately 67.1% of our senior secured second lien notes and approximately 73.1% of our convertible senior 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 Resources Inc. 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”) 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 ~~Plan~~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.~~11 as the successor reporting company of Denbury Resources Inc. On April 23, 2021, the ~~Emergence Date and pursuant to~~Bankruptcy Court entered a final decree closing the ~~terms~~Chapter 11 case captioned “In re Denbury Resources Inc., et al., Case No. 20-33801”, so all of the ~~Plan~~Chapter 11 cases have been closed.

Upon emergence from bankruptcy, we met the criteria and ~~the Confirmation Order, all outstanding obligations under the senior secured second lien notes, convertible senior notes, and senior subordinated notes~~ were ~~fully extinguished, relieving approximately $2.1 billion of debt by issuing equity and/or warrants~~required to adopt fresh start accounting in ~~the Successor to the former holders of that debt, and the Company:~~

Adopted an amended and restated certificate of incorporation and bylaws which reserved for issuance 250,000,000 shares of common stock, par value $0.001 per share, of Denbury (the “New Common Stock”) and 50,000,000 shares of preferred stock, par value $0.001 per share;

~~Cancelled all outstanding senior secured second lien notes, convertible senior notes, and senior subordinated notes issued by the Predecessor and related registration rights. In~~ accordance with ~~the Plan, claims against and interests in the Predecessor were treated as follows:~~


◦	Holders of secured pipeline lease claims received payment in full in cash, the collateral securing such pipeline lease claim, reinstatement, or such other treatment rendering such pipeline lease claim unimpaired (see Note 6, ~~Long-Term Debt~~ – ~~Pipeline Financing Transactions, for discussion of subsequent pipeline transactions);~~


◦	Holders of senior secured second lien notes claims received their pro rata share of 47,499,999 shares representing 95% of the New Common Stock issued on the Emergence Date, subject to dilution on account of warrants and a to-be-adopted management incentive plan;

◦

Holders of convertible senior notes claims received their pro rata share of (a) 2,500,000 shares representing 5% of the New Common Stock issued on the Emergence Date, subject to dilution on account of warrants and a to-be-adopted management incentive plan and (b) 100% of the series A warrants (see below), reflecting up to a maximum of 5% ownership stake in the reorganized company’s equity interests;


◦	Holders of subordinated notes claims received their pro rata share of 54.55% of the series B warrants (see below), reflecting up to a maximum of 3% of the reorganized company’s equity interests after giving effect to the exercise of the series A warrants;

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~~Denbury Inc.~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~


◦	~~Holders of general unsecured claims received payment in full in cash, reimbursement, or such other treatment rendering such general unsecured claim unimpaired; and~~


◦	Holder of existing equity interests received their pro rata share of 45.45% of the series B warrants (see below), reflecting up to a maximum of 2.5% of the reorganized company’s equity interests after giving effect to the exercise of the series A warrants.


◦	Issued 2,631,579 series A warrants at an initial exercise price of $32.59 per share to former holders of the Predecessor’s convertible senior notes and 2,894,740 series B warrants at an initial exercise price of $35.41 per share to former holders of the Predecessor’s senior subordinated notes and Predecessor’s equity interests;

~~Entered into a new senior secured revolving credit agreement with a syndicate of banks (the “Successor Bank Credit Agreement”) with total aggregate commitments of $575 million;~~

Appointed a new board of directors (the “Board”) consisting of four new independent members: Anthony Abate, Caroline Angoorly, Brett Wiggs and James N. “Jim” Chapman, and three continuing members: Dr. Kevin O. Meyers (Chairman of the Board), Lynn A. Peterson and Chris Kendall, Denbury’s President and Chief Executive Officer; and

Adopted a framework for a management incentive plan which will reserve primarily for employees and directors a pool of shares of New Common Stock representing up to 10% of the New Common Stock, determined on a fully diluted and fully distributed basis, with initial awards from within this pool to be issued within 60 days of emergence.

~~During the Predecessor period, the Company applied~~ Financial Accounting Standards Board Codification (“FASC”) Topic 852, Reorganizations ~~in preparing~~. Fresh start accounting requires that new fair values be established for the ~~consolidated financial statements. FASC Topic 852 requires the financial statements, for periods subsequent to the commencement~~Company’s assets, liabilities and equity as of the ~~Chapter 11 Restructuring, to distinguish transactions~~Emergence Date, and ~~events that are directly associated with the reorganization from the ongoing operations~~therefore certain values and operational results of the business. Accordingly, certain charges incurred during 2020 related to the Chapter 11 Restructuring, including the write-off of unamortized long-term debt fees and discounts associated with debt classified as liabilities subject to compromise, and professional fees incurred directly as a result of the Chapter 11 Restructuring are recorded as “Reorganization items, net” in our Unaudited Condensed Consolidated Statements of Operations in the Predecessor period. FASC Topic 852 requires certain additional reporting for financial statements prepared between the bankruptcy filing date and the date of emergence from bankruptcy, including:

Reclassification of pre-petition liabilities that are unsecured, under-secured or where it cannot be determined that the liabilities are fully secured, to a separate line item in the Unaudited Condensed Consolidated Balance Sheet titled “Liabilities subject to compromise”; and

~~Segregation of Reorganization items, net as a separate line in the Unaudited Condensed Consolidated Statements of Operations.~~

~~The accompanying unaudited~~ condensed consolidated financial statements ~~have been prepared assuming that~~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 ~~will continue as a going concern~~subsequent to September 18, 2020, and ~~contemplate~~references to “Predecessor” relate to the ~~realization~~financial position and results of assets and the satisfaction of liabilities in the normal course of business. During the Chapter 11 Restructuring, the Company’s ability to continue as a going concern was contingent upon the Company’s ability to successfully implement a prepackaged joint plan of reorganization, among other factors. As a resultoperations of the ~~effectiveness~~Company prior to, and ~~implementation of the restructuring, there is no longer substantial doubt about the Company's ability to continue as a going concern.~~including, September 18, 2020.

Interim Financial Statements

The accompanying unaudited condensed consolidated financial statements of Denbury 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 ~~the Predecessor’s~~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 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 ~~September~~June 30, ~~2020~~2021 (Successor) ~~and December 31, 2019 (Predecessor)~~; our consolidated results of operations for the three and six months ended June 30, 2021 (Successor) and June 30, 2020 (Predecessor); our consolidated cash flows for the six months ended June 30, 2021 (Successor) and June 30, 2020 (Predecessor); and our consolidated statements of changes in stockholders’ equity for the ~~periods September 19, 2020 through September~~three and six months ended June 30, ~~2020~~2021 (Successor), for the period ~~July 1, 2020~~

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~~Denbury Inc.~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

~~through September 18, 2020 (Predecessor) and~~ January 1, 2020 through September 18, 2020 (Predecessor), and for the ~~three and nine months ended September 30, 2019 (Predecessor); and our consolidated cash flows for the~~ period September 19, 2020 through ~~September 30,~~December 31, 2020 (Successor)~~, for the period January 1, 2020 through September 18, 2020 (Predecessor) and for the nine months ended September 30, 2019 (Predecessor)~~. Upon the adoption of fresh start accounting, the Company’s assets and liabilities were recorded at their fair values as of the fresh start reporting ~~date (see Note 2,~~ ~~Fresh Start Accounting~~).date. As a result of the adoption of fresh start

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

accounting, certain values and operational results of the Company’s condensed consolidated financial statements subsequent to September 18, 2020 are not comparable to those in its condensed consolidated financial statements prior to, and including September 18, ~~2020, and as such, “black-line” financial statements are presented to distinguish between the Predecessor and Successor companies.~~2020.

Reclassifications

~~Risks and Uncertainties~~

In March 2020, the World Health Organization declared the ongoing COVID-19 coronavirus (“COVID-19”) outbreak a pandemic, and the President of the United States declared the COVID-19 pandemic a national emergency. The COVID-19 pandemic has caused a rapid and precipitous drop in oil demand, which worsened an already deteriorated oil market that 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. Although OPEC+ subsequently agreed to reduced levels of production output, concerns about the ability of OPEC+ to maintain compliance with their reduced production targets and uncertainty about the duration of the COVID-19 pandemic and its resulting economic consequences has resulted in abnormally high worldwide inventories of produced oil. While oil prices have improved from the low points experienced during the second quarter of 2020, the concerns and uncertainties around the balance of supply and demand for oil are expected to continue for some time. Because the realized oil prices we have received since early March 2020Certain prior period amounts have been ~~significantly reduced,~~reclassified to conform to the current year presentation. Such reclassifications had no impact on our ~~operating cash flow and liquidity have been adversely affected.~~reported net income (loss), current assets, total assets, current liabilities, total liabilities or stockholders’ equity.

Cash, Cash Equivalents, and Restricted Cash

The following table provides a reconciliation of cash, cash equivalents, and restricted cash as reported within the Unaudited Condensed Consolidated Balance Sheets to “Cash, cash equivalents, and restricted cash at end of period” as reported within the Unaudited Condensed Consolidated Statements of Cash Flows:


	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

Successor Predecessor
In thousands Sept. 30, 2020 Dec. 31, 2019
Cash and cash equivalents $ 21,860
$ 516
Restricted cash, current 10,662
0
Restricted cash included in other assets 38,888
32,529
Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows $ 71,410
$ 33,045

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Denbury 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.

OVERVIEW

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.

~~September 18, 2020 Emergence from Chapter 11 Restructuring.~~ On July 30, 2020 (the “Petition Date”), Denbury Resources Inc. 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”) 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 chapter 11 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. On September 18, 2020, Denbury filed the Third Restated Certificate of Incorporation with the Delaware Secretary of State to effect a change of the Company’s corporate name from Denbury Resources Inc. to Denbury Inc. (the “Successor”), and on September 21, 2020, the Successor’s new common stock commenced trading on the New York Stock Exchange under the ticker symbol “DEN”. Key accomplishments of the Chapter 11 Restructuring include the following:

~~Eliminated approximately $2.1 billion of bond debt by issuing equity and/or warrants to the holders of that debt;~~

~~Significantly improved leverage ratios;~~

~~Reduced ongoing annual interest expense by approximately $165 million, significantly lowering our cash flow breakeven level;~~

~~Eliminated approximately $9 million from ongoing general and administrative expenses by terminating certain office leases and relocating our corporate headquarters; and~~

~~Established a new $575 million senior secured bank credit facility with $436.7 million of availability at September 30, 2020 after outstanding letters of credit.~~

~~For more information on the Chapter 11 Restructuring and related matters, refer to Note 1,~~ ~~Basis of Presentation~~ – ~~Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code, and Note 6,~~ ~~Long-Term Debt, to the condensed consolidated financial statements.~~

~~Fresh Start Accounting.~~ ~~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~~, which on the Emergence Date resulted in a new entity, the Successor, for financial reporting purposes, with no beginning retained earnings or deficit as of the fresh start reporting date. References to “Successor” relate to the financial position and results of operations of the Company subsequent to the Company’s emergence from bankruptcy on 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. In order to assist investors in understanding the comparability of our financial results for the applicable periods, we have provided certain comparative analysis on a combined basis, which management believes provides meaningful information to assist investors in understanding our financial results for the applicable period, but should not be considered in isolation, as a substitute for, or more meaningful than, independent results of the Predecessor and Successor periods for the quarter reported in accordance with GAAP.

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~~Denbury Inc.~~

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

Fresh start accounting requires that new fair values be established for the Company’s assets, liabilities and equity as of the date of emergence from bankruptcy, September 18, 2020, and therefore certain values and operational results of the condensed consolidated financial statements subsequent to September 18, 2020 are not comparable to the Company’s condensed consolidated financial statements prior to, and including September 18, 2020, principally due to the Emergence Date re-evaluation of the fair value of our oil and natural gas properties, CO₂ properties, and pipelines, together with the conversion of over $2 billion of previously outstanding debt into new common stock in the Successor. The reorganization value derived from the range of enterprise values associated with the Plan was allocated to the Company’s identifiable tangible and intangible assets and liabilities based on their fair values. The Emergence Date fair values of the Successor’s assets and liabilities differ materially from their recorded values as reflected on the historical balance sheet of the Predecessor and may materially affect our results of operations in Successor reporting periods.

Oil Price Impact on Our Business. Our financial results are significantly impacted by changes in oil prices, as 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

Three Months Ended
September 30, 2020 June 30, 2020 December 31, 2019 September 30, 2019
Average net realized prices
Oil price per Bbl - excluding impact of derivative settlements $ 39.23
$ 24.39
$ 56.58
$ 57.64
Oil price per Bbl - including impact of derivative settlements 43.23
34.64
58.30
59.23

~~Response to 2020 Oil Price Declines.~~ In January and February 2020, NYMEX WTI oil prices averaged in the mid-$50s per Bbl range before a precipitous decline in early March 2020 due to the combination of the COVID-19 coronavirus (“COVID-19”) pandemic and the failure of the group of oil producing nations known as OPEC+ to reach an agreement over proposed oil production cuts. Although OPEC+ subsequently agreed to reduced levels of production output, concerns about the ability of OPEC+ to maintain compliance with their reduced production targets and uncertainty about the duration of the COVID-19 pandemic and its resulting economic consequences has resulted in abnormally high worldwide inventories of produced oil. While oil prices have improved from the low points experienced during the second quarter of 2020, the concerns and uncertainties around the balance of supply and demand for oil are expected to continue for some time.

The decrease in NYMEX oil prices that began in the latter part of the first quarter of 2020 has significantly reduced our cash flow. In response to these developments, we 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, delayed uneconomic well repairs and workovers and reduced 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 oil price protection; and

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

~~Third Quarter 2020 Financial Results and Highlights.~~ As a result of Denbury filing for bankruptcy and emerging from bankruptcy during the same quarter, our quarterly financial results are broken out between the predecessor period (July 1, 2020 through September 18, 2020) and the successor period (September 19, 2020 through September 30, 2020). For the predecessor period we recognized a net loss of $809.1 million, and for the successor period we recognized net income of $2.8 million. The primary drivers of our significant financial net loss for the predecessor period included the following:

Reorganization items, net, resulted in a $850.0 million charge during the predecessor period, primarily consisting of fresh start accounting adjustments of $1.9 billion to decrease the carrying value of our assets, partially offset by a gain on settlements

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Denbury 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:

~~of liabilities subject~~


	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

NYMEX WTI oil prices strengthened from the mid-$40s per Bbl range in December 2020 to ~~compromise of $1.0 billion, primarily representing the net impact~~an average of approximately ~~$2.1 billion~~$66 per Bbl during the second quarter of ~~debt elimination offset by~~2021, reaching highs of over $74 per Bbl in June 2021.

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 ~~new equity value in Denbury;~~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. The principal determinant of our comparative second quarter results between 2020 and

~~A $261.7~~ 2021 was the $662.4 million full cost pool ceiling test write-down in the prior-year period. Additional drivers of the comparative operating results include the following:

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

•Commodity derivatives expense increased by $132.5 million consisting of a $109.0 million decrease in cash receipts upon contract settlements ($63.3 million in payments during the ~~predecessor~~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 ~~decline in NYMEX oil prices.~~

On a comparative basis, we recognized net income of $72.9 million in the prior year third quarter. The following reflects some of the primary drivers for our change in operating results between the third quarter 2020, in aggregate, and the thirdsecond quarter of ~~2019:~~

~~Oil and natural gas revenues decreased by $117.8 million (40%), with 28% of~~2020 which resulted in adjustments to the ~~decrease due to lower commodity prices and 12% of~~bonus program for 2020, as well as certain severance-related costs recorded during the ~~decrease due to lower production;~~


•	~~Lease operating expenses decreased by $46.7 million (40%), primarily due to lower expenses for workovers, CO~~₂~~, power and fuel, and labor costs as well as a $15.4 million insurance recovery of costs incurred in 2013.~~

~~October 2020 Restructuring of CO~~₂ ~~Pipeline Agreements.~~ ~~In late October 2020, we restructured our CO~~₂ pipeline financing arrangements with Genesis Energy, L.P. (“Genesis”), whereby (1) Denbury reacquired the NEJD pipeline system from Genesis in exchange for $70 million to be paid in four equal payments during 2021, representing full settlement of all remaining obligations under the NEJD secured financing lease; and (2) Denbury reacquired the Free State Pipeline from Genesis in exchange for a one-time payment of $22.5 million on October 30, 2020.

~~Delhi Insurance Receivable.~~ ~~During August 2020, we recorded~~ insurance reimbursements totaling $16.1 million ($15.4 million net to Denbury’s interest) for previously-incurred well control costs, cleanup costs, and damages associated with a 2013 incident at Delhi Field. Denbury’s portion of the insurance recovery of ~~$15.4 million was recorded as a reduction to lease operating expenses~~.

~~Houston Area Land Sales~~. ~~We have been actively marketing for sale non-producing surface acreage primarily around the Houston area.~~ On July 24, 2020, we completed the sale of a portion of this acreage for gross proceeds of approximately $14 million, and completed the sale on an additional portion for gross proceeds of approximately $11 million on October 30, 2020. To date, we have closed acreage sales for total gross proceeds of approximately $45 million, and we currently have an additional $4 million under contract which is expected to close in the fourthsecond quarter of 2020.

~~First Quarter 2020 Sale~~June 2021 Divestiture of ~~Working Interests~~Hartzog Draw Deep Mineral Rights. On June 30, 2021, we closed the sale of undeveloped, unconventional deep mineral rights in ~~Certain Texas~~Hartzog Draw Field in Wyoming. The cash proceeds of $18 million were recorded to “Proved properties” in our Unaudited Condensed Consolidated Balance Sheets. The proceeds reduced our full cost pool; therefore, no gain or loss was recorded on the transaction, and the sale had no impact on our production or reserves.

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Denbury Inc.

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

March 2021 Acquisition of Wyoming CO2 EOR Fields. On March ~~4, 2020,~~3, 2021, we ~~closed~~acquired a ~~farm-down transaction for the sale of half of our~~ nearly 100% working interest ~~positions~~(approximately 83% net revenue interest) in ~~four southeast Texas oil~~the Big Sand Draw and Beaver Creek EOR fields ~~(consisting~~(collectively “Wind River Basin”) located in Wyoming from a subsidiary of ~~Webster, Thompson, Manvel and East Hastings)~~Devon Energy Corporation for ~~$40~~$10.7 million ~~net~~ cash (before final closing adjustments), including surface facilities and a ~~carried interest~~46-mile CO2 transportation pipeline to the acquired fields. The acquisition agreement provides for us to make two contingent cash payments, one in ~~ten wells~~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 operating for years. During the first half of 2021, approximately 34% of the CO2 utilized in our oil and gas operations was industrial-sourced CO2, and we anticipate this percentage could increase in the 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 those locations. While EOR is the only CCUS operation reflected in our current and historical financial and operational results, and development of our 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 ~~drilled by the purchaser (the “Gulf Coast Working Interests Sale”).~~a leader in this industry.

CAPITAL RESOURCES AND LIQUIDITY

Overview. Our primary sources of capital and liquidity are our cash ~~flow~~flows from operations and availability under our ~~Successor~~senior secured bank credit facility. In 2020 our liquidity has been supplemented by $40 million of proceeds from our March 2020 sale of working interests in four southeast Texas fields and by $25 million of proceeds from sales of non-producing surface acreage primarily around the Houston area. 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 pipeline financing obligations. In ~~conjunction with~~addition, we have sold certain non-producing assets that will further supplement our ~~emergence~~cash flow from ~~bankruptcy,~~operations.

As of June 30, 2021, we ~~established a new~~had $35 million of outstanding borrowings on our $575 million senior secured bank credit facility, ~~under which we had $85 million borrowed as of September 30, 2020,~~ leaving us with ~~$436.7~~$517.7 million of borrowing base availability after consideration of ~~$53.3~~$22.3 million of outstanding letters of credit. ~~As discussed~~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 price environment and strategic importance of the EOR CO2 flood at Cedar Creek Anticline (“CCA”), we announced in February 2021 our plans to move forward with development of 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 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 the second half of 2021, with completion of the pipeline expected by the end of 2021, first CO~~Overview~~2 ~~above, NYMEX~~injection planned during the first half of 2022, and first tertiary production expected in the second half of 2023. We currently anticipate that our full-year 2021 development capital spending, excluding capitalized interest and

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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 105-mile extension of the Greencore CO2 pipeline to CCA;

•$50 million for CCA tertiary well work, facilities, and 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, 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 working interest positions in the Wind River Basin enhanced oil recovery fields acquired on March 3, 2021.

Based on current oil prices ~~have decreased significantly since~~and the ~~beginning of 2020, directly reducing our operating cash flow; however,~~Company’s hedge positions, we ~~have taken significant actions to reduce capital expenditures and operating expenses in order to adjust our spending levels such~~expect that our ~~spending for ongoing~~2021 cash flows from operations ~~is below~~will exceed our ~~cash flow generated from operations.~~budgeted level of planned development capital expenditures.

~~New~~ Senior Secured Bank Credit Agreement. In ~~connection with our emergence from Chapter 11 proceedings on~~ September ~~18,~~ 2020, we entered into a bank credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the “Bank Credit Agreement”). The Bank Credit Agreement is a senior secured revolving credit facility with ~~an initial~~a maturity date of January 30, 2024. As part of our spring 2021 semiannual borrowing base redetermination, the borrowing base and lender commitments ~~of $575 million. Additionally, under the~~for our Bank Credit Agreement ~~letters of credit are available in an aggregate amount not to exceed $100~~were reaffirmed at $575 million, ~~and short-term swingline loans are available in an aggregate amount not to exceed $25 million, each subject to the available commitments under the Bank Credit Agreement. Availability~~

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

~~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 redetermination around ~~May 1,~~November 2021. The borrowing base is adjusted at the lenders’ discretion and is based, in part, upon external factors over which we have no control. The borrowing base is subject to a reduction by twenty-five percent (25%) of the principal amount of any unsecured or subordinated debt issued or incurred. The borrowing base may also be reduced if we sell borrowing base properties and/or cancel commodity derivative positions with an aggregate value in excess of 5% of the then-effective borrowing base between redeterminations. 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

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period not to exceed six months. The Bank Credit Agreement ~~matures on January 30, 2024.~~

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 make other restricted payments in an amount not to exceed “Distributable Free Cash Flow”, but only if (1) no event of default or borrowing base deficiency exists; (2) our total leverage ratio is 2 to 1 or lower; and (3) availability under the Bank Credit Agreement is at least 20%. The Bank Credit Agreement also limits our ability to, among other things, incur and repay other indebtedness; grant liens; engage in certain mergers, consolidations, liquidations and dissolutions; engage in sales of assets; make acquisitions and investments; make other restricted payments (including redeeming, repurchasing or retiring our common stock); and enter into commodity derivative agreements, in each case subject to customary exceptions.

The Bank Credit Agreement 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 commodity accounts of Denbury Inc. and such subsidiaries (as applicable); and (5) a security interest in substantially all other collateral that may be perfected by a Uniform Commercial Code filing, subject to certain exceptions.

~~The Bank Credit Agreement~~ contains certain financial performance covenants ~~commencing with the fiscal quarter ending December 31, 2020 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 3.5 times; and

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

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 ~~that agreement,~~the 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. Under these financial performance covenant calculations, as of June 30, 2021, our ratio of consolidated total debt to consolidated EBITDAX was 0.18 to 1.0 (with a maximum permitted ratio of 3.5 to 1.0) and our current ratio was 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, which is ~~filed as~~ an exhibit to our Form 8-K Report filed with the SEC on September 18, 2020.

~~Capital Spending~~. We currently anticipate that our full-year 2020 capital spending, excluding capitalized interest and acquisitions, will be approximately $95 million to $105 million, approximately 78% of which has been incurred through 2020. This 2020 capital expenditure budget reflects a reduction on March 31, 2020 of $80 million, or 44%, 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. Our current 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.~~

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

Nine Months Ended
September 30,
In thousands 2020 2019
Capital expenditure summary
Tertiary oil fields $ 22,564
$ 72,333
Non-tertiary fields 19,115
55,939
Capitalized internal costs⁽¹⁾
26,695
35,389
Oil and natural gas capital expenditures 68,374
163,661
CO₂ pipelines, sources and other
9,192
25,778
Capital expenditures, before acquisitions and capitalized interest 77,566
189,439
Acquisitions of oil and natural gas properties 95
122
Capital expenditures, before capitalized interest 77,661
189,561
Capitalized interest 23,068
27,545
Capital expenditures, total $ 100,729
$ 217,106


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

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 ~~consists~~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, but excludes any potential payments related to the APMTG litigation being appealed.~~costs.

Our commitments and obligations consist of those detailed as of December 31, ~~2019,~~2020, in our Form 10-K under Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Commitments, Obligations and ~~Obligations~~Off-Balance Sheet Arrangements. ~~Material changes to~~During the six months ended June 30, 2021, our contractual commitments since December 31, 2019 detailed in this Form 10-Q report include changes to our senior secured bank credit agreement, the cancellation of the Predecessor senior secured second lien notes, convertible senior notes, and senior subordinated notes pursuant to the Plan, and a $41.3long-term asset retirement obligations increased by $47.3 million, ~~payment related to the NEJD pipeline lease financing during the third quarter of 2020. As part of the Chapter 11 Restructuring, we elected to terminate some of our operating leases,~~ primarily related to ~~office space, reducing~~ our ~~annual rent expense by approximately $9 million. In late October 2020, we reacquired the NEJD pipeline system~~acquisition of working interest positions in Wyoming CO2 EOR fields (see Note 2, Acquisition and ~~Free State Pipeline from Genesis, representing full settlement of all remaining pipeline financing obligations.~~Divestiture).

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.

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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.

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Sales Volumes

~~Operating Results Table~~

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:

~~Certain~~


	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 ~~financial results for our Successor~~working interests in Webster, Thompson, Manvel, and ~~Predecessor periods are presented~~East Hastings fields (the “Gulf Coast Working Interests Sale”).

Total sales volumes during the second quarter of 2021 averaged 49,133 BOE/d, including 33,452 Bbls/d from tertiary properties and 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 tables:~~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.

Successor Predecessor
Period from Sept. 19, 2020 through Period from July 1, 2020 through Three Months Ended
In thousands, except per-share and unit data Sept. 30, 2020 Sept. 18, 2020 Sept. 30, 2019
Operating results
Net income (loss)⁽¹⁾
$ 2,758
$ (809,120 ) $ 72,862
Net income (loss) per common share – basic⁽¹⁾
0.06
(1.63 ) 0.16
Net income (loss) per common share – diluted⁽¹⁾
0.06
(1.63 ) 0.14
Net cash provided by (used for) operating activities 32,910
40,597
130,578
23

Successor Predecessor
Period from Sept. 19, 2020 through Period from Jan. 1, 2020 through Nine Months Ended
In thousands, except per-share and unit data Sept. 30, 2020 Sept. 18, 2020 Sept. 30, 2019
Operating results
Net income (loss)⁽¹⁾
$ 2,758
$ (1,432,578 ) $ 193,880
Net income (loss) per common share – basic⁽¹⁾
0.06
(2.89 ) 0.43
Net income (loss) per common share – diluted⁽¹⁾
0.06
(2.89 ) 0.41
Net cash provided by (used for) operating activities 32,910
113,408
343,578


~~(1)~~	Includes a pre-tax full cost pool ceiling test write-down of our oil and natural gas properties of $261.7 million and $996.7 million for the Predecessor periods July 1, 2020 through September 18, 2020 and January 1, 2020 through September 18, 2020, respectively. In addition, includes reorganization adjustments, net totaling $850.0 million during the 2020 Predecessor periods.

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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 the second quarter of 2020, and (3) declines at Delhi Field due to lower CO2 purchases between late-February and 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 recovery fields acquired on March 3, 2021.

~~Certain~~

Our sales volumes during the three and six months ended June 30, 2021 were 97% oil, consistent with our 97% and 98% oil sales during the same prior-year periods.

Oil and Natural Gas Revenues

Our oil and natural gas revenues during the three and six months ended June 30, 2021 increased 158% and 53%, respectively, compared to these revenues for the same periods in 2020. The changes in our oil and natural gas revenues are due primarily to higher realized commodity prices (excluding any impact of our ~~operating results and statistics for the comparative three and nine months ended September 30, 2020 and 2019 are included~~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 Nine Months Ended
September 30, September 30,
In thousands, except per-share and unit data 2020 2019 2020 2019
Average daily production volumes

Bbls/d 48,334
55,085
50,619
56,836
Mcf/d 8,110
8,135
7,916
9,681
BOE/d⁽¹⁾
49,686
56,441
51,939
58,449
Operating revenues

Oil sales $ 174,447
$ 292,100
$ 511,562
$ 912,636
Natural gas sales 964
1,092
2,860
5,554
Total oil and natural gas sales $ 175,411
$ 293,192
$ 514,422
$ 918,190
Commodity derivative contracts⁽²⁾

Receipt on settlements of commodity derivatives $ 17,789
$ 8,057
$ 88,056
$ 14,714
Noncash fair value gains (losses) on commodity derivatives⁽³⁾
(18,363 ) 35,098
18,011
(30,176 )
Commodity derivatives income (expense) $ (574 ) $ 43,155
$ 106,067
$ (15,462 )
Unit prices – excluding impact of derivative settlements

Oil price per Bbl $ 39.23
$ 57.64
$ 36.88
$ 58.82
Natural gas price per Mcf 1.29
1.46
1.32
2.10
Unit prices – including impact of derivative settlements⁽²⁾

Oil price per Bbl $ 43.23
$ 59.23
$ 43.23
$ 59.77
Natural gas price per Mcf 1.29
1.46
1.32
2.10
Oil and natural gas operating expenses

Lease operating expenses $ 71,192
$ 117,850
$ 261,755
$ 361,205
Transportation and marketing expenses 9,499
10,067
28,508
32,076
Production and ad valorem taxes 13,697
20,220
40,450
65,780
Oil and natural gas operating revenues and expenses per BOE

Oil and natural gas revenues $ 38.37
$ 56.46
$ 36.15
$ 57.54
Lease operating expenses 15.57
22.70
18.39
22.64
Transportation and marketing expenses 2.08
1.94
2.00
2.01
Production and ad valorem taxes 3.00
3.89
2.84
4.12
CO₂ sources – revenues and expenses

CO₂ sales and transportation fees
$ 7,484
$ 8,976
$ 22,016
$ 25,532
CO₂ operating and discovery expenses
(1,197 ) (879 ) (2,834 ) (2,016 )
CO₂ revenue and expenses, net
$ 6,287
$ 8,097
$ 19,182
$ 23,516

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, 2021 and 2020 and the three and six months ended June 30, 2021 and 2020:


~~(1)~~	~~Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of natural gas (“BOE”).~~


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

~~(3)~~

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 $17.8 million and $88.1 million for the three and nine months ended September 30, 2020, respectively, compared to receipts on settlements of $8.1 million and $14.7 million for the three and nine months ended September 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


	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

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 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 three quarters of~~ ~~2020~~ ~~is shown below:~~

Average Daily Production (BOE/d)

First
Quarter

Second
Quarter

Third
Quarter

Fourth
Quarter

First
Quarter

Second
Quarter

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

4,256

4,085
3,813
3,529
3,208
Hastings 5,539
5,466

5,513

5,097
5,232
4,722
4,473
Heidelberg 3,987
4,082

4,297

4,409
4,371
4,366
4,256
Oyster Bayou 4,740
4,394

3,995

4,261
3,999
3,871
3,526
Tinsley 4,659
4,891

4,541

4,343
4,355
3,788
4,042
West Yellow Creek 436
586
728
807
775
695
588
Mature properties⁽¹⁾
6,479
6,448
6,415
6,347
6,386
5,249
5,683
Total Gulf Coast region 30,314

30,353

29,745

29,349

28,931
26,220
25,776
Rocky Mountain region

Bell Creek 4,650
5,951

4,686

5,618
5,731
5,715
5,551
Salt Creek 2,057
2,078
2,213
2,223
2,149
1,386
2,167
Grieve 52
41
58
60
50
7
0
Total Rocky Mountain region 6,759
8,070

6,957

7,901
7,930
7,108
7,718
Total tertiary oil production 37,073
38,423

36,702

37,250
36,861
33,328
33,494
Non-tertiary oil and gas production

Gulf Coast region

Mississippi 1,034
1,025
873
952
748
713
629
Texas 3,298
3,224
3,165
3,212
3,419
3,087
3,095
Other 10
6
6
5
6
5
4
Total Gulf Coast region 4,342
4,255

4,044

4,169
4,173

3,805
3,728
Rocky Mountain region

Cedar Creek Anticline 14,987
14,311

13,354

13,730
13,046

11,988
11,485
Other 1,313
1,305

1,238

1,192
1,105

1,069
979
Total Rocky Mountain region 16,300
15,616

14,592

14,922
14,151

13,057
12,464
Total non-tertiary production 20,642
19,871

18,636

19,091

18,324

16,862
16,192
Total continuing production 57,715
58,294

55,338

56,341
55,185

50,190
49,686
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
49,686


~~(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 production during the~~ ~~third quarter~~ of ~~2020~~ averaged 49,686 BOE/d, including 33,494 Bbls/d from tertiary properties and 16,192 BOE/d from non-tertiary properties. This production level represents a decrease of 504 BOE/d (1%) compared to production levels in the second quarter of 2020 and a decrease of 5,652 BOE/d (10%) compared to third quarter of 2019 continuing

~~Table of Contents~~

~~Denbury Inc.~~

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

production, which is adjusted for production from assets sold in the first quarter of 2020. Production during the second and third quarters of 2020 was impacted by approximately 4,300 BOE/d and 1,700 BOE/d, respectively, of production that was shut-in due to wells that were at that time uneconomic to produce or repair. In addition to shut-in production, the year-over-year production decline was primarily due to production declines at Delhi Field due to the lack of CO₂ ~~purchases since late-February 2020 as a result of the Delta-Tinsley CO~~₂ pipeline being down for repair, reduced levels of workovers and capital investment due to lower oil prices and higher than normal declines resulting from such. Although we returned to production approximately 2,600 BOE/d of shut-in production between the second and third quarters of 2020, sequential quarterly production declined slightly for various reasons, including the following: continued production declines at Delhi Field due to the lack of CO₂ ~~purchases, the impact of downtime from hurricanes impacting the Gulf Coast, typical seasonal impacts on CO~~₂ density due to higher temperatures, and a higher portion of production allocated to the net profits interest at our Cedar Creek Anticline Fields relative to the second quarter. In late October 2020, repairs to the Delta-Tinsley pipeline were completed and the pipeline was brought back into service, allowing CO₂ ~~purchases to resume at Delhi Field.~~

Our production during the three and nine months ended September 30, 2020 was 97% oil, slightly lower than our 98% oil production during the three months ended September 30, 2019 and consistent with oil production during the prior-year period.

~~Oil and Natural Gas Revenues~~

Our oil and natural gas revenues during the three and nine months ended September 30, 2020 decreased 40% and 44%, respectively, compared to these revenues for the same periods in 2019. The changes in our oil and natural gas revenues are due to changes in production quantities and realized commodity prices (excluding any impact of our commodity derivative contracts), as reflected in the following table:

Three Months Ended Nine Months Ended
September 30, September 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 $ (35,090 ) (12 )% $ (99,290 ) (11 )%
Decrease in realized commodity prices (82,691 ) (28 )% (304,478 ) (33 )%
Total decrease in oil and natural gas revenues $ (117,781 ) (40 )% $ (403,768 ) (44 )%

~~Table of Contents~~

~~Denbury Inc.~~

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

Excluding any impact of our commodity derivative contracts, our net realized commodity prices and NYMEX differentials were as follows during each of the first three quarters and nine months ended September 30, 2020 and 2019:

Three Months Ended Nine Months Ended
March 31, June 30, September 30, September 30,
2020 2019 2020 2019 2020 2019 2020 2019
Average net realized prices
Oil price per Bbl $ 45.96
$ 56.50
$ 24.39
$ 62.22
$ 39.23
$ 57.64
$ 36.88
$ 58.82
Natural gas price per Mcf 1.46
2.68
1.21
2.01
1.29
1.46
1.32
2.10
Price per BOE 45.09
55.27
23.95
60.80
38.37
56.46
36.15
57.54
Average NYMEX differentials

Gulf Coast region
Oil per Bbl $ 1.18
$ 4.26
$ (3.59 ) $ 4.85
$ (1.38 ) $ 3.11
$ (0.86 ) $ 4.08
Natural gas per Mcf (0.06 ) (0.10 ) (0.09 ) 0.10
(0.06 ) (0.24 ) (0.07 ) (0.06 )
Rocky Mountain region
Oil per Bbl $ (2.78 ) $ (2.56 ) $ (4.68 ) $ (1.48 ) $ (2.03 ) $ (1.65 ) $ (2.89 ) $ (1.85 )
Natural gas per Mcf (0.91 ) (0.28 ) (1.04 ) (1.13 ) (1.74 ) (1.61 ) (1.25 ) (0.90 )
Total Company
Oil per Bbl $ (0.38 ) $ 1.63
$ (4.03 ) $ 2.35
$ (1.64 ) $ 1.30
$ (1.67 ) $ 1.79
Natural gas per Mcf (0.41 ) (0.20 ) (0.54 ) (0.50 ) (0.83 ) (0.87 ) (0.60 ) (0.47 )

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 $1.38 per Bbl during the third quarter of 2020,~~

•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 positive $3.11 per Bbl during the third quarter of 2019 and~~ a negative $3.59 per Bbl during the second 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 storage constraints and weak demand caused these differentials to weaken significantly during the second and third quarters of 2020.

•

~~Rocky Mountain Region. NYMEX oil differentials in the Rocky Mountain region averaged $2.03 per Bbl and $1.65 per Bbl below NYMEX during the third quarters of 2020 and~~ ~~2019~~, respectively, and $4.68 per Bbl below NYMEX during the second 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 oil prices and differentials during 2020 have been significantly impacted by the rapid and precipitous drop in oil demand caused by the slowdown in economic activity due to the COVID-19 pandemic. This drop in oil demand 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. Although OPEC+ subsequently agreed to reduced levels of production output, concerns about the ability of OPEC+ to maintain compliance with their reduced production targets and uncertainty about the duration of the COVID-19 pandemic and its resulting economic consequences has resulted in abnormally high worldwide inventories of produced oil. While oil prices have improved from the low points experienced during the second quarter of 2020 ~~concerns~~ and ~~uncertainties around~~a negative $1.37 per Bbl during the ~~balance~~first quarter of ~~supply~~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 ~~for oil are expected to continue for some time. While our oil~~caused by the COVID-19 coronavirus (“COVID-19”) pandemic, these differentials ~~have improved since~~weakened significantly during the second quarter of 2020 and have remained lower than historical values since April 2020.

•Rocky Mountain Region. NYMEX oil ~~prices are expected~~differentials 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 ~~continue~~fluctuate with regional supply and demand trends and can fluctuate significantly on a month-to-month basis due to ~~be volatile as a result of these events,~~weather, refinery or transportation issues, and ~~as changes in~~Canadian and U.S. crude oil ~~inventories, oil demand and economic performance are reported.~~price index volatility.

~~Table of Contents~~

~~Denbury Inc.~~

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

CO₂ Revenues and Expenses

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

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 “Oil marketing sales” and the expenses incurred to market and transport the oil as “Oil marketing expenses” in our Unaudited Condensed Consolidated Statements of Operations.

Commodity Derivative Contracts

The following ~~tables summarize~~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, ~~indicated:~~and to the changes in oil futures prices between the second quarters of 2020 and 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.

Successor

Predecessor
Period from Sept. 19, 2020 through

Period from July 1, 2020 through
Three Months Ended
In thousands Sept. 30, 2020

Sept. 18, 2020
Sept. 30, 2019
Receipt on settlements of commodity derivatives $ 6,660
$ 11,129
$ 8,057
Noncash fair value gains (losses) on commodity derivatives⁽¹⁾
(2,625 ) (15,738 ) 35,098
Total income (expense) $ 4,035
$ (4,609 ) $ 43,155

Successor

Predecessor
Period from Sept. 19, 2020 through

Period from Jan. 1, 2020 through
Nine Months Ended
In thousands Sept. 30, 2020

Sept. 18, 2020
Sept. 30, 2019
Receipt (payment) on settlements of commodity derivatives $ 6,660
$ 81,396
$ 14,714
Noncash fair value gains (losses) on commodity derivatives⁽¹⁾
(2,625 ) 20,636
(30,176 )
Total income (expense) $ 4,035
$ 102,032
$ (15,462 )


~~(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.

~~Table of Contents~~

~~Denbury Inc.~~

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

In order to provide a level of price protection to a portion of our oil production, we have hedged a portion of our estimated oil production through ~~2020 using both NYMEX and LLS fixed-price swaps and three-way collars and oil production in 2021 and the first half of~~ 2022 using NYMEX fixed-price ~~swaps.~~swaps and costless collars. See Note ~~10,~~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 ~~September~~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 ~~November 12, 2020:~~August 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

4Q 2020 2021 1H 2022
WTI NYMEX Volumes Hedged (Bbls/d) 13,500 24,000 8,500
Fixed-Price Swaps
Swap Price⁽¹⁾
$40.52 $42.22 $43.55
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 24,000 8,500

(1)Averages are volume weighted.


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


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

Based on current contracts in place and NYMEX oil futures prices as of ~~November 12, 2020,~~August 4, 2021, which averaged approximately ~~$40~~$68 per Bbl, we currently expect that we would ~~receive~~make cash payments of approximately ~~$20~~$145 million upon settlement of our ~~October~~July through December ~~2020 contracts. Of this estimated~~2021 contracts, the amount ~~the majority relates to our three-way collars,~~of which settlements are 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

Total lease operating expenses increased $28.9 million (36%) and $1.6 million (1%) on an absolute-dollar basis, or $6.85 (38%) and $2.28 (12%) on a per-BOE basis, during the three and six months ended June 30, 2021, respectively, compared to the same prior-year periods. The increase during the second quarter of 2021 on an absolute-dollar basis compared to the same period in 2020 was primarily due to (a) higher expenses across nearly all expense categories as our costs are correlated to varying degrees with changes in oil prices, with the largest 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 CO2 expense 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 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 Company of approximately $16.3 million; as of June 30, 2021, $9.9 million of these savings were included in “Trade and other receivables, net” and $3.7 million included in “Other assets” in our Unaudited Condensed Consolidated Balance Sheets. Compared to the first quarter of 2021, lease operating expenses in the most recent quarter increased $28.3 million (34%) on an absolute-dollar basis and $5.42 (28%) on a per-BOE basis, due primarily to the first quarter 2021 utility benefit mentioned above, the second quarter of 2021 reflecting a full quarter of operating expenses for the Wind River Basin properties acquired in March 2021, as well as increases in workover and CO2 expense.

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Denbury Inc.

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

~~Production Expenses~~

~~Lease Operating Expenses~~

T~~otal lease operating expenses were $71.2 million, or $15.57 per BOE,~~ ~~for the combined Predecessor and Successor periods included within the three months ended September 30, 2020, compared to $117.9 million, or $22.70 per BOE, during the three months ended September 30, 2019. Total lease operating expenses were~~ ~~$261.8 million, or $18.39 per BOE, for the combined Predecessor and Successor periods included within the nine months ended~~ ~~September 30, 2020, compared to $361.2 million, or $22.64 per BOE, during the nine months ended September 30, 2019. The decreases on an absolute-dollar basis and per-BOE basis were primarily due to~~ ~~lower expenses across all expense categories, with the largest decreases in workover expense, labor, and power and fuel costs, as well as~~ insurance reimbursements totaling $15.4 million recorded for previously-incurred well control costs, cleanup costs, and damages associated with a 2013 incident at Delhi Field. In response to the significant decline in oil prices in 2020, we reduced our capital budget and implemented cost reduction measures which included shutting down compressors and delaying well repairs and workovers that were uneconomic. Compared to the second quarter of 2020, lease operating expenses decreased $10.1 million on an absolute-dollar basis and $2.23 on a per-BOE basis, due to the insurance reimbursement mentioned above, partially offset by higher workover expense as we resumed some repairs and maintenance activity.

~~Currently, our CO~~₂ ~~expense comprises approximately 20% to 25% of our typical tertiary lease operating expenses, and consists of CO~~₂ ~~production expenses for the CO~~₂ ~~reserves we own, and consists of our purchase of CO~~₂ ~~from royalty and working interest owners and industrial sources for the CO~~₂ ~~reserves we do not own. During the third quarters of 2020 and 2019, approximately 46% and 55%, 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 $0.37 per Mcf during the~~ ~~third 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 the third quarter of 2020 was consistent with the~~ ~~third quarter~~ of ~~2019~~ ~~and lower than the $0.39 per Mcf comparable measure during the second quarter of 2020 due to a lower utilization in our Gulf Coast operations of industrial-sourced CO~~₂~~, which has a higher average cost than our naturally-occurring CO~~₂ ~~source.~~

Transportation and Marketing Expenses

Transportation and marketing expenses primarily consist of amounts incurred relating to the transportation, marketing, and processing of oil and natural gas production. Transportation and marketing expenses were ~~$9.5~~$8.5 million and $9.4 million for the ~~combined Predecessor~~three months ended June 30, 2021 and 2020, respectively, and $16.3 million and $19.0 million for the six months ended June 30, 2021 and 2020, 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 increased $12.0 million (116%) and $11.3 million (38%) during the three and six months ended June 30, 2021, respectively, compared to the same prior-year periods, due primarily to an increase in production taxes resulting from 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 Inc.

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

Interest and Financing Expenses

and Successor periods included within the three months ended September 30, 2020, compared to $10.1 million during the three months ended September 30, 2019. Transportation and marketing expenses were $28.5 million for the combined Predecessor and Successor periods included within the nine months ended September 30, 2020, compared to $32.1 million for the nine months ended September 30, 2019. The decreases between periods were primarily due to fewer third-party oil purchases and lower compression expenses.


	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		%

~~Taxes Other Than Income~~

Taxes other than income were $15.5 million for the combined Predecessor and Successor periods included within the three months ended September 30, 2020, compared to $22.0 million during the three months ended September 30, 2019. Taxes other than income were $45.6 million for the combined Predecessor and Successor periods included within the nine months ended September 30, 2020, compared to $71.3 million for the nine months ended September 30, 2019. The decreases in both periods when compared to 2019 are due primarily to a decrease in production taxes resulting from lower oil and natural gas revenues.

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

Successor Predecessor
Period from Sept. 19, 2020 through Period from July 1, 2020 through Three Months Ended
In thousands, except per-BOE data and employees Sept. 30, 2020 Sept. 18, 2020 Sept. 30, 2019
Gross cash compensation and administrative costs $ 5,590
$ 41,464
$ 53,969
Gross stock-based compensation —
880
3,983
Operator labor and overhead recovery charges (3,343 ) (21,560 ) (29,865 )
Capitalized exploration and development costs (512 ) (5,771 ) (9,821 )
Net G&A expense $ 1,735
$ 15,013
$ 18,266

G&A per BOE

Net cash administrative costs $ 2.90
$ 3.64
$ 2.94
Net stock-based compensation —
0.14
0.58
Net G&A expenses $ 2.90
$ 3.78
$ 3.52

Employees as of period end 663
662
826

~~Table of Contents~~(1)

~~Denbury Inc.~~

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

Successor Predecessor
Period from Sept. 19, 2020 through Period from Jan. 1, 2020 through Nine Months Ended
In thousands, except per-BOE data Sept. 30, 2020 Sept. 18, 2020 Sept. 30, 2019
Gross cash compensation and administrative costs $ 5,590
$ 137,096
$ 162,589
Gross stock-based compensation —
5,771
12,958
Operator labor and overhead recovery charges (3,343 ) (74,780 ) (90,480 )
Capitalized exploration and development costs (512 ) (19,565 ) (30,370 )
Net G&A expense $ 1,735
$ 48,522
$ 54,697

G&A per BOE

Net cash administrative costs $ 2.90
$ 3.26
$ 2.81
Net stock-based compensation —
0.30
0.62
Net G&A expenses $ 2.90
$ 3.56
$ 3.43

Our net G&A expenses on an absolute-dollar basis were $16.7 million for the combined Predecessor and Successor periods included within the three months ended September 30, 2020, a decrease of $1.5 million (8%) from the three months ended September 30, 2019, and net G&A expenses on an absolute-dollar basis were $50.3 million for the combined Predecessor and Successor periods included within the nine months ended September 30, 2020, a decrease of $4.4 million (8%) from the nine months ended September 30, 2019. The decreases in net G&A expenses during 2020 compared to the three and nine month periods ended September 30, 2019, were primarily due to lower overall employee compensation and related costs due to reduced employee headcount, partially offset by lower G&A recoveries related to operator labor and overhead, and capitalized exploration and development costs which increased net G&A expense as a result of reductions in the number of employees, shut-in production and fewer producing wells in the current periods. On the Emergence Date, the Predecessor’s unvested shares were cancelled, resulting in the acceleration of stock compensation expenseCash interest during the Predecessor period includes the portion of ~~$4.6 million; thereby, no stock-based compensation expense will be recognized~~interest on 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 ~~Successor~~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 ~~until additional shares are granted. Also~~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 ~~Emergence Date and pursuant~~Petition Date.

(3)Excludes debt discounts related to the ~~terms of the Plan~~Predecessor’s 7¾% Senior Secured Notes and the Confirmation Order, we adopted a framework for a management incentive plan which will reserve primarily for employees and directors a pool of shares of new common stock representing up to 10% of Denbury common stock, determined on a fully diluted and fully distributed basis, with initial awards from this pool scheduled to be issued within 60 days of emergence.

2024 Convertible Senior Notes.

Compared to the second quarter of 2020, net G&A expenses decreased $7.0 million primarily due to the second quarter of 2020 including additional compensation-related expenses related to modifications in our compensation program which resulted in additional bonus accruals (see further discussion in Note 9, (4)~~Stock Compensation, to the Unaudited Condensed Consolidated Financial Statements).~~

Our 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 administrativeIncludes commitment fees but excludes debt issue 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.amortization of discount.

~~Table of Contents~~

~~Denbury Inc.~~

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

~~Interest and Financing Expenses~~

Successor Predecessor
Period from Sept. 19, 2020 through Period from July 1, 2020 through Three Months Ended
In thousands, except per-BOE data and interest rates Sept. 30, 2020 Sept. 18, 2020 Sept. 30, 2019
Cash interest⁽¹⁾
$ 403
$ 17,734
$ 48,297
Less: interest not reflected as expense for financial reporting purposes⁽¹⁾
—
(6,976 ) (21,372 )
Noncash interest expense 114
347
1,060
Amortization of debt discount⁽²⁾
—
1,303
3,646
Less: capitalized interest (183 ) (4,704 ) (8,773 )
Interest expense, net $ 334
$ 7,704
$ 22,858
Interest expense, net per BOE $ 0.56
$ 1.94
$ 4.40
Average debt principal outstanding⁽³⁾
$ 185,877
$ 815,025
$ 2,374,422
Average cash interest rate⁽⁴⁾
6.6 % 10.0 % 8.1 %

Successor Predecessor
Period from Sept. 19, 2020 through Period from Jan. 1, 2020 through Nine Months Ended
In thousands, except per-BOE data and interest rates Sept. 30, 2020 Sept. 18, 2020 Sept. 30, 2019
Cash interest⁽¹⁾
$ 403
$ 108,824
$ 144,616
Less: interest not reflected as expense for financial reporting purposes⁽¹⁾
—
(49,243 ) (64,006 )
Noncash interest expense 114
2,439
3,517
Amortization of debt discount⁽²⁾
—
9,132
4,090
Less: capitalized interest (183 ) (22,885 ) (27,545 )
Interest expense, net $ 334
$ 48,267
$ 60,672
Interest expense, net per BOE $ 0.56
$ 3.54
$ 3.80
Average debt principal outstanding⁽³⁾
$ 185,877
$ 1,767,605
$ 2,491,015
Average cash interest rate⁽⁴⁾
6.6 % 8.6 % 7.7 %

~~(1)~~

~~Cash interest includes the portion of interest on certain debt instruments accounted for as a reduction of debt for GAAP financial reporting purposes in accordance with FASC 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 and 9¼% Senior Secured Second Lien Notes due 2022. Amounts remaining in future interest payable were written-off to “Reorganization items, net” in the Unaudited Condensed Consolidated Statements of Operations on the Petition Date.

~~(2)~~

Represents amortization of debt discounts of $0.4 million and $3.0 million related to the 7¾% Senior Secured Second Lien Notes due 2024 (the “7¾% Senior Secured Notes”) during the Predecessor periods July 1, 2020 through September 18, 2020 and January 1, 2020 through September 18, 2020, respectively, and $0.9 million and $6.1 million related to the 6⅜% Convertible Senior Notes due 2024 (the “2024 Convertible Senior Notes”) during the Predecessor periods July 1, 2020 through September 18, 2020 and January 1, 2020 through September 18, 2020, respectively. Remaining debt discounts were written-off to “Reorganization items, net” in the Unaudited Condensed Consolidated Statements of Operations on the Petition Date.


~~(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.~~

Cash interest ~~was $18.1 million for the combined Predecessor and Successor periods included within the three months ended September 30, 2020, compared to $48.3 million~~ during the three and six months ended ~~September~~June 30, ~~2019. Cash interest was $109.2~~2021 decreased $43.5 million ~~for~~(96%) and $87.4 million (96%), respectively, when compared to the ~~combined Predecessor and Successor periods included within the nine months ended September 30, 2020, compared~~

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~~Denbury Inc.~~

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

~~to $144.6 million during the nine months ended September 30, 2019.~~same prior-year periods. The decreases between periods were primarily due to a decrease in the average debt principal outstanding, with the Successor ~~period~~periods reflecting the full extinguishment of all outstanding obligations under ~~the~~our previously outstanding senior secured second lien notes, convertible senior notes, and senior subordinated notes on the Emergence Date, pursuant to the terms of the ~~Plan,~~prepackaged joint plan of reorganization, relieving us of approximately $2.1 billion of debt by issuing equity and/or warrants in the Successor period to the holders of that debt. As a result, only interest expense associated with the Predecessor’s pipeline financings, capital leases and Senior Secured Superpriority Debtor-in-Possession Credit Agreement were recognized in interest expense during August and September 2020.

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

Successor Predecessor
Period from Sept. 19, 2020 through Period from July 1, 2020 through Three Months Ended
In thousands, except per-BOE data Sept. 30, 2020 Sept. 18, 2020 Sept. 30, 2019
Oil and natural gas properties $ 4,105
$ 21,636
$ 39,304
CO₂ properties, pipelines, plants and other property and equipment
1,178
12,890
15,760
Accelerated depreciation charge⁽¹⁾
—
1,791
—
Total DD&A $ 5,283
$ 36,317
$ 55,064

DD&A per BOE

Oil and natural gas properties $ 6.86
$ 5.45
$ 7.57
CO₂properties, pipelines, plants and other property and equipment
1.97
3.24
3.03
Accelerated depreciation charge⁽¹⁾
—
0.45
—
Total DD&A cost per BOE $ 8.83
$ 9.14
$ 10.60

Write-down of oil and natural gas properties $ —
$ 261,677
$ —
28

Successor Predecessor
Period from Sept. 19, 2020 through Period from Jan. 1, 2020 through Nine Months Ended
In thousands, except per-BOE data Sept. 30, 2020 Sept. 18, 2020 Sept. 30, 2019
Oil and natural gas properties $ 4,105
$ 104,495
$ 116,249
CO₂ properties, pipelines, plants and other property and equipment
1,178
44,939
54,376
Accelerated depreciation charge⁽¹⁾
—
39,159
—
Total DD&A $ 5,283
$ 188,593
$ 170,625

DD&A per BOE

Oil and natural gas properties $ 6.86
$ 7.66
$ 7.29
CO₂properties, pipelines, plants and other property and equipment
1.97
3.30
3.40
Accelerated depreciation charge⁽¹⁾
—
2.87
—
Total DD&A cost per BOE $ 8.83
$ 13.83
$ 10.69

Write-down of oil and natural gas properties $ —
$ 996,658
$ —


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

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Denbury Inc.

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

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


	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

DD&A expense was $41.6 million for the combined Predecessor and Successor periods included within the three months ended September 30, 2020, compared to $55.1 million during the three months ended September 30, 2019, with the decrease primarily due to a decrease in oil and natural gas properties depletion due to lower depletable costs, as well as lower CO

(1)₂ ~~properties, pipelines, plants and other property and equipment DD&A as a result of lower CO~~₂ ~~volumes from our CO~~₂ sources. DD&A expense was $193.9 million for the combined Predecessor and Successor periods included within the nine months ended September 30, 2020, compared to $170.6 million during the nine months ended September 30, 2019, with the increase primarily due toRepresents an accelerated depreciation charge ~~of $37.4 million~~ related to ~~assets~~capitalized amounts associated with ~~impaired~~ unevaluated properties that were transferred to the full cost ~~pool~~pool.

The decreases in DD&A expense during the three and six months ended June 30, 2021, when compared to the same periods in 2020, were primarily due to lower depletable costs due to the step down in book value resulting from fresh start accounting as of September 18, 2020, with the year-over-year decrease further impacted by accelerated depreciation of $37.4 million in the first quarter of 2020 ~~partially offset by a decrease in oil and natural gas~~related to unevaluated properties ~~depletion due~~that were transferred to ~~lower depletable costs, as well as lower CO~~the full cost pool.

₂ ~~properties, pipelines, plants and other property and equipment DD&A as a result of lower CO~~₂ ~~volumes from our CO~~₂ ~~sources.~~

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 $40.08 per Bbl as of September 18, 2020, $44.74 per Bbl as of June 30, 2020 and $55.17 per Bbl as of March 31, 2020. In addition, the first-day-of-the-month natural gas prices for the preceding 12 months, after adjustments for market differentials by field, averaged $1.72 per MMBtu as of September 18, 2020, $1.91 per MMBtu as of June 30, 2020 and $1.68 per MMBtu as of March 31, 2020. 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 weused to value the cost ceiling. We also recognized ~~additional~~ 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. We did not record a ceiling test write-down during the three months ended June 30, ~~2020 and $261.7 million during the period from July 1, 2020 through September 18, 2020.~~

~~Based upon fresh start accounting, oil and gas properties were recorded at fair value as of September 18, 2020. See Note 2,~~ ~~Fresh Start Accounting~~, to the Unaudited Condensed Consolidated Financial Statements for further discussion. There was no full cost pool ceiling test write-down for the period from September 19, 2020 through September 30, 2020.2021.

~~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.

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 no impairment was recorded.

Significant assumptions impacting expected future undiscounted net cash flows include projections of future oil and natural gas prices (management’s assumption of 2020 oil prices at strip pricing, gradually increasing to a long-term oil price of $65 per

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Denbury Inc.

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

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 September 18, 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 or for the period ending September 18, 2020.

~~Reorganization Items, Net~~

Reorganization items represent (i) expenses incurred during the Chapter 11 Restructuring subsequent to the Petition Date as a direct result of the Plan, (ii) gains or losses from liabilities settled, and (iii) fresh start accounting adjustments and are recorded in “Reorganization items, net” in our Unaudited Condensed Consolidated Statements of Operations. Professional service provider charges associated with our restructuring that were incurred before the Petition Date and after the Emergence Date are recorded in “Other expenses” in our Unaudited Condensed Consolidated Statements of Operations. The following table summarizes the losses (gains) on reorganization items, net:

Predecessor
Period from July 1, 2020 through
In thousands Sept. 18, 2020
Gain on settlement of liabilities subject to compromise $ (1,024,864 )
Fresh start accounting adjustments 1,834,423
Professional service provider fees and other expenses 11,267
Success fees for professional service providers 9,700
Loss on reject contracts and leases 10,989
Valuation adjustments to debt classified as subject to compromise 757
DIP credit agreement fees 3,107
Accelerated and unvested stock compensation 4,601
Total reorganization items, net $ 849,980

~~Other Expenses~~

Other expenses totaled $24.2 million for the combined Predecessor and Successor periods included within the three months ended September 30, 2020, and $38.0 million for the combined Predecessor and Successor periods included within the nine months ended September 30, 2020. Other expenses during 2020 primarily are comprised of $24.1 million of professional fees associated with restructuring activities, $4.2 million for the write-off of certain trade receivables, $3.8 million of costs associated with the Delta-Tinsley CO₂ pipeline incident, and $1.6 million of costs associated with the APMTG Helium, LLC helium supply contract ruling. The 2019 amounts are primarily comprised of $1.5 million of transaction costs related to the Predecessor’s privately negotiated debt exchanges, $1.3 million of acquisition transaction costs, $1.3 million of expense related to an impairment of assets, and $1.3 million of costs associated with the APMTG Helium, LLC helium supply contract ruling.

~~Table of Contents~~

~~Denbury Inc.~~

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

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

Successor Predecessor
Period from Sept. 19, 2020 through Period from July 1, 2020 through Three Months Ended
In thousands, except per-BOE amounts and tax rates Sept. 30, 2020 Sept. 18, 2020 Sept. 30, 2019
Current income tax expense (benefit) $ 6
$ (1,451 ) $ (859 )
Deferred income tax expense (benefit) 6
(302,356 ) 37,909
Total income tax expense (benefit) $ 12
$ (303,807 ) $ 37,050
Average income tax expense (benefit) per BOE $ 0.02
$ (76.47 ) $ 7.13
Effective tax rate 0.4 % 27.3 % 33.7 %
Total net deferred tax liability $ 3,836

$ 400,213

Successor Predecessor
Period from Sept. 19, 2020 through Period from Jan. 1, 2020 through Nine Months Ended
In thousands, except per-BOE amounts and tax rates Sept. 30, 2020 Sept. 18, 2020 Sept. 30, 2019
Current income tax expense $ 6
$ (7,260 ) $ 1,214
Deferred income tax expense 6
(408,869 ) 90,454
Total income tax expense $ 12
$ (416,129 ) $ 91,668
Average income tax expense per BOE $ 0.02
$ (30.52 ) $ 5.75
Effective tax rate 0.4 % 22.5 % 32.1 %

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 Predecessor period from January 1, 2020 through September 18, 2020 was the best estimate of our annual effective tax rate.2020. Our effective tax ~~rate~~rates for the ~~Predecessor period was~~Successor three and six months ended June 30, 2021 were significantly lower than our estimated statutory rate, primarily due to our overall deferred tax asset position and the ~~establishment of a~~ valuation allowance ~~on our federal~~offsetting those assets. As we had a pre-tax loss for the second quarter of 2021 and ~~state deferred~~first half of 2021, the income tax ~~assets after the application of fresh start accounting.~~

~~We have evaluated the impact of the Plan of Reorganization, including~~benefit resulting from these losses is fully offset by the change in ~~control,~~valuation allowance, resulting ~~from our emergence from bankruptcy. The cancellation of debt income (“CODI”) realized upon emergence is excludable from income but results~~ in ~~a reduction or elimination of available net operating loss carryforwards,~~essentially no tax credit carryforwards and tax basis in assets, in accordance with the attribute reduction and ordering rules of Section 108 of the Internal Revenue Code of 1986 (the “Code”). The reduction in the Company’s tax attributes for excludable CODI does not occur until the last day of the Company’s tax year, December 31, 2020. Accordingly, the tax adjustments recorded in the Predecessor period represent our best estimate using all available information at September 30, 2020. Thus, the Company expects to fully reduce its federal net operating loss carryforwards, enhanced oil recovery credits, research and development tax credits, and a partial reduction of tax basis in assets. The final tax impacts of the bankruptcy emergence, as well as the Plan of Reorganization’s overall effect on the Company’s tax attributes will be refined based on the Company’s final financial position at December 31, 2020 as required under the Code. The Company is exploring an election under the ordering rules of the Code to first reduce tax basis in assets, followed by net operating losses and tax credits. The final tax impact on the Company’s tax attributes could change from the current estimates.provision.

~~As the~~The tax basis of our assets, primarily our oil and gas properties, is in excess of ~~the~~their carrying value, as adjusted in fresh start ~~accounting, the Successor is~~accounting; therefore, we are currently in a net deferred tax asset position. ~~We evaluated~~Based on all available evidence, both positive and negative, we continue to record a valuation allowance on our 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 the tax impacts of the Chapter 11 Restructuring~~allowances, which will largely be determined based on oil prices and the ~~full reduction~~Company’s ability to generate positive pre-tax income. A $1.2 million state deferred tax liability is recorded on the Successor balance sheet.

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

As of June 30, 2021, we had $0.6 million of alternative minimum tax credits, which under the Tax Cut and Jobs Act will be refunded in 2021 and are recorded as a receivable on the balance sheet. Our state net operating ~~losses and tax credits and partial reduction of tax basis~~loss carryforwards expire in ~~assets (collectively “tax attributes”). Given our cumulative~~various years, starting in 2025.

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

loss position and the continued low oil price environment, we recorded a total valuation allowance of $129.4 million on our underlying deferred tax assets, consisting of $43.8 million on our federal deferred tax assets and $85.6 million on our state deferred tax assets as of September 18, 2020. Valuation allowances totaling $68.6 million and $13.5 million were recorded for our State of Louisiana and State of Mississippi deferred tax assets, respectively. A $3.8 million state deferred tax liability is recorded on the Successor balance sheet. For the Successor period, we continue to offset our deferred tax assets with a valuation allowance. Thus, the income tax expense associated with the Successor’s pre-tax book income was offset by a change in valuation allowance. As of September 30, 2020, we had no federal net operating loss carryforwards and state net operating loss carryforwards of $52.3 million, all of which were fully offset with the valuation allowance.

The current income tax benefits for the Predecessor period ended September 18, 2020 and for the three month period ended September 30, 2019 represent amounts estimated to be receivable resulting from alternative minimum tax credits and certain state tax obligations. We received our 2019 federal income tax refund of $9.5 million in late September 2020.

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 Nine Months Ended
September 30, September 30,
Per-BOE data 2020 2019 2020 2019
Oil and natural gas revenues $ 38.37
$ 56.46
$ 36.15
$ 57.54
Receipt on settlements of commodity derivatives 3.90
1.56
6.19
0.92
Lease operating expenses (15.57 ) (22.70 ) (18.39 ) (22.64 )
Production and ad valorem taxes (3.00 ) (3.89 ) (2.84 ) (4.12 )
Transportation and marketing expenses (2.08 ) (1.94 ) (2.00 ) (2.01 )
Production netback 21.62
29.49
19.11
29.69
CO₂ sales, net of operating and discovery expenses
1.38
1.56
1.35
1.47
General and administrative expenses (3.66 ) (3.52 ) (3.53 ) (3.43 )
Interest expense, net (1.76 ) (4.40 ) (3.42 ) (3.80 )
Reorganization items settled in cash (8.55 ) —
(2.75 ) —
Other (2.72 ) 1.09
(0.74 ) 0.48
Changes in assets and liabilities relating to operations 9.77
0.93
0.26
(2.88 )
Cash flows from operations 16.08
25.15
10.28
21.53
DD&A – excluding accelerated depreciation charge (8.71 ) (10.60 ) (10.87 ) (10.69 )
DD&A – accelerated depreciation charge⁽¹⁾
(0.39 ) —
(2.75 ) —
Write-down of oil and natural gas properties (57.25 ) —
(70.03 ) —
Deferred income taxes 66.14
(7.30 ) 28.73
(5.67 )
Gain on extinguishment of debt —
1.13
1.33
6.66
Noncash fair value gains (losses) on commodity derivatives⁽²⁾
(4.03 ) 6.75
1.26
(1.89 )
Noncash reorganization items, net (177.40 ) —
(56.98 ) —
Other noncash items (10.85 ) (1.10 ) (1.44 ) 2.21
Net income $ (176.41 ) $ 14.03
$ (100.47 ) $ 12.15


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

(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.

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


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

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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 capitalize on emerging from bankruptcy~~the level and ~~our ability to succeed on a long-term basis, the extent and length~~sustainability of the ~~drop~~recent 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, statements or predictions related to the scope, timing and economic aspects of the carbon capture, use and storage industry or results of negotiations of CCUS arrangements, possible future write-downs of oil and natural gas reserves, 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 its 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, 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, 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 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;~~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; 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 ~~September~~June 30, ~~2020,~~2021, we had ~~$85.0~~$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 does not have any triggers or covenants regarding our debt ratings with rating agencies. The following table presents the principal and fair values of our outstanding debt as of ~~September~~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 4.0% at September 30, 2020) $ —
$ —
$ —
$ 85,000
$ 85,000
$ 85,000

See Note 6,4, 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 using both NYMEX and LLS fixed-price swaps and three-way collars and oil production in 2021 and the first half of~~ 2022 using NYMEX fixed-price ~~swaps.~~swaps and costless collars. Depending on market conditions, we may continue to add to our existing 2021 and 2022 hedges. See also Note ~~10,~~6, Commodity Derivative Contracts, and Note 117, Fair Value Measurements, to the Unaudited Condensed Consolidated Financial Statements for additional information regarding our commodity derivative contracts. Under the terms of our Successor senior secured bank credit facility, at any point in time within the initial measurement period of August 1, 2020 through July 31, 2021, we are required to have hedges in place covering a minimum of 65% of our anticipated crude oil production for the first twelve calendar months and 35% of our anticipated crude oil production for the second twelve month period. We have until December 31, 2020 to enter into transactions for the initial measurement period to be in compliance.

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.

At ~~September~~June 30, ~~2020,~~2021, our commodity derivative contracts were recorded at their fair value, which was a net ~~asset~~liability of ~~$21.6~~$245.4 million, ~~an $18.4 million decrease from the $40.0 million net asset recorded at June 30, 2020, and an $18.0~~a $109.3 million increase from the ~~$3.6~~$136.1 million net ~~asset~~liability recorded at March 31, 2021, and a $186.6 million increase from the $58.8 million net 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 ~~nine~~six months ended ~~September~~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~~ ~~September 30, 2020~~.

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Commodity Derivative Sensitivity Analysis

Based on NYMEX ~~and LLS~~ crude oil futures prices as of ~~September~~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 ~~September~~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 September 30, 2020 $ 21,842
10% increase in prices (3,200 )
10% decrease in prices 46,886

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 ~~September~~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 ~~third~~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 ~~12,~~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 recently emerged from bankruptcy, which could adversely affect our business and relationships.~~

It is possible that our having filed for bankruptcy and our recent emergence from the Chapter 11 bankruptcy proceedings could adversely affect our business and relationships with customers, employees and suppliers. Due to uncertainties, many risks exist, including the following:

~~key suppliers could terminate their relationship or require financial assurances or enhanced performance;~~

~~the ability to renew existing contracts and compete for new business may be adversely affected;~~

~~the ability to attract, motivate and/or retain key executives and employees may be adversely affected;~~

~~employees may be distracted from performance of their duties or more easily attracted to other employment opportunities; and~~

~~competitors may take business away from us, and our ability to attract and retain customers may be negatively impacted.~~

~~The occurrence of one or more of these events could~~2020. There have abeen no material ~~and adverse effect on our operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.~~

~~Our actual financial results after emergence from bankruptcy may not be comparable~~changes to our ~~historical financial information as a result of the implementation of the plan of reorganization and the transactions contemplated thereby and our adoption of fresh start accounting.~~

In connection with the disclosure statement we filed with the bankruptcy court, and the hearing to consider confirmation of the plan of reorganization, we prepared projected financial information to demonstrate to the bankruptcy court the feasibility of the plan of reorganization and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of the bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance and with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks and the assumptions underlying the projections and/or valuation estimates may prove to be wrong in material respects. Actual results will likely vary significantly from those contemplated by the projections. As a result, investors should not rely on these projections.

In addition, upon our emergence from bankruptcy, we adopted fresh start accounting. Accordingly, certain values and operational results of the Company’s condensed consolidated financial statements subsequent to September 18, 2020 are not comparable to those in its condensed consolidated financial statements prior to, and including September 18, 2020. The lack of comparable historical financial information may discourage investors from purchasing our common stock.

~~There is a limited trading market for our securities and the market price of our securities is subject to volatility.~~

Upon our emergence from bankruptcy, our old common stock was canceled and we issued new common stock. The market price of our common stock could be subject to wide fluctuations in response to, and the level of trading that develops with our common stock may be affected by, numerous factors, many of which are beyond our control. These factors include, among other things, our new capital structure as a result of the transactions contemplated by the plan of reorganization, our limited trading

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~~Denbury Inc.~~

history subsequent to our emergence from bankruptcy, our limited trading volume, the concentration of holdings of our common stock, the lack of comparable historical financial information due to our adoption of fresh start accounting, actual or anticipated variations in our operating results and cash flow, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described in this Report. No assurance can be given that an active market will develop for the common stock or as to the liquidity of the trading market for the common stock. The common stock may be traded only infrequently, and reliable market quotations may not be available. Holders of our common stock may experience difficulty in reselling, or an inability to sell, their shares. In addition, if an active trading market does not develop or is not maintained, significant sales of our common stock, or the expectation of these sales, could materially and adversely affect the market price of our common stock.

~~Upon our emergence from bankruptcy, the composition of our Board of Directors changed significantly.~~

Pursuant to the plan of reorganization, the composition of the Board changed significantly. Currently, the Board is made up of seven directors, four of whom have not previously served on the Board of the Company. The new directors have different backgrounds, experiences and perspectives from those individuals who previously served on the Board and, thus, may have different views on the issues that will determine the future of the Company. As a result, the future strategy and plans of the Company may differ materially from those of the past.

~~The continued COVID-19 pandemic, together with oil prices remaining at current levels, are likely to continue to negatively affect our cash flow.~~

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 intensity 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.

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 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 continue to shut-in uneconomic production.

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

Information regarding issuance on September 18, 2020 of new common stock and series A and B warrants to former debt and equity holders of the Predecessor upon cancellation of such debt and equity is contained in Item 3.02 of the Company’s Form 8-K filed with the Commission on September 18, 2020.None.

Item 3. Defaults Upon Senior Securities

~~Information regarding defaults upon senior securities is contained in Item 2.04 of the Company’s Form 8-K filed with the Commission on July 31, 2020.~~None.

Item 4. Mine Safety Disclosures

None.

Item 5. Other Information

None.

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Item 6. Exhibits



Exhibit No.		Exhibit
~~2(a)~~31(a)*		Joint Chapter 11 Plan of Reorganization of Denbury Resources Inc. and its Debtor Affiliates (Technical Modifications) (incorporated by reference to Exhibit A of the Order Approving the Debtors’ Disclosure Statement For, and Confirming, the Debtors’ Joint Chapter 11 Plan of Reorganization of Denbury Resources Inc. and its Debtor Affiliates, filed as Exhibit 2.1 to Form 8-K filed by the Company on September 4, 2020, File No. 001-12935).
~~3(a)~~	~~Third Restated Certificate of Incorporation of Denbury Resources Inc. (incorporated by reference to Exhibit 3.1 of Form 8-K filed by the Company on September 18, 2020, File No. 001-12935).~~
~~3(b)~~	Fourth Amended and Restated Bylaws of Denbury Resources Inc., as of September 18, 2020 (incorporated by reference to Exhibit 3.2 of Form 8-K filed by the Company on September 18, 2020, File No. 001-12935).
~~4(a)~~	Series A Warrant Agreement, dated as of September 18, 2020, by and between Denbury Inc., and Broadridge Corporate Issuer Solutions, Inc. (incorporated by reference to Exhibit 10.2 of Form 8-K filed by the Company on September 18, 2020, File No. 001-12935).
~~4(b)~~	Series B Warrant Agreement, dated as of September 18, 2020, by and between Denbury Inc., and Broadridge Corporate Issuer Solutions, Inc. (incorporated by reference to Exhibit 10.3 of Form 8-K filed by the Company on September 18, 2020, File No. 001-12935).
~~4(c)~~	Registration Rights Agreement, dated as of September 18, 2020, among Denbury Inc. and certain holders identified therein (incorporated by reference to Exhibit 10.4 of Form 8-K filed by the Company on September 18, 2020, File No. 001-12935).
~~10(a)†~~	Credit Agreement, dated as of September 18, 2020, by and among Denbury Inc., as borrower, the lenders party thereto, and JPMorgan Chase Bank, N.A., as administrative agent, swingline lender, and letter of credit issuer (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on September 18, 2020, File No. 001-12935).
~~10(b)~~	Form of Indemnification Agreement, by and between Denbury Inc. and its officers and directors (incorporated by reference to Exhibit 10.5 of Form 8-K filed by the Company on September 18, 2020, File No. 001-12935).
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

~~Table of Contents~~

~~Denbury Inc.~~


104
~~104~~		The cover page from the Company’s Quarterly Report on Form 10-Q for the quarter ended ~~September~~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.


†	~~Certain schedules and similar attachments have been omitted pursuant to Item 601(a)(5) of Regulation S-K and will be provided to the SEC upon request.~~

6838

Table of Contents

Denbury 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 INC.~~

~~November 16, 2020~~	/s/ Mark C. Allen
		Mark C. Allen Executive Vice President and Chief Financial Officer

~~November 16, 2020~~August 5, 2021		/s/ ~~Alan Rhoades~~Nicole Jennings
		~~Alan Rhoades~~ Nicole Jennings Vice President and Chief Accounting Officer

6939



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


	Successor			Predecessor				Successor
	September 30, 2020			December 31, 2019				June 30, 2021		December 31, 2020
Assets							Assets
Current assets							Current assets
Cash and cash equivalents	$	21,860		$	516		Cash and cash equivalents	$	13,565	$	518
Restricted cash	10,662			0			Restricted cash	0		1,000
Accrued production receivable	74,296			139,407			Accrued production receivable	140,302		91,421
Trade and other receivables, net	34,788			18,318			Trade and other receivables, net	24,740		19,682
Derivative assets	26,778			11,936			Derivative assets	0		187
Other current assets	11,730			10,434
Prepaids							Prepaids	12,454		14,038
Total current assets	180,114			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	796,687			11,447,680			Proved properties	949,128		851,208
Unevaluated properties	98,656			872,910			Unevaluated properties	103,088		85,304
CO₂ properties	187,397			1,198,846			CO2 properties	188,700		188,288
Pipelines	132,669			2,329,078			Pipelines	143,633		133,485
Other property and equipment	97,770			212,334			Other property and equipment	97,699		86,610
Less accumulated depletion, depreciation, amortization and impairment	(4,446		)	(11,688,020		)	Less accumulated depletion, depreciation, amortization and impairment	(120,073)		(41,095)
Net property and equipment	1,308,733			4,372,828			Net property and equipment	1,362,175		1,303,800
Operating lease right-of-use assets	1,225			34,099			Operating lease right-of-use assets	19,000		20,342
Derivative assets	1,147			0

Intangible assets, net	99,655			22,139			Intangible assets, net	92,814		97,362
Other assets	86,996			82,190			Other assets	85,044		86,408
Total assets	$	1,677,870		$	4,691,867		Total assets	$	1,750,094	$	1,634,758
Liabilities and Stockholders’ Equity							Liabilities and Stockholders’ Equity
Current liabilities							Current liabilities
Accounts payable and accrued liabilities							Accounts payable and accrued liabilities	$	163,905	$	112,671
Oil and gas production payable							Oil and gas production payable	69,390		49,165
Derivative liabilities							Derivative liabilities	223,212		53,865
Current maturities of long-term debt							Current maturities of long-term debt	34,498		68,008
Operating lease liabilities							Operating lease liabilities	2,596		1,350
Total current liabilities							Total current liabilities	493,601		285,059
Long-term liabilities							Long-term liabilities
Long-term debt, net of current portion							Long-term debt, net of current portion	35,000		70,000
Asset retirement obligations							Asset retirement obligations	226,615		179,338
Derivative liabilities							Derivative liabilities	22,164		5,087
Deferred tax liabilities, net							Deferred tax liabilities, net	1,187		1,274
Operating lease liabilities							Operating lease liabilities	18,157		19,460
Other liabilities							Other liabilities	26,172		20,872
Total long-term liabilities							Total long-term liabilities	329,295		296,031
Commitments and contingencies (Note 8)							Commitments and contingencies (Note 8)	0		0
Stockholders’ equity							Stockholders’ equity
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							Paid-in capital in excess of par	1,125,143		1,104,276
Accumulated deficit							Accumulated deficit	(197,995)		(50,658)
Total stockholders’ equity							Total stockholders’ equity	927,198		1,053,668
Total liabilities and stockholders’ equity							Total liabilities and stockholders’ equity	$	1,750,094	$	1,634,758


	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



	Successor	Predecessor
	Period from Sept. 19, 2020 through	Period from Jan. 1, 2020 through	Nine Months Ended
In thousands	Sept. 30, 2020	Sept. 18, 2020	Sept. 30, 2019
Stock appreciation rights	0	1,007	2,043
Restricted stock and performance-based equity awards	0	7,280	5,859
Convertible senior notes	0	87,888	0
Warrants⁽¹⁾	5,526	0	0



In thousands	Sept. 18, 2020
Enterprise value	$	1,280,856
Plus: Cash and cash equivalents	45,585
Less: Total debt	(231,022		)
Equity value	$	1,095,419


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


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


~~(1)~~	Shares shown under “warrants” represent the impact over the Successor periods of the approximately 5.5 million shares of the Successor’s common stock issuable upon full exercise of the series A and series B warrants which were issued pursuant to the Plan to the Predecessor’s convertible senior notes, senior subordinated notes, and equity holders.



	Predecessor
	Period from July 1, 2020 through
In thousands	Sept. 18, 2020
Gain on settlement of liabilities subject to compromise	$	(1,024,864	)
Fresh start accounting adjustments	1,834,423
Professional service provider fees and other expenses	11,267
Success fees for professional service providers	9,700
Loss on rejected contracts and leases	10,989
Valuation adjustments to debt classified as subject to compromise	757
DIP credit agreement fees	3,107
Acceleration of Predecessor stock compensation expense	4,601
Total reorganization items, net	$	849,980


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



	As of September 18, 2020
In thousands	Predecessor			Reorganization Adjustments				Fresh Start Adjustments				Successor
Assets
Current assets
Cash and cash equivalents	$	73,372		$	(27,787	)	⁽¹⁾	$	—			$	45,585
Restricted cash	—			10,662			⁽²⁾	—				10,662
Accrued production receivable	112,832			—				—				112,832
Trade and other receivables, net	36,221			—				0				36,221
Derivative assets	32,635			—				—				32,635
Other current assets	12,968			(539		)	⁽³⁾	—				12,429
Total current assets	268,028			(17,664		)		0				250,364
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved properties	11,723,546			—				(10,941,313		)		782,233
Unevaluated properties	650,553			—				(538,570		)		111,983
CO₂ properties	1,198,515			—				(1,011,169		)		187,346
Pipelines	2,339,864			—				(2,207,246		)		132,618
Other property and equipment	201,565			—				(104,152		)		97,413
Less accumulated depletion, depreciation, amortization and impairment	(12,864,141		)	—				12,864,141				0
Net property and equipment	3,249,902			—				(1,938,309		)	⁽¹⁰⁾	1,311,593
Operating lease right-of-use assets	1,774			0				69			⁽¹⁰⁾	1,843
Derivative assets	501			—				—				501
Intangible assets, net	20,405			—				79,678			⁽¹¹⁾	100,083
Other assets	81,809			8,241			⁽⁴⁾	(3,027		)	⁽¹²⁾	87,023
Total assets	$	3,622,419		$	(9,423	)		$	(1,861,589	)		$	1,751,407


~~(1)~~	~~Represents the net cash payments that occurred on the Emergence Date as follows:~~



In thousands
Sources:
Cash proceeds from Successor Bank Credit Agreement	$	140,000
	140,000

Uses:
Payment in full of DIP Facility and pre-petition revolving bank credit facility	(140,000		)
Retained professional service provider fees paid to escrow account	(10,662		)
Non-retained professional service provider fees paid	(7,420		)
Accrued interest and fees on DIP Facility	(1,464		)
Debt issuance costs related to Successor Bank Credit Agreement	(8,241		)
	(167,787		)

Net uses	$	(27,787	)


~~(2)~~	~~Represents the transfer of funds to a restricted cash account utilized for the payment of fees to retained professional service providers assisting in the bankruptcy process.~~


~~(3)~~	Represents the write-off of costs related to the DIP Facility and a run-off policy for directors and officers’ insurance coverage, partially offset by the recording of prepaid amounts for non-retained professional service provider fees.


~~(4)~~	~~Represents debt issuance costs related to the Successor Bank Credit Agreement.~~


~~(5)~~	~~Adjustments to accounts payable and accrued liabilities as follows:~~



In thousands
Accrual of professional service provider fees	$	2,826
Payment of accrued interest and fees on DIP Facility	(1,464		)
Reinstatement of accounts payable and accrued liabilities from liabilities subject to compromise	101,431
Accounts payable and accrued liabilities	$	102,793


~~(6)~~	~~Liabilities subject to compromise were settled as follows in accordance with the Plan:~~



In thousands
Liabilities subject to compromise prior to the Emergence Date:
Settled liabilities subject to compromise
Senior secured second lien notes	$	1,629,417
Convertible senior notes	234,055
Senior subordinated notes	251,480
Total settled liabilities subject to compromise	2,114,952
Reinstated liabilities subject to compromise
Current maturities of long-term debt	73,199
Accounts payable and accrued liabilities	101,431
Oil and gas production payable	16,705
Operating lease liabilities, current	757
Long-term debt, net of current portion	42,610
Asset retirement obligations	180,408
Deferred tax liabilities	289,389
Operating lease liabilities, long-term	515
Other long-term liabilities	3,540
Total reinstated liabilities subject to compromise	708,554
Total liabilities subject to compromise	2,823,506

Issuance of New Common Stock to second lien note holders	(1,014,608		)
Issuance of New Common Stock to convertible note holders	(53,400		)
Issuance of series A warrants to convertible note holders	(15,683		)
Issuance of series B warrants to senior subordinated note holders	(6,398		)
Reinstatement of liabilities subject to compromise	(708,553		)
Gain on settlement of liabilities subject to compromise	$	1,024,864


~~(7)~~	Represents the cancellation of the Predecessor’s common stock, treasury stock, and related components of the Predecessor’s paid-in capital in excess of par. Paid-in capital in excess of par includes $4.6 million as a result of terminated Predecessor stock compensation plans.


~~(8)~~	~~Represents the Successor’s common stock and additional paid-in capital as follows:~~



In thousands
Capital in excess of par value of 47,499,999 issued and outstanding shares of New Common Stock issued to holders of the senior secured second lien note claims	$	1,014,608
Capital in excess of par value of 2,500,000 issued and outstanding shares of New Common Stock issued to holders of the convertible senior note claims	53,400
Fair value of series A warrants issued to convertible senior note holders	15,683
Fair value of series B warrants issued to senior subordinated note holders	6,398
Fair value of series B warrants issued to Predecessor equity holders	5,330
Total change in Successor common stock and additional paid-in-capital	1,095,419
Less: Par value of Successor common stock	(50		)
Change in Successor additional paid-in-capital	$	1,095,369


~~(9)~~	~~Reflects the cumulative net impact of the effects on accumulated deficit as follows:~~



In thousands
Cancellation of Predecessor common stock, paid-in capital in excess of par, and treasury stock	$	2,763,824
Gain on settlement of liabilities subject to compromise	1,024,864
Acceleration of Predecessor stock compensation expense	(4,601		)
Recognition of tax expenses related to reorganization adjustments	(128,556		)
Professional service provider fees recognized at emergence	(9,700		)
Issuance of series B warrants to Predecessor equity holders	(5,330		)
Other	(1,092		)
Net impact to Predecessor accumulated deficit	$	3,639,409


~~(10)~~	~~Reflects fair value adjustments to our (i) oil and natural gas properties, CO~~₂ properties, pipelines, and other property and equipment, as well as the elimination of accumulated depletion, depreciation, and amortization, (ii) operating lease right-of-use assets and liabilities, and (iii) asset retirement obligations.


~~(11)~~	~~Reflects fair value adjustments to our long-term CO~~₂ ~~customer contracts.~~


~~(12)~~	~~Reflects fair value adjustments to our other assets as follows:~~



In thousands
Fair value adjustment for CO₂ and oil pipeline line-fill	$	(3,698	)
Fair value adjustments for escrow accounts	671
Fair value adjustments to other assets	$	(3,027	)


~~(13)~~	~~Reflects fair value adjustments to accounts payable and accrued liabilities as follows:~~



In thousands	��
Fair value adjustment for the current portion of an unfavorable vendor contract		$	3,500
Fair value adjustment for the current portion of Predecessor asset retirement obligation		689
Write-off accrued interest on NEJD pipeline financing		(451		)
Fair value adjustments to accounts payable and accrued liabilities		$	3,738


~~(14)~~	~~Represents adjustments to current and long-term maturities of debt associated with pipeline lease financings. The cumulative effect is as follows:~~



In thousands
Fair value adjustment for Free State pipeline lease financing	$	(24,699	)
Fair value adjustment for NEJD pipeline lease financing	(88		)
Fair value adjustments to current and long-term maturities of debt	$	(24,787	)


~~(16)~~	~~Represents a fair value adjustment for the long-term portion of an unfavorable vendor contract.~~


~~(17)~~	~~Represents the cumulative effect of the fresh start accounting adjustments discussed above.~~