UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, ~~2021~~2022

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

For the transition period from _______ to ________

Commission file number: 001-12935

DENBURY INC.

(Exact name of registrant as specified in its charter)

Delaware

20-0467835

(State or other jurisdiction of incorporation or organization)

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

5851 Legacy Circle,

Plano,

75024

(Address of principal executive offices)

(Zip Code)


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

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


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

Not applicable

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

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

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

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

Large accelerated filer

☐☑

Accelerated filer

☑☐

Non-accelerated filer

☐

Smaller reporting company

☑☐

Emerging growth company

☐

(Do not check if a smaller reporting company)

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

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

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

The number of shares outstanding of the registrant’s Common Stock, $.001 par value, as of July 31, ~~2021,~~2022, was ~~50,109,950.~~49,722,204.

Denbury Inc.

Table of Contents

Page

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements

Unaudited Condensed Consolidated Balance Sheets

Unaudited Condensed Consolidated Statements of Operations

Unaudited Condensed Consolidated Statements of Cash Flows

Unaudited Condensed Consolidated Statements of Changes in Stockholders’ Equity

Notes to Unaudited Condensed Consolidated Financial Statements

Item 2.

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

Item 3.

Quantitative and Qualitative Disclosures about Market Risk

Item 4.

Controls and Procedures

3534

PART II. OTHER INFORMATION

Unregistered Sales of Equity Securities and Use of Proceeds

3736

Item 3.

Defaults Upon Senior Securities

3736

Item 4.

Mine Safety Disclosures

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Denbury Inc.

Unaudited Condensed Consolidated Balance Sheets

(In thousands, except par value and share data)


		Successor
		June 30, 2021		December 31, 2020			June 30, 2022		December 31, 2021
Assets	Assets					Assets
Current assets	Current assets					Current assets
Cash and cash equivalents	Cash and cash equivalents	$	13,565	$	518	Cash and cash equivalents	$	517	$	3,671
Restricted cash		0		1,000
Accrued production receivable	Accrued production receivable	140,302		91,421		Accrued production receivable	229,151		143,365
Trade and other receivables, net	Trade and other receivables, net	24,740		19,682		Trade and other receivables, net	30,918		19,270
Derivative assets	Derivative assets	0		187		Derivative assets	2,829		—
Prepaids	Prepaids	12,454		14,038		Prepaids	18,686		9,099
Total current assets	Total current assets	191,061		126,846		Total current assets	282,101		175,405
Property and equipment	Property and equipment					Property and equipment
Oil and natural gas properties (using full cost accounting)	Oil and natural gas properties (using full cost accounting)					Oil and natural gas properties (using full cost accounting)
Proved properties	Proved properties	949,128		851,208		Proved properties	1,217,778		1,109,011
Unevaluated properties	Unevaluated properties	103,088		85,304		Unevaluated properties	155,901		112,169
CO2 properties	CO2 properties	188,700		188,288		CO2 properties	184,861		183,369
Pipelines	Pipelines	143,633		133,485		Pipelines	226,318		224,394
CCUS storage sites and related assets						CCUS storage sites and related assets	24,026		—
Other property and equipment	Other property and equipment	97,699		86,610		Other property and equipment	98,777		93,950
Less accumulated depletion, depreciation, amortization and impairment	Less accumulated depletion, depreciation, amortization and impairment	(120,073)		(41,095)		Less accumulated depletion, depreciation, amortization and impairment	(240,133)		(181,393)
Net property and equipment	Net property and equipment	1,362,175		1,303,800		Net property and equipment	1,667,528		1,541,500
Operating lease right-of-use assets	Operating lease right-of-use assets	19,000		20,342		Operating lease right-of-use assets	18,118		19,502
Derivative assets						Derivative assets	2,071		—

Intangible assets, net	Intangible assets, net	92,814		97,362		Intangible assets, net	83,688		88,248
Restricted cash for future asset retirement obligations						Restricted cash for future asset retirement obligations	46,869		46,673
Other assets	Other assets	85,044		86,408		Other assets	38,305		31,625
Total assets	Total assets	$	1,750,094	$	1,634,758	Total assets	$	2,138,680	$	1,902,953
Liabilities and Stockholders’ Equity	Liabilities and Stockholders’ Equity					Liabilities and Stockholders’ Equity
Current liabilities	Current liabilities					Current liabilities
Accounts payable and accrued liabilities	Accounts payable and accrued liabilities	$	163,905	$	112,671	Accounts payable and accrued liabilities	$	262,752	$	191,598
Oil and gas production payable	Oil and gas production payable	69,390		49,165		Oil and gas production payable	109,228		75,899
Derivative liabilities	Derivative liabilities	223,212		53,865		Derivative liabilities	162,551		134,509
Current maturities of long-term debt		34,498		68,008

Operating lease liabilities	Operating lease liabilities	2,596		1,350		Operating lease liabilities	4,670		4,677
Total current liabilities	Total current liabilities	493,601		285,059		Total current liabilities	539,201		406,683
Long-term liabilities	Long-term liabilities					Long-term liabilities
Long-term debt, net of current portion	Long-term debt, net of current portion	35,000		70,000		Long-term debt, net of current portion	—		35,000
Asset retirement obligations	Asset retirement obligations	226,615		179,338		Asset retirement obligations	273,852		284,238
Derivative liabilities	Derivative liabilities	22,164		5,087		Derivative liabilities	5,415		—
Deferred tax liabilities, net	Deferred tax liabilities, net	1,187		1,274		Deferred tax liabilities, net	17,630		1,638
Operating lease liabilities	Operating lease liabilities	18,157		19,460		Operating lease liabilities	15,571		17,094
Other liabilities	Other liabilities	26,172		20,872		Other liabilities	18,170		22,910
Total long-term liabilities	Total long-term liabilities	329,295		296,031		Total long-term liabilities	330,638		360,880
Commitments and contingencies (Note 8)		0		0
Commitments and contingencies (Note 9)						Commitments and contingencies (Note 9)	0		0
Stockholders’ equity	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		Preferred stock, $.001 par value, 50,000,000 shares authorized, none issued and outstanding	—		—
Common stock, $.001 par value, 250,000,000 shares authorized; 50,017,491 and 49,999,999 shares issued, respectively		50		50
Common stock, $.001 par value, 250,000,000 shares authorized; 50,875,988 and 50,193,656 shares issued, respectively						Common stock, $.001 par value, 250,000,000 shares authorized; 50,875,988 and 50,193,656 shares issued, respectively	51		50
Paid-in capital in excess of par	Paid-in capital in excess of par	1,125,143		1,104,276		Paid-in capital in excess of par	1,137,575		1,129,996
Accumulated deficit		(197,995)		(50,658)
Retained earnings						Retained earnings	159,966		5,344
Treasury stock, at cost, 457,549 and 0 shares, respectively						Treasury stock, at cost, 457,549 and 0 shares, respectively	(28,751)		—
Total stockholders’ equity	Total stockholders’ equity	927,198		1,053,668		Total stockholders’ equity	1,268,841		1,135,390
Total liabilities and stockholders’ equity	Total liabilities and stockholders’ equity	$	1,750,094	$	1,634,758	Total liabilities and stockholders’ equity	$	2,138,680	$	1,902,953

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		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			Three Months Ended June 30,				Six Months Ended June 30,
											2022		2021		2022		2021
Revenues and other income	Revenues and other income									Revenues and other income
Oil, natural gas, and related product sales	Oil, natural gas, and related product sales	$	282,708	$	109,387	$	518,153	$	339,011	Oil, natural gas, and related product sales	$	451,970	$	282,708	$	836,881	$	518,153
CO2 sales and transportation fees	CO2 sales and transportation fees	10,134		6,504		19,362		14,532		CO2 sales and transportation fees	12,610		10,134		26,032		19,362
Oil marketing revenues	Oil marketing revenues	7,819		1,490		13,945		5,211		Oil marketing revenues	16,786		7,819		30,062		13,945
Other income	Other income	707		494		1,067		1,322		Other income	790		707		1,040		1,067
Total revenues and other income	Total revenues and other income	301,368		117,875		552,527		360,076		Total revenues and other income	482,156		301,368		894,015		552,527
Expenses	Expenses									Expenses
Lease operating expenses	Lease operating expenses	110,225		81,293		192,195		190,563		Lease operating expenses	124,351		110,225		242,179		192,195
Transportation and marketing expenses	Transportation and marketing expenses	8,522		9,388		16,319		19,009		Transportation and marketing expenses	4,802		8,522		9,447		16,319
CO2 operating and discovery expenses	CO2 operating and discovery expenses	1,531		885		2,524		1,637		CO2 operating and discovery expenses	1,681		1,531		4,498		2,524
Taxes other than income	Taxes other than income	22,382		10,372		41,345		30,058		Taxes other than income	36,317		22,382		67,698		41,345
Oil marketing expenses		7,738		1,450		13,823		5,111
Oil marketing purchases										Oil marketing purchases	15,027		7,738		28,067		13,823
General and administrative expenses	General and administrative expenses	15,450		23,776		47,433		33,509		General and administrative expenses	19,235		15,450		37,927		47,433
Interest, net of amounts capitalized of $1,168, $8,729, $2,251 and $18,181, respectively		1,252		20,617		2,788		40,563
Interest, net of amounts capitalized of $975, $1,168, $2,133 and $2,251, respectively										Interest, net of amounts capitalized of $975, $1,168, $2,133 and $2,251, respectively	1,526		1,252		2,183		2,788
Depletion, depreciation, and amortization	Depletion, depreciation, and amortization	36,381		55,414		75,831		152,276		Depletion, depreciation, and amortization	35,400		36,381		70,745		75,831
Commodity derivatives expense (income)		172,664		40,130		288,407		(106,641)
Gain on debt extinguishment		0		0		0		(18,994)
Commodity derivatives expense										Commodity derivatives expense	56,854		172,664		249,573		288,407

Write-down of oil and natural gas properties	Write-down of oil and natural gas properties	0		662,440		14,377		734,981		Write-down of oil and natural gas properties	—		—		—		14,377

Other expenses	Other expenses	3,214		11,290		5,360		13,784		Other expenses	6,621		3,214		8,733		5,360
Total expenses	Total expenses	379,359		917,055		700,402		1,095,856		Total expenses	301,814		379,359		721,050		700,402
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)
Income (loss) before income taxes										Income (loss) before income taxes	180,342		(77,991)		172,965		(147,875)
Income tax provision (benefit)										Income tax provision (benefit)	24,848		(296)		18,343		(538)
Net income (loss)										Net income (loss)	$	155,494	$	(77,695)	$	154,622	$	(147,337)

Net loss per common share
Net income (loss) per common share										Net income (loss) per common share
Basic	Basic	$	(1.52)	$	(1.41)	$	(2.91)	$	(1.26)	Basic	$	3.00	$	(1.52)	$	2.99	$	(2.91)
Diluted	Diluted	$	(1.52)	$	(1.41)	$	(2.91)	$	(1.26)	Diluted	$	2.83	$	(1.52)	$	2.81	$	(2.91)

Weighted average common shares outstanding	Weighted average common shares outstanding									Weighted average common shares outstanding
Basic	Basic	50,999		495,245		50,661		494,752		Basic	51,757		50,999		51,680		50,661
Diluted	Diluted	50,999		495,245		50,661		494,752		Diluted	54,886		50,999		54,931		50,661

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			Six Months Ended June 30,
							2022		2021
Cash flows from operating activities	Cash flows from operating activities					Cash flows from operating activities
Net loss		$	(147,337)	$	(623,458)
Adjustments to reconcile net loss to cash flows from operating activities

Net income (loss)						Net income (loss)	$	154,622	$	(147,337)
Adjustments to reconcile net income (loss) to cash flows from operating activities						Adjustments to reconcile net income (loss) to cash flows from operating activities
Depletion, depreciation, and amortization	Depletion, depreciation, and amortization	75,831		152,276		Depletion, depreciation, and amortization	70,745		75,831
Write-down of oil and natural gas properties	Write-down of oil and natural gas properties	14,377		734,981		Write-down of oil and natural gas properties	—		14,377
Deferred income taxes	Deferred income taxes	(87)		(106,513)		Deferred income taxes	15,992		(87)
Stock-based compensation	Stock-based compensation	20,232		3,540		Stock-based compensation	7,075		20,232
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
Commodity derivatives expense						Commodity derivatives expense	249,573		288,407
Payment on settlements of commodity derivatives						Payment on settlements of commodity derivatives	(221,016)		(101,796)
Debt issuance costs						Debt issuance costs	1,934		1,370
Other, net	Other, net	744		(1,642)		Other, net	(3,155)		744
Changes in assets and liabilities, net of effects from acquisitions	Changes in assets and liabilities, net of effects from acquisitions					Changes in assets and liabilities, net of effects from acquisitions
Accrued production receivable	Accrued production receivable	(48,881)		62,063		Accrued production receivable	(85,786)		(48,881)
Trade and other receivables	Trade and other receivables	(5,578)		(16,162)		Trade and other receivables	(11,783)		(5,578)
Other current and long-term assets	Other current and long-term assets	1,294		(4,552)		Other current and long-term assets	(12,175)		1,294
Accounts payable and accrued liabilities	Accounts payable and accrued liabilities	27,292		(60,295)		Accounts payable and accrued liabilities	52,010		27,292
Oil and natural gas production payable	Oil and natural gas production payable	20,224		(22,217)		Oil and natural gas production payable	33,329		20,224
Other liabilities		(2,554)		237
Asset retirement obligations and other liabilities						Asset retirement obligations and other liabilities	(11,257)		(2,554)
Net cash provided by operating activities	Net cash provided by operating activities	143,538		72,811		Net cash provided by operating activities	240,108		143,538

Cash flows from investing activities	Cash flows from investing activities					Cash flows from investing activities
Oil and natural gas capital expenditures	Oil and natural gas capital expenditures	(53,411)		(79,897)		Oil and natural gas capital expenditures	(139,522)		(53,411)
CCUS storage sites and related capital expenditures						CCUS storage sites and related capital expenditures	(17,758)		—
Acquisitions of oil and natural gas properties	Acquisitions of oil and natural gas properties	(10,811)		0		Acquisitions of oil and natural gas properties	(374)		(10,811)
Pipelines and plants capital expenditures	Pipelines and plants capital expenditures	(4,851)		(10,962)		Pipelines and plants capital expenditures	(20,264)		(4,851)
Net proceeds from sales of oil and natural gas properties and equipment	Net proceeds from sales of oil and natural gas properties and equipment	18,456		40,971		Net proceeds from sales of oil and natural gas properties and equipment	237		18,456
Other	Other	(4,159)		(105)		Other	(5,623)		(4,159)
Net cash used in investing activities	Net cash used in investing activities	(54,776)		(49,993)		Net cash used in investing activities	(183,304)		(54,776)

Cash flows from financing activities	Cash flows from financing activities					Cash flows from financing activities
Bank repayments	Bank repayments	(485,000)		(226,000)		Bank repayments	(524,000)		(485,000)
Bank borrowings	Bank borrowings	450,000		491,000		Bank borrowings	489,000		450,000
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)
Pipeline financing repayments						Pipeline financing repayments	—		(33,510)
Common stock repurchase program						Common stock repurchase program	(23,374)		—
Other	Other	(2,735)		(9,529)		Other	(1,388)		(2,735)
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
Net cash used in financing activities						Net cash used in financing activities	(59,762)		(71,245)
Net increase (decrease) in cash, cash equivalents, and restricted cash						Net increase (decrease) in cash, cash equivalents, and restricted cash	(2,958)		17,517
Cash, cash equivalents, and restricted cash at beginning of period	Cash, cash equivalents, and restricted cash at beginning of period	42,248		33,045		Cash, cash equivalents, and restricted cash at beginning of period	50,344		42,248
Cash, cash equivalents, and restricted cash at end of period	Cash, cash equivalents, and restricted cash at end of period	$	59,765	$	247,642	Cash, cash equivalents, and restricted cash at end of period	$	47,386	$	59,765

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 ($.001 Par Value)			Paid-In Capital in Excess of Par		Retained Earnings (Accumulated Deficit)		Treasury Stock (at cost)						Common Stock ($.001 Par Value)			Paid-In Capital in Excess of Par		Retained Earnings		Treasury Stock (at cost)
		Shares	Amount						Shares	Amount		Total Equity			Shares	Amount						Shares	Amount		Total Equity
Balance – December 31, 2020 (Successor)		49,999,999	$	50	$	1,104,276	$	(50,658)	—	$	—	$	1,053,668
Balance – December 31, 2021														Balance – December 31, 2021	50,193,656	$	50	$	1,129,996	$	5,344	—	$	—	$	1,135,390
Issued pursuant to stock compensation plans														Issued pursuant to stock compensation plans	141,581	0		—		—		—	—		0
Stock-based compensation	Stock-based compensation	—	—		19,172		—		—	—		19,172		Stock-based compensation	—	—		3,142		—		—	—		3,142
Tax withholding for stock compensation plans	Tax withholding for stock compensation plans	—	—		(1,467)		—		—	—		(1,467)		Tax withholding for stock compensation plans	—	—		(58)		—		—	—		(58)
Issued pursuant to exercise of warrants	Issued pursuant to exercise of warrants	5,620	0		195		—		—	—		195		Issued pursuant to exercise of warrants	14,153	0		47		—		—	—		47
Net loss	Net loss	—	—		—		(69,642)		—	—		(69,642)		Net loss	—	—		—		(872)		—	—		(872)
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
Balance – March 31, 2022														Balance – March 31, 2022	50,349,390	50		1,133,127		4,472		—	—		1,137,649

Stock repurchase program														Stock repurchase program	(457,549)	—		—		—		457,549	(28,751)		(28,751)
Forfeited pursuant to stock compensation plans														Forfeited pursuant to stock compensation plans	(3,264)	—		—		—		—	—		—
Stock-based compensation														Stock-based compensation	—	—		4,400		—		—	—		4,400
Tax withholding for stock compensation plans														Tax withholding for stock compensation plans	—	—		(5)		—		—	—		(5)
Issued pursuant to exercise of warrants														Issued pursuant to exercise of warrants	987,411	1		53		—		—	—		54
Net income														Net income	—	—		—		155,494		—	—		155,494
Balance – June 30, 2022														Balance – June 30, 2022	50,875,988	$	51	$	1,137,575	$	159,966	457,549	$	(28,751)	$	1,268,841

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, 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 directors’ compensation plan 37,367 — — — — — —
Stock-based compensation — — 3,204 — — — 3,204
Tax withholding for stock compensation plans — — — — 175,673 (34) (34)
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
Canceled pursuant to stock compensation plans (6,218,868) (6) 6 — — — —
Issued pursuant to notes conversion 7,357,450 8 11,453 — — — 11,461
Stock-based compensation — — 987 — — — 987
Net loss — — — (697,474) — — (697,474)
Balance – June 30, 2020 (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) — — — — — —
Issued pursuant to notes conversion 14,800 — 40 — — — 40
Stock-based compensation — — 10,126 — — — 10,126
Tax withholding for stock compensation plans — — — — 567,189 (134) (134)
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)
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 19, 2020 (Successor) 49,999,999 $ 50 $ 1,095,369 $ — — $ — $ 1,095,419
Net income — — — 2,758 — — 2,758
Balance – September 30, 2020 (Successor) 49,999,999 50 1,095,369 2,758 — — 1,098,177
Stock-based compensation — — 8,907 — — — 8,907
Net loss — — — (53,416) — — (53,416)
Balance – December 31, 2020 (Successor) 49,999,999 $ 50 $ 1,104,276 $ (50,658) — $ — $ 1,053,668


	Common Stock ($.001 Par Value)			Paid-In Capital in Excess of Par		Retained Earnings (Accumulated Deficit)		Treasury Stock (at cost)
	Shares	Amount						Shares	Amount		Total Equity
Balance – December 31, 2020	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	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	50,017,491	$	50	$	1,125,143	$	(197,995)	—	$	—	$	927,198

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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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 energy company with operations focused in the Gulf Coast and Rocky Mountain ~~regions.~~regions of the United States. The Company is 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 CO~~2 ~~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 CO~~2 ~~emissions within this decade, primarily through increasing the amount of captured industrial-sourced CO~~2 ~~used in its operations.~~

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

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

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

Interim Financial Statements

The accompanying unaudited condensed consolidated financial statements of Denbury Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, ~~2020~~2021 (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 presentation of our consolidated financial position as of June 30, ~~2021 (Successor);~~2022, our consolidated results of operations for the three and six months ended June 30, ~~2021 (Successor)~~2022 and ~~June 30, 2020 (Predecessor);~~2021, our consolidated cash flows for the six months ended June 30, ~~2021 (Successor)~~2022 and ~~June 30, 2020 (Predecessor);~~2021, and our consolidated statements of changes in stockholders’ equity for the three and six months ended June 30, ~~2021 (Successor), for the period January 1, 2020 through September 18, 2020 (Predecessor),~~2022 and for the period September 19, 2020 through December 31, 2020 (Successor). 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. 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, 2020.2021.

Reclassifications

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

Cash, Cash Equivalents, and Restricted Cash

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	In thousands	June 30, 2021		December 31, 2020		In thousands	June 30, 2022		December 31, 2021
Cash and cash equivalents	Cash and cash equivalents	$	13,565	$	518	Cash and cash equivalents	$	517	$	3,671
Restricted cash, current		0		1,000
Restricted cash included in other assets		46,200		40,730

Restricted cash for future asset retirement obligations						Restricted cash for future asset retirement obligations	46,869		46,673
Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows	Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows	$	59,765	$	42,248	Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows	$	47,386	$	50,344

Restricted cash ~~included in other assets~~for future asset retirement obligations in the table above consists of escrow accounts that are legally restricted for certain of our asset retirement ~~obligations, and are included in “Other assets” in the accompanying Unaudited Condensed Consolidated Balance Sheets.~~obligations.

Net Income (Loss) per Common Share

Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. ~~Diluted net income per~~Basic weighted average common ~~share is calculated in the same manner but includes the impact of potentially dilutive securities. Potentially dilutive securities during the Successor periods consist~~shares exclude shares of nonvested restricted stock ~~units and outstanding series A and series B warrants, and during the Predecessor periods consisted of~~(although nonvested restricted stock ~~nonvested performance-based equity awards,~~is issued and ~~convertible senior notes~~outstanding upon grant). ~~For~~ As these restricted shares vest, they will be included in the ~~three and six months ended June 30, 2021 and 2020, there were no adjustments~~shares outstanding used to calculate basic net ~~loss for purposes of calculating basic and diluted net loss~~income (loss) per common share.

Restricted stock units and performance stock units are also excluded from basic weighted

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

~~The following is a reconciliation of the weighted~~ average ~~shares used in the basic and diluted net loss per~~ common ~~share calculations for the periods indicated:~~

Successor Predecessor Successor Predecessor
In thousands Three Months Ended
June 30, 2021 Three Months Ended
June 30, 2020 Six Months Ended
June 30, 2021 Six Months Ended
June 30, 2020
Weighted average common shares outstanding – basic 50,999 495,245 50,661 494,752
Effect of potentially dilutive securities
Restricted stock units 0 0 0 0
Warrants 0 0 0 0
Restricted stock and performance-based equity awards 0 0 0 0
Convertible senior notes(1)
0 0 0 0
Weighted average common shares outstanding – diluted(2)
50,999 495,245 50,661 494,752

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

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

vesting date. Basic weighted average common shares ~~during the Successor periods includes 987,987 and 563,416 performance stock units~~ during the three and six months ended June 30, ~~2021, respectively, with vesting parameters tied to the Company’s common~~2022 includes 1,404,649 performance-based and restricted stock ~~trading prices and~~units which ~~became~~are fully vested ~~on March 3, 2021. Although the performance measures for vesting~~as of ~~these awards have been achieved,~~June 30, 2022; however, the shares underlying these ~~awards~~stock units are not included in shares currently issued or outstanding as actual delivery of the shares is not scheduled to occur until ~~after~~December 4, 2023.

Diluted net income (loss) per common share is calculated in the ~~end~~same manner but includes the impact of all potentially dilutive securities. Potentially dilutive securities include restricted stock, restricted stock units, performance stock units, and series A and series B warrants.

For each of the ~~performance period, December 4, 2023. Basic~~three and six months ended June 30, 2022 and 2021, there were no adjustments to net income (loss) for purposes of calculating basic and diluted net income (loss) per common share.

The following table reconciles the weighted average shares used in the basic and diluted net income (loss) per common share calculations for the periods indicated:


	Three Months Ended		Six Months Ended
	June 30,		June 30,
In thousands	2022	2021	2022	2021







Weighted average common shares outstanding – basic	51,757	50,999	51,680	50,661
Effect of potentially dilutive securities
Restricted stock, restricted stock units and performance stock units	603	—	591	—

Warrants	2,526	—	2,660	—
Weighted average common shares outstanding – diluted	54,886	50,999	54,931	50,661

For the three and six months ended June 30, 2021, the weighted average common shares outstanding used to calculate basic earnings per share and diluted earnings per share were the same, since the Company recorded net losses each period. Assuming the Company had recorded net income during the ~~Predecessor periods included time-vesting~~three and six months ended June 30, 2021, the weighted average diluted shares outstanding would have been 54.3 million (including the impact of 0.8 million restricted stock ~~that vested during~~units and 2.4 million shares with respect to warrants) and 52.7 million (including the ~~periods.~~impact of 0.6 million restricted stock units and 1.4 million shares with respect to warrants), respectively.

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

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


	June 30,
In thousands	2022	2021
Restricted stock, restricted stock units and performance stock units	124	1,255

Warrants	—	5,503

~~For the Successor period, the Company’s restricted stock units and series A and series B warrants were antidilutive based on the Company’s net loss position for the period.~~ At June 30, ~~2021,~~2022, the Company had approximately ~~5.5~~3.4 million warrants outstanding that can be exercised for shares of ~~the Successor’s~~our common stock, at an exercise price of $32.59 per share for the ~~2.6~~1.8 million series A warrants outstanding and at an exercise price of $35.41 per share for the ~~2.9~~1.6 million series B ~~warrants.~~warrants outstanding. The warrants may be exercised for cash or on a cashless basis. The series A warrants are exercisable until September 18, 2025, and the series B warrants are exercisable until September 18, 2023, at which ~~time~~times the warrants expire.~~The~~ During the three and six months ended June 30, 2022, 1,796,237 and 1,822,013 warrants were issued pursuant to the Plan to holders of the Predecessor’s convertible senior notes, senior subordinated notes, and equity. As of June 30, 2021, 2,315 series A warrants and 20,927 series B warrants had been exercised. The warrants may be exercised for ~~cash or~~a total of 987,411 shares and 1,001,564 shares, respectively, most of which were exercised on a cashless basis. ~~If warrants are exercised on a cashless basis, the amount of dilution will be less than 5.5 million shares.~~

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~~Denbury Inc.~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

Oil and Natural Gas Properties

~~Unevaluated Costs.~~ Under full cost accounting, we exclude certain unevaluated costs from the amortization base and full cost ceiling test pending the determination of whether proved reserves can be assigned to such properties. These costs are transferred to the full cost amortization base as these properties are developed, tested and evaluated. At least annually, we test these assets for impairment based on an evaluation of management’s expectations of future pricing, evaluation of lease expiration terms, and planned development activities. In the first quarter of 2020 Predecessor period, given the significant declines in NYMEX oil prices in March and April 2020, we reassessed our development plans and transferred $244.9 million of our unevaluated costs to the full cost amortization base. Upon emergence from bankruptcy, the Company adopted fresh start accounting which resulted in our oil and natural gas properties, including unevaluated properties, being recorded at their fair values at the Emergence Date.

Write-Down of Oil and Natural Gas Properties. Under full cost accounting, the net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as (1)

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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

We recognized a full cost pool ceiling test write-down of $14.4 million during the three months ended March 31, ~~2021, with first-day-of-the-month NYMEX oil prices for the preceding 12 months averaging $36.40 per Bbl, after adjustments for market differentials and transportation expenses by field.~~2021. The write-down was primarily a result of the ~~recent~~March 2021 acquisition ~~(see~~ of Wyoming CO~~Note~~ 2 –EOR properties (see Note 2, Acquisition and Divestiture) which was recorded based on a valuation that utilized NYMEX strip oil prices at the acquisition date, which were significantly higher than the average first-day-of-the-month NYMEX oil prices used to value the cost ceiling. We ~~also recognized full cost pool ceiling test write-downs of $662.4 million and $72.5 million during the Predecessor three months ended June 30, 2020 and March 31, 2020, respectively. We~~ did 0tnot record a ceiling test write-down during the three or six months ended June 30, ~~2021.~~2022.

~~Recent Accounting Pronouncements~~

~~Recently Adopted~~CCUS Storage Sites and Related Assets

~~Income Taxes.~~Capitalized Costs. ~~In December 2019,~~We capitalize various costs that we incur to acquire and develop storage sites for the ~~Financial Accounting Standards Board (“FASB”) issued ASU 2019-12,~~ injection of CO~~Income Taxes (Topic 740) – Simplifying the Accounting~~2. These costs generally include, or are expected to include, expenditures for ~~Income Taxes~~ ~~(“ASU 2019-12”). The objective~~acquiring surface and subsurface rights; third-party acquisition costs; permitting; drilling; facilities; environmental monitoring equipment for groundwater and storage site gas; engineering; capitalized interest; on-site road construction and other capital infrastructure costs. If a storage site is no longer deemed probable of ASU 2019-12 is to simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740 and to provide more consistent application to improve the comparability of financial statements. Effective January 1, 2021, we adopted ASU 2019-02. The implementation of this standard did not have a material impact on our consolidated financial statements and related footnote disclosures.being developed, all previously capitalized costs are expensed.

Amortization. Our CCUS storage sites are not yet operational. Accordingly, we currently have no amortization of capitalized costs. Amortization of these costs will begin when CO2 storage operations commence.

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~~Denbury Inc.~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

Note 2. Acquisition and Divestiture

2021 Acquisition of Wyoming CO2 EOR ~~Fields~~Properties

On March 3, 2021, we acquired a nearly 100% working interest (approximately 83% net revenue interest) in the Big Sand Draw and Beaver Creek EOR fields located in Wyoming from a subsidiary of Devon Energy Corporation, ~~for $10.7 million cash (before final closing adjustments),~~ including surface facilities and a 46-mile CO2 transportation pipeline to the acquired fields. The acquisition ~~agreement provides for us to make~~purchase price was $10.9 million (after final closing adjustments) plus two contingent $4 million cash payments ~~one in January 2022 and one in January 2023, of $4 million each, conditioned on~~if NYMEX WTI oil prices ~~averaging~~average at least $50 per Bbl during each of 2021 and 2022. We made the first contingent payment in January 2022 ~~respectively.~~and if the price condition is met, the second $4 million payment will be due in January 2023. The ~~fair value of the contingent consideration on the acquisition date was $5.3 million, and as of June 30, 2021, the~~ fair value of the contingent consideration recorded on our unaudited condensed consolidated balance sheets was $7.0 million. The $1.7 million increase from the March 2021 acquisition date fair value was the result of higher NYMEX WTI oil prices and was recorded to “Other expenses” in our Unaudited Condensed Consolidated ~~Statements~~Balance Sheets was $3.8 million as of ~~Operations.~~June 30, 2022.

The fair values allocated to our assets acquired and liabilities assumed for the acquisition, ~~were~~ based on significant inputs not observable in the market and considered level 3 ~~inputs.~~inputs, were finalized during the third quarter of 2021, after consideration of

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

final closing adjustments and evaluation of reserves and liabilities assumed. The following table presents a summary of the fair value of assets acquired and liabilities assumed in the acquisition:


In thousands
Consideration:
Cash consideration	$	~~10,657~~10,906

Less: Fair value of assets acquired and liabilities assumed:~~(1)~~
Proved oil and natural gas properties	~~59,852~~60,101
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~~10,906

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

2021 Divestiture of Hartzog Draw Deep Mineral Rights

On June 30, 2021, we closed the sale of undeveloped, unconventional deep mineral rights in Hartzog Draw Field in Wyoming. The cash proceeds of $18 million were recorded to “Proved properties” in our ~~Unaudited Condensed~~ Consolidated Balance Sheets. The proceeds reduced our full cost pool; therefore, 0no gain or loss was recorded on the transaction, and the sale had no impact on our production or reserves.

Note 3. Revenue Recognition

We record revenue in accordance with ~~FASC~~Financial Accounting Standards Board (“FASB”) Codification (“FASC”) Topic 606, Revenue from Contracts with Customers. The core principle of FASC Topic 606 is that an entity should recognize revenue for the transfer of goods or services equal to the amount of consideration that it expects to be entitled to receive for those goods or services. Once we have delivered the volume of commodity to the delivery point and the customer takes delivery and possession, we are entitled to payment and we invoice the customer for such delivered production. Payment under most oil and CO2 contracts is received within aone month following product delivery, and for natural gas and NGL contracts, payment is generally received within two months following delivery. Timing of revenue recognition may differ from the timing of invoicing to customers; however, as the right to consideration after delivery is unconditional based on only the passage of time before payment of the consideration is due, upon delivery we record a receivable in “Accrued production receivable” in our Unaudited Condensed Consolidated Balance Sheets. ~~From time to time,~~

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~~Denbury Inc.~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

In certain situations, the Company enters into marketing arrangements for the purchase and subsequent sale of crude oil ~~for~~from third parties. ~~Revenues~~We recognize the revenues received and the associated expenses ~~from~~incurred on these ~~transactions are presented~~sales on a gross basis, as “Oil marketing revenues” and “Oil marketing purchases” in our Unaudited Condensed Consolidated Statements of Operations, since we act as a principal in the transaction by assuming control of the commodities purchased and responsibility to deliver the commodities sold. Revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser.

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Disaggregation of Revenue

The following table summarizes our revenues by product ~~type:~~type for the three and six months ended June 30, 2022 and 2021:


		Successor		Predecessor		Successor		Predecessor			Three Months Ended				Six Months Ended
											June 30,				June 30,
In thousands	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		In thousands	2022		2021		2022		2021
Oil sales	Oil sales	$	280,577	$	108,538	$	513,621	$	337,115	Oil sales	$	446,592	$	280,577	$	827,834	$	513,621
Natural gas sales	Natural gas sales	2,131		849		4,532		1,896		Natural gas sales	5,378		2,131		9,047		4,532
CO2 sales and transportation fees	CO2 sales and transportation fees	10,134		6,504		19,362		14,532		CO2 sales and transportation fees	12,610		10,134		26,032		19,362
Oil marketing revenues	Oil marketing revenues	7,819		1,490		13,945		5,211		Oil marketing revenues	16,786		7,819		30,062		13,945
Total revenues	Total revenues	$	300,661	$	117,381	$	551,460	$	358,754	Total revenues	$	481,366	$	300,661	$	892,975	$	551,460

Note 4. Long-Term Debt

The table below reflects long-term debt outstanding as of the dates indicated:

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


In thousands	June 30, 2022		December 31, 2021
Senior Secured Bank Credit Agreement	$	—	$	35,000



Long-term debt	$	—	$	35,000

Senior Secured Bank Credit Agreement

On ~~the Emergence Date,~~September 18, 2020, we entered into a $575 million credit agreement for a senior secured revolving credit facility 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 borrowing base and lender commitments of $575 million.~~ Availability under the Bank Credit Agreement is subject to a borrowing base, which is redetermined semiannually on or around May 1 and November 1 of each year, with our next scheduled redetermination around November 1, ~~2021.~~2022. The borrowing base is adjusted at the lenders’ discretion and is based, in part, upon external factors over which we have no control. If our outstanding debt under the Bank Credit Agreement exceeds the then-effective borrowing base, we would be required to repay the excess amount over a period not to exceed six months. The ~~Bank Credit Agreement matures on January 30, 2024. The weighted average interest rate on borrowings outstanding as of June 30, 2021 under the Bank Credit Agreement was 4.0%. The~~ undrawn portion of the aggregate lender commitments under the Bank Credit Agreement is subject to a commitment fee of 0.5% per annum.

~~The~~On May 4, 2022, we entered into a Second Amendment to the Bank Credit Agreement, ~~prohibits~~which among other things:

•Increased the borrowing base and lender commitments from $575 million to $750 million;

•Extended the maturity date from January 30, 2024 to May 4, 2027;

•Modified the interest provisions on loans under the Bank Credit Agreement to (1) reduce the applicable margin for alternate base rate loans from 2% to 3% per annum to 1.5% to 2.5% per annum and (2) replace provisions referencing LIBOR loans with Secured Overnight Financing Rate loans, with an applicable margin of 2.5% to 3.5% per annum; and

•Permitted us ~~from paying dividends on our common stock through September 17, 2021. Commencing on September 18, 2021, we may~~to pay dividends on our common stock orand make other unlimited restricted payments ~~in an amount not to exceed “Distributable Free Cash Flow”, but only if~~and investments so long as (1) no event of default or borrowing base deficiency exists; (2) our total leverage ratio is 21.5 to 1 or lower; and (3) availability under the Bank Credit Agreement is at least 20%. of the borrowing base.

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 certain customary ~~exceptions.~~

~~Table~~exceptions to such limitations, as specified in the Bank Credit Agreement. Our Bank Credit Agreement required certain minimum commodity hedge levels in connection with our emergence from bankruptcy; however, these conditions were met as of ~~Contents~~

~~Denbury Inc.~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

December 31, 2020, and we currently have no ongoing hedging requirements under the Bank Credit Agreement.

The ~~Successor~~ 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

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

agreements; (4) a pledge of deposit accounts, securities accounts and our commodity accounts; and (5) a security interest in substantially all other collateral that may be perfected by a Uniform Commercial Code filing, subject to certain exceptions.

The Bank Credit Agreement contains certain financial performance covenants 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 time.~~1.0.

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

~~Pipeline Financing Transactions~~

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

Note 5. Stockholders' Equity

Share Repurchase Program

In early May 2022, our Board of Directors authorized a common share repurchase program for up to $250 million of outstanding Denbury common stock. During the second quarter of 2022, the Company repurchased 457,549 shares of Denbury common stock for $28.8 million, or $62.84 per share. Cumulatively through July 31, 2022, the Company repurchased 1,615,356 shares of Denbury common stock for approximately $100 million, or an average price of $61.92 per share. On August 2, 2022, the Board of Directors increased the dollar amount of Denbury common stock that can be purchased under the program to an aggregate of $350 million, and at that date, we were authorized to repurchase up to an additional $250.0 million of common stock. The program has no pre-established ending date and may be suspended or discontinued at any time. The Company is not obligated to repurchase any dollar amount or specific number of shares of its common stock under the program.

Employee Stock Purchase Plan

At the annual meeting of stockholders on June 1, 2022, the Company’s stockholders voted to approve the Denbury Inc. Employee Stock Purchase Plan (“ESPP”) authorizing the sale of up to 2,000,000 shares of common stock thereunder. In accordance with the ESPP, eligible employees may contribute up to 10% of eligible compensation, subject to certain limitations, to purchase previously unissued Denbury common stock. Participants in the ESPP may purchase common stock at a 15% discount to the fair market value of a share of common stock determined as the lower of the closing sales price on the first or last trading day of each offering period. We currently anticipate the first offering period under the ESPP will commence on September 1, 2022 and end on December 31, 2022. The plan is administered by the Compensation Committee of our Board of Directors.

Note 6. Income Taxes

We make estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Significant judgment is required in estimating valuation allowances, and in making this determination we consider all available positive and negative evidence and make certain assumptions. The realization of a deferred tax asset ultimately depends on the existence of sufficient taxable income in the applicable carryback or carryforward periods. In our assessment, we consider the nature, frequency, and severity of current and cumulative losses, as well as historical and forecasted financial results, the overall business environment, our industry’s historic cyclicality, the reversal of existing deferred tax assets and liabilities, and tax planning strategies.

We assess the valuation allowance recorded on our deferred tax assets, which was $125.5 million at December 31, 2021, on a quarterly basis. This valuation allowance on our federal and certain state deferred tax assets was recorded in September 2020

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Notes to Unaudited Condensed Consolidated Financial Statements

after the application of fresh start accounting, as (1) the tax basis of our assets, primarily our oil and gas properties, was in excess of the carrying value, as adjusted for fresh start accounting and (2) our historical pre-tax income reflected a three-year cumulative loss primarily due to ceiling test write-downs and reorganization items that were recorded in 2020. While we continued to be in a cumulative three-year-loss position through the first quarter of 2022, we initially determined as of March 31, 2022, that there was sufficient positive evidence, primarily related to a substantial increase in worldwide oil prices, to conclude that $64.9 million of our federal and certain state deferred tax assets are more likely than not to be realized. Accordingly, we reversed $5.9 million of this valuation allowance during the three months ended March 31, 2022, $18.8 million during the three months ended June 30, 2022, and currently expect to reverse the remaining $40.2 million during the second half of 2022, resulting in a reduction to our annualized effective tax rate. We continue to maintain a valuation allowance of $60.6 million for certain state tax benefits that we currently do not expect to realize before their expiration.

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 ~~2021~~2022 and ~~2020.~~2021. Our effective tax ~~rates~~rate for the three and six months ended June 30, ~~2021 (Successor) differed from~~2022 was significantly lower than our estimated statutory rate asprimarily due to the ~~deferred tax benefit generated from our operating losses were offset by a~~release of the valuation allowance ~~applied to our underlying federal~~that was recorded in the three and ~~state deferred tax assets.~~six months ended June 30, 2022.

Note 6.7. Commodity Derivative Contracts

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

Historically, we have entered into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength and expectation of future commodity prices. In addition, our new senior secured bank credit facility entered into on the Emergence Date required that, by December 31, 2020, we have certain minimum commodity hedge levels in place covering anticipated crude oil production through July 31, 2022. The requirement is non-recurring, and we were in compliance with the hedging requirements as of December 31, 2020.

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We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of June 30, ~~2021,~~2022, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.

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Notes to Unaudited Condensed Consolidated Financial Statements

The following table summarizes our commodity derivative contracts as of June 30, ~~2021,~~2022, none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic:

Months Index Price Volume (Barrels per day) Contract Prices ($/Bbl)
Range(1)
Weighted Average Price
Swap Floor Ceiling
Oil Contracts:
2021 Fixed-Price Swaps
July – Dec NYMEX 29,000 $ 38.68 – 56.00 $ 43.86 $ — $ —
2021 Collars
July – Dec NYMEX 4,000 $ 45.00 – 59.30 $ — $ 46.25 $ 53.04
2022 Fixed-Price Swaps
Jan – June NYMEX 15,500 $ 42.65 – 58.15 $ 49.01 $ — $ —
July – Dec NYMEX 9,000 50.13 – 60.35 56.35 — —
2022 Collars
Jan – June NYMEX 11,000 $ 47.50 – 70.75 $ — $ 49.77 $ 64.31
July – Dec NYMEX 10,000 47.50 – 70.75 — 49.75 64.18

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


Months	Index Price	Volume (Barrels per day)	Contract Prices ($/Bbl)
			Weighted Average Price
			Swap		Floor		Ceiling
Oil Contracts:
2022 Fixed-Price Swaps
July – Dec	NYMEX	9,500	$	57.52	$	—	$	—
2022 Collars
July – Dec	NYMEX	11,500	$	—	$	52.39	$	67.29
2023 Fixed-Price Swaps
Jan – June	NYMEX	4,500	$	74.88	$	—	$	—
July – Dec	NYMEX	2,000	76.80		—		—
2023 Collars
Jan – June	NYMEX	17,500	$	—	$	69.71	$	100.42
July – Dec	NYMEX	9,000	—		68.33		100.69

Note 7.8. Fair Value Measurements

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

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

•Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded oil derivatives that are based on NYMEX and regional pricing other than NYMEX (e.g., Light Louisiana Sweet). Our costless collars ~~and the sold put features of our three-way collars~~ are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contractual prices for the underlying instruments, maturity, quoted forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term

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

•Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

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

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Notes to Unaudited Condensed Consolidated Financial Statements

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


		Fair Value Measurements Using:									Fair Value Measurements Using:
In thousands	In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
June 30, 2021
June 30, 2022										June 30, 2022
Assets										Assets
Oil derivative contracts – current										Oil derivative contracts – current	$	—	$	2,829	$	—	$	2,829
Oil derivative contracts – long-term										Oil derivative contracts – long-term	—		2,071		—		2,071
Total Assets										Total Assets	$	—	$	4,900	$	—	$	4,900

Liabilities										Liabilities
Oil derivative contracts – current										Oil derivative contracts – current	$	—	$	(162,551)	$	—	$	(162,551)
Oil derivative contracts – long-term										Oil derivative contracts – long-term	—		(5,415)		—		(5,415)
Total Liabilities										Total Liabilities	$	—	$	(167,966)	$	—	$	(167,966)

December 31, 2021										December 31, 2021

Liabilities	Liabilities									Liabilities
Oil derivative contracts – current	Oil derivative contracts – current	$	0	$	(223,212)	$	0	$	(223,212)	Oil derivative contracts – current	$	—	$	(134,509)	$	—	$	(134,509)
Oil derivative contracts – long-term		0		(22,164)		0		(22,164)

Total Liabilities	Total Liabilities	$	0	$	(245,376)	$	0	$	(245,376)	Total Liabilities	$	—	$	(134,509)	$	—	$	(134,509)

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

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

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

Other Fair Value Measurements

The carrying value of our loans under our Bank Credit Agreement approximate fair value, as they are subject to short-term floating interest rates that approximate the rates available to us for those periods. ~~The~~We had no debt outstanding as of June 30, 2022, and the estimated fair value of the principal amount of our debt ~~as of June 30, 2021 and December 31, 2020, excluding pipeline financing obligations,~~ was $35.0 million ~~and $70.0 million.~~as of December 31, 2021. We have other financial instruments consisting primarily of cash, cash equivalents, U.S. Treasury notes, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.

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Note 8.9. Commitments and Contingencies

~~Chapter 11~~Litigation and Regulatory Proceedings

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

~~Litigation~~

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

On May 26, 2022, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) of the U.S. Department of Transportation issued a Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order (“NOPV”) relating to the February 2020 pipeline failure near Satartia, Mississippi in our CO2 pipeline running between the Tinsley and Delhi fields. The NOPV proposes a preliminarily assessed civil penalty of $3.9 million in connection with the incident, which

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Notes to Unaudited Condensed Consolidated Financial Statements

we recorded in our second quarter of 2022 financial statements. We have responded to the NOPV and are pursuing discussions with PHMSA regarding the probable violations alleged in the NOPV, the proposed civil penalty, and the nature of the compliance order contained in the NOPV.

Note 9.10. Additional Balance Sheet Details

Trade and Other Receivables, Net

Successor
In thousands June 30, 2021 December 31, 2020
Trade accounts receivable, net $ 11,795 $ 11,691
Federal income tax receivable, net 597 597
Commodity derivative settlement receivables 0 5,716
Other receivables(1)
12,348 1,678
Total $ 24,740 $ 19,682

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


In thousands	June 30, 2022		December 31, 2021
Trade accounts receivable, net	$	18,014	$	10,832
Federal income tax receivable, net	597		597
Other receivables	12,307		7,841
Total	$	30,918	$	19,270

Accounts Payable and Accrued Liabilities

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


In thousands	June 30, 2022		December 31, 2021
Accounts payable	$	53,007	$	25,700
Accrued derivative settlements	46,888		27,336
Accrued lease operating expenses	44,195		27,901
Accrued asset retirement obligations – current	34,400		18,373
Accrued compensation	21,270		23,735
Taxes payable	12,506		14,453
Accrued exploration and development costs	10,363		18,936
Other	40,123		35,164
Total	$	262,752	$	191,598

Note 11. Subsequent Event

Delhi Insurance Receivable

In July 2022, we finalized a settlement agreement with certain of our insurance carriers, pursuant to which they agreed to pay Denbury $7.0 million ($6.7 million net to Denbury’s interest) as a reimbursement of previously incurred property damage costs at Delhi Field. The reimbursement is included as a reduction of “Lease operating expenses” in the accompanying Unaudited Condensed Consolidated Statements of Operations during the three and six months ended June 30, 2022, as a result of the resolution of these claims which arose in 2013.

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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, ~~2020~~2021 (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 energy company with operations focused in the Gulf Coast and Rocky Mountain regions. The Company is 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~~making the Company’s Scope 1 and 2 CO2 emissions negative today, with a goal to ~~fully offset~~be net-zero on its Scope 1, 2, and 3 CO2 emissions ~~within this decade,~~by 2030, primarily through increasing the amount of captured industrial-sourced CO2 used in its operations.

~~Oil Price Impact on Our Business.~~ Our financial results are significantly impacted by changes in oil prices, as 97% of our 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 selected financial

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

Successor Predecessor
Three Months Ended Three Months Ended
June 30, 2020
In thousands, except per-unit data June 30, 2021 March 31, 2021 December 31, 2020
Oil, natural gas, and related product sales $ 282,708 $ 235,445 $ 178,787 $ 109,387
Receipt (payment) on settlements of commodity derivatives (63,343) (38,453) 14,429 45,629
Oil, natural gas, and related product sales and commodity settlements, combined $ 219,365 $ 196,992 $ 193,216 $ 155,016
Average daily sales (BOE/d) 49,133 47,357 48,805 50,190
Average net realized prices
Oil price per Bbl - excluding impact of derivative settlements $ 64.70 $ 56.28 $ 40.63 $ 24.39
Oil price per Bbl - including impact of derivative settlements 50.10 47.00 43.94 34.64

NYMEX WTI oil prices strengthened from the mid-$40s per Bbl range in December 2020 to an average of approximately $66 per Bbl during the second quarter of 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 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 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 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 CO~~2 ~~expense, $3.7 million in power and fuel, and approximately $7.1 million due to the Wind River Basin acquisition in March 2021~~;

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

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

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

~~June 2021 Divestiture of Hartzog Draw Deep Mineral Rights.~~ On June 30, 2021, we closed the sale of undeveloped, unconventional deep mineral rights in Hartzog Draw Field in Wyoming. The cash proceeds of $18 million 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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~~Management’s Discussion and Analysis of Financial Condition and Results of Operations~~

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

Carbon Capture, Use and Storage. CCUS is a process that captures CO2 from industrial sources and reuses it or stores the CO2 in geologic formations in order to prevent its release into the atmosphere. We utilize CO2 from industrial sources in our EOR operations, and our extensive CO2 pipeline infrastructure and operations, particularly in the Gulf Coast, are strategically located in close proximity to large sources of industrial emissions. We believe that the assets and technical expertise required for CCUS are highly aligned with our existing CO2 EOR operations, providing us with a significant advantage and opportunity to ~~participate~~lead 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,~~2022, approximately ~~34%~~39% of the CO2 utilized in our oil and gas operations was industrial-sourced CO2, ~~and we~~equivalent to an annualized average usage rate of over 4 million metric tons in 2022. This compares to 34% utilized during the first half of 2021, with the increase related to commencing CO2 injection in the first phase of our Cedar Creek Anticline (“CCA”) EOR project. We anticipate this percentage ~~could~~will 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~~

As we seek to ~~proactively~~grow our CCUS business and pursue ~~these~~ new CCUS opportunities, we ~~are~~have been engaged in discussions with existing and potential third-party industrial CO2 emitters regarding CO2 offtake, transportation and storage ~~solutions,~~solutions. In the nearer term, while the energy transition is still evolving nationally, we believe that a key driver in speeding that transition is identifying and securing the long-term supply of industrial CO2, while also identifying potential future sequestration sites and landowners of those locations. We continue to make material progress in both of these areas, and thus far have signed agreements securing the rights to five future sequestration sites which we believe have the potential to store up to 1.5 billion metric tons of CO2. In addition, we have executed several term sheets for the future transportation and sequestration of CO2. During the first half of 2022, we capitalized $24.0 million in “CCUS storage sites and related assets” in our Unaudited Condensed Consolidated Balance Sheets, primarily consisting of acquisition costs associated with sequestration sites. While our use of CO2 in EOR is the only CCUS operation reflected in our ~~current and~~ historical financial and operational results (as a cost), we believe the incentives offered under Section 45Q of the Internal Revenue Code and ~~development~~the proposed Inflation Reduction Act of 2022 or otherwise will drive demand for CCUS and allow us to collect a fee for the transportation and storage of captured industrial-sourced CO2, including CO2 utilized in our ~~permanent carbon sequestration business is~~EOR operations. It will likely to take several years weto construct new capture facilities and for dedicated storage sites to be developed. We believe ~~Denbury is well positioned to leverage~~ our existing CO2 pipeline infrastructure, EOR operations, and ~~EOR~~experience and expertise in working with CO2 all position us to be a leader in this rapidly developing industry.

Oil Price Impact on Our Business. Our financial results are significantly impacted by changes in oil prices, as 97% of our sales volumes are 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

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


	Three Months Ended
In thousands, except per-unit data	June 30, 2022		March 31,2022		Dec. 31, 2021		Sept. 30, 2021		June 30, 2021
Oil, natural gas, and related product sales	$	451,970	$	384,911	$	333,348	$	308,454	$	282,708
Payment on settlements of commodity derivatives	(127,959)		(93,057)		(97,774)		(77,670)		(63,343)
Oil, natural gas, and related product sales and commodity derivative settlements, combined	$	324,011	$	291,854	$	235,574	$	230,784	$	219,365

Average daily sales (BOE/d)	46,561		46,925		48,882		49,682		49,133

Average net realized oil prices
Oil price per Bbl - excluding impact of derivative settlements	$	108.81	$	93.17	$	75.68	$	68.88	$	64.70
Oil price per Bbl - including impact of derivative settlements	77.63		70.43		53.21		51.35		50.10

Average NYMEX WTI oil prices increased from the mid-$70s per Bbl range in the fourth quarter of 2021 to approximately $95 per Bbl during the first quarter of 2022, then increasing to approximately $109 per Bbl during the second quarter of 2022. This increase in oil prices was due in part to worldwide oil supply disruptions associated with the Russian invasion of Ukraine during the first half of 2022.

As shown in the table above, our oil and natural gas revenues increased significantly during the last four quarters as oil prices increased. However, the benefit of the increase in revenues over this time period was offset in part by the impact of higher cash payments on our commodity derivative contracts. These contracts were largely required to be entered into during the fourth quarter of 2020 under the one-time requirement of our September 18, 2020 bank credit facility. During the second quarter of 2022, we paid $128.0 million related to the expiration of commodity derivative contracts and expect to make additional payments on the settlement of our contracts expiring during the remainder of 2022. In the second half of 2022, less of our production is hedged, and our hedges are at more favorable prices and with a greater mix of collars, providing the potential for us to realize a greater portion of increased oil prices.

Second Quarter 2022 Financial Results and Highlights. We recognized net income of $155.5 million, or $2.83 per diluted common share, during the second quarter of 2022, compared to a net loss of $77.7 million, or $1.52 per diluted common share, during the second quarter of 2021. The primary drivers of the comparative second quarter operating results include the following:

•Oil and natural gas revenues increased $169.3 million (60%) due primarily to an increase in oil prices;

•Commodity derivatives expense decreased by $115.8 million consisting of a $180.4 million increase in noncash fair value changes ($71.1 million gain during the second quarter of 2022 compared to a $109.3 million loss in the prior-year period), partially offset by a $64.6 million increase in cash payments upon derivative contract settlements;

•Lease operating expenses increased $14.1 million (13%), primarily consisting of increases of $6.5 million in power and fuel costs, $4.6 million in workovers, $2.8 million in labor costs, and $2.4 million in CO2 expense, partially offset by a $6.7 million insurance recovery of costs incurred in 2013 from property damage at Delhi Field;

•Taxes other than income increased $13.9 million (62%) primarily due to an increase in production taxes resulting from higher oil and gas revenues; and

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

•Income taxes increased to an expense of $24.8 million during the second quarter of 2022 compared to a benefit of $0.3 million during the prior-year period.

Commencement of Cedar Creek Anticline CO2 Injection. In early February 2022, we commenced CO2 injection in the first phase of our CCA EOR project and have subsequently continued to increase CO2 injections into the field. In order to stay ahead of potential supply chain delays, we plan to increase capital investment in the second half of the year at CCA to accelerate our procurement of compression equipment and construction of CO2 recycle facilities to ensure facilities are in place to handle anticipated production from the field. We continue to expect tertiary oil production response from CCA in the second half of 2023.

Common Share Repurchase Program. In early May 2022, our Board of Directors authorized a common share repurchase program for up to $250 million of outstanding Denbury common stock. During the second quarter of 2022, the Company repurchased 457,549 shares of Denbury common stock for $28.8 million, or $62.84 per share. Cumulatively through July 31, 2022, the Company repurchased 1,615,356 shares of Denbury common stock (approximately 3.2% of our outstanding shares of common stock at March 31, 2022) for approximately $100.0 million, or an average price of $61.92 per share. On August 2, 2022, the Board of Directors increased the dollar amount of Denbury common stock that can be purchased under the program to an aggregate of $350 million, and at that date, we were authorized to repurchase up to an additional $250.0 million of common stock. The program has no pre-established ending date and may be suspended or discontinued at any time. The Company is not obligated to repurchase any dollar amount or specific number of shares of its common stock under the program.

Increase in 2022 Capital Expenditure Plans. Based on inflationary cost increases and the desire to accelerate capital spending to offset potential supply chain delays, we are increasing our 2022 capital expenditures estimate for oil and gas development activities from the previously anticipated upper end of $320 million to approximately $360 million. Approximately half of the increase relates to overall service cost inflation impacting the Company’s operations, primarily related to labor and steel costs, and the rest of the increase is associated with CCA EOR development activities, where the Company is accelerating the purchase of compression equipment and construction of CO2 recycle facilities to ensure the field is ready to process the expected oil production response. In addition, our original budget for CCUS capital is still estimated at $50 million, but could increase depending on activity in the second half of the year. See further discussion under Capital Resources and Liquidity – 2022 Plans and Capital Budget.

May 2022 Amendment to Senior Secured Bank Credit Agreement. In early May 2022, we amended our bank credit facility to among other things, (1) increase the borrowing base and lender commitments to $750 million, (2) extend the maturity date to May 4, 2027, (3) modify certain interest rate provisions, and (4) provide additional flexibility regarding our ability to make restricted payments and investments. See further discussion of this amendment under Capital Resources and Liquidity – Senior Secured Bank Credit Agreement. As of June 30, 2022, we had no outstanding borrowings on our senior secured bank credit facility.

Warrant Exercises. During the three and six months ended June 30, 2022, 1,796,237 and 1,822,013 warrants were exercised for a total of 987,411 shares and 1,001,564 shares, respectively, most of which were exercised on a cashless basis. At June 30, 2022, the Company had approximately 3.4 million warrants outstanding that can be exercised for shares of our common stock, which represents approximately 60.9% of the aggregate series A and B warrants issued in September 2020, at an exercise price of $32.59 per share for the 1.8 million series A warrants outstanding and at an exercise price of $35.41 per share for the 1.6 million series B warrants outstanding. The warrants may be exercised for cash or on a cashless basis. The series A warrants are exercisable until September 18, 2025, and the series B warrants are exercisable until September 18, 2023, at which times the warrants expire.

CAPITAL RESOURCES AND LIQUIDITY

Overview. Our ~~primary sources of capital and liquidity are our~~ cash flows from operations and availability under our senior secured bank credit ~~facility.~~facility are our primary sources of capital and liquidity. Our most significant cash capital outlays ~~in 2021~~ relate to our ~~$250 million to $270 million of budgeted~~oil and gas development capital expenditures and $70 million of pipeline financing obligations associated with the NEJD pipeline. Based on our current 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 addition, we have sold certain non-producing assets that will further supplement our cash flow from operations.CCUS initiatives.

As of June 30, ~~2021,~~2022, we had ~~$35~~no outstanding borrowings and $12.0 million of outstanding ~~borrowings on~~letters of credit under our ~~$575~~$750 million senior secured bank credit facility, leaving us with ~~$517.7~~$738.0 million of borrowing base availability ~~after consideration of $22.3~~and approximately $738.5 million of ~~outstanding letters of credit. Our borrowing base availability, coupled with unrestricted cash of $13.6 million, provides us~~ total liquidity ~~of $531.3 million as of~~including our cash position at June 30, ~~2021, which~~2022. This liquidity 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 CO~~2 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 CO2 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~~currently planned operating and capital needs as we currently project our cash flow from operations to significantly exceed our planned capital expenditures in ~~a range~~2022. In early May 2022, we amended our bank credit facility to among other things, increase the borrowing base availability and lender commitments to $750 million (see further discussion 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:~~this amendment under Senior Secured Bank Credit Agreement below).

•Six Months Ended 2022 Sources and Uses. ~~$100~~During the first half of 2022, we generated cash flows from operations of $240.1 million, while incurring capital costs of $169.9 million, consisting primarily of oil and gas development capital expenditures of $143.9 million, CCUS related capital expenditures of $23.9 million, and capitalized interest of $2.1 million. During the second quarter of 2022, the Company also repurchased 457,549 shares of Denbury common stock for $28.8 million, or $62.84 per share.

As further discussed below, based on oil price futures as of early August 2022, we currently anticipate funding all of our 2022 capital budget from projected operating cash flow while also generating excess cash flow. As the ~~105-mile extension~~level of excess cash we expect to generate in 2022 and future periods has increased with the rise in oil prices during 2022, our Board of Directors adopted a share repurchase program in early May 2022 authorizing the repurchase of up to $250 million of Denbury’s common stock. Cumulatively through July 31, 2022, the Company repurchased 1,615,356 shares of Denbury common stock (approximately 3.2% of our outstanding shares of common stock at March 31, 2022) for approximately $100 million, or an average price of $61.92 per share. On August 2, 2022, the Board of Directors increased the dollar amount of Denbury common stock that can be purchased under the program to an aggregate of $350 million, and at that date, we were authorized to repurchase up to an additional $250.0 million of common stock. The ultimate level of excess cash we may generate in 2022 and future periods will be highly dependent on oil prices and many other factors, but we currently believe our level of cash flow generation will be adequate to fund our EOR and CCUS strategic priorities while also returning capital to our shareholders through our share repurchase program.

2022 Plans and Capital Budget. Based on inflationary cost increases and the desire to accelerate capital spending to offset potential supply chain delays, we are increasing our 2022 capital expenditures estimate for oil and gas development activities from the previously anticipated upper end of our range of $320 million to approximately $360 million. Approximately half of the ~~Greencore~~increase relates to overall service cost inflation impacting the Company’s operations, primarily related to labor and steel costs, and the rest of the increase is associated with CCA EOR development activities, where the Company is accelerating the purchase of compression equipment and construction of CO2 ~~pipeline~~recycle facilities to ~~CCA;~~

•ensure the field is ready to process the expected oil production response. In addition, anticipated spending for our CCUS business of approximately $50 million remains unchanged but could increase depending on activity levels in the second half of the year, with expenditures primarily focused on securing CO~~$50 million for CCA tertiary well work, facilities,~~2 sequestration sites 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.~~drilling one or more stratigraphic test wells in those sequestration sites.

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.

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

Capital Expenditure Summary. The following table reflects incurred capital expenditures ~~(including accrued capital)~~ for the six months ended June 30, ~~2021~~2022 and ~~2020:~~2021:

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


	Six Months Ended
	June 30,
In thousands	2022		2021
Capital expenditure summary(1)
CCA EOR field expenditures(2)	$	39,205	$	9,100
CCA CO2 pipelines	1,241		9,999
CCA tertiary development	40,446		19,099
Non-CCA tertiary and non-tertiary fields	86,437		40,297
CO2 sources and other CO2 pipelines	2,110		—

Capitalized internal costs(3)	14,903		14,785
Oil & gas development capital expenditures	143,896		74,181
CCUS storage sites and related capital expenditures	23,900		—
Acquisitions of oil and natural gas properties(4)	374		10,811

Capitalized interest	2,133		2,251
Total capital expenditures	$	170,303	$	87,243

(1)Capital expenditures in this summary are presented on an as-incurred basis (including accruals), and are $7.6 million lower than the capital expenditures in the Unaudited Condensed Consolidated Statements of Cash Flows which are presented on a cash basis.

(2)Includes pre-production CO2 costs associated with the CCA EOR development project totaling $10.8 million during the first half of 2022.

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

~~(2)~~(4)Primarily consists of working interest positions in the Wind River Basin enhanced oil recovery fields acquired on March 3, 2021.

Supply Chain Issues and Potential Cost Inflation. Recent worldwide and U.S. supply chain issues, together with rising commodity prices and tight labor markets in the U.S., have increased our costs during late 2021 and thus far in 2022. Based on ~~current oil prices~~cost increases and shortages experienced across the ~~Company’s hedge positions,~~industry and higher fuel and power costs thus far in 2022, we ~~expect that~~anticipate additional increases in the cost of, and demand for, goods and services and wages in our ~~2021~~operations during the remainder of 2022 which could negatively impact our results of operations and cash flows ~~from operations will exceed our budgeted level of planned development capital expenditures.~~in future periods.

Senior Secured Bank Credit Agreement. In September 2020, we entered into a $575 million bank credit agreement for a senior secured revolving credit facility with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the “Bank Credit Agreement”). ~~The~~Availability under the Bank Credit Agreement is subject to a ~~senior secured revolving credit facility with a maturity date of January 30, 2024. As part of our spring 2021 semiannual~~ borrowing base, ~~redetermination, the borrowing base and lender commitments for our Bank Credit Agreement were reaffirmed at $575 million,~~which is redetermined semiannually on or around May 1 or November 1 of each year, with our next scheduled redetermination around November ~~2021.~~1, 2022. The borrowing base is adjusted at the lenders’ discretion and is based, in part, upon external factors over which we have no control. If our outstanding debt under the Bank Credit Agreement exceeds the then-effective borrowing base, we would be required to repay the excess amount over a period not to exceed six months.

On May 4, 2022, we entered into a Second Amendment to the Bank Credit Agreement, which among other things:

•Increased the borrowing base and lender commitments from $575 million to $750 million;

•Extended the maturity date from January 30, 2024 to May 4, 2027;

•Permitted us to pay dividends on our common stock and make other unlimited restricted payments and investments so long as (1) no event of default or borrowing base deficiency exists; (2) our total leverage ratio is 1.5 to 1 or lower; and (3) availability under the Bank Credit Agreement is at least 20% of the borrowing base.

2021

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~~period not~~

The Bank Credit Agreement also limits our ability to, ~~exceed six months.~~ 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 certain customary exceptions to such limitations, as specified in the Bank Credit Agreement. Our Bank Credit Agreement required certain minimum commodity hedge levels in connection with our emergence from bankruptcy; however, these conditions were met as of December 31, 2020, and we currently have no ongoing hedging requirements under the Bank Credit Agreement.

The Bank Credit Agreement contains certain financial performance covenants 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 time.~~1.0.

For purposes of computing the current ratio per the Bank Credit Agreement, Consolidated Current Assets exclude the current portion of derivative assets but include available borrowing capacity under the 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,~~2022, our ratio of consolidated total debt to consolidated EBITDAX was ~~0.18~~0.00 to 1.0 (with a maximum permitted ratio of 3.5 to 1.0) and our current ratio was ~~3.00~~2.70 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,~~3, 2022, and current oil commodity ~~derivative~~ futures prices, we currently anticipate continuing to be in compliance with our financial performance covenants during the foreseeable future.

The above description of our Bank Credit Agreement is qualified by the express language and defined terms contained in the Bank Credit Agreement and amendments thereto, each of which is filed as an exhibit to our ~~Form 8-K Report~~periodic reports filed with the ~~SEC~~Securities and Exchange Commission (“SEC”). The Second Amendment to the Credit Agreement, which is attached as Exhibit 10(d) to the Form 10-Q filed on ~~September 18, 2020.~~May 6, 2022, contains the full text of the current version of the Bank Credit Agreement inclusive of all changes made by virtue of both the First and Second Amendments thereto.

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

Our commitments and obligations consist of those detailed as of December 31, ~~2020,~~2021, 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 Off-Balance Sheet Arrangements~~. During the six months ended June 30, 2021, our long-term asset retirement obligations increased by $47.3 million, primarily related to our acquisition of working interest positions in Wyoming CO~~2 ~~EOR fields (see Note 2,~~ ~~Acquisition and 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

Certain of our ~~financial and~~ operating results and statistics for the comparative three and six months ended June 30, ~~2021~~2022 and ~~2020~~2021 are included in the following table:


											Three Months Ended				Six Months Ended
		Successor		Predecessor		Successor		Predecessor			June 30,				June 30
In thousands, except per-share and unit data	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		In thousands, except per-share and unit data	2022		2021		2022		2021
Financial results	Financial results									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 income (loss)(1)										Net income (loss)(1)	$	155,494	$	(77,695)	$	154,622	$	(147,337)
Net income (loss) per common share – basic(1)										Net income (loss) per common share – basic(1)	3.00		(1.52)		2.99		(2.91)
Net income (loss) per common share – diluted(1)										Net income (loss) per common share – diluted(1)	2.83		(1.52)		2.81		(2.91)
Net cash provided by operating activities	Net cash provided by operating activities	90,882		10,969		143,538		72,811		Net cash provided by operating activities	149,965		90,882		240,108		143,538
Average daily sales volumes	Average daily sales volumes									Average daily sales volumes
Bbls/d	Bbls/d	47,653		48,900		46,834		51,774		Bbls/d	45,104		47,653		45,284		46,834
Mcf/d	Mcf/d	8,882		7,737		8,494		7,818		Mcf/d	8,741		8,882		8,747		8,494
BOE/d(2)	BOE/d(2)	49,133		50,190		48,250		53,077		BOE/d(2)	46,561		49,133		46,742		48,250
Oil and natural gas sales	Oil and natural gas sales									Oil and natural gas sales
Oil sales	Oil sales	$	280,577	$	108,538	$	513,621	$	337,115	Oil sales	$	446,592	$	280,577	$	827,834	$	513,621
Natural gas sales	Natural gas sales	2,131		849		4,532		1,896		Natural gas sales	5,378		2,131		9,047		4,532
Total oil and natural gas sales	Total oil and natural gas sales	$	282,708	$	109,387	$	518,153	$	339,011	Total oil and natural gas sales	$	451,970	$	282,708	$	836,881	$	518,153
Commodity derivative contracts(3)	Commodity derivative contracts(3)									Commodity derivative contracts(3)
Receipt (payment) on settlements of commodity derivatives		$	(63,343)	$	45,629	$	(101,796)	$	70,267
Payment on settlements of commodity derivatives										Payment on settlements of commodity derivatives	$	(127,959)	$	(63,343)	$	(221,016)	$	(101,796)
Noncash fair value gains (losses) on commodity derivatives	Noncash fair value gains (losses) on commodity derivatives	(109,321)		(85,759)		(186,611)		36,374		Noncash fair value gains (losses) on commodity derivatives	71,105		(109,321)		(28,557)		(186,611)
Commodity derivatives income (expense)		$	(172,664)	$	(40,130)	$	(288,407)	$	106,641
Commodity derivatives expense										Commodity derivatives expense	$	(56,854)	$	(172,664)	$	(249,573)	$	(288,407)
Unit prices – excluding impact of derivative settlements	Unit prices – excluding impact of derivative settlements									Unit prices – excluding impact of derivative settlements
Oil price per Bbl	Oil price per Bbl	$	64.70	$	24.39	$	60.59	$	35.78	Oil price per Bbl	$	108.81	$	64.70	$	101.00	$	60.59
Natural gas price per Mcf	Natural gas price per Mcf	2.64		1.21		2.95		1.33		Natural gas price per Mcf	6.76		2.64		5.71		2.95
Unit prices – including impact of derivative settlements(3)	Unit prices – including impact of derivative settlements(3)									Unit prices – including impact of derivative settlements(3)
Oil price per Bbl	Oil price per Bbl	$	50.10	$	34.64	$	48.58	$	43.23	Oil price per Bbl	$	77.63	$	50.10	$	74.03	$	48.58
Natural gas price per Mcf	Natural gas price per Mcf	2.64		1.21		2.95		1.33		Natural gas price per Mcf	6.76		2.64		5.71		2.95
Oil and natural gas operating expenses	Oil and natural gas operating expenses									Oil and natural gas operating expenses
Lease operating expenses	Lease operating expenses	$	110,225	$	81,293	$	192,195	$	190,563	Lease operating expenses	$	124,351	$	110,225	$	242,179	$	192,195
Transportation and marketing expenses	Transportation and marketing expenses	8,522		9,388		16,319		19,009		Transportation and marketing expenses	4,802		8,522		9,447		16,319
Production and ad valorem taxes	Production and ad valorem taxes	21,836		8,766		39,731		26,753		Production and ad valorem taxes	35,570		21,836		66,013		39,731
Oil and natural gas operating revenues and expenses per BOE	Oil and natural gas operating revenues and expenses per BOE									Oil and natural gas operating revenues and expenses per BOE
Oil and natural gas revenues	Oil and natural gas revenues	$	63.23	$	23.95	$	59.33	$	35.09	Oil and natural gas revenues	$	106.67	$	63.23	$	98.92	$	59.33
Lease operating expenses	Lease operating expenses	24.65		17.80		22.01		19.73		Lease operating expenses	29.35		24.65		28.63		22.01
Transportation and marketing expenses	Transportation and marketing expenses	1.91		2.06		1.87		1.97		Transportation and marketing expenses	1.13		1.91		1.12		1.87
Production and ad valorem taxes	Production and ad valorem taxes	4.88		1.92		4.55		2.77		Production and ad valorem taxes	8.40		4.88		7.80		4.55
CO2 – revenues and expenses	CO2 – revenues and expenses									CO2 – revenues and expenses
CO2 sales and transportation fees	CO2 sales and transportation fees	$	10,134	$	6,504	$	19,362	$	14,532	CO2 sales and transportation fees	$	12,610	$	10,134	$	26,032	$	19,362
CO2 operating and discovery expenses	CO2 operating and discovery expenses	(1,531)		(885)		(2,524)		(1,637)		CO2 operating and discovery expenses	(1,681)		(1,531)		(4,498)		(2,524)
CO2 revenue and expenses, net	CO2 revenue and expenses, net	$	8,603	$	5,619	$	16,838	$	12,895	CO2 revenue and expenses, net	$	10,929	$	8,603	$	21,534	$	16,838

(1)Includes a pre-tax full cost pool ceiling test write-down of our oil and natural gas properties of $14.4 million during the first quarter of ~~2021, as compared to write-downs of $662.4 million and $735.0 million for the three and six months ended June 30, 2020, respectively.~~2021.

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

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

2223

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

Sales Volumes

Average daily sales volumes by area for each of the four quarters of ~~2020~~2021 and for the first and second quarters of ~~2021~~2022 is shown below:


		Average Daily Sales Volumes (BOE/d)							Average Daily Sales Volumes (BOE/d)
		First Quarter	Second Quarter	First Quarter	Second Quarter	Third Quarter	Fourth Quarter		Second Quarter	First Quarter	Fourth Quarter	Third Quarter	Second Quarter	First Quarter
Operating Area	Operating Area	2021	2021	2020	2020	2020	2020	Operating Area	2022	2022	2021	2021	2021	2021
Tertiary oil sales
Tertiary oil sales volumes								Tertiary oil sales volumes
Gulf Coast region	Gulf Coast region							Gulf Coast region
Delhi	Delhi	2,925	2,931	3,813	3,529	3,208	3,132	Delhi	2,478	2,675	2,731	2,859	2,931	2,925
Hastings	Hastings	4,226	4,487	5,232	4,722	4,473	4,598	Hastings	4,304	4,430	4,212	4,343	4,487	4,226
Heidelberg	Heidelberg	4,054	3,942	4,371	4,366	4,256	4,198	Heidelberg	3,528	3,653	3,797	3,895	3,942	4,054
Oyster Bayou	Oyster Bayou	3,554	3,791	3,999	3,871	3,526	3,880	Oyster Bayou	3,423	3,745	4,039	3,942	3,791	3,554
Tinsley	Tinsley	3,424	3,455	4,355	3,788	4,042	3,654	Tinsley	3,050	3,015	3,353	3,390	3,455	3,424
Other(1)	Other(1)	6,098	6,074	7,161	5,944	6,271	6,332	Other(1)	5,422	5,498	5,801	5,907	6,074	6,098
Total Gulf Coast region	Total Gulf Coast region	24,281	24,680	28,931	26,220	25,776	25,794	Total Gulf Coast region	22,205	23,016	23,933	24,336	24,680	24,281
Rocky Mountain region	Rocky Mountain region							Rocky Mountain region
Bell Creek	Bell Creek	4,614	4,394	5,731	5,715	5,551	5,079	Bell Creek	4,122	4,474	4,331	4,330	4,394	4,614
Other(2)	Other(2)	2,573	4,378	2,199	1,393	2,167	2,007	Other(2)	5,064	4,746	4,551	4,703	4,378	2,573
Total Rocky Mountain region	Total Rocky Mountain region	7,187	8,772	7,930	7,108	7,718	7,086	Total Rocky Mountain region	9,186	9,220	8,882	9,033	8,772	7,187
Total tertiary oil sales		31,468	33,452	36,861	33,328	33,494	32,880
Non-tertiary oil and gas sales
Total tertiary oil sales volumes								Total tertiary oil sales volumes	31,391	32,236	32,815	33,369	33,452	31,468
Non-tertiary oil and gas sales volumes								Non-tertiary oil and gas sales volumes
Gulf Coast region	Gulf Coast region							Gulf Coast region
Total Gulf Coast region	Total Gulf Coast region	3,621	3,415	4,173	3,805	3,728	3,523	Total Gulf Coast region	3,566	3,630	3,929	3,763	3,415	3,621
Rocky Mountain region	Rocky Mountain region							Rocky Mountain region
Cedar Creek Anticline	Cedar Creek Anticline	11,150	10,918	13,046	11,988	11,485	11,433	Cedar Creek Anticline	10,224	9,721	10,784	11,182	10,918	11,150
Other(2)		1,118	1,348	1,105	1,069	979	969
Other(3)								Other(3)	1,380	1,338	1,354	1,368	1,348	1,118
Total Rocky Mountain region	Total Rocky Mountain region	12,268	12,266	14,151	13,057	12,464	12,402	Total Rocky Mountain region	11,604	11,059	12,138	12,550	12,266	12,268
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
Total non-tertiary sales volumes								Total non-tertiary sales volumes	15,170	14,689	16,067	16,313	15,681	15,889

Total sales volumes								Total sales volumes	46,561	46,925	48,882	49,682	49,133	47,357

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

(2)Includes tertiary sales volumes related to our working interest positions in the Big Sand Draw and Beaver Creek EOR fields (collectively “Wind River Basin”) acquired on March 3, ~~2021.~~2021, as well as Salt Creek and Grieve fields.

(3)Includes non-tertiary sales ~~related to the March 2020 sale of 50% of our working interests in Webster, Thompson, Manvel,~~volumes from Wind River Basin, as well as Hartzog Draw and ~~East Hastings fields (the “Gulf Coast Working Interests Sale”).~~Bell Creek fields.

Total sales volumes during the second quarter of ~~2021~~2022 averaged ~~49,133~~46,561 BOE/d, including ~~33,452~~31,391 Bbls/d from tertiary properties and ~~15,681~~15,170 BOE/d from non-tertiary properties. This sales volume ~~represents an increase~~was relatively flat with first quarter of ~~1,776~~2022 sales volumes as sales volume increases at CCA, Wind River Basin (262 BOE/d ~~(4%~~increase) and Grieve fields (297 BOE/d increase) in the Rocky Mountain region were offset by declines across various fields, with the largest declines at Bell Creek and Oyster Bayou due to downtime related to compressor and workover activities. On a year-over-year basis, sales volumes decreased 2,572 BOE/d (5%) compared to sales levels in the ~~first~~second quarter of 2021 primarily attributable to low levels of capital investment and ~~a decrease~~development spending in recent years (excluding the new EOR development at CCA). We currently expect sales volumes during the third quarter of ~~1,057 BOE/d (2%) compared~~2022 to be consistent with the second quarter of ~~2020. The increase on a sequential-quarter basis was primarily attributable to our Wind River Basin acquisition in March 2021~~2022 and sales ~~from these properties~~volumes to increase during the ~~most recent quarter.~~fourth quarter of 2022, as a result of incremental production increases from development projects completed in the first half of the year.

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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.

Our sales volumes during the three and six months ended June 30, ~~2021~~2022 were 97% oil, consistent with our ~~97% and 98% oil~~ sales during the ~~same~~comparable prior-year periods.

Oil and Natural Gas Revenues

Our oil and natural gas revenues during the three and six months ended June 30, ~~2021~~2022 increased ~~158%~~60% and ~~53%~~62%, respectively, compared to these revenues for the same periods in ~~2020.~~2021. The changes in our oil and natural gas revenues are due ~~primarily~~ to higher realized commodity prices (excluding any impact of our commodity derivative contracts), ~~offset somewhat by changes in sales volumes,~~ as reflected in the following table:


		Three Months Ended				Six Months Ended					Three Months Ended				Six Months Ended
		June 30,				June 30,					June 30,				June 30,
		2021 vs. 2020				2021 vs. 2020					2022 vs. 2021				2022 vs. 2021
In thousands	In thousands	Increase (Decrease) in Revenues		Percentage Increase (Decrease) in Revenues		Increase (Decrease) in Revenues		Percentage Increase (Decrease) in Revenues		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:	Change in oil and natural gas revenues due to:									Change in oil and natural gas revenues due to:
Decrease in sales volumes	Decrease in sales volumes	$	(2,303)	(2)	%	$	(32,528)	(10)	%	Decrease in sales volumes	$	(14,799)	(5)	%	$	(16,191)	(3)	%
Increase in realized commodity prices	Increase in realized commodity prices	175,624		160	%	211,670		63	%	Increase in realized commodity prices	184,061		65	%	334,919		65	%
Total increase in oil and natural gas revenues	Total increase in oil and natural gas revenues	$	173,321	158	%	$	179,142	53	%	Total increase in oil and natural gas revenues	$	169,262	60	%	$	318,728	62	%

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~~2022 and ~~2020~~2021 and the three and six months ended June 30, ~~2021~~2022 and ~~2020:~~2021:

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


	Three Months Ended				Three Months Ended					Six Months Ended
	March 31,				June 30,				June 30,
	2022		2021		2022		2021			2022		2021
Average net realized prices
Oil price per Bbl	$	93.17	$	56.28	$	108.81	$	64.70		$	101.00	$	60.59
Natural gas price per Mcf	4.66		3.29		6.76		2.64			5.71		2.95
Price per BOE	91.14		55.24		106.67		63.23			98.92		59.33
Average NYMEX differentials
Gulf Coast region
Oil per Bbl	$	(1.37)	$	(1.37)	$	0.16	$	(1.13)		$	(0.72)	$	(1.23)
Natural gas per Mcf	0.16		0.68		0.02		(0.11)			0.01		0.30
Rocky Mountain region
Oil per Bbl	$	(1.38)	$	(1.80)	$	0.01	$	(1.59)		$	(0.59)	$	(1.54)
Natural gas per Mcf	0.08		0.49		(1.12)		(0.47)			(0.49)		(0.04)
Total Company
Oil per Bbl	$	(1.37)	$	(1.54)	$	0.09	$	(1.32)		$	(0.67)	$	(1.36)
Natural gas per Mcf	0.11		0.58		(0.71)		(0.33)			(0.31)		0.11

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

•Gulf Coast Region. Our average NYMEX oil differential in the Gulf Coast region was a positive $0.16 per Bbl during the second quarter of 2022, an improvement compared to a negative $1.13 per Bbl during the second quarter of 2021 ~~compared to a negative $3.59 per Bbl during the second quarter of 2020~~ and a negative $1.37 per Bbl during the first quarter of 2021. For both the first quarter of 2020 and for many years prior, our Gulf Coast region differentials were positive to NYMEX due to historically higher prices received for Gulf Coast crudes, such as Light Louisiana Sweet crude oil. As a result of the market disruptions, storage constraints and weak demand caused by the COVID-19 coronavirus (“COVID-19”) pandemic, these differentials weakened significantly during2022. During the second quarter of ~~2020~~2022, the Company

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Management’s Discussion and ~~have remained lower than historical values since April 2020.~~Analysis of Financial Condition and Results of Operations

modified certain of its sales contracts and benefited from improved pricing for its Gulf Coast grades relative to NYMEX WTI prices.

•Rocky Mountain Region. NYMEX oil differentials in the Rocky Mountain region ~~averaged~~were essentially flat with NYMEX WTI prices during the second quarter of 2022, compared to $1.59 ~~per Bbl and $4.68~~ per Bbl below NYMEX during the second ~~quarters~~quarter of 2021 and ~~2020, respectively, and $1.80~~$1.38 per Bbl below NYMEX during the first quarter of ~~2021.~~2022. Similar to our differentials in the Gulf Coast region, differentials in the Rocky Mountain region improved significantly during the second quarter of 2022 as regional demand for our Rockies crude was strong. Differentials in the Rocky Mountain region tend to fluctuate with regional supply and demand trends and can fluctuate significantly on a month-to-month basis due to weather, refinery or transportation issues, and Canadian and U.S. crude oil price index volatility.

CO2 Revenues and Expenses

We sell a portion of the CO2 ~~produced from Jackson Dome~~we own 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. CO2 sales and transportation fees were $12.6 million and $26.0 million during the three and six months ended June 30, 2022, respectively, compared to $10.1 million and $19.4 million during the three and six-month periods ended June 30, 2021, respectively. The increases from the prior-year periods were primarily due to new contracts and an increase in CO2 sales volumes.

Oil Marketing Revenues and ~~Expenses~~Purchases

~~From time to time,~~In certain situations, we ~~market third-party production for sale in exchange for a fee.~~purchase and subsequently sell oil from third parties. We recognize the revenue received and the associated expenses incurred on these ~~oil~~ sales on a gross basis as “Oil marketing ~~sales”~~revenues” and ~~the expenses incurred to market and transport the oil as~~ “Oil marketing ~~expenses”~~purchases” in our Unaudited Condensed Consolidated Statements of Operations.

Commodity Derivative Contracts

The following table summarizes the impact our crude oil derivative contracts had on our operating results for the three and six months ended June 30, ~~2021~~2022 and ~~2020:~~2021:


		Successor		Predecessor		Successor		Predecessor			Three Months Ended				Six Months Ended
											June 30,				June 30,
In thousands	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		In thousands	2022		2021		2022		2021
Receipt (payment) on settlements of commodity derivatives		$	(63,343)	$	45,629	$	(101,796)	$	70,267
Payment on settlements of commodity derivatives										Payment on settlements of commodity derivatives	$	(127,959)	$	(63,343)	$	(221,016)	$	(101,796)
Noncash fair value gains (losses) on commodity derivatives	Noncash fair value gains (losses) on commodity derivatives	(109,321)		(85,759)		(186,611)		36,374		Noncash fair value gains (losses) on commodity derivatives	71,105		(109,321)		(28,557)		(186,611)
Total income (expense)		$	(172,664)	$	(40,130)	$	(288,407)	$	106,641
Total expense										Total expense	$	(56,854)	$	(172,664)	$	(249,573)	$	(288,407)

Changes in our commodity derivatives expense ~~were primarily~~are related to the expiration of commodity derivative contracts, ~~new commodity derivative contracts entered into for future periods, and to the~~ changes in oil futures prices between the second ~~quarters~~quarter of ~~2020~~2021 and ~~2021. The period-to-period changes reflect~~2022, and new commodity derivative contract commitments for future periods. During the ~~very~~first half of 2022, we paid $221.0 million upon settlement of commodity derivative contracts, corresponding with the large ~~fluctuations~~increase in oil prices ~~between March 2020 ($30.45 per barrel), when worldwide financial markets were first beginning to absorb~~and the ~~potential impact of a global pandemic, and June 2021~~Company’s oil ~~prices ($71.35 per barrel) as prospects for increased economic activity and oil demand showed improvement.~~revenues during that same period.

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 ~~2022~~2023 using NYMEX fixed-price swaps and costless collars. See Note 6,7, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements for additional details of our outstanding commodity

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derivative contracts as of June 30, ~~2021,~~2022, and Item 3, Quantitative and Qualitative Disclosures about Market Risk below for additional discussion. In addition, the following table summarizes our commodity derivative contracts as of August ~~4, 2021:~~3, 2022:

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

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


		2H 2022	1H 2023	2H 2023
WTI NYMEX	Volumes Hedged (Bbls/d)	9,500	4,500	2,000
Fixed-Price Swaps	Weighted Average Swap Price	$57.52	$74.88	$76.80
WTI NYMEX	Volumes Hedged (Bbls/d)	11,500	17,500	9,000
Collars	Weighted Average Floor / Ceiling Price	$52.39 / $67.29	$69.71 / $100.42	$68.33 / $100.69
	Total Volumes Hedged (Bbls/d)	21,000	22,000	11,000

Based on current contracts in place and NYMEX oil futures prices as of August ~~4, 2021,~~3, 2022, which averaged approximately ~~$68~~$89 per Bbl, we currently expect that we would make cash payments of approximately ~~$145~~$115 million upon settlement of our July through December ~~2021~~2022 contracts, the amount of which is primarily dependent upon fluctuations in future NYMEX oil prices in relation to the prices of our ~~2021~~remaining 2022 fixed-price swaps which have a weighted average NYMEX oil price of ~~$43.69~~$57.52 per Bbl and weighted average ceiling prices of our 2022 collars of $67.29 per Bbl. Changes in commodity prices, expiration of contracts, and new commodity ~~contracts entered into~~contract commitments 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			Three Months Ended				Six Months Ended
											June 30,				June 30,
In thousands, except per-BOE data	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		In thousands, except per-BOE data	2022		2021		2022		2021
Total lease operating expenses	Total lease operating expenses	$	110,225	$	81,293	$	192,195	$	190,563	Total lease operating expenses	$	124,351	$	110,225	$	242,179	$	192,195

Total lease operating expenses per BOE	Total lease operating expenses per BOE	$	24.65	$	17.80	$	22.01	$	19.73	Total lease operating expenses per BOE	$	29.35	$	24.65	$	28.63	$	22.01

Total lease operating expenses increased ~~$28.9~~$14.1 million ~~(36%~~(13%) and ~~$1.6~~$50.0 million ~~(1%~~(26%) on an absolute-dollar basis, or ~~$6.85 (38%~~$4.70 (19%) and ~~$2.28 (12%~~$6.62 (30%) on a per-BOE basis, during the three and six months ended June 30, ~~2021,~~2022, respectively, compared to the same prior-year periods. The ~~increase during the second quarter of 2021~~increases 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~~per-BOE basis 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~~2022 were ~~relatively flat with the same prior-year period as increased expenses resulting from our Wind River Basin acquisition in March 2021 and~~primarily due to increases ~~in workover and CO~~2 ~~expense were largely offset by a $11.1~~of $6.5 million ~~reduction in power and fuel costs.~~ ~~The significant reduction~~ in power and fuel costs, $4.6 million in workovers, $2.8 million in labor costs, and $2.4 million in CO2 expense, partially offset by an insurance reimbursement totaling $6.7 million recorded for property damage costs incurred during 2013 at Delhi Field. The increase in lease operating expenses during the six months ended June 30, 2022 was ~~associated with~~further impacted by (a) a benefit of $16.3 million during the six months ended June 30, 2021 resulting from compensation under the Company’s power agreements for power interruption during the severe winter storm in February 2021 which ~~created widespread~~related to 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~~operations and (b) an additional $9.5 million of ~~these savings were included in “Trade and other receivables, net” and $3.7 million included in “Other assets” in~~expense as the 2022 period reflects an entire six month’s worth of lease operating expenses from our ~~Unaudited Condensed Consolidated Balance Sheets.~~March 2021 acquisition of Wind River Basin properties. Compared to the first quarter of ~~2021~~2022, lease operating expenses in the most recent quarter increased ~~$28.3~~$6.5 million ~~(34%~~(6%) on an absolute-dollar basis and ~~$5.42 (28%~~$1.45 (5%) 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 inhigher workover, ~~and~~labor costs, CO2 ~~expense.~~expense, and power and fuel costs, partially offset by the insurance reimbursement discussed above.

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~~Denbury Inc.~~

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

Transportation and Marketing Expenses

Transportation and marketing expenses primarily consist of amounts incurred relating to the transportation, marketing, and processing of oil and natural gas production. Transportation and marketing expenses were ~~$8.5~~$4.8 million and ~~$9.4~~$8.5 million for the three months ended June 30, ~~2021~~2022 and ~~2020,~~2021, respectively, and ~~$16.3~~$9.4 million and ~~$19.0~~$16.3 million for the six months ended June 30, ~~2021~~2022 and ~~2020,~~2021, respectively. The decreases ~~between~~during the most recent comparative three and six-month 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 expensechange in the ~~first quarter~~sales contracts of ~~2021 resulting from the full vesting~~certain 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.our production, which reduced our transportation expense.

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Denbury Inc.

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

Taxes Other Than Income

Taxes other than income includes production, ad valorem and franchise taxes. Taxes other than income increased $13.9 million (62%) and $26.4 million (64%) during the three and six months ended June 30, 2022, 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”)


	Three Months Ended				Six Months Ended
	June 30,				June 30,
In thousands, except per-BOE data and employees	2022		2021		2022		2021
Cash G&A costs	$	15,131	$	12,898	$	30,852	$	27,201
Stock-based compensation	4,104		2,552		7,075		20,232
G&A expense	$	19,235	$	15,450	$	37,927	$	47,433

G&A per BOE
Cash G&A costs	$	3.57	$	2.89	$	3.65	$	3.11
Stock-based compensation	0.97		0.57		0.83		2.32
G&A expenses	$	4.54	$	3.46	$	4.48	$	5.43

Employees as of period end	740		690

Our G&A expense on an absolute-dollar basis was $19.2 million during the three months ended June 30, 2022, an increase of $3.8 million from the same prior-year period, primarily due to higher employee-related costs ($1.6 million for stock-based compensation) and higher professional service fees. During the six months ended June 30, 2022, our G&A expense decreased $9.5 million, primarily due to a decrease in stock-based compensation as the six months ended June 30, 2021 included $15.3 million of stock-based compensation expense in the first quarter of 2021 resulting from the accelerated performance achievement and vesting of performance-based equity awards granted in late 2020, partially offset by higher employee-related costs and professional service fees.

Interest and Financing Expenses


															Three Months Ended						Six Months Ended
		Successor			Predecessor			Successor			Predecessor				June 30,						June 30,
In thousands, except per-BOE data and interest rates	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			In thousands, except per-BOE data and interest rates	2022			2021			2022			2021
Cash interest(1)	Cash interest(1)	$	1,735		$	45,263		$	3,669		$	91,089		Cash interest(1)	$	1,252		$	1,735		$	2,382		$	3,669
Less: interest not reflected as expense for financial reporting purposes(1)		—			(20,912)			—			(42,266)

Noncash interest expense	Noncash interest expense	685			1,061			1,370			2,092			Noncash interest expense	1,249			685			1,934			1,370
Amortization of debt discount(2)		—			3,934			—			7,829

Less: capitalized interest	Less: capitalized interest	(1,168)			(8,729)			(2,251)			(18,181)			Less: capitalized interest	(975)			(1,168)			(2,133)			(2,251)
Interest expense, net	Interest expense, net	$	1,252		$	20,617		$	2,788		$	40,563		Interest expense, net	$	1,526		$	1,252		$	2,183		$	2,788
Interest expense, net per BOE	Interest expense, net per BOE	$	0.28		$	4.51		$	0.32		$	4.20		Interest expense, net per BOE	$	0.36		$	0.28		$	0.26		$	0.32
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		%
Average debt principal outstanding														Average debt principal outstanding	$	29,088		$	107,542		$	31,669		$	121,392
Average cash interest rate(2)														Average cash interest rate(2)	6.0		%	4.2		%	5.7		%	4.1		%

(1)Cash interest during the Predecessor period 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 (the “2021 Notes”) and 9¼% Senior Secured Second Lien Notes due 2022 (the “2022 Notes”). Amounts related to the 2021 Notes and 2022 Notes remaining in future interest payable were written-off on July 30, 2020 (the “Petition Date”).

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

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

~~(4)Includes commitment fees~~Company’s bank credit facility but excludes debt issue ~~costs~~costs.

(2)Excludes commitment fees paid on the Company’s bank credit facility and ~~amortization of discount.~~debt issue costs.

Cash interest during the three and six months ended June 30, ~~2021~~2022 decreased ~~$43.5~~$0.5 million ~~(96%~~(28%) and ~~$87.4~~$1.3 million ~~(96%~~(35%)~~, respectively,~~ when compared to the same prior-year periods. The decreases between periods were primarily due to repayment of our pipeline financings in October 2021 and a decrease in the average ~~debt~~ principal outstanding ~~with the Successor periods reflecting the full extinguishment of all outstanding obligations under~~on 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 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.

bank credit facility. The

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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

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

~~The decreases~~increase in ~~DD&A~~noncash interest expense during the three and six months ended June 30, ~~2021,~~2022, compared to the same prior-year periods, was due to a write-off of debt issuance costs related to lenders who exited our senior secured bank credit facility in conjunction with our May 2022 amendment.

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
In thousands, except per-BOE data	2022		2021		2022		2021
Oil and natural gas properties	$	29,084	$	28,550	$	57,752	$	60,565
CO2 properties, pipelines, plants and other property and equipment	6,316		7,831		12,993		15,266

Total DD&A	$	35,400	$	36,381	$	70,745	$	75,831

DD&A per BOE
Oil and natural gas properties	$	6.86	$	6.39	$	6.83	$	6.94
CO2 properties, pipelines, plants and other property and equipment	1.49		1.75		1.53		1.74

Total DD&A cost per BOE	$	8.35	$	8.14	$	8.36	$	8.68

Write-down of oil and natural gas properties	$	—	$	—	$	—	$	14,377

The decrease in DD&A expense during the three months ended June 30, 2022, when compared to the same ~~periods~~period in ~~2020, were~~2021, was primarily due to lower ~~depletable costs~~depreciation on other fixed assets and CO2 sources, partially offset by higher accretion expense related to asset retirement obligations at our oil and gas properties. DD&A expense decreased $5.1 million during the six months ended June 30, 2022, when compared to the same prior-year period, primarily due to a lower depletion rate as a result of an increase in our estimate of proved reserves between 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~~periods based on higher commodity pricing and lower depreciation ~~of $37.4 million in the first quarter of 2020 related to unevaluated properties that were transferred to the full cost pool.~~on other fixed assets and CO2 sources.

First Quarter 2021 Full Cost Pool Ceiling Test ~~Write-Downs~~Write-Down

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. We recognized a full cost pool ceiling test write-down of $14.4 million during the three months ended March 31, ~~2021, with first-day-of-the-month NYMEX oil prices for the preceding 12 months averaging $36.40 per Bbl, after adjustments for market differentials and transportation expenses by field.~~2021. The write-down was primarily a result of the ~~recent acquisition (see~~ ~~Overview~~ – March 2021 ~~Acquisition~~acquisition of Wyoming CO2 EOR ~~Fields~~properties (see Note 2, Acquisition and Divestiture) which was recorded based on a valuation that utilized NYMEX strip oil prices at the acquisition date, which were significantly higher than the average first-day-of-the-month NYMEX oil prices used to value the cost ceiling. We ~~also recognized full cost pool ceiling test write-downs of $662.4 million and $72.5 million during the Predecessor three months ended June 30, 2020 and March 31, 2020, respectively. We~~ did not record a ceiling test write-down during the three or six months ended June 30, ~~2021.~~2022.

Other Expenses

Other expenses during the three and six months ended June 30, 2022 include a $3.9 million accrual for a preliminarily assessed civil penalty proposed by the Pipeline and Hazardous Materials Safety Administration of the U.S. Department of Transportation in a Notice of Probable Violation (see Item 1, Legal Proceedings – Notice of Probable Violation from Pipeline and Hazardous Materials Safety Administration (“PHMSA”) Regarding Delta-Tinsley CO2 Pipeline Failure). Other expenses totaled $3.2 million and $5.4 million during the three and six months ended June 30, 2021, respectively.

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Denbury Inc.

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

Income Taxes


		Successor			Predecessor			Successor				Predecessor				Three Months Ended							Six Months Ended
											June 30,								June 30,
In thousands, except per-BOE amounts and tax rates	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			In thousands, except per-BOE amounts and tax rates	2022				2021			2022			2021
Current income tax expense (benefit)	Current income tax expense (benefit)	$	(260)		$	598		$	(451)			$	(5,809)		Current income tax expense (benefit)	$	2,912			$	(260)		$	2,351		$	(451)
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)
Deferred income tax expense (benefit)															Deferred income tax expense (benefit)	21,936				(36)			15,992			(87)
Total income tax expense (benefit)															Total income tax expense (benefit)	$	24,848			$	(296)		$	18,343		$	(538)
Average income tax expense (benefit) per BOE															Average income tax expense (benefit) per BOE	$	5.87			$	(0.07)		$	2.17		$	(0.06)
Effective tax rate	Effective tax rate	0.4		%	12.7		%	0.4		%		15.3		%	Effective tax rate	13.8		%		0.4		%	10.6		%	0.4		%
Total net deferred tax liability	Total net deferred tax liability	$	1,187		$	306,186									Total net deferred tax liability	$	17,630			$	1,187

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 ~~2021~~2022 and ~~2020.~~2021. Our effective tax ~~rates~~rate for the ~~Successor~~ three and six months ended June 30, ~~2021 were~~2022 was significantly lower than our estimated statutory rate primarily due to the release of the valuation allowance that was recorded in the three and six months ended June 30, 2022. Our annualized effective tax rate for the year ended December 31, 2022 is currently estimated to be approximately 15%, as it includes the impact of the release of an additional $40.2 million of valuation allowances over the remaining two quarters of 2022. This rate could move higher or lower based on our ~~overall~~ultimate level of income.

We make estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Significant judgment is required in estimating valuation allowances, and in making this determination we consider all available positive and negative evidence and make certain assumptions. The realization of a deferred tax asset ~~position~~ultimately depends on the existence of sufficient taxable income in the applicable carryback or carryforward periods. In our assessment, we consider the nature, frequency, and severity of current and cumulative losses, as well as historical and forecasted financial results, the overall business environment, our industry’s historic cyclicality, the reversal of existing deferred tax assets and liabilities, and tax planning strategies.

We assess the valuation allowance ~~offsetting those assets. As we had~~recorded on our deferred tax assets, which was $125.5 million at December 31, 2021, on a ~~pre-tax loss for the second quarter of 2021 and first half of 2021, the income tax benefit resulting from these losses is fully offset by the change in~~quarterly basis. This valuation allowance ~~resulting~~on our federal and certain state deferred tax assets was recorded in ~~essentially no tax provision.~~

~~The~~September 2020 after the application of fresh start accounting, as (1) the tax basis of our assets, primarily our oil and gas properties, iswas in excess of ~~their~~the carrying value, as adjusted infor fresh start ~~accounting; therefore,~~accounting and (2) our historical pre-tax income reflected a three-year cumulative loss primarily due to ceiling test write-downs and reorganization items that were recorded in 2020. While we ~~are currently~~continued to be in a ~~net deferred tax asset position. Based on all available~~cumulative three-year-loss position during the first quarter of 2022, we initially determined, at that time, that there was sufficient positive evidence, ~~both positive~~primarily related to a substantial increase in worldwide oil prices, to conclude that $64.9 million of our federal and ~~negative, we continue to record a valuation allowance on our underlying deferred tax assets as of June 30, 2021, as we believe our~~certain state deferred tax assets are more likely than not ~~more-likely-than-not~~ to be realized. ~~We intend to maintain~~Accordingly, we reversed $5.9 million of this valuation allowance during the ~~valuation allowances on our deferred tax assets until there is sufficient evidence to support~~three months ended March 31, 2022, $18.8 million during the reversal of all or some portion of the allowances, which will largely be determined based on oil prices and the 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~~three months ended June 30, ~~2020, represent amounts estimated~~2022, and currently expect to ~~be receivable~~reverse the remaining $40.2 million during the second half of 2022, resulting ~~from alternative minimum~~in a reduction to our annualized effective tax ~~credits.~~rate. We will continue to maintain a valuation allowance of $60.6 million for certain state tax benefits that we currently do not expect to realize before their expiration.

As of June 30, ~~2021,~~2022, we had $0.6 million of alternative minimum tax credits, which under the Tax Cut and Jobs Act will be ~~refunded in 2021~~refundable by 2022 and are recorded as a receivable on the balance sheet. Our significant state net operating loss carryforwards expire in various years, starting in 2025.

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Denbury Inc.

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

Per-BOE Data

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


		Three Months Ended		Six Months Ended					Three Months Ended				Six Months Ended
		June 30,		June 30,					June 30,				June 30,
Per-BOE data	Per-BOE data	2021			2020		2021			2020		Per-BOE data	2022		2021		2022		2021
Oil and natural gas revenues	Oil and natural gas revenues	$	63.23		$	23.95	$	59.33		$	35.09	Oil and natural gas revenues	$	106.67	$	63.23	$	98.92	$	59.33
Receipt (payment) on settlements of commodity derivatives		(14.17)			9.99		(11.65)			7.28
Payment on settlements of commodity derivatives												Payment on settlements of commodity derivatives	(30.20)		(14.17)		(26.13)		(11.65)
Lease operating expenses	Lease operating expenses	(24.65)			(17.80)		(22.01)			(19.73)		Lease operating expenses	(29.35)		(24.65)		(28.63)		(22.01)
Production and ad valorem taxes	Production and ad valorem taxes	(4.88)			(1.92)		(4.55)			(2.77)		Production and ad valorem taxes	(8.40)		(4.88)		(7.80)		(4.55)
Transportation and marketing expenses	Transportation and marketing expenses	(1.91)			(2.06)		(1.87)			(1.97)		Transportation and marketing expenses	(1.13)		(1.91)		(1.12)		(1.87)
Production netback	Production netback	17.62			12.16		19.25			17.90		Production netback	37.59		17.62		35.24		19.25
CO2 sales, net of operating and discovery expenses	CO2 sales, net of operating and discovery expenses	1.93			1.23		1.93			1.33		CO2 sales, net of operating and discovery expenses	2.58		1.93		2.55		1.93
General and administrative expenses(1)	General and administrative expenses(1)	(3.46)			(5.21)		(5.43)			(3.47)		General and administrative expenses(1)	(4.54)		(3.46)		(4.48)		(5.43)
Interest expense, net	Interest expense, net	(0.28)			(4.51)		(0.32)			(4.20)		Interest expense, net	(0.36)		(0.28)		(0.26)		(0.32)

Stock compensation and other	Stock compensation and other	0.12			(1.71)		1.95			0.22		Stock compensation and other	(1.01)		0.12		(0.45)		1.95
Changes in assets and liabilities relating to operations	Changes in assets and liabilities relating to operations	4.40			0.44		(0.94)			(4.24)		Changes in assets and liabilities relating to operations	1.13		4.40		(4.22)		(0.94)
Cash flows from operations	Cash flows from operations	20.33			2.40		16.44			7.54		Cash flows from operations	35.39		20.33		28.38		16.44
DD&A – excluding accelerated depreciation charge		(8.14)			(12.13)		(8.68)			(11.89)
DD&A – accelerated depreciation charge(2)		—			—		—			(3.87)
DD&A												DD&A	(8.35)		(8.14)		(8.36)		(8.68)

Write-down of oil and natural gas properties	Write-down of oil and natural gas properties	—			(145.04)		(1.65)			(76.08)		Write-down of oil and natural gas properties	—		—		—		(1.65)
Deferred income taxes	Deferred income taxes	0.01			22.40		0.01			11.03		Deferred income taxes	(5.18)		0.01		(1.89)		0.01
Gain on extinguishment of debt		—			—		—			1.97

Noncash fair value gains (losses) on commodity derivatives	Noncash fair value gains (losses) on commodity derivatives	(24.45)			(18.78)		(21.37)			3.76		Noncash fair value gains (losses) on commodity derivatives	16.78		(24.45)		(3.37)		(21.37)

Other noncash items	Other noncash items	(5.13)			(1.56)		(1.62)			3.00		Other noncash items	(1.94)		(5.13)		3.52		(1.62)
Net loss		$	(17.38)		$	(152.71)	$	(16.87)		$	(64.54)
Net income (loss)												Net income (loss)	$	36.70	$	(17.38)	$	18.28	$	(16.87)

(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.~~

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, such as those related to our CCUS storage sites and related assets, 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, regarding possible or assumed future results of operations, ~~and~~ cash flows, production and capital expenditures, and other plans and objectives for the future operations of Denbury, projections or assumptions as to oil markets or general economic conditions ~~predictions as to~~and the ~~nature and~~ economics of a carbon capture, use and storage industry (“CCUS”), ~~and anticipated effects of COVID-19 on U.S. and global oil~~

~~Table of Contents~~

~~Denbury Inc.~~

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

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

Such forward-looking statements may be or may concern, among other things, the level and sustainability of ~~the~~ recent ~~recovery in~~higher worldwide oil ~~prices from their COVID-19 coronavirus caused downturn, financial forecasts,~~prices; the extent of future ~~hydrocarbon prices and their volatility,~~oil price volatility; current or future liquidity sources or their adequacy to support our

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Denbury Inc.

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

anticipated future ~~activities,~~activities; statements or predictions related to the ~~scope,~~ultimate timing and ~~economic aspects~~financial impact of ~~the~~our current or proposed carbon capture, use and storage ~~industry or results of negotiations of CCUS arrangements, possible future write-downs of~~arrangements; our projected production levels, oil and natural gas ~~reserves, together with assumptions based on current and projected production levels,~~revenues, oil and gas prices and oilfield costs, the impact of current supply chain and inflation on our results of operations; current or future expectations or estimations of our cash flows or the impact of changes in commodity prices on cash ~~flows,~~flows; availability, ~~of capital, borrowing capacity, price~~terms and ~~availability~~financial statement and cash settlement impact of ~~advantageous~~ commodity derivative contracts or ~~the~~their predicted downside cash flow ~~benefits therefrom,~~protection; 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,~~thereof; estimated timing of commencement of CO2 ~~flooding of~~injections in particular fields or areas, ~~including Cedar Creek Anticline (“CCA”),~~ or ~~its date of completion, timing of CO~~2 ~~injections and~~ initial production responses in tertiary flooding ~~projects,~~projects; other 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,~~place; the impact of ~~regulatory rulings~~changes or proposed changes in Federal or state tax or environmental laws or regulations; the outcomes of any 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 expendituresor regulatory proceedings; and overall ~~economics,~~ worldwide or U.S. 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,~~outcomes, 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, especially as oil prices are affected by the war in Ukraine, and ~~consequently in the prices received or demand for our oil produced;~~geopolitical and economic consequences of such war and resulting financial sanctions; decisions as to production levels and/or pricing by ~~OPEC+~~OPEC or ~~production levels by~~ U.S. ~~shale~~ producers in future periods; the impact of COVID-19 or other viral outbreaks on economic activity levels and ultimately oil prices; the pace and terms of ~~future capital expenditures;~~agreements reached with third parties for the capture, transportation, use and ultimate permanent sequestration of CO2; the timing and success of CCUS projects that, while undertaken by third parties, are related to our CCUS efforts; 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, climate events such as hurricanes, tropical storms, floods, forest fires, or other natural occurrences; ~~acquisition risks; requirements for capital or its availability;~~ conditions in the worldwide financial, trade currency 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,~~activities; and the ~~portions referenced above,~~risks and ~~the~~ uncertainties set forth from time to time in this or our other public reports, filings and public statements including, without limitation, the Company’s most recent Form 10-K.

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Denbury Inc.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

~~Debt and Interest Rate Sensitivity~~

As of June 30, 2021, we had $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 June 30, 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

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

Commodity Derivative Contracts

We enter into oil derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength, ~~and~~ expectation of future commodity ~~prices. In addition,~~prices, and occasionally requirements under our ~~new senior secured~~ bank credit ~~facility entered into on the Emergence Date required that, by December 31, 2020,~~facility. As of June 30, 2022, we do not 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~~any hedging requirements ~~as of December 31, 2020.~~under our Bank Credit Agreement. 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 ~~2022~~2023 using NYMEX fixed-price swaps and costless collars. Depending on market conditions, we may continue to add to our existing ~~2021~~2022 and ~~2022~~2023 hedges. See also Note 6, ~~Commodity Derivative Contracts~~Income Taxes, and Note 78, Fair Value Measurements, to the Unaudited Condensed Consolidated Financial Statements for additional information regarding our commodity derivative contracts.

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

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

At June 30, ~~2021,~~2022, the fair value of our commodity derivative contracts ~~were recorded at their fair value, which~~ was a net liability of ~~$245.4~~$163.1 million, a ~~$109.3~~$71.1 million ~~increase~~decrease from the ~~$136.1~~$234.2 million net liability recorded at March 31, ~~2021,~~2022 and a ~~$186.6~~$28.6 million increase from the ~~$58.8~~$134.5 million net liability recorded at December 31, ~~2020. These~~2021. The changes are primarily related to the expiration of commodity derivative contracts during the three and six months ended June 30, ~~2021, new commodity derivative contracts entered into during 2021 for future periods, and to the changes~~2022, increase in oil futures prices ~~from period to period.~~between December 31, 2021 and June 30, 2022, and new commodity derivative contract commitments during 2022 for future periods.

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~~Denbury Inc.~~

Commodity Derivative Sensitivity Analysis

Based on NYMEX crude oil futures prices and derivative contracts in place as of June 30, ~~2021,~~2022, and assuming both a 10% increase and decrease thereon, we would expect to make payments on our crude oil derivative contracts ~~outstanding at June 30, 2021~~ as shown in the following table:


In thousands	Receipt / (Payment)
~~In thousands~~	~~Crude Oil Derivative Contracts~~
Based on:
Futures prices as of June 30, ~~2021~~2022	$	~~(234,002)~~(156,344)
10% increase in prices	~~(326,894)~~(216,621)
10% decrease in prices	~~(152,780)~~(102,227)

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

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, ~~2021,~~2022, to ensure that information that is required to be disclosed in the reports the Company files and submits under the Securities Exchange Act of 1934 is recorded, that it is processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and that information that is required to be disclosed under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

Evaluation of Changes in Internal Control over Financial Reporting. Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we have determined that, during the second quarter of fiscal ~~2021,~~2022, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our financial position, results of operations or cash flows, litigation and regulatory proceedings are subject to inherent uncertainties. We accrue for losses from litigation and claims if we determine that a loss is probable and the amount can be reasonably estimated.

~~The information under Note 8,~~

Notice of Probable Violation from Pipeline and Hazardous Materials Safety Administration (“PHMSA”) Regarding Delta-Tinsley CO~~Commitments~~2 Pipeline Failure

On May 26, 2022, the PHMSA of the U.S. Department of Transportation issued a Notice of Probable Violation, Proposed Civil Penalty, and ~~Contingencies~~,Proposed Compliance Order (“NOPV”) relating to the ~~Unaudited Condensed Consolidated Financial Statements is incorporated herein by reference.~~February 2020 pipeline failure near Satartia, Mississippi in our CO2 pipeline running between the Tinsley and Delhi fields. The NOPV proposes a preliminarily assessed civil penalty of $3.9 million in connection with the incident, which we accrued during the second quarter of 2022. We have responded to the NOPV and are pursuing discussions with PHMSA regarding the probable violations alleged in the NOPV, the proposed civil penalty, and the nature of the compliance order contained in the NOPV.

Item 1A. Risk Factors

Please refer to Part I, Item 1A of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, ~~2020.~~2021. There have been no material changes to our risk factors contained in our Annual Report on Form 10-K for the year ended December 31, ~~2020.~~2021.

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

~~None.~~Issuer Purchases of Equity Securities

The following table summarizes purchases of our common stock during the second quarter of 2022:


Month	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans of Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (in millions)(1)
April 2022	—	$	—	—	$	—
May 2022	—	—		—	250.0
June 2022	—	—		457,549	221.2
Total	—			457,549

(1)In early May 2022, our Board of Directors approved a common share repurchase program authorizing repurchase of up to an aggregate of $250.0 million of Denbury common shares. The program has no pre-established ending date and may be suspended or discontinued at any time. We are not obligated to repurchase any dollar amount or specific number of shares of our common stock under the program.

An aggregate of 1,615,356 shares of Denbury common stock (approximately 3.2% of our outstanding shares of common stock at March 31, 2022) were repurchased during this program through July 31, 2022 for $100.0 million. As of August 2, 2022, an additional $250.0 million remains authorized for purchases of common stock under this repurchase program.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

None.

Item 5. Other Information

None.

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Item 6. Exhibits


Exhibit No.						Exhibit
10(a)						Denbury Inc. Employee Stock Purchase Plan (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on June 6, 2022, 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
104						The cover page from the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, ~~2021,~~2022, has been formatted in Inline XBRL.

* Included herewith.

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

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SIGNATURES

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


						DENBURY INC.

August ~~5, 2021~~4, 2022						/s/ Mark C. Allen
						Mark C. Allen Executive Vice President and Chief Financial Officer

August ~~5, 2021~~4, 2022						/s/ Nicole Jennings
						Nicole Jennings Vice President and Chief Accounting Officer

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		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