DENBURY INC - Quarter Report: 2020 September (Form 10-Q)

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 September 30, 2020

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

For the transition period from _______ to ________

Commission file number: 001-12935

DENBURY 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,	TX	75024
(Address of principal executive offices)		(Zip Code)



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

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



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

The number of shares outstanding of the registrant’s Common Stock, $.001 par value, as of October 31, 2020, was 49,999,999.

Denbury Inc.

Table of Contents




		Page

	PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements
	Unaudited Condensed Consolidated Balance Sheets	3
	Unaudited Condensed Consolidated Statements of Operations	5
	Unaudited Condensed Consolidated Statements of Cash Flows	7
	Unaudited Condensed Consolidated Statements of Changes in Stockholders’ Equity	8
	Notes to Unaudited Condensed Consolidated Financial Statements	10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	61
Item 4.	Controls and Procedures	63

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	64
Item 1A.	Risk Factors	64
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	66
Item 3.	Defaults Upon Senior Securities	66
Item 4.	Mine Safety Disclosures	66
Item 5.	Other Information	66
Item 6.	Exhibits	67
	Signatures	69

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Denbury Inc.

Unaudited Condensed Consolidated Balance Sheets

(In thousands, except par value and share data)



	Successor			Predecessor
	September 30, 2020			December 31, 2019
Assets
Current assets
Cash and cash equivalents	$	21,860		$	516
Restricted cash	10,662			—
Accrued production receivable	74,296			139,407
Trade and other receivables, net	34,788			18,318
Derivative assets	26,778			11,936
Other current assets	11,730			10,434
Total current assets	180,114			180,611
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved properties	796,687			11,447,680
Unevaluated properties	98,656			872,910
CO₂ properties	187,397			1,198,846
Pipelines	132,669			2,329,078
Other property and equipment	97,770			212,334
Less accumulated depletion, depreciation, amortization and impairment	(4,446		)	(11,688,020		)
Net property and equipment	1,308,733			4,372,828
Operating lease right-of-use assets	1,225			34,099
Derivative assets	1,147			—
Intangible assets, net	99,655			22,139
Other assets	86,996			82,190
Total assets	$	1,677,870		$	4,691,867

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Denbury Inc.

Unaudited Condensed Consolidated Balance Sheets (continued)

(In thousands, except par value and share data)



	Successor		Predecessor
	September 30, 2020		December 31, 2019
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	166,385	$	183,832
Oil and gas production payable	45,013		62,869
Derivative liabilities	5,739		8,346
Current maturities of long-term debt (including future interest payable of $0 and $86,054, respectively – see Note 6)	73,511		102,294
Operating lease liabilities	763		6,901
Total current liabilities	291,411		364,242
Long-term liabilities
Long-term debt, net of current portion (including future interest payable of $0 and $78,860, respectively – see Note 6)	102,456		2,232,570
Asset retirement obligations	158,757		177,108
Derivative liabilities	584		—
Deferred tax liabilities, net	3,836		410,230
Operating lease liabilities	463		41,932
Other liabilities	22,186		53,526
Total long-term liabilities	288,282		2,915,366
Commitments and contingencies (Note 12)
Stockholders’ equity
Predecessor preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding	—		—
Predecessor common stock, $.001 par value, 750,000,000 shares authorized; 508,065,495 shares issued	—		508
Predecessor paid-in capital in excess of par	—		2,739,099
Predecessor treasury stock, at cost, 1,652,771 shares	—		(6,034		)
Successor preferred stock, $.001 par value, 50,000,000 shares authorized, none issued and outstanding	—		—
Successor common stock, $.001 par value, 250,000,000 shares authorized; 49,999,999 shares issued	50		—
Successor paid-in-capital in excess of par	1,095,369		—
Retained earnings (accumulated deficit)	2,758		(1,321,314		)
Total stockholders’ equity	1,098,177		1,412,259
Total liabilities and stockholders’ equity	$	1,677,870	$	4,691,867

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Denbury Inc.

Unaudited Condensed Consolidated Statements of Operations

(In thousands, except per share data)



	Successor			Predecessor
	Period from Sept. 19, 2020 through			Period from July 1, 2020 through			Three Months Ended
	Sept. 30, 2020			Sept. 18, 2020			Sept. 30, 2019
Revenues and other income
Oil, natural gas, and related product sales	$	22,321		$	153,090		$	293,192
CO₂sales and transportation fees	967			6,517			8,976
Oil marketing sales	151			3,332			5,468
Other income	94			7,097			7,817
Total revenues and other income	23,533			170,036			315,453
Expenses
Lease operating expenses	11,484			59,708			117,850
Transportation and marketing expenses	1,344			8,155			10,067
CO₂ operating and discovery expenses	242			955			879
Taxes other than income	2,073			13,473			22,010
Oil marketing expenses	139			3,288			5,436
General and administrative expenses	1,735			15,013			18,266
Interest, net of amounts capitalized of $183, $4,704 and $8,773, respectively	334			7,704			22,858
Depletion, depreciation, and amortization	5,283			36,317			55,064
Commodity derivatives expense (income)	(4,035		)	4,609			(43,155		)
Gain on debt extinguishment	—			—			(5,874		)
Write-down of oil and natural gas properties	—			261,677			—
Reorganization items, net	—			849,980			—
Other expenses	2,164			22,084			2,140
Total expenses	20,763			1,282,963			205,541
Income (loss) before income taxes	2,770			(1,112,927		)	109,912
Income tax provision (benefit)	12			(303,807		)	37,050
Net income (loss)	$	2,758		$	(809,120	)	$	72,862

Net income (loss) per common share
Basic	$	0.06		$	(1.63	)	$	0.16
Diluted	$	0.06		$	(1.63	)	$	0.14

Weighted average common shares outstanding
Basic	50,000			497,398			455,487
Diluted	50,000			497,398			547,205

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Denbury Inc.

Unaudited Condensed Consolidated Statements of Operations

(In thousands, except per share data)



	Successor			Predecessor
	Period from Sept. 19, 2020 through			Period from Jan. 1, 2020 through			Nine Months Ended
	Sept. 30, 2020			Sept. 18, 2020			Sept. 30, 2019
Revenues and other income
Oil, natural gas, and related product sales	$	22,321		$	492,101		$	918,190
CO₂sales and transportation fees	967			21,049			25,532
Oil marketing sales	151			8,543			8,274
Other income	94			8,419			12,274
Total revenues and other income	23,533			530,112			964,270
Expenses
Lease operating expenses	11,484			250,271			361,205
Transportation and marketing expenses	1,344			27,164			32,076
CO₂ operating and discovery expenses	242			2,592			2,016
Taxes other than income	2,073			43,531			71,312
Oil marketing expenses	139			8,399			8,213
General and administrative expenses	1,735			48,522			54,697
Interest, net of amounts capitalized of $183, $22,885 and $27,545, respectively	334			48,267			60,672
Depletion, depreciation, and amortization	5,283			188,593			170,625
Commodity derivatives expense (income)	(4,035		)	(102,032		)	15,462
Gain on debt extinguishment	—			(18,994		)	(106,220		)
Write-down of oil and natural gas properties	—			996,658			—
Reorganization items, net	—			849,980			—
Other expenses	2,164			35,868			8,664
Total expenses	20,763			2,378,819			678,722
Income (loss) before income taxes	2,770			(1,848,707		)	285,548
Income tax provision (benefit)	12			(416,129		)	91,668
Net income (loss)	$	2,758		$	(1,432,578	)	$	193,880

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

Weighted average common shares outstanding
Basic	50,000			495,560			453,287
Diluted	50,000			495,560			490,054

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Denbury Inc.

Unaudited Condensed Consolidated Statements of Cash Flows

(In thousands)



	Successor			Predecessor
	Period from Sept. 19, 2020 through			Period from Jan. 1, 2020 through			Nine Months Ended
	Sept. 30, 2020			Sept. 18, 2020			Sept. 30, 2019
Cash flows from operating activities
Net income (loss)	$	2,758		$	(1,432,578	)	$	193,880
Adjustments to reconcile net income (loss) to cash flows from operating activities
Noncash reorganization items, net	—			810,909			—
Depletion, depreciation, and amortization	5,283			188,593			170,625
Write-down of oil and natural gas properties	—			996,658			—
Deferred income taxes	6			(408,869		)	90,454
Stock-based compensation	—			4,111			9,866
Commodity derivatives expense (income)	(4,035		)	(102,032		)	15,462
Receipt on settlements of commodity derivatives	6,660			81,396			14,714
Gain on debt extinguishment	—			(18,994		)	(106,220		)
Debt issuance costs and discounts	114			11,571			7,607
Other, net	589			439			(6,862		)
Changes in assets and liabilities, net of effects from acquisitions
Accrued production receivable	38,537			26,575			(1,428		)
Trade and other receivables	1,366			(22,343		)	(147		)
Other current and long-term assets	705			743			27
Accounts payable and accrued liabilities	(7,980		)	(16,102		)	(33,167		)
Oil and natural gas production payable	(11,064		)	(6,792		)	(1,819		)
Other liabilities	(29		)	123			(9,414		)
Net cash provided by operating activities	32,910			113,408			343,578

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

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

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Denbury Inc.

Unaudited Condensed Consolidated Statements of Changes in Stockholders' Equity

(Dollar amounts in thousands)



	Common Stock ($.001 Par Value)					Paid-In Capital in Excess of Par			Retained Earnings (Accumulated Deficit)			Treasury Stock (at cost)
	Shares		Amount			Paid-In Capital in Excess of Par			Retained Earnings (Accumulated Deficit)			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

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Denbury Inc.

Unaudited Condensed Consolidated Statements of Changes in Stockholders' Equity

(Dollar amounts in thousands)



	Common Stock ($.001 Par Value)			Paid-In Capital in Excess of Par			Retained Earnings (Accumulated Deficit)			Treasury Stock (at cost)
	Shares	Amount		Paid-In Capital in Excess of Par			Retained Earnings (Accumulated Deficit)			Shares	Amount			Total Equity
Balance – December 31, 2018 (Predecessor)	462,355,725	$	462	$	2,685,211		$	(1,533,112	)	1,941,749	$	(10,784	)	$	1,141,777
Issued pursuant to stock compensation plans	1,331,050	2		—			—			—	—			2
Issued pursuant to directors’ compensation plan	41,487	—		—			—			—	—			—
Stock-based compensation	—	—		4,306			—			—	—			4,306
Tax withholding for stock compensation plans	—	—		—			—			531,494	(1,091		)	(1,091		)
Net loss	—	—		—			(25,674		)	—	—			(25,674		)
Balance – March 31, 2019 (Predecessor)	463,728,262	464		2,689,517			(1,558,786		)	2,473,243	(11,875		)	1,119,320
Issued pursuant to stock compensation plans	400,850	—		—			—			—	—			—
Issued pursuant to directors’ compensation plan	37,367	—		—			—			—	—			—
Stock-based compensation	—	—		4,667			—			—	—			4,667
Tax withholding for stock compensation plans	—	—		—			—			1,661	(3		)	(3		)
Net income	—	—		—			146,692			—	—			146,692
Balance – June 30, 2019 (Predecessor)	464,166,479	464		2,694,184			(1,412,094		)	2,474,904	(11,878		)	1,270,676
Issued pursuant to stock compensation plans	9,046,748	9		(9		)	—			—	—			—
Stock-based compensation	—	—		3,983			—			—	—			3,983
Tax withholding for stock compensation plans	—	—		—			—			1,145,881	(1,401		)	(1,401		)
Net income	—	—		—			72,862			—	—			72,862
Balance – September 30, 2019 (Predecessor)	473,213,227	$	473	$	2,698,158		$	(1,339,232	)	3,620,785	$	(13,279	)	$	1,346,120

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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

As further described in Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code below, Denbury Inc. became the successor reporting company of Denbury Resources Inc. (the “Predecessor”) upon the Predecessor’s emergence from bankruptcy on September 18, 2020. References to “Successor” relate to the financial position and results of operations of the Company subsequent to September 18, 2020, and references to “Predecessor” relate to the financial position and results of operations of the Company prior to, and including, September 18, 2020. On September 18, 2020, Denbury filed the Third Restated Certificate of Incorporation with the Delaware Secretary of State to effect a change of the Company’s corporate name from Denbury Resources Inc. to Denbury Inc., and on September 21, 2020, the Successor’s new common stock commenced trading on the New York Stock Exchange under the ticker symbol DEN.

Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code

On July 28, 2020, Denbury Resources Inc. and its subsidiaries entered into a Restructuring Support Agreement (the “RSA”) with lenders holding 100% of the revolving loans under our pre-petition revolving bank credit facility and debtholders holding approximately 67.1% of our senior secured second lien notes and approximately 73.1% of our convertible senior notes, which contemplated a restructuring of the Company pursuant to a prepackaged joint plan of reorganization (the “Plan”). On July 30, 2020 (the “Petition Date”), Denbury Resources Inc. and its subsidiaries filed petitions for reorganization in a “prepackaged” voluntary bankruptcy (the “Chapter 11 Restructuring”) under chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”) under the caption “In re Denbury Resources Inc., et al., Case No. 20-33801”. On September 2, 2020, the Bankruptcy Court entered an order (the “Confirmation Order”) confirming the Plan and approving the Disclosure Statement, and on September 18, 2020 (the “Emergence Date”), the Plan became effective in accordance with its terms and the Company emerged from Chapter 11. On the Emergence Date and pursuant to the terms of the Plan and the Confirmation Order, all outstanding obligations under the senior secured second lien notes, convertible senior notes, and senior subordinated notes were fully extinguished, relieving approximately $2.1 billion of debt by issuing equity and/or warrants in the Successor to the former holders of that debt, and the Company:


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


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


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


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

◦

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


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

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements


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


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


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


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


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


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

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


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


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

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

Interim Financial Statements

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

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end, and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year. In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair statement of our consolidated financial position as of September 30, 2020 (Successor) and December 31, 2019 (Predecessor); our consolidated results of operations and consolidated statements of changes in stockholders’ equity for the periods September 19, 2020 through September 30, 2020 (Successor), for the period July 1, 2020

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

through September 18, 2020 (Predecessor) and January 1, 2020 through September 18, 2020 (Predecessor), and for the three and nine months ended September 30, 2019 (Predecessor); and our consolidated cash flows for the period September 19, 2020 through September 30, 2020 (Successor), for the period January 1, 2020 through September 18, 2020 (Predecessor) and for the nine months ended September 30, 2019 (Predecessor). Upon the adoption of fresh start accounting, the Company’s assets and liabilities were recorded at their fair values as of the fresh start reporting date (see Note 2, Fresh Start Accounting). As a result of the adoption of fresh start accounting, certain values and operational results of the Company’s condensed consolidated financial statements subsequent to September 18, 2020 are not comparable to those in its condensed consolidated financial statements prior to, and including September 18, 2020, and as such, “black-line” financial statements are presented to distinguish between the Predecessor and Successor companies.

Risks and Uncertainties

In March 2020, the World Health Organization declared the ongoing COVID-19 coronavirus (“COVID-19”) outbreak a pandemic, and the President of the United States declared the COVID-19 pandemic a national emergency. The COVID-19 pandemic has caused a rapid and precipitous drop in oil demand, which worsened an already deteriorated oil market that followed the early-March 2020 failure by the group of oil producing nations known as OPEC+ to reach an agreement over proposed oil production cuts. Although OPEC+ subsequently agreed to reduced levels of production output, concerns about the ability of OPEC+ to maintain compliance with their reduced production targets and uncertainty about the duration of the COVID-19 pandemic and its resulting economic consequences has resulted in abnormally high worldwide inventories of produced oil. While oil prices have improved from the low points experienced during the second quarter of 2020, the concerns and uncertainties around the balance of supply and demand for oil are expected to continue for some time. Because the realized oil prices we have received since early March 2020 have been significantly reduced, our operating cash flow and liquidity have been adversely affected.

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

Restricted cash, current in the table above represents restricted escrow funds maintained by the Successor as required by certain contractual arrangements in accordance with the Plan. Other restricted cash amounts represent 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.

Net Income (Loss) per Common Share

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

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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



	Successor		Predecessor
	Period from Sept. 19, 2020 through		Period from July 1, 2020 through			Three Months Ended
In thousands	Sept. 30, 2020		Sept. 18, 2020			Sept. 30, 2019
Numerator
Net income (loss) – basic	$	2,758	$	(809,120	)	$	72,862
Effect of potentially dilutive securities
Interest on convertible senior notes including amortization of discount, net of tax	—		—			5,101
Net income (loss) – diluted	$	2,758	$	(809,120	)	$	77,963

Denominator
Weighted average common shares outstanding – basic	50,000		497,398			455,487
Effect of potentially dilutive securities
Restricted stock and performance-based equity awards	—		—			865
Convertible senior notes⁽¹⁾	—		—			90,853
Weighted average common shares outstanding – diluted	50,000		497,398			547,205



	Successor		Predecessor
	Period from Sept. 19, 2020 through		Period from Jan. 1, 2020 through			Nine Months Ended
In thousands	Sept. 30, 2020		Sept. 18, 2020			Sept. 30, 2019
Numerator
Net income (loss) – basic	$	2,758	$	(1,432,578	)	$	193,880
Effect of potentially dilutive securities
Interest on convertible senior notes including amortization of discount, net of tax	—		—			5,649
Net income (loss) – diluted	$	2,758	$	(1,432,578	)	$	199,529

Denominator
Weighted average common shares outstanding – basic	50,000		495,560			453,287
Effect of potentially dilutive securities
Restricted stock and performance-based equity awards	—		—			2,489
Convertible senior notes⁽¹⁾	—		—			34,278
Weighted average common shares outstanding – diluted	50,000		495,560			490,054


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

Time-vesting restricted stock is included in basic weighted average common shares from the vesting date (although time-vesting restricted stock is issued and outstanding upon grant). For purposes of calculating diluted weighted average common shares for the three and nine months ended September 30, 2019, the nonvested restricted stock and performance-based equity

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

awards are included in the computation using the treasury stock method, with the deemed proceeds equal to the average unrecognized compensation during the period, and for the shares underlying the convertible senior notes as if the convertible senior notes were converted at the beginning of 2019.

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



	Successor	Predecessor
	Period from Sept. 19, 2020 through	Period from July 1, 2020 through	Three Months Ended
In thousands	Sept. 30, 2020	Sept. 18, 2020	Sept. 30, 2019
Stock appreciation rights	—	—	2,011
Restricted stock and performance-based equity awards	—	165	7,996
Convertible senior notes	—	82,445	—
Warrants⁽¹⁾	5,526	—	—



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


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

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. Given the significant declines in NYMEX oil prices in March and April 2020 due to the oil supply and demand imbalance precipitated by the dramatic fall in demand associated with the COVID-19 pandemic combined with the concurrent OPEC+ decision to increase oil supply, we reassessed our development plans and recognized an impairment of $244.9 million of our unevaluated costs during the three months ended March 31, 2020 (Predecessor), whereby these costs were transferred to the full cost amortization base. Upon emergence from bankruptcy, the Company adopted fresh start accounting which resulted in our oil and natural gas properties, including unevaluated properties, being recorded at their fair values at the Emergence Date (see Note 2, Fresh Start Accounting, for additional information).

Write-Down of Oil and Natural Gas Properties. The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as (1) the present value of estimated future net revenues from proved oil and natural gas reserves before future abandonment costs (discounted at 10%), based on the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects. Our future net revenues from proved oil and natural gas reserves are not reduced for development costs related to the cost of drilling for and developing

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

CO₂ reserves nor those related to the cost of constructing CO₂ pipelines, as we do not have to incur additional costs to develop the proved oil and natural gas reserves. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO₂ costs related to CO₂ reserves and CO₂ pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes. The cost center ceiling test is prepared quarterly and was also prepared as of the Emergence Date.

The Predecessor recognized full cost pool ceiling test write-downs of $261.7 million during the period from July 1, 2020 through September 18, 2020, $662.4 million during the three months ended June 30, 2020, and $72.5 million during the three months ended March 31, 2020. There was no full cost pool ceiling test write-down for the Successor period from September 19, 2020 through September 30, 2020. The first-day-of-the-month oil prices for the preceding 12 months, after adjustments for market differentials by field, averaged $40.08 per Bbl as of September 18, 2020, $44.74 per Bbl as of June 30, 2020, and $55.17 per Bbl as of March 31, 2020. In addition, the first-day-of-the-month natural gas prices for the preceding 12 months, after adjustments for market differentials by field, averaged $1.72 per MMBtu as of September 18, 2020, $1.91 per MMBtu as of June 30, 2020, and $1.68 per MMBtu as of March 31, 2020.

Impairment Assessment of Long-Lived Assets

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

We perform our long-lived asset impairment test by comparing the net carrying costs of our two long-lived asset groups to the respective expected future undiscounted net cash flows that are supported by these long-lived assets which include production of our probable and possible oil and natural gas reserves. The portion of our capitalized CO₂ costs related to CO₂ reserves and CO₂ pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves is included in the full cost pool ceiling test as a reduction to future net revenues. The remaining net capitalized costs that are not included in the full cost pool ceiling test, and related intangible assets, are subject to long-lived asset impairment testing. These costs totaled approximately $1.3 billion as of March 31, 2020 (Predecessor). If the undiscounted net cash flows are below the net carrying costs for an asset group, we must record an impairment loss by the amount, if any, that net carrying costs exceed the fair value of the long-lived asset group. The undiscounted net cash flows for our asset groups exceeded the net carrying costs; thus, step two of the impairment test was not required and no impairment was recorded.

Significant assumptions impacting expected future undiscounted net cash flows include projections of future oil and natural gas prices, projections of estimated quantities of oil and natural gas reserves, projections of future rates of production, timing and amount of future development and operating costs, projected availability and cost of CO₂, projected recovery factors of tertiary reserves and risk-adjustment factors applied to the cash flows. We performed a qualitative assessment as of June 30, 2020 and September 18, 2020 (Predecessor periods) and determined there were no material changes to our key cash flow assumptions and no triggering events since the analysis performed as of March 31, 2020; therefore, no impairment test was performed for the second quarter of 2020 or for the period ending September 18, 2020. Upon emergence from bankruptcy, the Company adopted fresh start accounting which resulted in our long-lived assets being recorded at their fair value at the Emergence Date (see Note 2, Fresh Start Accounting, for additional information).

Recent Accounting Pronouncements

Recently Adopted

Financial Instruments – Credit Losses. In June 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-13, Financial Instruments – Credit Losses (“ASU 2016-13”). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires the use of a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. Effective January 1, 2020, we adopted ASU 2016-13. The implementation of this standard did not have a material impact on our consolidated financial statements.

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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

Not Yet Adopted

Income Taxes. In December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes (“ASU 2019-12”). The objective of ASU 2019-12 is to simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740 and to provide more consistent application to improve the comparability of financial statements. The amendments in this ASU are effective for fiscal years beginning after December 15, 2020, and early adoption is permitted. We are currently evaluating the impact this guidance may have on our consolidated financial statements and related footnote disclosures.

Note 2. Fresh Start Accounting

Fresh Start Accounting

Upon emergence from bankruptcy, we met the criteria and were required to adopt fresh start accounting in accordance with FASC Topic 852, Reorganizations, which on the Emergence Date resulted in a new entity, the Successor, for financial reporting purposes, with no beginning retained earnings or deficit as of the fresh start reporting date. The criteria requiring fresh start accounting are: (1) the holders of the then-existing common shares of the Predecessor received less than 50 percent of the new common shares of the Successor outstanding upon emergence from bankruptcy and (2) the reorganization value of the Company’s assets immediately prior to confirmation of the Plan was less than the total of all post-petition liabilities and allowed claims.

Reorganization Value

The reorganization value derived from the range of enterprise values associated with the Plan was allocated to the Company’s identifiable tangible and intangible assets and liabilities based on their fair values. Under FASC Topic 852, reorganization value generally approximates the fair value of the entity before considering liabilities and is intended to approximate the amount a willing buyer would pay for the assets immediately after the effects of the restructuring. The value of the reconstituted entity (i.e., Successor) was based on management projections and the valuation models as determined by the Company’s financial advisors in setting an estimated range of enterprise values. As set forth in the Plan and Disclosure Statement approved by the Bankruptcy Court, the valuation analysis resulted in an enterprise value between $1.1 billion and $1.5 billion, with a mid-point of $1.3 billion. For U.S. GAAP purposes, we valued the Successor’s individual assets, liabilities, and equity instruments and determined the value of the enterprise was approximately $1.3 billion as of the Emergence Date, which fell in line with the mid-point of the forecast enterprise value ranges approved by the Bankruptcy Court. Specific valuation approaches and key assumptions used to arrive at reorganization value, and the value of discrete assets and liabilities resulting from the application of fresh start accounting, are described below in greater detail within the valuation process.

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

The following table reconciles the enterprise value to the equity value of the Successor as of the Emergence Date:



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

The following table reconciles enterprise value to reorganization value of the Successor (i.e., value of the reconstituted entity) and total reorganization value:



In thousands	Sept. 18, 2020
Enterprise value	$	1,280,856
Plus: Cash and cash equivalents	45,585
Plus: Current liabilities excluding current maturities of long-term debt	239,738
Plus: Non-interest bearing noncurrent liabilities	185,228
Reorganization value of the reconstituted Successor	$	1,751,407

With the assistance of third-party valuation advisors, we determined the enterprise and corresponding equity value of the Successor using various valuation approaches and methods, including: (i) income approach using a calculation of the present value of future cash flows based on our financial projections, (ii) the market approach using selling prices of similar assets and (iii) the cost approach.

The enterprise value and corresponding equity value are dependent upon achieving the future financial results set forth in our valuation using an asset-based methodology of estimated proved reserves, undeveloped properties, and other financial information, considerations and projections, applying a combination of the income, cost and market approaches as of the fresh start reporting date of September 18, 2020. All estimates, assumptions, valuations and financial projections, including the fair value adjustments, the financial projections, the enterprise value and equity value projections, are inherently subject to significant uncertainties and the resolution of contingencies beyond our control. Accordingly, there is no assurance that the estimates, assumptions, valuations or financial projections will be realized, and actual results could vary materially, including variances when presented in our upcoming Form 10-K report for the year ended December 31, 2020.

Reorganization Items, Net

Reorganization items represent (i) expenses incurred during the Chapter 11 Restructuring subsequent to the Petition Date as a direct result of the Plan, (ii) gains or losses from liabilities settled and (iii) fresh start accounting adjustments and are recorded in “Reorganization items, net” in our Unaudited Condensed Consolidated Statements of Operations. Professional service provider charges associated with our restructuring that were incurred before the Petition Date and after the Emergence Date are recorded in “Other expenses” in our Unaudited Condensed Consolidated Statements of Operations. Contractual interest expense of $22.0 million from the Petition Date through the Emergence Date associated with our outstanding senior secured second lien notes, convertible senior notes, and senior subordinated notes was not accrued or recorded in the unaudited condensed consolidated statement of operations as interest expense.

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

The following table summarizes the losses (gains) on reorganization items, net:



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

Payments of professional service provider fees and success fees of $12.7 million and fees of $3.1 million related to the Senior Secured Superpriority Debtor-in-Possession Credit Agreement (“DIP Facility”) were included in cash outflows from operating activities and financing activities, respectively, in our Unaudited Condensed Consolidated Statements of Cash Flows for the period January 1, 2020 through September 18, 2020.

Valuation Process

The fair values of our principal assets, including oil and natural gas properties, CO₂ properties, pipelines, other property and equipment, long-term CO₂ customer contracts, favorable and unfavorable vendor contracts, pipeline financing liabilities and right-of-use assets, asset retirement obligations and warrants were estimated as of the Emergence Date.

Oil and Natural Gas Properties

The Company’s principal assets are its oil and natural gas properties, which are accounted for under the full cost accounting method as described in Note 1, Basis of Presentation – Oil and Natural Gas Properties. The Company determined the fair value of its oil and gas properties based on the discounted cash flows expected to be generated from these assets. The computations were based on market conditions and reserves in place as of the Emergence Date.

The fair value analysis was based on the Company’s estimated future production of proved and probable reserves as prepared by the Company’s independent petroleum engineering firm. Discounted cash flow models were prepared using the estimated future revenues and operating costs for all developed wells and undeveloped properties comprising the proved and probable reserves. Future revenues were based upon forward strip oil and natural gas prices as of the Emergence Date through 2024 and escalated for inflation thereafter, adjusted for differentials. Operating costs were adjusted for inflation beginning in year 2025. A risk adjustment factor was applied to each reserve category, consistent with the risk of the category. The discounted cash flow models also included adjustments for income tax expenses.

Discount factors utilized were derived using a weighted average cost of capital computation, which included an estimated cost of debt and equity for market participants with similar geographies and asset development type and varying corporate income tax rates based on the expected point of sale for each property’s produced assets. Cash flows were also adjusted for a market participant profit on CO₂ costs, since Denbury charges oil fields for CO₂ use on a cost basis. Finally, reserve values were adjusted for any asset retirement obligations as well as for CO₂ indirect costs not directly allocable to oil fields. Based on this analysis, the Company concluded the fair value of its proved and probable reserves was $865.4 million as of the Emergence Date (see footnote 10 to Fresh Start Adjustments discussion below).

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

CO₂ Properties

The fair value of CO₂ properties includes the value of CO₂ mineral rights and associated infrastructure and was determined using the discounted cash flow method under the income approach. After-tax cash flows were forecast based on expected costs to produce and transport CO₂ as provided by management, and income was imputed using a gross-up of costs based on a five-year average historical EBITDA margin for publicly traded companies that primarily develop or produce natural gas. Cash flows were then discounted using a rate considering reduced risk associated with CO₂ industrial sales.

Pipelines

The fair values of our pipelines were determined using a combination of the replacement cost method under the cost approach and the discounted cash flow method under the income approach. The replacement cost method considers historical acquisition costs for the assets adjusted for inflation, as well as factors in any potential obsolescence based on the current condition of the assets and the ability of those assets to generate cash flow. For assets valued using the discounted cash flow method, after-tax cash flows were forecast based on expected costs provided by management, and profits were imputed using a gross-up of costs based on a five-year average historical EBITDA margin for publicly traded companies that primarily transport natural gas. Pipeline depreciable lives represent the remaining estimated useful lives of the pipelines, which will be depreciated on a straight-line basis ranging from 20 to 43 years.

Other Property and Equipment

The fair value of the non-reserve related property and equipment such as land, buildings, equipment, leasehold improvements and software was determined using the replacement cost method under the cost approach which considers historical acquisition costs for the assets adjusted for inflation, as well as factors in any potential obsolescence based on the current condition of the assets and the ability of those assets to generate cash flow.

Long-Term CO₂ Customer Contracts

The fair value of long-term CO₂ customer contracts was determined using the multi-period excess earnings method (“MPEEM”) under the income approach. MPEEM attributes cash flow to a specific intangible asset based on residual cash flows from a set of assets generating revenues after accounting for appropriate returns on and of other assets contributing to that revenue generation. Cash flows were forecast based on expected changes in pricing, volumes, renewal rates, and costs using volumes and prices through and beyond the initial contract terms. After-tax cash flows were discounted using a rate considering reduced risk of these industrial contracts relative to overall oil and gas production risks. The contracts will be depreciated over a useful life of seven to 14 years.

Favorable and Unfavorable Vendor Contracts

We recognized both favorable and unfavorable contracts using the incremental value method under the income approach. The incremental value method calculates value on the basis of the pricing differential between historical contracted rates and estimated pricing that the Company would most likely receive if it entered into similar contract conditions (other than the price) as of the Emergence Date. The differential is applied to expected contract volumes, tax-affected and discounted at a discount rate consistent with the risk of the associated cash flows.

Asset Retirement Obligations

The fair value of the asset retirement obligations was revalued based upon estimated current reclamation costs for our assets with reclamation obligations, an appropriate long-term inflation adjustment, and our revised credit adjusted risk-free rate (“CARFR”). The new CARFR was based on an evaluation of similar industry peers with similar factors such as emergence, new capital structure and current rates for oil and gas companies.

Pipeline Financing Liabilities

The fair value of the pipeline financing liabilities was measured as the present value of the remaining payments under the restructured pipeline agreements (see Note 6, Long-Term Debt – Pipeline Financing Transactions, for further discussion).

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Warrants

The fair values of the warrants issued upon the Emergence Date were estimated by applying a Black-Scholes-Merton model. The Black-Scholes-Merton model is a pricing model used to estimate the fair value of a European-style call or put option/warrant based on a current stock price, strike price, time to maturity, risk-free rate, annual volatility rate, and annual dividend yield.

The model used the following assumptions: implied stock price (total equity divided by total shares outstanding) of the Successor’s shares of common stock of $22.14; initial strike price per share of $32.59 and $35.41 for series A and B warrants, respectively; expected volatility of 49.3% and 53.6% for series A and B warrants, respectively; risk-free interest rates of 0.3% and 0.2% for series A and B warrants, respectively, using the United States Treasury Constant Maturity rates; and an expected annual dividend yield of 0%. Expected volatility was estimated using volatilities of similar entities whose share or option prices and assumptions were publicly available. The time to maturity of the warrants was based on the contractual terms of the warrants of five and three years for series A and series B warrants, respectively. The values were also adjusted for potential dilution impacts.

Condensed Consolidated Balance Sheet

The following illustrates the effects on the Company’s consolidated balance sheet due to the reorganization and fresh start accounting adjustments. The explanatory notes following the table below provide further details on the adjustments, including the assumptions and methods used to determine fair value for its assets, liabilities, and warrants.



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

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements



	As of September 18, 2020
In thousands	Predecessor			Reorganization Adjustments				Fresh Start Adjustments				Successor
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	67,789		$	102,793		⁽⁵⁾	$	3,738		⁽¹³⁾	$	174,320
Oil and gas production payable	39,372			16,705			⁽⁶⁾	—				56,077
Derivative liabilities	8,613			—				—				8,613
Current maturities of long-term debt	—			73,199			⁽⁶⁾	364			⁽¹⁴⁾	73,563
Operating lease liabilities	—			757			⁽⁶⁾	(29		)	⁽¹⁰⁾	728
Total current liabilities	115,774			193,454				4,073				313,301
Long-term liabilities
Long-term debt, net of current portion	140,000			42,610			⁽⁶⁾	(25,151		)	⁽¹⁴⁾	157,459
Asset retirement obligations	2,727			180,408			⁽⁶⁾	(24,697		)	⁽¹⁰⁾	158,438
Derivative liabilities	295			—				—				295
Deferred tax liabilities, net	—			417,951			^(6)(15)	(414,120		)	⁽¹⁵⁾	3,831
Operating lease liabilities	—			515			⁽⁶⁾	10			⁽¹⁰⁾	525
Other liabilities	—			3,540			⁽⁶⁾	18,599			⁽¹⁶⁾	22,139
Total long-term liabilities not subject to compromise	143,022			645,024				(445,359		)		342,687
Liabilities subject to compromise	2,823,506			(2,823,506		)	⁽⁶⁾	—				—
Commitments and contingencies (Note 12)
Stockholders’ equity
Predecessor preferred stock	—			—				—				—
Predecessor common stock	510			(510		)	⁽⁷⁾	—				—
Predecessor paid-in capital in excess of par	2,764,915			(2,764,915		)	⁽⁷⁾	—				—
Predecessor treasury stock, at cost	(6,202		)	6,202			⁽⁷⁾	—				—
Successor preferred stock	—			—				—				—
Successor common stock	—			50			⁽⁸⁾	—				50
Successor paid-in-capital in excess of par	—			1,095,369			⁽⁸⁾	—				1,095,369
Accumulated deficit	(2,219,106		)	3,639,409			⁽⁹⁾	(1,420,303		)	⁽¹⁷⁾	—
Total stockholders’ equity	540,117			1,975,605				(1,420,303		)		1,095,419
Total liabilities and stockholders’ equity	$	3,622,419		$	(9,423	)		$	(1,861,589	)		$	1,751,407

Reorganization Adjustments


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



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

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

Net uses	$	(27,787	)

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements


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


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


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


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



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


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



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

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

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements


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


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



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


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



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

Fresh Start Adjustments


(10)	Reflects fair value adjustments to our (i) oil and natural gas properties, CO₂ properties, pipelines, and other property and equipment, as well as the elimination of accumulated depletion, depreciation, and amortization, (ii) operating lease right-of-use assets and liabilities, and (iii) asset retirement obligations.


(11)	Reflects fair value adjustments to our long-term CO₂ customer contracts.


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



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

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements


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



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


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



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

Our pipeline lease financings were restructured in late October 2020 (see Note 6, Long-Term Debt – Pipeline Financing Transactions).

(15)

Represents (i) adjustment to deferred taxes, including the recognition of tax expenses related to reorganization adjustments as a result of the cancellation of debt and retaining tax attributes for the Successor and the reinstatement of deferred tax liabilities subject to compromise totaling $128.6 million and (ii) adjustments to deferred tax liabilities related to fresh start accounting of $414.1 million.


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


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

Note 3. Leases

We evaluate contracts for leasing arrangements at inception. We lease office space, equipment, and vehicles that have non-cancelable lease terms. Leases with a term of 12 months or less are not recorded on our balance sheet. As part of the Chapter 11 Restructuring, the Predecessor elected to terminate some of its operating leases, primarily related to office space.

Lease costs for operating leases or leases with a term of 12 months or less are recognized on a straight-line basis over the lease term. For finance leases, interest on the lease liability and the amortization of the right-of-use asset are recognized separately, with the depreciable life reflective of the expected lease term. The Predecessor previously subleased part of the office space included in its operating leases for which it received rental payments. Since those office space leases were terminated during the Chapter 11 Restructuring, the underlying sublease agreements were also terminated as of September 30, 2020.

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

The following tables summarize the components of lease costs and sublease income:



		Successor		Predecessor
		Period from Sept. 19, 2020 through		Period from July 1, 2020 through		Three Months Ended
In thousands	Income Statement Presentation	Sept. 30, 2020		Sept. 18, 2020		Sept. 30, 2019
Operating lease cost	General and administrative expenses	$	8	$	1,715	$	1,187
	Lease operating expenses	19		121		—
	CO₂ operating and discovery expenses	2		11		—
		$	29	$	1,847	$	1,187

Finance lease cost
Amortization of right-of-use assets	Depletion, depreciation, and amortization	$	1	$	5	$	54
Interest on lease liabilities	Interest expense	—		2		2
Total finance lease cost		$	1	$	7	$	56

Sublease income	General and administrative expenses	$	100	$	790	$	964



		Successor		Predecessor
		Period from Sept. 19, 2020 through		Period from Jan. 1, 2020 through		Nine Months Ended
In thousands	Income Statement Presentation	Sept. 30, 2020		Sept. 18, 2020		Sept. 30, 2019
Operating lease cost	General and administrative expenses	$	8	$	5,683	$	6,014
	Lease operating expenses	19		214		—
	CO₂ operating and discovery expenses	2		37		—
		$	29	$	5,934	$	6,014

Finance lease cost
Amortization of right-of-use assets	Depletion, depreciation, and amortization	$	1	$	9	$	1,188
Interest on lease liabilities	Interest expense	—		3		40
Total finance lease cost		$	1	$	12	$	1,228

Sublease income	General and administrative expenses	$	100	$	2,584	$	3,331

Note 4. Predecessor Divestiture

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

Note 5. Revenue Recognition

We record revenue in accordance with 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

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

point and the customer takes delivery and possession, we are entitled to payment and we invoice the customer for such delivered production. Payment under most oil and CO₂ contracts is made within a month following product delivery and for natural gas and NGL contracts is generally made within two months following delivery. Timing of revenue recognition may differ from the timing of invoicing to customers; however, as the right to consideration after delivery is unconditional based on only the passage of time before payment of the consideration is due, upon delivery we record a receivable in “Accrued production receivable” in our Unaudited Condensed Consolidated Balance Sheets, which was $74.3 million and $139.4 million as of September 30, 2020 (Successor) and December 31, 2019 (Predecessor), respectively. From time to time, the Company enters into marketing arrangements for the purchase and sale of crude oil for third parties in the Gulf Coast region. Revenues and expenses from these transactions are presented on a gross basis, as we act as a principal in the transaction by assuming control of the commodities purchased and the responsibility to deliver the commodities sold. Revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser.

Disaggregation of Revenue

The following tables summarize our revenues by product type:



	Successor		Predecessor
	Period from Sept. 19, 2020 through		Period from July 1, 2020 through		Three Months Ended
In thousands	Sept. 30, 2020		Sept. 18, 2020		Sept. 30, 2019
Oil sales	$	22,311	$	152,136	$	292,100
Natural gas sales	10		954		1,092
CO₂ sales and transportation fees	967		6,517		8,976
Oil marketing sales	151		3,332		5,468
Total revenues	$	23,439	$	162,939	$	307,636



	Successor		Predecessor
	Period from Sept. 19, 2020 through		Period from Jan. 1, 2020 through		Nine Months Ended
In thousands	Sept. 30, 2020		Sept. 18, 2020		Sept. 30, 2019
Oil sales	$	22,311	$	489,251	$	912,636
Natural gas sales	10		2,850		5,554
CO₂ sales and transportation fees	967		21,049		25,532
Oil marketing sales	151		8,543		8,274
Total revenues	$	23,439	$	521,693	$	951,996

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 6. Long-Term Debt

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



	Successor			Predecessor
In thousands	Sept. 30, 2020			Dec. 31, 2019
Successor Senior Secured Bank Credit Agreement	$	85,000		$	—
Predecessor Senior Secured Bank Credit Agreement	—			—
9% Senior Secured Second Lien Notes due 2021	—			614,919
9¼% Senior Secured Second Lien Notes due 2022	—			455,668
7¾% Senior Secured Second Lien Notes due 2024	—			531,821
7½% Senior Secured Second Lien Notes due 2024	—			20,641
6⅜% Convertible Senior Notes due 2024	—			245,548
6⅜% Senior Subordinated Notes due 2021	—			51,304
5½% Senior Subordinated Notes due 2022	—			58,426
4⅝% Senior Subordinated Notes due 2023	—			135,960
Pipeline financings	90,815			167,439
Capital lease obligations	152			—
Total debt principal balance	175,967			2,281,726
Debt discount	—			(101,767		)
Future interest payable	—			164,914
Debt issuance costs	—			(10,009		)
Total debt, net of debt issuance costs and discount	175,967			2,334,864
Less: current maturities of long-term debt	(73,511		)	(102,294		)
Long-term debt	$	102,456		$	2,232,570

The ultimate parent company in our corporate structure, Denbury Inc., is the sole issuer of all our outstanding obligations under our Successor Bank Credit Agreement. Denbury Inc. has no independent assets or operations. Each of the subsidiary guarantors of such obligations is 100% owned, directly or indirectly, by Denbury Inc., and the guarantees of such obligations are full and unconditional and joint and several.

Prior to our emergence from bankruptcy, our debt consisted of the Predecessor’s Bank Credit Agreement, senior secured second lien notes, convertible senior notes, senior subordinated notes, pipeline financings, and capital lease obligations. On the Emergence Date, pursuant to the terms of the Plan, all outstanding obligations under the senior secured second lien notes, convertible senior notes, and senior subordinated notes were fully extinguished, relieving approximately $2.1 billion of debt by issuing equity and/or warrants in the Successor to the holders of that debt. See Note 1, Basis of Presentation – Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code, for additional information.

Successor Senior Secured Bank Credit Agreement

In connection with our emergence from Chapter 11 proceedings on September 18, 2020, we entered into a new credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the “Successor Bank Credit Agreement”). The Successor Bank Credit Agreement is a senior secured revolving credit facility with an initial borrowing base and lender commitments of $575 million. Additionally, under the Successor Bank Credit Agreement, letters of credit are available in an aggregate amount not to exceed $100 million, and short-term swingline loans are available in an aggregate amount not to exceed $25 million, each subject to the available commitments under the Successor Bank Credit Agreement. Availability under the Successor Bank Credit Agreement is subject to a borrowing base, which is redetermined semiannually on or around May 1 and November 1 of each year, with our next scheduled redetermination around May 1, 2021. The borrowing base is adjusted at the lenders’ discretion and is based, in part, upon external factors over which we have no control. The borrowing base is subject to a reduction by twenty-five percent (25%) of the principal amount of any unsecured or subordinated debt issued or incurred. The borrowing

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

base may also be reduced if we sell borrowing base properties and/or cancel commodity derivative positions with an aggregate value in excess of 5% of the then-effective borrowing base between redeterminations. If our outstanding debt under the Successor 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 Successor Bank Credit Agreement matures on January 30, 2024.

The Successor Bank Credit Agreement prohibits us from paying dividends on our common stock through September 17, 2021. Commencing on September 18, 2021, we may pay dividends on our common stock or make other restricted payments in an amount not to exceed “Distributable Free Cash Flow”, but only if (1) no event of default or borrowing base deficiency exists; (2) our total leverage ratio is 2 to 1 or lower; and (3) availability under the Successor Bank Credit Agreement is at least 20%. The Successor Bank Credit Agreement also limits our ability to, among other things, incur and repay other indebtedness; grant liens; engage in certain mergers, consolidations, liquidations and dissolutions; engage in sales of assets; make acquisitions and investments; make other restricted payments (including redeeming, repurchasing or retiring our common stock); and enter into commodity derivative agreements, in each case subject to customary exceptions.

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

The Successor Bank Credit Agreement contains certain financial performance covenants, commencing with the fiscal quarter ending December 31, 2020 through the maturity of the facility, including the following:


•	A Consolidated Total Debt to Consolidated EBITDAX covenant, with such ratio not to exceed 3.5 times; and


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

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

Loans under the Successor Bank Credit Agreement are subject to varying rates of interest based on either (1) for ABR Loans, a base rate determined under the Successor Bank Credit Agreement (the “ABR”) plus an applicable margin ranging from 2.00% to 3.00% per annum, or (2) for LIBOR Loans, the LIBOR rate (subject to a 1% floor) plus an applicable margin ranging from 3.00% to 4.00% per annum (capitalized terms as defined in the Successor Bank Credit Agreement). The weighted average interest rate on borrowings outstanding as of September 30, 2020 under the Successor Bank Credit Agreement was 4.0%. The undrawn portion of the aggregate lender commitments under the Successor Bank Credit Agreement is subject to a commitment fee of 0.5% per annum.

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

Pipeline Financing Transactions

On August 7, 2020, Genesis Energy, L.P. (“Genesis”) as the beneficiary of the $41.3 million letter of credit issued as “financial assurances” under the NEJD pipeline lease financing drew the full amount of such letter of credit in accordance with its terms as a result of the Predecessor’s Chapter 11 Restructuring, which resulted in a corresponding reduction to the principal balance outstanding. In late October 2020, we restructured our CO₂ pipeline financing arrangements with Genesis, whereby (1) Denbury reacquired the NEJD pipeline system from Genesis in exchange for $70 million to be paid in four equal payments during 2021, representing full settlement of all remaining obligations under the NEJD secured financing lease; and (2) Denbury reacquired the Free State Pipeline from Genesis in exchange for a one-time payment of $22.5 million on October 30, 2020.

Predecessor Senior Secured Bank Credit Facility

From December 2014 through September 18, 2020, the Company maintained a senior secured revolving credit facility with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the “Predecessor Bank Credit Agreement”).

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

All but a minor portion of the Predecessor Bank Credit Agreement was refinanced through the DIP Facility from August 4, 2020 through September 18, 2020, which was in turn refinanced by the Successor Bank Credit Agreement upon emergence from the Chapter 11 Restructuring.

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

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

First Quarter 2020 Repurchases of Senior Secured Notes

During March 2020, the Predecessor repurchased a total of $30.2 million aggregate principal amount of its 9% Senior Secured Second Lien Notes due 2021 in open-market transactions for a total purchase price of $14.2 million, excluding accrued interest. In connection with these transactions, the Predecessor recognized a $19.0 million gain on debt extinguishment, net of unamortized debt issuance costs and future interest payable written off.

Note 7. Income Taxes

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

We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. Our income taxes are based on an estimated statutory rate of approximately 25% in 2020 and 2019. Our effective tax rate for the Predecessor period ended September 18, 2020 differed from our estimated statutory rate, primarily due to the numerous tax impacts related to the emergence from the Chapter 11 Restructuring, including the reduction of tax attributes from the exclusion of cancellation of debt income according to Section 108 of the U.S. Internal Revenue Code, and the establishment of a valuation allowance of our federal and state deferred tax assets existing after fresh start accounting. For the Successor period ended September 30, 2020, our effective tax rate differed from our estimated statutory rate as a result of a valuation allowance applied to our federal and state deferred tax assets.

Note 8. Stockholders' Equity

Registration Rights Agreement

On the Emergence Date, the Company entered into a registration rights agreement (the “Registration Rights Agreement”) with former beneficial holders of the second lien notes of the Predecessor who entered into the RSA dated July 28, 2020, and that together with their affiliates received 4% or more of New Common Stock (including as a result of exercise of series A warrants of the Successor) pursuant to the Plan, or their affiliates.

Under the Registration Rights Agreement, Securityholders have customary demand and piggyback registration rights, subject to the limitations set forth in the Registration Rights Agreement. As part of the offering registration rights, Securityholders have the right to demand the Company to effectuate the distribution of any or all of its Registrable Securities (as defined in the Registration Rights Agreement) by means of an underwritten offering pursuant to an effective registration statement; provided, however, that the expected aggregate offering price is equal to or greater than $25.0 million or includes at least 20% of the then-outstanding Registrable Securities.

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in an offering and the Company’s right to delay or withdraw a registration statement under certain circumstances. The Company will generally pay all registration expenses in connection with its obligations under the Registration Rights Agreement, regardless of whether a registration statement is filed or becomes effective. The registration rights granted in the Registration Rights Agreement are subject to customary indemnification and contribution provisions, as well as customary restrictions such as blackout periods and, if an underwritten offering is contemplated, limitations on the number of shares to be included in the underwritten offering that may be imposed by the managing underwriter.

Note 9. Stock Compensation

2020 Compensation Adjustments

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

Under part of the revised compensation structure, which applies to a group of 21 of the Company’s executives (including our named executive officers) and senior managers, all outstanding equity awards and 2020 targeted variable cash-based compensation for those individuals were canceled and replaced with a cash retention incentive. In total, $15.2 million in cash retention incentives were prepaid to those employees in June 2020, with an obligation to repay up to 100% of the compensation (on an after-tax basis) if specified conditions are not satisfied. The Predecessor’s named executive officers’ cash retention incentive will be earned 50% based on their continued employment for a period of up to 12 months, and 50% based on achieving certain specified incentive metrics. In accordance with FASC Topic 718, Compensation – Stock Compensation, we accounted for the transaction involving equity compensation as an award modification and reclassified the awards from equity to liability awards. As a result of the modification of the awards, unrecognized compensation at the time of modification was determined to be $18.7 million ($4.1 million of incremental compensation expense, of which $3.4 million was expensed during the second quarter of 2020 and $0.7 million was expensed during the Predecessor period from July 1, 2020 through September 18, 2020), which was higher than the $15.2 million cash payment, and was calculated as the greater of (i) grant date fair value of the previously-outstanding awards plus incremental compensation (defined as cash paid related to the cash retention incentive in excess of the modification date fair value of the previously-existing awards) or (ii) cash paid for the cash retention incentive for each award. The value was recognized as total compensation expense for each award over the service period. We recognized $11.5 million of the $18.7 million as compensation expense in “General and administrative expenses” in our Unaudited Condensed Consolidated Statements of Operations during the second quarter of 2020, and the remaining $7.2 million during the Predecessor period from July 1, 2020 through September 18, 2020. The accounting for the Predecessor’s remaining share-based compensation awards continued throughout the period covered by the Chapter 11 Restructuring, and upon cancellation of the awards, an additional $4.6 million of compensation expense was recognized during the Predecessor period ended September 18, 2020.

Note 10. Commodity Derivative Contracts

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

Historically, we have entered into various oil and natural gas derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil and natural gas production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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. Under the terms of our Successor Bank Credit Agreement, at any point in time within the initial measurement period of August 1, 2020 through July 31, 2021, we are required to have hedges in place covering a minimum of 65% of our anticipated crude oil production and 35% of our anticipated crude oil production for the second measurement period of August 1, 2021 through July 31, 2022. We have until December 31, 2020 to enter into transactions for the initial measurement period to be in compliance.

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 Successor Bank Credit Agreement (or affiliates of such lenders). As of September 30, 2020, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.

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



Months	Index Price	Volume (Barrels per day)	Contract Prices ($/Bbl)
			Range⁽¹⁾				Weighted Average Price
			Range⁽¹⁾				Swap		Sold Put		Floor		Ceiling
Oil Contracts:
2020 Fixed-Price Swaps
Oct – Dec	NYMEX	13,500	$	36.25	–	61.00	$	40.52	$	—	$	—	$	—
Oct – Dec	Argus LLS	7,500		35.00	–	64.26	51.67		—		—		—
2020 Three-Way Collars⁽²⁾
Oct – Dec	NYMEX	9,500	$	55.00	–	82.65	$	—	$	47.93	$	57.00	$	63.25
Oct – Dec	Argus LLS	5,000		58.00	–	87.10	—		52.80		61.63		70.35
2021 Fixed-Price Swaps
Jan – Dec	NYMEX	8,000	$	41.70	–	45.20	$	43.41	$	—	$	—	$	—
2022 Fixed-Price Swaps
Jan – June	NYMEX	6,000	$	42.90	–	45.50	$	43.75	$	—	$	—	$	—


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

(2)

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

Note 11. 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

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Notes to Unaudited Condensed Consolidated Financial Statements

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

•

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

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:
In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			Total
September 30, 2020 (Successor)
Assets
Oil derivative contracts – current	$	—	$	26,778		$	—		$	26,778
Oil derivative contracts – long-term	—		1,147			—			1,147
Total Assets	$	—	$	27,925		$	—		$	27,925

Liabilities
Oil derivative contracts – current	$	—	$	(5,739	)	$	—		$	(5,739	)
Oil derivative contracts – long-term	—		(584		)	—			(584		)
Total Liabilities	$	—	$	(6,323	)	$	—		$	(6,323	)


December 31, 2019 (Predecessor)
Assets
Oil derivative contracts – current	$	—	$	8,503		$	3,433		$	11,936
Total Assets	$	—	$	8,503		$	3,433		$	11,936

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

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

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Notes to Unaudited Condensed Consolidated Financial Statements

Level 3 Fair Value Measurements

The following tables summarize the changes in the fair value of our Level 3 assets and liabilities:



	Successor		Predecessor
	Period from Sept. 19, 2020 through		Period from July 1, 2020 through		Three Months Ended
In thousands	Sept. 30, 2020		Sept. 18, 2020		Sept. 30, 2019
Fair value of Level 3 instruments, beginning of period	$	—	$	—	$	6,073
Transfers out of Level 3	—		—		—
Fair value gains on commodity derivatives	—		—		6,450
Receipts on settlements of commodity derivatives	—		—		(1,323		)
Fair value of Level 3 instruments, end of period	$	—	$	—	$	11,200

The amount of total gains for the period included in earnings attributable to the change in unrealized gains relating to assets or liabilities still held at the reporting date	$	—	$	—	$	6,234



	Successor		Predecessor
	Period from Sept. 19, 2020 through		Period from Jan. 1, 2020 through			Nine Months Ended
In thousands	Sept. 30, 2020		Sept. 18, 2020			Sept. 30, 2019
Fair value of Level 3 instruments, beginning of period	$	—	$	1,609		$	13,624
Transfers out of Level 3	—		(1,609		)	—
Fair value gains on commodity derivatives	—		—			90
Receipts on settlements of commodity derivatives	—		—			(2,514		)
Fair value of Level 3 instruments, end of period	$	—	$	—		$	11,200

The amount of total gains for the period included in earnings attributable to the change in unrealized gains relating to assets or liabilities still held at the reporting date	$	—	$	—		$	6,540

Instruments previously categorized as Level 3 included non-exchange-traded three-way collars that were based on regional pricing other than NYMEX, whereby the implied volatilities utilized were developed using a benchmark, which was considered a significant unobservable input. The transfers between Level 3 and Level 2 during the period generally relate to changes in the significant relevant observable and unobservable inputs that are available for the fair value measurements of such financial instruments.

Other Fair Value Measurements

The carrying value of our loans under our Successor Bank Credit Agreement approximate fair value, as they are subject to short-term floating interest rates that approximate the rates available to us for those periods. We use a market approach to determine the fair value of our fixed-rate long-term debt using observable market data. The fair values of the Predecessor’s senior secured second lien notes, convertible senior notes, and senior subordinated notes were based on quoted market prices, which are considered Level 1 measurements under the fair value hierarchy. The estimated fair value of the principal amount of our debt as of September 30, 2020 and December 31, 2019, excluding pipeline financing obligations, was $85.0 million and $1,833.1 million, respectively, which decrease is primarily the result of the cancellation of $2.1 billion principal amount of debt as part of the Chapter 11 Restructuring. See Note 1, Basis of Presentation – Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code, for additional information. We have other financial instruments consisting primarily of cash, cash equivalents, U.S. Treasury

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Notes to Unaudited Condensed Consolidated Financial Statements

notes, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.

Note 12. Commitments and Contingencies

Chapter 11 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. The chapter 11 case captioned “In re Denbury Resources Inc., et al., Case No. 20-33801” will remain pending until the final resolution of all outstanding claims.

Litigation

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

Riley Ridge Helium Supply Contract Claim

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

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

On March 11, 2019, the trial court entered a final judgment that a force majeure condition did exist, but the Company’s performance was excused by the force majeure provisions of the contract for only a 35-day period in 2014, and as a result the Company should pay APMTG liquidated damages and interest thereon for those time periods from contract commencement to the close of evidence (November 29, 2017). The Company’s position continues to be that its contractual obligations have been and continue to be excused by events that fall within the force majeure provisions of the helium supply contract, so the Company has appealed the trial court’s ruling to the Wyoming Supreme Court. Oral arguments were heard by the Wyoming Supreme Court on August 13, 2020. We anticipate the Wyoming Supreme Court will enter its judgment on the appeal within the next few months; however, the outcome of the appeal is currently unpredictable.

Absent reversal of the trial court’s ruling on appeal, the Company anticipates total liquidated damages would equal the $46.0 million aggregate cap under the helium supply contract plus $6.7 million of associated costs (through September 30, 2020), for a total of $52.7 million, included in “Accounts payable and accrued liabilities” in our Unaudited Condensed Consolidated Balance Sheets as of September 30, 2020. The Company has a $32.8 million letter of credit posted as security in this case as part of the appeal process.

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 13. Additional Balance Sheet Details

Trade and Other Receivables, Net



	Successor		Predecessor
In thousands	Sept. 30, 2020		Dec. 31, 2019
Trade accounts receivable, net	$	9,447	$	12,630
Commodity derivative settlement receivables	7,606		675
Federal income tax receivable, net	1,600		2,987
Other receivables	16,135		2,026
Total	$	34,788	$	18,318

Note 14. Subsequent Events

Houston Area Land Sale

On October 30, 2020, we completed the sale of a portion of certain non-producing surface acreage in the Houston area for approximately $11 million.

Pipeline Financing Transactions

In late October 2020, we restructured our CO₂ pipeline financing arrangements with Genesis, resulting in Denbury reacquiring the NEJD and Free State pipelines. See Note 6, Long-Term Debt – Pipeline Financing Transactions, for further discussion.

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Denbury Inc.

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

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

The following discussion and analysis should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and Notes thereto included herein and our Consolidated Financial Statements and Notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2019 (the “Form 10-K”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K. Any terms used but not defined herein have the same meaning given to them in the Form 10-K.

Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Risk Factors under Item 1A of this Form 10-Q as well as Item 1A of the Form 10-K, along with Forward-Looking Information at the end of this section for information on the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

OVERVIEW

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

September 18, 2020 Emergence from Chapter 11 Restructuring. On July 30, 2020 (the “Petition Date”), Denbury Resources Inc. and its subsidiaries filed petitions for reorganization in a “prepackaged” voluntary bankruptcy (the “Chapter 11 Restructuring”) under chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”) under the caption “In re Denbury Resources Inc., et al., Case No. 20-33801”. On September 2, 2020, the Bankruptcy Court entered an order (the “Confirmation Order”) confirming the chapter 11 plan of reorganization (the “Plan”) and approving the disclosure statement, and on September 18, 2020 (the “Emergence Date”), the Plan became effective in accordance with its terms and the Company emerged from Chapter 11. On September 18, 2020, Denbury filed the Third Restated Certificate of Incorporation with the Delaware Secretary of State to effect a change of the Company’s corporate name from Denbury Resources Inc. to Denbury Inc. (the “Successor”), and on September 21, 2020, the Successor’s new common stock commenced trading on the New York Stock Exchange under the ticker symbol “DEN”. Key accomplishments of the Chapter 11 Restructuring include the following:


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


•	Significantly improved leverage ratios;


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


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


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

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

Fresh Start Accounting. Upon emergence from bankruptcy, we met the criteria and were required to adopt fresh start accounting in accordance with Financial Accounting Standards Board Codification (“FASC”) Topic 852, Reorganizations, which on the Emergence Date resulted in a new entity, the Successor, for financial reporting purposes, with no beginning retained earnings or deficit as of the fresh start reporting date. References to “Successor” relate to the financial position and results of operations of the Company subsequent to the Company’s emergence from bankruptcy on September 18, 2020, and references to “Predecessor” relate to the financial position and results of operations of the Company prior to, and including, September 18, 2020. In order to assist investors in understanding the comparability of our financial results for the applicable periods, we have provided certain comparative analysis on a combined basis, which management believes provides meaningful information to assist investors in understanding our financial results for the applicable period, but should not be considered in isolation, as a substitute for, or more meaningful than, independent results of the Predecessor and Successor periods for the quarter reported in accordance with GAAP.

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Denbury Inc.

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

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

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



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

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

The decrease in NYMEX oil prices that began in the latter part of the first quarter of 2020 has significantly reduced our cash flow. In response to these developments, we implemented the following operational and financial measures:


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


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


•	Implemented cost reduction measures including shutting down compressors, delayed uneconomic well repairs and workovers and reduced our workforce to better align with current and projected near-term needs;


•	Restructured approximately 50% of our three-way collars covering 14,500 barrels per day (“Bbls/d”) into fixed-price swaps for the second quarter through the fourth quarter of 2020 in order to increase downside oil price protection; and


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

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


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

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

of liabilities subject to compromise of $1.0 billion, primarily representing the net impact of approximately $2.1 billion of debt elimination offset by the new equity value in Denbury; and


•	A $261.7 million full cost pool ceiling test write-down during the predecessor period as a result of the decline in NYMEX oil prices.

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


•	Oil and natural gas revenues decreased by $117.8 million (40%), with 28% of the decrease due to lower commodity prices and 12% of the decrease due to lower production;


•	Lease operating expenses decreased by $46.7 million (40%), primarily due to lower expenses for workovers, CO₂, power and fuel, and labor costs as well as a $15.4 million insurance recovery of costs incurred in 2013.

October 2020 Restructuring of CO₂ Pipeline Agreements. In late October 2020, we restructured our CO₂ pipeline financing arrangements with Genesis Energy, L.P. (“Genesis”), whereby (1) Denbury reacquired the NEJD pipeline system from Genesis in exchange for $70 million to be paid in four equal payments during 2021, representing full settlement of all remaining obligations under the NEJD secured financing lease; and (2) Denbury reacquired the Free State Pipeline from Genesis in exchange for a one-time payment of $22.5 million on October 30, 2020.

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

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

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

CAPITAL RESOURCES AND LIQUIDITY

Overview. Our primary sources of capital and liquidity are our cash flow from operations and availability under our Successor bank credit facility. In 2020 our liquidity has been supplemented by $40 million of proceeds from our March 2020 sale of working interests in four southeast Texas fields and by $25 million of proceeds from sales of non-producing surface acreage primarily around the Houston area. Our most significant cash outlays relate to our development capital expenditures and current period operating expenses. In conjunction with our emergence from bankruptcy, we established a new $575 million senior secured bank credit facility, under which we had $85 million borrowed as of September 30, 2020, leaving us with $436.7 million of availability after consideration of $53.3 million of outstanding letters of credit. As discussed in the Overview above, NYMEX oil prices have decreased significantly since the beginning of 2020, directly reducing our operating cash flow; however, we have taken significant actions to reduce capital expenditures and operating expenses in order to adjust our spending levels such that our spending for ongoing operations is below our cash flow generated from operations.

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

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Denbury Inc.

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

under the Bank Credit Agreement is subject to a borrowing base, which is redetermined semiannually on or around May 1 and November 1 of each year, with our next scheduled redetermination around May 1, 2021. The borrowing base is adjusted at the lenders’ discretion and is based, in part, upon external factors over which we have no control. The borrowing base is subject to a reduction by twenty-five percent (25%) of the principal amount of any unsecured or subordinated debt issued or incurred. The borrowing base may also be reduced if we sell borrowing base properties and/or cancel commodity derivative positions with an aggregate value in excess of 5% of the then-effective borrowing base between redeterminations. If our outstanding debt under the Bank Credit Agreement exceeds the then-effective borrowing base, we would be required to repay the excess amount over a period not to exceed six months. The Bank Credit Agreement matures on January 30, 2024.

The Bank Credit Agreement prohibits us from paying dividends on our common stock through September 17, 2021. Commencing on September 18, 2021, we may pay dividends on our common stock or make other restricted payments in an amount not to exceed “Distributable Free Cash Flow”, but only if (1) no event of default or borrowing base deficiency exists; (2) our total leverage ratio is 2 to 1 or lower; and (3) availability under the Bank Credit Agreement is at least 20%. The Bank Credit Agreement also limits our ability to, among other things, incur and repay other indebtedness; grant liens; engage in certain mergers, consolidations, liquidations and dissolutions; engage in sales of assets; make acquisitions and investments; make other restricted payments (including redeeming, repurchasing or retiring our common stock); and enter into commodity derivative agreements, in each case subject to customary exceptions.

The Bank Credit Agreement is secured by (1) our proved oil and natural gas properties, which are held through our restricted subsidiaries; (2) the pledge of equity interests of such subsidiaries; (3) a pledge of our commodity derivative agreements; (4) a pledge of deposit accounts, securities accounts and commodity accounts of Denbury Inc. and such subsidiaries (as applicable); and (5) a security interest in substantially all other collateral that may be perfected by a Uniform Commercial Code filing, subject to certain exceptions.

The Bank Credit Agreement contains certain financial performance covenants, commencing with the fiscal quarter ending December 31, 2020 through the maturity of the facility, including the following:


•	A Consolidated Total Debt to Consolidated EBITDAX covenant, with such ratio not to exceed 3.5 times; and


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

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

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

Capital Spending. We currently anticipate that our full-year 2020 capital spending, excluding capitalized interest and acquisitions, will be approximately $95 million to $105 million, approximately 78% of which has been incurred through 2020. This 2020 capital expenditure budget reflects a reduction on March 31, 2020 of $80 million, or 44%, from the late-February 2020 estimate of between $175 million and $185 million in response to the more than 50% decline in NYMEX WTI prices during March 2020. Our current 2020 capital budget, excluding capitalized interest and acquisitions, provides for approximate spending as follows:


•	$35 million allocated for tertiary oil field expenditures;


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


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


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

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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 nine months ended September 30, 2020 and 2019:



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


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

Commitments and Obligations. We have numerous contractual commitments in the ordinary course of business including debt service requirements, operating and finance leases, purchase obligations, and asset retirement obligations. Our operating leases primarily consists of our office leases. Our purchase obligations represent future cash commitments primarily for purchase contracts for CO₂ captured from industrial sources, transportation agreements and well-related costs, but excludes any potential payments related to the APMTG litigation being appealed.

Our commitments and obligations consist of those detailed as of December 31, 2019, in our Form 10-K under Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Commitments and Obligations. Material changes to our contractual commitments since December 31, 2019 detailed in this Form 10-Q report include changes to our senior secured bank credit agreement, the cancellation of the Predecessor senior secured second lien notes, convertible senior notes, and senior subordinated notes pursuant to the Plan, and a $41.3 million payment related to the NEJD pipeline lease financing during the third quarter of 2020. As part of the Chapter 11 Restructuring, we elected to terminate some of our operating leases, primarily related to office space, reducing our annual rent expense by approximately $9 million. In late October 2020, we reacquired the NEJD pipeline system and Free State Pipeline from Genesis, representing full settlement of all remaining pipeline financing obligations.

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

RESULTS OF OPERATIONS

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

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Operating Results Table

Certain of our financial results for our Successor and Predecessor periods are presented in the following tables:



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



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


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

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

Certain of our operating results and statistics for the comparative three and nine months ended September 30, 2020 and 2019 are included in the following table:



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
In thousands, except per-share and unit data	2020			2019			2020			2019
Average daily production volumes
Bbls/d	48,334			55,085			50,619			56,836
Mcf/d	8,110			8,135			7,916			9,681
BOE/d⁽¹⁾	49,686			56,441			51,939			58,449
Operating revenues
Oil sales	$	174,447		$	292,100		$	511,562		$	912,636
Natural gas sales	964			1,092			2,860			5,554
Total oil and natural gas sales	$	175,411		$	293,192		$	514,422		$	918,190
Commodity derivative contracts⁽²⁾
Receipt on settlements of commodity derivatives	$	17,789		$	8,057		$	88,056		$	14,714
Noncash fair value gains (losses) on commodity derivatives⁽³⁾	(18,363		)	35,098			18,011			(30,176		)
Commodity derivatives income (expense)	$	(574	)	$	43,155		$	106,067		$	(15,462	)
Unit prices – excluding impact of derivative settlements
Oil price per Bbl	$	39.23		$	57.64		$	36.88		$	58.82
Natural gas price per Mcf	1.29			1.46			1.32			2.10
Unit prices – including impact of derivative settlements⁽²⁾
Oil price per Bbl	$	43.23		$	59.23		$	43.23		$	59.77
Natural gas price per Mcf	1.29			1.46			1.32			2.10
Oil and natural gas operating expenses
Lease operating expenses	$	71,192		$	117,850		$	261,755		$	361,205
Transportation and marketing expenses	9,499			10,067			28,508			32,076
Production and ad valorem taxes	13,697			20,220			40,450			65,780
Oil and natural gas operating revenues and expenses per BOE
Oil and natural gas revenues	$	38.37		$	56.46		$	36.15		$	57.54
Lease operating expenses	15.57			22.70			18.39			22.64
Transportation and marketing expenses	2.08			1.94			2.00			2.01
Production and ad valorem taxes	3.00			3.89			2.84			4.12
CO₂ sources – revenues and expenses
CO₂ sales and transportation fees	$	7,484		$	8,976		$	22,016		$	25,532
CO₂ operating and discovery expenses	(1,197		)	(879		)	(2,834		)	(2,016		)
CO₂ revenue and expenses, net	$	6,287		$	8,097		$	19,182		$	23,516


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


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

(3)

Noncash fair value gains (losses) on commodity derivatives is a non-GAAP measure and is different from “Commodity derivatives expense (income)” in the Unaudited Condensed Consolidated Statements of Operations in that the noncash fair value gains (losses) on commodity derivatives represent only the net changes between periods of the fair market values of commodity derivative positions, and exclude the impact of settlements on commodity derivatives during the period, which were receipts on settlements of $17.8 million and $88.1 million for the three and nine months ended September 30, 2020, respectively, compared to receipts on settlements of $8.1 million and $14.7 million for the three and nine months ended September 30, 2019. We believe that noncash fair value gains (losses) on commodity derivatives is a useful supplemental disclosure to “Commodity derivatives expense (income)” in order to differentiate noncash fair market value adjustments from receipts or payments upon settlements on commodity derivatives during the period. This supplemental disclosure is widely

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

used within the industry and by securities analysts, banks and credit rating agencies in calculating EBITDA and in adjusting net income (loss) to present those measures on a comparative basis across companies, as well as to assess compliance with certain debt covenants. Noncash fair value gains (losses) on commodity derivatives is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for “Commodity derivatives expense (income)” in the Unaudited Condensed Consolidated Statements of Operations.

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Denbury Inc.

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

Production

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



	Average Daily Production (BOE/d)
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	First Quarter	Second Quarter	Third Quarter
Operating Area	2019	2019	2019	2019	2020	2020	2020
Tertiary oil production
Gulf Coast region
Delhi	4,474	4,486	4,256	4,085	3,813	3,529	3,208
Hastings	5,539	5,466	5,513	5,097	5,232	4,722	4,473
Heidelberg	3,987	4,082	4,297	4,409	4,371	4,366	4,256
Oyster Bayou	4,740	4,394	3,995	4,261	3,999	3,871	3,526
Tinsley	4,659	4,891	4,541	4,343	4,355	3,788	4,042
West Yellow Creek	436	586	728	807	775	695	588
Mature properties⁽¹⁾	6,479	6,448	6,415	6,347	6,386	5,249	5,683
Total Gulf Coast region	30,314	30,353	29,745	29,349	28,931	26,220	25,776
Rocky Mountain region
Bell Creek	4,650	5,951	4,686	5,618	5,731	5,715	5,551
Salt Creek	2,057	2,078	2,213	2,223	2,149	1,386	2,167
Grieve	52	41	58	60	50	7	0
Total Rocky Mountain region	6,759	8,070	6,957	7,901	7,930	7,108	7,718
Total tertiary oil production	37,073	38,423	36,702	37,250	36,861	33,328	33,494
Non-tertiary oil and gas production
Gulf Coast region
Mississippi	1,034	1,025	873	952	748	713	629
Texas	3,298	3,224	3,165	3,212	3,419	3,087	3,095
Other	10	6	6	5	6	5	4
Total Gulf Coast region	4,342	4,255	4,044	4,169	4,173	3,805	3,728
Rocky Mountain region
Cedar Creek Anticline	14,987	14,311	13,354	13,730	13,046	11,988	11,485
Other	1,313	1,305	1,238	1,192	1,105	1,069	979
Total Rocky Mountain region	16,300	15,616	14,592	14,922	14,151	13,057	12,464
Total non-tertiary production	20,642	19,871	18,636	19,091	18,324	16,862	16,192
Total continuing production	57,715	58,294	55,338	56,341	55,185	50,190	49,686
Property sales
Gulf Coast Working Interests Sale⁽²⁾	1,047	1,019	1,103	1,170	780	—	—
Citronelle⁽³⁾	456	406	—	—	—	—	—
Total production	59,218	59,719	56,441	57,511	55,965	50,190	49,686


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


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


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

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

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

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

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

Oil and Natural Gas Revenues

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



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2020 vs. 2019					2020 vs. 2019
In thousands	Decrease in Revenues			Percentage Decrease in Revenues		Decrease in Revenues			Percentage Decrease in Revenues
Change in oil and natural gas revenues due to:
Decrease in production	$	(35,090	)	(12	)%	$	(99,290	)	(11	)%
Decrease in realized commodity prices	(82,691		)	(28	)%	(304,478		)	(33	)%
Total decrease in oil and natural gas revenues	$	(117,781	)	(40	)%	$	(403,768	)	(44	)%

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

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



	Three Months Ended																		Nine Months Ended
	March 31,						June 30,						September 30,						September 30,
	2020			2019			2020			2019			2020			2019			2020			2019
Average net realized prices
Oil price per Bbl	$	45.96		$	56.50		$	24.39		$	62.22		$	39.23		$	57.64		$	36.88		$	58.82
Natural gas price per Mcf	1.46			2.68			1.21			2.01			1.29			1.46			1.32			2.10
Price per BOE	45.09			55.27			23.95			60.80			38.37			56.46			36.15			57.54
Average NYMEX differentials
Gulf Coast region
Oil per Bbl	$	1.18		$	4.26		$	(3.59	)	$	4.85		$	(1.38	)	$	3.11		$	(0.86	)	$	4.08
Natural gas per Mcf	(0.06		)	(0.10		)	(0.09		)	0.10			(0.06		)	(0.24		)	(0.07		)	(0.06		)
Rocky Mountain region
Oil per Bbl	$	(2.78	)	$	(2.56	)	$	(4.68	)	$	(1.48	)	$	(2.03	)	$	(1.65	)	$	(2.89	)	$	(1.85	)
Natural gas per Mcf	(0.91		)	(0.28		)	(1.04		)	(1.13		)	(1.74		)	(1.61		)	(1.25		)	(0.90		)
Total Company
Oil per Bbl	$	(0.38	)	$	1.63		$	(4.03	)	$	2.35		$	(1.64	)	$	1.30		$	(1.67	)	$	1.79
Natural gas per Mcf	(0.41		)	(0.20		)	(0.54		)	(0.50		)	(0.83		)	(0.87		)	(0.60		)	(0.47		)

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

•

Gulf Coast Region. Our average NYMEX oil differential in the Gulf Coast region was a negative $1.38 per Bbl during the third quarter of 2020, compared to a positive $3.11 per Bbl during the third quarter of 2019 and a negative $3.59 per Bbl during the second quarter of 2020. Generally, our Gulf Coast region differentials are positive to NYMEX and highly correlated to the changes in prices of Light Louisiana Sweet crude oil, though storage constraints and weak demand caused these differentials to weaken significantly during the second and third quarters of 2020.

•

Rocky Mountain Region. NYMEX oil differentials in the Rocky Mountain region averaged $2.03 per Bbl and $1.65 per Bbl below NYMEX during the third quarters of 2020 and 2019, respectively, and $4.68 per Bbl below NYMEX during the second quarter of 2020. Differentials in the Rocky Mountain region can fluctuate significantly on a month-to-month basis due to weather, refinery or transportation issues, and Canadian and U.S. crude oil price index volatility.

Our realized oil prices and differentials during 2020 have been significantly impacted by the rapid and precipitous drop in oil demand caused by the slowdown in economic activity due to the COVID-19 pandemic. This drop in oil demand worsened a deteriorated oil market which followed the early-March 2020 failure by the group of oil producing nations known as OPEC+ to reach an agreement over proposed oil production cuts. Although OPEC+ subsequently agreed to reduced levels of production output, concerns about the ability of OPEC+ to maintain compliance with their reduced production targets and uncertainty about the duration of the COVID-19 pandemic and its resulting economic consequences has resulted in abnormally high worldwide inventories of produced oil. While oil prices have improved from the low points experienced during the second quarter of 2020, concerns and uncertainties around the balance of supply and demand for oil are expected to continue for some time. While our oil differentials have improved since the second quarter of 2020, oil prices are expected to continue to be volatile as a result of these events, and as changes in oil inventories, oil demand and economic performance are reported.

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Denbury Inc.

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

CO₂ Revenues and Expenses

We sell CO₂ produced from Jackson Dome to third-party industrial users at various contracted prices primarily under long-term contracts. We recognize the revenue received on these CO₂ sales as “CO₂ sales and transportation fees” with the corresponding costs recognized as “CO₂ operating and discovery expenses” in our Unaudited Condensed Consolidated Statements of Operations.

Oil Marketing Revenues and Expenses

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

Commodity Derivative Contracts

The following tables summarize the impact our crude oil derivative contracts had on our operating results for the periods indicated:



	Successor			Predecessor
	Period from Sept. 19, 2020 through			Period from July 1, 2020 through			Three Months Ended
In thousands	Sept. 30, 2020			Sept. 18, 2020			Sept. 30, 2019
Receipt on settlements of commodity derivatives	$	6,660		$	11,129		$	8,057
Noncash fair value gains (losses) on commodity derivatives⁽¹⁾	(2,625		)	(15,738		)	35,098
Total income (expense)	$	4,035		$	(4,609	)	$	43,155



	Successor			Predecessor
	Period from Sept. 19, 2020 through			Period from Jan. 1, 2020 through		Nine Months Ended
In thousands	Sept. 30, 2020			Sept. 18, 2020		Sept. 30, 2019
Receipt (payment) on settlements of commodity derivatives	$	6,660		$	81,396	$	14,714
Noncash fair value gains (losses) on commodity derivatives⁽¹⁾	(2,625		)	20,636		(30,176		)
Total income (expense)	$	4,035		$	102,032	$	(15,462	)


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

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Denbury Inc.

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

In order to provide a level of price protection to a portion of our oil production, we have hedged a portion of our estimated oil production through 2020 using both NYMEX and LLS fixed-price swaps and three-way collars and oil production in 2021 and the first half of 2022 using NYMEX fixed-price swaps. See Note 10, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements for additional details of our outstanding commodity derivative contracts as of September 30, 2020, and Item 3, Quantitative and Qualitative Disclosures about Market Risk below for additional discussion. In addition, the following table summarizes our commodity derivative contracts as of November 12, 2020:



		4Q 2020	2021	1H 2022
WTI NYMEX	Volumes Hedged (Bbls/d)	13,500	24,000	8,500
Fixed-Price Swaps	Swap Price⁽¹⁾	$40.52	$42.22	$43.55
Argus LLS	Volumes Hedged (Bbls/d)	7,500	—	—
Fixed-Price Swaps	Swap Price⁽¹⁾	$51.67	—	—
WTI NYMEX	Volumes Hedged (Bbls/d)	9,500	—	—
3-Way Collars	Sold Put Price / Floor / Ceiling Price⁽¹⁾⁽²⁾	$47.93 / $57.00 / $63.25	—	—
Argus LLS	Volumes Hedged (Bbls/d)	5,000	—	—
3-Way Collars	Sold Put Price / Floor / Ceiling Price⁽¹⁾⁽²⁾	$52.80 / $61.63 / $70.35	—	—
	Total Volumes Hedged (Bbls/d)	35,500	24,000	8,500


(1)	Averages are volume weighted.


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

Based on current contracts in place and NYMEX oil futures prices as of November 12, 2020, which averaged approximately $40 per Bbl, we currently expect that we would receive cash payments of approximately $20 million upon settlement of our October through December 2020 contracts. Of this estimated amount, the majority relates to our three-way collars, which settlements are currently limited to the extent oil prices remain below the price of our sold puts. The weighted average differences between the floor and sold put prices of our 2020 three-way collars are $9.07 per Bbl and $8.83 per Bbl for NYMEX and LLS hedges, respectively. Settlements with respect to our fixed-price swaps are dependent upon fluctuations in future oil prices in relation to the prices of our 2020 fixed-price swaps which have weighted average prices of $40.52 per Bbl and $51.67 per Bbl for NYMEX and LLS hedges, respectively. Changes in commodity prices, expiration of contracts, and new commodity contracts entered into cause fluctuations in the estimated fair value of our oil derivative contracts. Because we do not utilize hedge accounting for our commodity derivative contracts, the period-to-period changes in the fair value of these contracts, as outlined above, are recognized in our statements of operations.

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Denbury Inc.

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

Production Expenses

Lease Operating Expenses



	Successor		Predecessor
	Period from Sept. 19, 2020 through		Period from July 1, 2020 through		Three Months Ended
In thousands, except per-BOE data	Sept. 30, 2020		Sept. 18, 2020		Sept. 30, 2019
Total lease operating expenses	$	11,484	$	59,708	$	117,850

Total lease operating expenses per BOE	$	19.20	$	15.03	$	22.70



	Successor		Predecessor
	Period from Sept. 19, 2020 through		Period from Jan. 1, 2020 through		Nine Months Ended
In thousands, except per-BOE data	Sept. 30, 2020		Sept. 18, 2020		Sept. 30, 2019
Total lease operating expenses	$	11,484	$	250,271	$	361,205

Total lease operating expenses per BOE	$	19.20	$	18.36	$	22.64

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

Currently, our CO₂ expense comprises approximately 20% to 25% of our typical tertiary lease operating expenses, and consists of CO₂ production expenses for the CO₂ reserves we own, and consists of our purchase of CO₂ from royalty and working interest owners and industrial sources for the CO₂ reserves we do not own. During the third quarters of 2020 and 2019, approximately 46% and 55%, respectively, of the CO₂ utilized in our CO₂ floods consisted of CO₂ owned and produced by us (our net revenue interest). The price we pay others for CO₂ varies by source and is generally indexed to oil prices. When combining the production cost of the CO₂ we own with what we pay third parties for CO₂, our average cost of CO₂ was approximately $0.37 per Mcf during the third quarter of 2020, including taxes paid on CO₂ production but excluding depletion, depreciation and amortization of capital expended at our CO₂ source fields and industrial sources. This per-Mcf CO₂ cost during the third quarter of 2020 was consistent with the third quarter of 2019 and lower than the $0.39 per Mcf comparable measure during the second quarter of 2020 due to a lower utilization in our Gulf Coast operations of industrial-sourced CO₂, which has a higher average cost than our naturally-occurring CO₂ source.

Transportation and Marketing Expenses

Transportation and marketing expenses primarily consist of amounts incurred relating to the transportation, marketing, and processing of oil and natural gas production. Transportation and marketing expenses were $9.5 million for the combined Predecessor

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Denbury Inc.

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

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

Taxes Other Than Income

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

General and Administrative Expenses (“G&A”)



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

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

Employees as of period end	663			662			826

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



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

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

Our net G&A expenses on an absolute-dollar basis were $16.7 million for the combined Predecessor and Successor periods included within the three months ended September 30, 2020, a decrease of $1.5 million (8%) from the three months ended September 30, 2019, and net G&A expenses on an absolute-dollar basis were $50.3 million for the combined Predecessor and Successor periods included within the nine months ended September 30, 2020, a decrease of $4.4 million (8%) from the nine months ended September 30, 2019. The decreases in net G&A expenses during 2020 compared to the three and nine month periods ended September 30, 2019, were primarily due to lower overall employee compensation and related costs due to reduced employee headcount, partially offset by lower G&A recoveries related to operator labor and overhead, and capitalized exploration and development costs which increased net G&A expense as a result of reductions in the number of employees, shut-in production and fewer producing wells in the current periods. On the Emergence Date, the Predecessor’s unvested shares were cancelled, resulting in the acceleration of stock compensation expense during the Predecessor period of $4.6 million; thereby, no stock-based compensation expense will be recognized in the Successor period until additional shares are granted. Also on the Emergence Date and pursuant to the terms of the Plan and the Confirmation Order, we adopted a framework for a management incentive plan which will reserve primarily for employees and directors a pool of shares of new common stock representing up to 10% of Denbury common stock, determined on a fully diluted and fully distributed basis, with initial awards from this pool scheduled to be issued within 60 days of emergence.

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

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

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Denbury Inc.

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

Interest and Financing Expenses



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



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

(1)

Cash interest includes the portion of interest on certain debt instruments accounted for as a reduction of debt for GAAP financial reporting purposes in accordance with FASC 470-60, Troubled Debt Restructuring by Debtors. The portion of interest treated as a reduction of debt related to the Predecessor’s 9% Senior Secured Second Lien Notes due 2021 and 9¼% Senior Secured Second Lien Notes due 2022. Amounts remaining in future interest payable were written-off to “Reorganization items, net” in the Unaudited Condensed Consolidated Statements of Operations on the Petition Date.

(2)

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


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


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

Cash interest was $18.1 million for the combined Predecessor and Successor periods included within the three months ended September 30, 2020, compared to $48.3 million during the three months ended September 30, 2019. Cash interest was $109.2 million for the combined Predecessor and Successor periods included within the nine months ended September 30, 2020, compared

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Denbury Inc.

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

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

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



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

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

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



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

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

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


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

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Denbury Inc.

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

DD&A expense was $41.6 million for the combined Predecessor and Successor periods included within the three months ended September 30, 2020, compared to $55.1 million during the three months ended September 30, 2019, with the decrease primarily due to a decrease in oil and natural gas properties depletion due to lower depletable costs, as well as lower CO₂ properties, pipelines, plants and other property and equipment DD&A as a result of lower CO₂ volumes from our CO₂ sources. DD&A expense was $193.9 million for the combined Predecessor and Successor periods included within the nine months ended September 30, 2020, compared to $170.6 million during the nine months ended September 30, 2019, with the increase primarily due to an accelerated depreciation charge of $37.4 million related to assets associated with impaired unevaluated properties that were transferred to the full cost pool during the first quarter of 2020, partially offset by a decrease in oil and natural gas properties depletion due to lower depletable costs, as well as lower CO₂ properties, pipelines, plants and other property and equipment DD&A as a result of lower CO₂ volumes from our CO₂ sources.

Full Cost Pool Ceiling Test

Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation. Under these rules, the full cost ceiling value is calculated using the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period. The first-day-of-the-month oil prices for the preceding 12 months, after adjustments for market differentials by field, averaged $40.08 per Bbl as of September 18, 2020, $44.74 per Bbl as of June 30, 2020 and $55.17 per Bbl as of March 31, 2020. In addition, the first-day-of-the-month natural gas prices for the preceding 12 months, after adjustments for market differentials by field, averaged $1.72 per MMBtu as of September 18, 2020, $1.91 per MMBtu as of June 30, 2020 and $1.68 per MMBtu as of March 31, 2020. While representative oil prices at March 31, 2020 were roughly consistent with adjusted prices used to calculate the December 31, 2019 full cost ceiling value, the decline in NYMEX oil prices in late March 2020 due to OPEC supply pressures and a reduction in worldwide oil demand amid the COVID-19 pandemic contributed to the impairment and transfer of $244.9 million of our unevaluated costs to the full cost amortization base during the three months ended March 31, 2020. Primarily as a result of adding these additional costs to the amortization base, we recognized a full cost pool ceiling test write-down of $72.5 million during the three months ended March 31, 2020. In addition, as a result of the precipitous decline in NYMEX oil prices, we recognized additional full cost pool ceiling test write-downs of $662.4 million during the three months ended June 30, 2020 and $261.7 million during the period from July 1, 2020 through September 18, 2020.

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

Impairment Assessment of Long-lived Assets

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

We perform our long-lived asset impairment test by comparing the net carrying costs of our two long-lived asset groups to the respective expected future undiscounted net cash flows that are supported by these long-lived assets which include production of our probable and possible oil and natural gas reserves. The portion of our capitalized CO₂ costs related to CO₂ reserves and CO₂ pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves is included in the full cost pool ceiling test as a reduction to future net revenues. The remaining net capitalized costs that are not included in the full cost pool ceiling test, and related intangible assets, are subject to long-lived asset impairment testing. These costs totaled approximately $1.3 billion as of March 31, 2020. If the undiscounted net cash flows are below the net carrying costs for an asset group, we must record an impairment loss by the amount, if any, that net carrying costs exceed the fair value of the long-lived asset group. The undiscounted net cash flows for our asset groups exceeded the net carrying costs; thus, step two of the impairment test was not required and no impairment was recorded.

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

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Denbury Inc.

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

Bbl beginning in 2026, and gas futures pricing were used for the March 31, 2020 analysis), projections of estimated quantities of oil and natural gas reserves, projections of future rates of production, timing and amount of future development and operating costs, projected availability and cost of CO₂, projected recovery factors of tertiary reserves and risk-adjustment factors applied to the cash flows. We performed a qualitative assessment as of June 30, 2020 and September 18, 2020 and determined there were no material changes to our key cash flow assumptions and no triggering events since the analysis performed as of March 31, 2020; therefore, no impairment test was performed for the second quarter of 2020 or for the period ending September 18, 2020.

Reorganization Items, Net

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



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

Other Expenses

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

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Denbury Inc.

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

Income Taxes



	Successor			Predecessor
	Period from Sept. 19, 2020 through			Period from July 1, 2020 through			Three Months Ended
In thousands, except per-BOE amounts and tax rates	Sept. 30, 2020			Sept. 18, 2020			Sept. 30, 2019
Current income tax expense (benefit)	$	6		$	(1,451	)	$	(859	)
Deferred income tax expense (benefit)	6			(302,356		)	37,909
Total income tax expense (benefit)	$	12		$	(303,807	)	$	37,050
Average income tax expense (benefit) per BOE	$	0.02		$	(76.47	)	$	7.13
Effective tax rate	0.4		%	27.3		%	33.7		%
Total net deferred tax liability	$	3,836					$	400,213



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

We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. Our income taxes are based on an estimated statutory rate of approximately 25% in 2020 and 2019. As provided for under FASC 740-270-35-2, we determined the actual effective tax rate for the Predecessor period from January 1, 2020 through September 18, 2020 was the best estimate of our annual effective tax rate. Our effective tax rate for the Predecessor period was lower than our estimated statutory rate, primarily due to the establishment of a valuation allowance on our federal and state deferred tax assets after the application of fresh start accounting.

We have evaluated the impact of the Plan of Reorganization, including the change in control, resulting from our emergence from bankruptcy. The cancellation of debt income (“CODI”) realized upon emergence is excludable from income but results in a reduction or elimination of available net operating loss carryforwards, tax credit carryforwards and tax basis in assets, in accordance with the attribute reduction and ordering rules of Section 108 of the Internal Revenue Code of 1986 (the “Code”). The reduction in the Company’s tax attributes for excludable CODI does not occur until the last day of the Company’s tax year, December 31, 2020. Accordingly, the tax adjustments recorded in the Predecessor period represent our best estimate using all available information at September 30, 2020. Thus, the Company expects to fully reduce its federal net operating loss carryforwards, enhanced oil recovery credits, research and development tax credits, and a partial reduction of tax basis in assets. The final tax impacts of the bankruptcy emergence, as well as the Plan of Reorganization’s overall effect on the Company’s tax attributes will be refined based on the Company’s final financial position at December 31, 2020 as required under the Code. The Company is exploring an election under the ordering rules of the Code to first reduce tax basis in assets, followed by net operating losses and tax credits. The final tax impact on the Company’s tax attributes could change from the current estimates.

As the tax basis of our assets, primarily our oil and gas properties, is in excess of the carrying value, as adjusted in fresh start accounting, the Successor is in a net deferred tax asset position. We evaluated our deferred tax assets in light of all available evidence as of the balance sheet date, including the tax impacts of the Chapter 11 Restructuring and the full reduction of net operating losses and tax credits and partial reduction of tax basis in assets (collectively “tax attributes”). Given our cumulative

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Denbury Inc.

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

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

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

Per-BOE Data

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



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


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

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


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

CRITICAL ACCOUNTING POLICIES

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

FORWARD-LOOKING INFORMATION

The data and/or statements contained in this Quarterly Report on Form 10-Q that are not historical facts, including, but not limited to, statements found in the section Management’s Discussion and Analysis of Financial Condition and Results of Operations, and information regarding the available sources of liquidity, possible or assumed future results of operations, and other plans and objectives for the future operations of Denbury, projections or assumptions as to general economic conditions, and anticipated continuation of the COVID-19 pandemic and its impact on U.S. and global oil demand are forward-looking statements, as that term is defined in Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, our ability to capitalize on emerging from bankruptcy and our ability to succeed on a long-term basis, the extent and length of the drop in worldwide oil demand due to the COVID-19 coronavirus, financial forecasts, future hydrocarbon prices and their volatility, current or future liquidity sources or their adequacy to support our anticipated future activities, possible future write-downs of oil and natural gas reserves, together with assumptions based on current and projected production levels, oil and gas prices and oilfield costs, current or future expectations or estimations of our cash flows or the impact of changes in commodity prices on cash flows, availability of capital, borrowing capacity, price and availability of advantageous commodity derivative contracts or the predicted cash flow benefits therefrom, forecasted capital expenditures, drilling activity or methods, including the timing and location thereof, the nature of any future asset purchases or sales or the timing or proceeds thereof, estimated timing of commencement of CO₂ flooding of particular fields or areas, timing of CO₂ injections and initial production responses in tertiary flooding projects, development activities, finding costs, anticipated future cost savings, capital budgets, interpretation or prediction of formation details, production rates and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO₂ reserves and supply and their availability, potential reserves, barrels or percentages of recoverable original oil in place, the impact of regulatory rulings or changes, outcomes of pending litigation, prospective legislation affecting the oil and gas industry, environmental regulations, mark-to-market values, competition, rates of return, estimated costs, changes in costs, future capital expenditures and overall economics, worldwide economic conditions, and other variables surrounding operations and future plans. Such forward-looking statements generally are accompanied by words such as “plan,” “estimate,” “expect,” “predict,” “forecast,” “to our knowledge,” “anticipate,” “projected,” “preliminary,” “should,” “assume,” “believe,” “may” or other words that convey, or are intended to convey, the uncertainty of future events or outcomes. Such forward-looking information is based upon management’s current plans, expectations, estimates, and assumptions and is subject to a number of risks and uncertainties that could significantly and adversely affect current plans, anticipated actions, the timing of such actions and our financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by us or on our behalf. Among the factors that could cause actual results to differ materially are fluctuations in worldwide oil prices or in U.S. oil prices and consequently in the prices received or demand for our oil and natural gas; decisions as to production levels and/or pricing by OPEC or production levels by U.S. shale producers in future periods; levels of future capital expenditures; 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 well incidents, hurricanes, tropical storms, floods, forest fires, or other natural occurrences; acquisition risks; requirements for capital or its availability; conditions in the worldwide financial, trade and credit markets; general economic conditions; competition; government regulations, including changes in tax or environmental laws or regulations; and unexpected delays, as well as the risks and uncertainties inherent in oil and gas drilling and production activities or that are otherwise discussed in this quarterly report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in our other public reports, filings and public statements including, without limitation, the Company’s most recent Form 10-K.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

Debt and Interest Rate Sensitivity

As of September 30, 2020, we had $85.0 million of outstanding borrowings under our Bank Credit Agreement. At this level of variable-rate debt, an increase or decrease of 10% in interest rates would have an immaterial effect on our interest expense. Our Bank Credit Agreement does not have any triggers or covenants regarding our debt ratings with rating agencies. The following table presents the principal and fair values of our outstanding debt as of September 30, 2020.



In thousands	2021		2022		2023		2024		Total		Fair Value
Variable rate debt:
Senior Secured Bank Credit Facility (weighted average interest rate of 4.0% at September 30, 2020)	$	—	$	—	$	—	$	85,000	$	85,000	$	85,000

See Note 6, Long-Term Debt, to the Unaudited Condensed Consolidated Financial Statements for details regarding our long-term debt.

Commodity Derivative Contracts

We enter into oil derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength, and expectation of future commodity prices. In order to provide a level of price protection to a portion of our oil production, we have hedged a portion of our estimated oil production through 2020 using both NYMEX and LLS fixed-price swaps and three-way collars and oil production in 2021 and the first half of 2022 using NYMEX fixed-price swaps. Depending on market conditions, we may continue to add to our existing 2021 and 2022 hedges. See also Note 10, Commodity Derivative Contracts, and Note 11, Fair Value Measurements, to the Unaudited Condensed Consolidated Financial Statements for additional information regarding our commodity derivative contracts. Under the terms of our Successor senior secured bank credit facility, at any point in time within the initial measurement period of August 1, 2020 through July 31, 2021, we are required to have hedges in place covering a minimum of 65% of our anticipated crude oil production for the first twelve calendar months and 35% of our anticipated crude oil production for the second twelve month period. We have until December 31, 2020 to enter into transactions for the initial measurement period to be in compliance.

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

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

At September 30, 2020, our commodity derivative contracts were recorded at their fair value, which was a net asset of $21.6 million, an $18.4 million decrease from the $40.0 million net asset recorded at June 30, 2020, and an $18.0 million increase from the $3.6 million net asset recorded at December 31, 2019. These changes are primarily related to the expiration or early termination of commodity derivative contracts during the three and nine months ended September 30, 2020, new commodity derivative contracts entered into during 2020 for future periods, and to the changes in oil futures prices between December 31, 2019 and September 30, 2020.

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Commodity Derivative Sensitivity Analysis

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



	Receipt / (Payment)
In thousands	Crude Oil Derivative Contracts
Based on:
Futures prices as of September 30, 2020	$	21,842
10% increase in prices	(3,200		)
10% decrease in prices	46,886

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

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Item 4. Controls and Procedures

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

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

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

The information under Note 12, Commitments and Contingencies, to the Unaudited Condensed Consolidated Financial Statements is incorporated herein by reference.

Item 1A. Risk Factors

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

We recently emerged from bankruptcy, which could adversely affect our business and relationships.

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


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


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


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


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


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

The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.

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

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

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

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

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

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

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

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

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

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

Prices in the oil market have remained depressed since March 2020. Oil prices are expected to continue to be volatile as a result of the near-term production instability, ongoing COVID-19 outbreaks, changes in oil inventories, industry demand and global and national economic performance.

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

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

Information regarding issuance on September 18, 2020 of new common stock and series A and B warrants to former debt and equity holders of the Predecessor upon cancellation of such debt and equity is contained in Item 3.02 of the Company’s Form 8-K filed with the Commission on September 18, 2020.

Item 3. Defaults Upon Senior Securities

Information regarding defaults upon senior securities is contained in Item 2.04 of the Company’s Form 8-K filed with the Commission on July 31, 2020.

Item 4. Mine Safety Disclosures

None.

Item 5. Other Information

None.

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Item 6. Exhibits



Exhibit No.		Exhibit
2(a)		Joint Chapter 11 Plan of Reorganization of Denbury Resources Inc. and its Debtor Affiliates (Technical Modifications) (incorporated by reference to Exhibit A of the Order Approving the Debtors’ Disclosure Statement For, and Confirming, the Debtors’ Joint Chapter 11 Plan of Reorganization of Denbury Resources Inc. and its Debtor Affiliates, filed as Exhibit 2.1 to Form 8-K filed by the Company on September 4, 2020, File No. 001-12935).
3(a)		Third Restated Certificate of Incorporation of Denbury Resources Inc. (incorporated by reference to Exhibit 3.1 of Form 8-K filed by the Company on September 18, 2020, File No. 001-12935).
3(b)		Fourth Amended and Restated Bylaws of Denbury Resources Inc., as of September 18, 2020 (incorporated by reference to Exhibit 3.2 of Form 8-K filed by the Company on September 18, 2020, File No. 001-12935).
4(a)		Series A Warrant Agreement, dated as of September 18, 2020, by and between Denbury Inc., and Broadridge Corporate Issuer Solutions, Inc. (incorporated by reference to Exhibit 10.2 of Form 8-K filed by the Company on September 18, 2020, File No. 001-12935).
4(b)		Series B Warrant Agreement, dated as of September 18, 2020, by and between Denbury Inc., and Broadridge Corporate Issuer Solutions, Inc. (incorporated by reference to Exhibit 10.3 of Form 8-K filed by the Company on September 18, 2020, File No. 001-12935).
4(c)		Registration Rights Agreement, dated as of September 18, 2020, among Denbury Inc. and certain holders identified therein (incorporated by reference to Exhibit 10.4 of Form 8-K filed by the Company on September 18, 2020, File No. 001-12935).
10(a)†		Credit Agreement, dated as of September 18, 2020, by and among Denbury Inc., as borrower, the lenders party thereto, and JPMorgan Chase Bank, N.A., as administrative agent, swingline lender, and letter of credit issuer (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on September 18, 2020, File No. 001-12935).
10(b)		Form of Indemnification Agreement, by and between Denbury Inc. and its officers and directors (incorporated by reference to Exhibit 10.5 of Form 8-K filed by the Company on September 18, 2020, File No. 001-12935).
31(a)*		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)*		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32**		Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*		Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH*		Inline XBRL Taxonomy Extension Schema Document
101.CAL*		Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*		Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*		Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE*		Inline XBRL Taxonomy Extension Presentation Linkbase Document

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104		The cover page from the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2020, has been formatted in Inline XBRL.


*	Included herewith.


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


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

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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.

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

November 16, 2020		/s/ Alan Rhoades
		Alan Rhoades Vice President and Chief Accounting Officer