Denbury 10Q 2021 Q1 Quarterly report

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 March 31, 2021

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

For the transition period from _______ to ________

Commission file number: 001-12935

DENBURY INC.

(Exact name of registrant as specified in its charter)

Delaware

20-0467835

(State or other jurisdiction of incorporation or organization)

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

5851 Legacy Circle,

Plano,

75024

(Address of principal executive offices)

(Zip Code)


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

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


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

Not applicable

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

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

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

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

Large accelerated filer

☐

Accelerated filer

☑

Non-accelerated filer

☐

Smaller reporting company

☑

Emerging growth company

☐

(Do not check if a smaller reporting company)

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

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

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

The number of shares outstanding of the registrant’s Common Stock, $.001 par value, as of April 30, 2021, was 50,006,643.

Denbury Inc.

Table of Contents

Page

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements

Unaudited Condensed Consolidated Balance Sheets

Unaudited Condensed Consolidated Statements of Operations

Unaudited Condensed Consolidated Statements of Cash Flows

Unaudited Condensed Consolidated Statements of Changes in Stockholders’ Equity

Notes to Unaudited Condensed Consolidated Financial Statements

Item 2.

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

Item 3.

Quantitative and Qualitative Disclosures about Market Risk

Item 4.

Controls and Procedures

PART II. OTHER INFORMATION

Unregistered Sales of Equity Securities and Use of Proceeds

Item 3.

Defaults Upon Senior Securities

Item 4.

Mine Safety Disclosures

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Denbury Inc.

Unaudited Condensed Consolidated Balance Sheets

(In thousands, except par value and share data)



	Successor
	March 31, 2021		December 31, 2020
Assets
Current assets
Cash and cash equivalents	$	5,647	$	518
Restricted cash	400		1,000
Accrued production receivable	128,171		91,421
Trade and other receivables, net	18,322		19,682
Derivative assets	236		187
Prepaids	9,043		14,038
Total current assets	161,819		126,846
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved properties	936,742		851,208
Unevaluated properties	86,878		85,304
CO2 properties	188,516		188,288
Pipelines	133,722		133,485
Other property and equipment	92,037		86,610
Less accumulated depletion, depreciation, amortization and impairment	(89,538)		(41,095)
Net property and equipment	1,348,357		1,303,800
Operating lease right-of-use assets	19,832		20,342
Derivative assets	3,021		0
Intangible assets, net	95,096		97,362
Other assets	93,035		86,408
Total assets	$	1,721,160	$	1,634,758
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	118,189	$	112,671
Oil and gas production payable	61,960		49,165
Derivative liabilities	129,124		53,865
Current maturities of long-term debt	51,499		68,008
Operating lease liabilities	2,660		1,350
Total current liabilities	363,432		285,059
Long-term liabilities
Long-term debt, net of current portion	75,000		70,000
Asset retirement obligations	223,465		179,338
Derivative liabilities	10,188		5,087
Deferred tax liabilities, net	1,224		1,274
Operating lease liabilities	18,961		19,460
Other liabilities	26,964		20,872
Total long-term liabilities	355,802		296,031
Commitments and contingencies (Note 8)	0		0
Stockholders’ equity
Preferred stock, $.001 par value, 50,000,000 shares authorized, none issued and outstanding	0		0
Common stock, $.001 par value, 250,000,000 shares authorized; 50,005,619 and 49,999,999 shares issued, respectively	50		50
Paid-in capital in excess of par	1,122,176		1,104,276
Accumulated deficit	(120,300)		(50,658)
Total stockholders’ equity	1,001,926		1,053,668
Total liabilities and stockholders’ equity	$	1,721,160	$	1,634,758

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
	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020

Revenues and other income
Oil, natural gas, and related product sales	$	235,445	$	229,624
CO2 sales and transportation fees	9,228		8,028
Oil marketing revenues	6,126		3,721
Other income	360		828
Total revenues and other income	251,159		242,201
Expenses
Lease operating expenses	81,970		109,270
Transportation and marketing expenses	7,797		9,621
CO2 operating and discovery expenses	993		752
Taxes other than income	18,963		19,686
Oil marketing expenses	6,085		3,661
General and administrative expenses	31,983		9,733
Interest, net of amounts capitalized of $1,083 and $9,452, respectively	1,536		19,946
Depletion, depreciation, and amortization	39,450		96,862
Commodity derivatives expense (income)	115,743		(146,771)
Gain on debt extinguishment	0		(18,994)
Write-down of oil and natural gas properties	14,377		72,541

Other expenses	2,146		2,494
Total expenses	321,043		178,801
Income (loss) before income taxes	(69,884)		63,400
Income tax benefit	(242)		(10,616)
Net income (loss)	$	(69,642)	$	74,016

Net income (loss) per common share
Basic	$	(1.38)	$	0.15
Diluted	$	(1.38)	$	0.14

Weighted average common shares outstanding
Basic	50,319		494,259
Diluted	50,319		586,190

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
	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020

Cash flows from operating activities
Net income (loss)	$	(69,642)	$	74,016
Adjustments to reconcile net income (loss) to cash flows from operating activities

Depletion, depreciation, and amortization	39,450		96,862
Write-down of oil and natural gas properties	14,377		72,541
Deferred income taxes	(51)		(4,209)
Stock-based compensation	17,680		2,453
Commodity derivatives expense (income)	115,743		(146,771)
Receipt (payment) on settlements of commodity derivatives	(38,453)		24,638
Gain on debt extinguishment	0		(18,994)
Debt issuance costs and discounts	685		4,926
Other, net	727		(673)
Changes in assets and liabilities, net of effects from acquisitions
Accrued production receivable	(36,750)		66,937
Trade and other receivables	865		(22,914)
Other current and long-term assets	(2,542)		2,539
Accounts payable and accrued liabilities	(1,402)		(72,607)
Oil and natural gas production payable	12,795		(15,948)
Other liabilities	(826)		(954)
Net cash provided by operating activities	52,656		61,842

Cash flows from investing activities
Oil and natural gas capital expenditures	(19,627)		(46,016)
Acquisitions of oil and natural gas properties	(10,665)		(42)
Pipelines and plants capital expenditures	(458)		(6,294)
Net proceeds from sales of oil and natural gas properties and equipment	3		40,543
Other	(2,916)		(4,479)
Net cash used in investing activities	(33,663)		(16,288)

Cash flows from financing activities
Bank repayments	(202,000)		(161,000)
Bank borrowings	207,000		161,000
Interest payments treated as a reduction of debt	0		(18,211)
Cash paid in conjunction with debt repurchases	0		(14,171)


Pipeline financing debt repayments	(16,509)		(3,690)
Other	(3,013)		(2,953)
Net cash used in financing activities	(14,522)		(39,025)
Net increase in cash, cash equivalents, and restricted cash	4,471		6,529
Cash, cash equivalents, and restricted cash at beginning of period	42,248		33,045
Cash, cash equivalents, and restricted cash at end of period	$	46,719	$	39,574

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						Shares	Amount		Total Equity
Balance – December 31, 2020 (Successor)	49,999,999	$	50	$	1,104,276	$	(50,658)	—	$	—	$	1,053,668
Stock-based compensation	—	—		19,172		—		—	—		19,172
Tax withholding for stock compensation plans	—	—		(1,467)		—		—	—		(1,467)
Issued pursuant to exercise of warrants	5,620	0		195		—		—	—		195
Net loss	—	—		—		(69,642)		—	—		(69,642)
Balance – March 31, 2021 (Successor)	50,005,619	$	50	$	1,122,176	$	(120,300)	—	$	—	$	1,001,926


	Common Stock ($.001 Par Value)			Paid-In Capital in Excess of Par		Retained Earnings (Accumulated Deficit)		Treasury Stock (at cost)
	Shares	Amount						Shares	Amount		Total Equity
Balance – December 31, 2019 (Predecessor)	508,065,495	$	508	$	2,739,099	$	(1,321,314)	1,652,771	$	(6,034)	$	1,412,259
Issued pursuant to stock compensation plans	312,516	—		—		—		—	—		—
Issued pursuant to directors’ compensation plan	37,367	—		—		—		—	—		—
Stock-based compensation	—	—		3,204		—		—	—		3,204
Tax withholding for stock compensation plans	—	—		—		—		175,673	(34)		(34)
Net income	—	—		—		74,016		—	—		74,016
Balance – March 31, 2020 (Predecessor)	508,415,378	508		2,742,303		(1,247,298)		1,828,444	(6,068)		1,489,445
Canceled pursuant to stock compensation plans	(6,218,868)	(6)		6		—		—	—		—
Issued pursuant to notes conversion	7,357,450	8		11,453		—		—	—		11,461
Stock-based compensation	—	—		987		—		—	—		987
Net loss	—	—		—		(697,474)		—	—		(697,474)
Balance – June 30, 2020 (Predecessor)	509,553,960	510		2,754,749		(1,944,772)		1,828,444	(6,068)		804,419
Canceled pursuant to stock compensation plans	(95,016)	—		—		—		—	—		—
Issued pursuant to notes conversion	14,800	—		40		—		—	—		40
Stock-based compensation	—	—		10,126		—		—	—		10,126
Tax withholding for stock compensation plans	—	—		—		—		567,189	(134)		(134)
Net loss	—	—		—		(809,120)		—	—		(809,120)
Cancellation of Predecessor equity	(509,473,744)	(510)		(2,764,915)		2,753,892		(2,395,633)	6,202		(5,331)
Issuance of Successor equity	49,999,999	50		1,095,369		—		—	—		1,095,419
Balance – September 18, 2020 (Predecessor)	49,999,999	$	50	$	1,095,369	$	—	—	$	—	$	1,095,419


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

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 1. Basis of Presentation

Organization and Nature of Operations

Denbury Inc. (“Denbury,” “Company” or the “Successor”), a Delaware corporation, is an independent energy company with operations and assets focused on carbon capture, use, and storage (“CCUS”) and enhanced oil recovery (“EOR”) in the Gulf Coast and Rocky Mountain regions. For over two decades, the Company has maintained a unique strategic focus on utilizing CO2 in its EOR operations and since 2012 has also been active in CCUS through the injection of captured industrial-sourced CO2. The Company currently injects captured industrial-sourced CO2, and its objective is to fully offset its Scope 1, 2, and 3 CO2 emissions within this decade, primarily through increasing the amount of captured industrial-sourced CO2 used in its operations.

Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code

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

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

Interim Financial Statements

The accompanying unaudited condensed consolidated financial statements of Denbury Inc. and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) and do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2020 (the “Form 10-K”). Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company” or “Denbury,” refer to Denbury Inc. and its subsidiaries.

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end, and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year. In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair presentation of our consolidated financial position as of March 31, 2021 (Successor); our consolidated results of operations and consolidated cash flows for the three months ended March 31, 2021 (Successor) and March 31, 2020 (Predecessor); and our consolidated statements of changes in stockholders’ equity for the three months ended March 31, 2021 (Successor), for the period January 1, 2020 through September 18, 2020 (Predecessor), and for the period September 19, 2020 through December 31, 2020 (Successor). Upon the adoption of fresh start accounting, the Company’s assets and liabilities were recorded at their fair values as of the fresh start reporting date. As a result of the adoption of fresh start accounting, certain values and operational results of the Company’s condensed consolidated financial statements

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Denbury Inc.

Notes to Unaudited 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.

Reclassifications

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

Cash, Cash Equivalents, and Restricted Cash

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


	Successor
In thousands	March 31, 2021		December 31, 2020
Cash and cash equivalents	$	5,647	$	518
Restricted cash, current	400		1,000
Restricted cash included in other assets	40,672		40,730
Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows	$	46,719	$	42,248

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

Net Income (Loss) per Common Share

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

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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


	Successor		Predecessor
In thousands	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
Numerator
Net income (loss) – basic	$	(69,642)	$	74,016
Effect of potentially dilutive securities
Interest on convertible senior notes including amortization of discount, net of tax	0		5,857
Net income (loss) – diluted	$	(69,642)	$	79,873

Denominator
Weighted average common shares outstanding – basic	50,319		494,259
Effect of potentially dilutive securities



Restricted stock and performance-based equity awards	0		1,078
Convertible senior notes(1)	0		90,853
Weighted average common shares outstanding – diluted	50,319		586,190

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

Basic weighted average common shares during the Successor period includes performance stock units with vesting parameters tied to the Company’s common stock trading prices and which became fully vested on March 3, 2021. Although the performance measures for vesting of these awards have been achieved, the shares underlying these awards are not currently outstanding as actual delivery of the shares is not scheduled to occur until after the end of the performance period, December 4, 2023. Basic weighted average common shares during the Predecessor period included time-vesting restricted stock that vested during the period. For purposes of calculating diluted weighted average common shares for the three months ended March 31, 2020, diluted weighted average common shares includes nonvested time-based and performance-based equity awards using the treasury stock method, and for the shares underlying the convertible senior notes as if the convertible senior notes were converted at the beginning of 2020.

The following securities were excluded from the computation of diluted net income (loss) per share, as their effect would have been antidilutive:


	Successor	Predecessor
In thousands	Three Months Ended March 31, 2021	Three Months Ended March 31, 2020
Restricted stock units	466	0
Warrants	5,525	0
Stock appreciation rights	0	1,528
Nonvested time-based restricted stock and performance-based equity awards	0	14,007

For the Successor period, the Company’s restricted stock units and series A and series B warrants were antidilutive based on the Company’s net loss position for the period. At March 31, 2021, the Company has approximately 5.5 million warrants outstanding that can be exercised for shares of the Successor’s common stock, at an exercise price of $32.59 per share for the 2.6 million series A warrants and at an exercise price of $35.41 per share for the 2.9 million series B warrants. The warrants were issued pursuant to the Plan to holders of the Predecessor’s convertible senior notes, senior subordinated notes, and equity. As of March 31, 2021, 6,384 series B warrants and no series A warrants had been exercised. The warrants may be exercised for

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

cash or on a cashless basis. If warrants are exercised on a cashless basis the amount of dilution will be less than 5.5 million shares.

Oil and Natural Gas Properties

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

Write-Down of Oil and Natural Gas Properties. Under full cost accounting, the net capitalized costs of oil and natural gas properties are limited to the lower of unamortized cost or the cost center ceiling. The cost center ceiling is defined as (1) the present value of estimated future net revenues from proved oil and natural gas reserves before future abandonment costs (discounted at 10%), based on the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period; plus (2) the cost of properties not being amortized; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) related income tax effects. Our future net revenues from proved oil and natural gas reserves are not reduced for development costs related to the cost of drilling for and developing CO2 reserves nor those related to the cost of constructing CO2 pipelines, as we do not have to incur additional costs to develop the proved oil and natural gas reserves. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes. The cost center ceiling test is prepared quarterly.

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

Recent Accounting Pronouncements

Recently Adopted

Income Taxes. In December 2019, the Financial Accounting Standards Board (“FASB”) issued ASU 2019-12, Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes (“ASU 2019-12”). The objective of ASU 2019-12 is to simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740 and to provide more consistent application to improve the comparability of financial statements. Effective January 1, 2021, we adopted ASU 2019-02. The implementation of this standard did not have a material impact on our consolidated financial statements and related footnote disclosures.

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 2. Acquisition

On March 3, 2021, we acquired a nearly 100% working interest (approximately 83% net revenue interest) in the Big Sand Draw and Beaver Creek EOR fields located in Wyoming from a subsidiary of Devon Energy Corporation for $10.7 million cash (before final closing adjustments), including surface facilities and a 46-mile CO2 transportation pipeline to the acquired fields. The acquisition agreement provides for us to make two contingent cash payments, one in January 2022 and one in January 2023, of $4 million each, conditioned on NYMEX WTI oil prices averaging at least $50 per Bbl during 2021 and 2022, respectively.

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


In thousands
Consideration:
Cash consideration	$	10,657

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

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

Note 3. 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 point and the customer takes delivery and possession, we are entitled to payment and we invoice the customer for such delivered production. Payment under most oil and CO2 contracts is received within a month following product delivery and for natural gas and NGL contracts payment is generally received within two months following delivery. Timing of revenue recognition may differ from the timing of invoicing to customers; however, as the right to consideration after delivery is unconditional based on only the passage of time before payment of the consideration is due, upon delivery we record a receivable in “Accrued production receivable” in our Unaudited Condensed Consolidated Balance Sheets. From time to time, the Company enters into marketing arrangements for the purchase and sale of crude oil for third parties. Revenues and expenses from these transactions are presented on a gross basis, as we act as a principal in the transaction by assuming control of the commodities purchased and responsibility to deliver the commodities sold. Revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser.

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Notes to Unaudited Condensed Consolidated Financial Statements

Disaggregation of Revenue

The following table summarizes our revenues by product type:


	Successor		Predecessor

In thousands	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
Oil sales	$	233,044	$	228,577
Natural gas sales	2,401		1,047
CO2 sales and transportation fees	9,228		8,028
Oil marketing revenues	6,126		3,721
Total revenues	$	250,799	$	241,373

Note 4. Long-Term Debt

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


	Successor
In thousands	March 31, 2021		December 31, 2020
Senior Secured Bank Credit Agreement	$	75,000	$	70,000
Pipeline financings	51,499		68,008
Total debt principal balance	126,499		138,008
Less: current maturities of long-term debt	(51,499)		(68,008)
Long-term debt	$	75,000	$	70,000

Senior Secured Bank Credit Agreement

On the Emergence Date, we entered into a 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. Availability under the Bank Credit Agreement is subject to a borrowing base, which is redetermined semiannually on or around May 1 and November 1 of each year, with our next scheduled redetermination around November 1, 2021. The borrowing base is adjusted at the lenders’ discretion and is based, in part, upon external factors over which we have no control. If our outstanding debt under the Bank Credit Agreement exceeds the then-effective borrowing base, we would be required to repay the excess amount over a period not to exceed six months. The Bank Credit Agreement matures on January 30, 2024. The weighted average interest rate on borrowings outstanding as of March 31, 2021 under the Bank Credit Agreement was 4.0%. The undrawn portion of the aggregate lender commitments under the Bank Credit Agreement is subject to a commitment fee of 0.5% per annum.

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

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Notes to Unaudited Condensed Consolidated Financial Statements

The Bank Credit Agreement contains certain financial performance covenants including the following:

•A Consolidated Total Debt to Consolidated EBITDAX covenant (as defined in the Bank Credit Agreement), with such ratio not to exceed 3.5 times; and

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

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

Pipeline Financing Transactions

During the first quarter of 2021, Denbury paid $17.5 million to Genesis Energy, L.P. in the first of four quarterly installments totaling $70 million to be paid during 2021 in accordance with the October 2020 restructuring of our NEJD CO2 pipeline system. The second quarterly installment of $17.5 million was paid in April 2021, and the remaining quarterly payments are payable on July 31 and October 31, 2021.

Note 5. Income Taxes

We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. Our income taxes are based on an estimated combined federal and state statutory rate of approximately 25% in 2021 and 2020. Our effective tax rate for the Successor period ended March 31, 2021 differed from our estimated statutory rate as the deferred tax benefit generated from our operating loss was offset by a valuation allowance applied to our underlying federal and state deferred tax assets.

Note 6. Commodity Derivative Contracts

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

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

We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Bank Credit Agreement (or affiliates of such lenders). As of March 31, 2021, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables

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Notes to Unaudited Condensed Consolidated Financial Statements

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 March 31, 2021, none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic:


Months	Index Price	Volume (Barrels per day)	Contract Prices ($/Bbl)
			Range(1)				Weighted Average Price
							Swap		Floor		Ceiling
Oil Contracts:
2021 Fixed-Price Swaps
Apr – Dec	NYMEX	29,000	$	38.68	–	56.00	$	43.86	$	—	$	—
2021 Collars
Apr – Dec	NYMEX	4,000	$	45.00	–	59.30	$	—	$	46.25	$	53.04
2022 Fixed-Price Swaps
Jan – June	NYMEX	13,500	$	42.65	–	57.13	$	47.69	$	—	$	—
July – Dec	NYMEX	5,000		50.13	–	57.13	54.72		—		—
2022 Collars
Jan – Dec	NYMEX	3,000	$	47.50	–	61.60	$	—	$	49.17	$	58.03

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

Note 7. Fair Value Measurements

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

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

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

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Notes to Unaudited Condensed Consolidated Financial Statements

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

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


	Fair Value Measurements Using:
In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
March 31, 2021
Assets
Oil derivative contracts – current	$	0	$	236	$	0	$	236
Oil derivative contracts – long-term	0		3,021		0		3,021
Total Assets	$	0	$	3,257	$	0	$	3,257

Liabilities
Oil derivative contracts – current	$	0	$	(129,124)	$	0	$	(129,124)
Oil derivative contracts – long-term	0		(10,188)		0		(10,188)
Total Liabilities	$	0	$	(139,312)	$	0	$	(139,312)

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

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

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

Other Fair Value Measurements

The carrying value of our loans under our Bank Credit Agreement approximate fair value, as they are subject to short-term floating interest rates that approximate the rates available to us for those periods. The estimated fair value of the principal amount of our debt as of March 31, 2021 and December 31, 2020, excluding pipeline financing obligations, was $75.0 million and $70.0 million. We have other financial instruments consisting primarily of cash, cash equivalents, U.S. Treasury notes, short-term receivables and payables that approximate fair value due to the nature of the instrument and the relatively short maturities.

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Notes to Unaudited Condensed Consolidated Financial Statements

Note 8. 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. On April 23, 2021, the Bankruptcy Court entered a final decree closing the Chapter 11 case captioned “In re Denbury Resources Inc., et al., Case No. 20-33801”, so all of the Chapter 11 cases have been closed.

Litigation

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

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

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

The following discussion and analysis should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and Notes thereto included herein and our Consolidated Financial Statements and Notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2020 (the “Form 10-K”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K. Any terms used but not defined herein have the same meaning given to them in the Form 10-K.

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

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

OVERVIEW

Denbury is an independent energy company with operations and assets focused on carbon capture, use, and storage (“CCUS”) and enhanced oil recovery (“EOR”) in the Gulf Coast and Rocky Mountain regions. For over two decades, the Company has maintained a unique strategic focus on utilizing CO2 in its EOR operations and since 2012 has also been active in CCUS through the injection of captured industrial-sourced CO2. The Company currently injects over three million tons of captured industrial-sourced CO2 annually, and its objective is to fully offset its Scope 1, 2, and 3 CO2 emissions within this decade, primarily through increasing the amount of captured industrial-sourced CO2 used in its operations.

Oil Price Impact on Our Business. Our financial results are significantly impacted by changes in oil prices, as 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 selected financial items and production, along with changes in our realized oil prices, before and after commodity derivative impacts, for our most recent comparative periods:


	Successor				Predecessor
	Three Months Ended				Three Months Ended March 31, 2020
In thousands, except per-unit data	March 31, 2021		December 31, 2020
Oil, natural gas, and related product sales	$	235,445	$	178,787		$	229,624
Receipt (payment) on settlements of commodity derivatives	(38,453)		14,429			24,638
Oil, natural gas, and related product sales and commodity settlements, combined	$	196,992	$	193,216		$	254,262

Average daily production (BOE/d)	47,357		48,805			55,965

Average net realized prices
Oil price per Bbl - excluding impact of derivative settlements	$	56.28	$	40.63		$	45.96
Oil price per Bbl - including impact of derivative settlements	47.00		43.94			50.92

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

NYMEX WTI oil prices strengthened from the mid-$40s per Bbl range in December 2020 to an average of approximately $58 per Bbl during the first quarter of 2021, reaching highs of over $66 per Bbl in March 2021.

First Quarter 2021 Financial Results and Highlights. We recognized a net loss of $69.6 million, or $1.38 per diluted common share, during the first quarter of 2021, compared to net income of $74.0 million, or $0.14 per diluted common share, during the first quarter of 2020. The principal determinant of our comparative first quarter results between 2020 and 2021 was the $262.5 million increase in commodity derivatives expense ($115.7 million of expense during the first quarter of 2021 compared to $146.8 million of income during the first quarter of 2020), resulting from a $199.4 million loss on noncash fair value changes and a $63.1 million decrease in cash receipts upon contract settlements ($38.5 million in payments during the first quarter of 2021 compared to $24.6 million in receipts upon settlements during the first quarter of 2020). Additional drivers of the comparative operating results were the following:

•Oil and natural gas revenues increased $5.8 million (3%), as the increase in commodity prices was largely offset by production declines;

•A $14.4 million full cost pool ceiling test write-down during the first quarter of 2021 compared to a $72.5 million write-down in the prior-year period;

•A reduction in depletion, depreciation, and amortization expense of $57.4 million as a result of a $37.4 million accelerated depreciation charge recorded in the first quarter of 2020 and lower depletable costs due to the step down in book value resulting from fresh start accounting on the Emergence Date;

•A $27.3 million reduction in lease operating expense across nearly all expense categories with the largest decrease in power and fuel ($16.0 million) primarily associated with the severe winter storm in February 2021 which created significant power outages in Texas and disrupted the Company’s operations. Other significant drivers included lower workover costs ($3.2 million) and a decrease of $4.4 million due to the Gulf Coast Working Interests Sale in March 2020;

•A $22.3 million increase in general and administrative expense in the first quarter of 2021 primarily due to non-recurring stock-based compensation expense of $15.3 million in the first quarter of 2021 due to 100% vesting of performance awards upon the achievement of specified common stock trading price levels;

•An $18.4 million reduction in net interest expense resulting from the full extinguishment of senior secured second lien notes, convertible senior notes, and senior subordinated notes pursuant to the terms of the prepackaged joint plan of reorganization completed in September 2020; and

•A noncash gain on debt extinguishment of $19.0 million in the first quarter of 2020.

March 2021 Acquisition of Wyoming CO2 EOR Fields. On March 3, 2021, we acquired a nearly 100% working interest (approximately 83% net revenue interest) in the Big Sand Draw and Beaver Creek EOR fields (collectively “Wind River Basin”) located in Wyoming from a subsidiary of Devon Energy Corporation for $10.7 million cash (before final closing adjustments), including surface facilities and a 46-mile CO2 transportation pipeline to the acquired fields. The acquisition agreement provides for us to make two contingent cash payments, one in January 2022 and one in January 2023, of $4 million each, conditioned on NYMEX WTI oil prices averaging at least $50 per Bbl during 2021 and 2022, respectively. As of March 31, 2021, the contingent consideration was recorded on our unaudited condensed consolidated balance sheets at its fair value of $5.3 million. Wind River Basin production averaged approximately 2,700 BOE/d from the March 3, 2021 acquisition date through March 31, 2021, contributing 871 BOE/d to first quarter of 2021 average daily production.

Carbon Capture, Use and Storage. In addition to our oil and natural gas operations, our strategically located and extensive CO2 pipeline infrastructure provides a meaningful opportunity to participate in the emerging CCUS industry. We believe that the assets and technical expertise required for CCUS are highly aligned with our existing CO2 EOR operations, providing us with an advantage, particularly in the Gulf Coast region, where our CO2 infrastructure is located in close proximity to multiple large sources of industrial emissions. During the first quarter of 2021, approximately 36% of the CO2 utilized in our oil and gas operations was industrial-sourced CO2, and we anticipate this percentage could increase in the future as supportive U.S. government policy and public pressure on industrial CO2 emitters will provide strong incentives for these entities to capture their CO2 emissions. In an effort to proactively pursue these new CCUS opportunities, we have begun engaging in discussions with third-party industrial CO2 emitters regarding transportation and storage solutions and identifying future sequestration sites and landowners of those locations. While our financial and operational results today do not reflect activities associated with the emerging CCUS industry, and development of this business is likely to take several years, we believe Denbury is well positioned to leverage our existing CO2 pipeline infrastructure and EOR expertise to be a leader in this industry.

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

CAPITAL RESOURCES AND LIQUIDITY

Overview. Our primary sources of capital and liquidity are our cash flows from operations and availability under our senior secured bank credit facility. Our most significant cash outlays relate to our development capital expenditures and current period operating expenses, as well as our pipeline financing obligations associated with the NEJD pipeline. During the first quarter of 2021, Denbury paid $17.5 million to Genesis Energy, L.P. in the first of four quarterly installments totaling $70.0 million to be paid during 2021 in accordance with the restructuring of our NEJD CO2 pipeline system. The second quarterly installment of $17.5 million was paid in April 2021, and the remaining quarterly payments are payable on July 31 and October 31, 2021.

As of March 31, 2021, we had $75 million of outstanding borrowings on our $575 million senior secured bank credit facility, leaving us with $477.0 million of borrowing base availability after consideration of $23.0 million of outstanding letters of credit. Our borrowing base availability coupled with unrestricted cash of $5.6 million, provides us total liquidity of $482.6 million as of March 31, 2021, which is more than adequate to meet our currently planned operating and capital needs.

2021 Plans and Capital Budget. Considering the current oil price environment and strategic importance of the EOR CO2 flood at Cedar Creek Anticline (“CCA”), we announced in February 2021 our plans to move forward with development of this significant long-term project. We expect to spend approximately $150 million in 2021 on this CCA development, consisting of approximately $100 million dedicated to the 105-mile extension of the Greencore CO2 pipeline from Bell Creek to CCA, with the remainder dedicated to facilities, well work and field development at CCA. Based on our current plans, most of the capital spend for the pipeline extension to CCA will occur in the second half of 2021, with completion of the pipeline expected by the end of 2021, first CO2 injection planned during the first half of 2022, and first tertiary production expected in the second half of 2023. We currently anticipate that our full-year 2021 development capital spending, excluding capitalized interest and acquisitions, will be in a range of $250 million to $270 million. Our current 2021 capital budget, excluding capitalized interest and acquisitions, at the $260 million midpoint level is as follows:

•$100 million for the 105-mile extension of the Greencore CO2 pipeline to CCA;

•$50 million for CCA tertiary well work, facilities, and field development;

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

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

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

Based on these capital spending plans, we currently anticipate 2021 average daily production to be between 47,500 BOE/d and 51,500 BOE/d, including the Big Sand Draw and Beaver Creek working interests acquisition which closed in early March 2021.

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

Capital Expenditure Summary. The following table reflects incurred capital expenditures (including accrued capital) for the three months ended March 31, 2021 and 2020:


	Three Months Ended
	March 31,
In thousands	2021		2020
Capital expenditure summary
CCA tertiary development	$	36	$	1,354
Other tertiary oil fields	4,080		13,372
Non-tertiary fields	8,342		10,954
Capitalized internal costs(1)	7,600		8,881
Oil and natural gas capital expenditures	20,058		34,561
CCA CO2 pipeline	21		4,175
Other CO2 pipelines, sources and other	—		49
Development capital expenditures	20,079		38,785
Acquisitions of oil and natural gas properties(2)	10,665		42
Capital expenditures, before capitalized interest	30,744		38,827
Capitalized interest	1,083		9,452
Capital expenditures, total	$	31,827	$	48,279

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

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

Based on current oil prices and the Company’s hedge positions, we expect that our 2021 cash flows from operations will exceed our budgeted level of planned development capital expenditures; nonetheless, we may seek other sources of funding or fund any potential shortfall with incremental borrowings under our senior secured bank credit facility.

Senior Secured Bank Credit Agreement. In September 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 a maturity date of January 30, 2024. As part of our spring 2021 semiannual borrowing base redetermination, the borrowing base and lender commitments for our Bank Credit Agreement were reaffirmed at $575 million, with our next scheduled redetermination around November 2021. The borrowing base is adjusted at the lenders’ discretion and is based, in part, upon external factors over which we have no control. 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 contains certain financial performance covenants including the following:

•A Consolidated Total Debt to Consolidated EBITDAX covenant (as defined in the Bank Credit Agreement), with such ratio not to exceed 3.5 times; and

•A requirement to maintain a current ratio (i.e., Consolidated Current Assets to Consolidated Current Liabilities) of 1.0 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 the Bank Credit Agreement, and Consolidated Current Liabilities exclude the current portion of derivative liabilities as well as the current portions of long-term indebtedness outstanding. Under these financial performance covenant calculations, as of March 31, 2021, our ratio of consolidated total debt to consolidated EBITDAX was 0.38 to 1.0 (with a maximum permitted ratio of 3.5 to 1.0) and our current ratio was 3.49 to 1.0 (with a required ratio of not less than 1.0 to 1.0). Based upon our currently forecasted levels of

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

production and costs, hedges in place as of May 5, 2021, and current oil commodity derivative futures prices, we currently anticipate continuing to be in compliance with our financial performance covenants during the foreseeable future.

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

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

Our commitments and obligations consist of those detailed as of December 31, 2020, in our Form 10-K under Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Commitments, Obligations and Off-Balance Sheet Arrangements. During the three months ended March 31, 2021, our long-term asset retirement obligations increased by $44.1 million, primarily related to our acquisition of working interest positions in Wyoming CO2 EOR fields (see Note 2, Acquisition).

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

Certain of our financial and operating results and statistics for the comparative three months ended March 31, 2021 and 2020 are included in the following table:


	Successor		Predecessor
In thousands, except per-share and unit data	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
Financial results
Net income (loss)	$	(69,642)	$	74,016
Net income (loss) per common share – basic	(1.38)		0.15
Net income (loss) per common share – diluted	(1.38)		0.14
Net cash provided by operating activities	52,656		61,842
Average daily production volumes
Bbls/d	46,007		54,649
Mcf/d	8,102		7,899
BOE/d(1)	47,357		55,965
Oil and natural gas sales
Oil sales	$	233,044	$	228,577
Natural gas sales	2,401		1,047
Total oil and natural gas sales	$	235,445	$	229,624
Commodity derivative contracts(2)
Receipt (payment) on settlements of commodity derivatives	$	(38,453)	$	24,638
Noncash fair value gains (losses) on commodity derivatives	(77,290)		122,133
Commodity derivatives income (expense)	$	(115,743)	$	146,771
Unit prices – excluding impact of derivative settlements
Oil price per Bbl	$	56.28	$	45.96
Natural gas price per Mcf	3.29		1.46
Unit prices – including impact of derivative settlements(2)
Oil price per Bbl	$	47.00	$	50.92
Natural gas price per Mcf	3.29		1.46
Oil and natural gas operating expenses
Lease operating expenses	$	81,970	$	109,270
Transportation and marketing expenses	7,797		9,621
Production and ad valorem taxes	17,895		17,987
Oil and natural gas operating revenues and expenses per BOE
Oil and natural gas revenues	$	55.24	$	45.09
Lease operating expenses	19.23		21.46
Transportation and marketing expenses	1.83		1.89
Production and ad valorem taxes	4.20		3.53
CO2 – revenues and expenses
CO2 sales and transportation fees	$	9,228	$	8,028
CO2 operating and discovery expenses	(993)		(752)
CO2 revenue and expenses, net	$	8,235	$	7,276

(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.

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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 2020 and for the first quarter of 2021 is shown below:


	Average Daily Production (BOE/d)
	First Quarter	First Quarter	Second Quarter	Third Quarter	Fourth Quarter
Operating Area	2021	2020	2020	2020	2020
Tertiary oil production
Gulf Coast region
Delhi	2,925	3,813	3,529	3,208	3,132
Hastings	4,226	5,232	4,722	4,473	4,598
Heidelberg	4,054	4,371	4,366	4,256	4,198
Oyster Bayou	3,554	3,999	3,871	3,526	3,880
Tinsley	3,424	4,355	3,788	4,042	3,654
Other(1)	6,098	7,161	5,944	6,271	6,332
Total Gulf Coast region	24,281	28,931	26,220	25,776	25,794
Rocky Mountain region
Bell Creek	4,614	5,731	5,715	5,551	5,079
Other(2)	2,573	2,199	1,393	2,167	2,007
Total Rocky Mountain region	7,187	7,930	7,108	7,718	7,086
Total tertiary oil production	31,468	36,861	33,328	33,494	32,880
Non-tertiary oil and gas production
Gulf Coast region



Total Gulf Coast region	3,621	4,173	3,805	3,728	3,523
Rocky Mountain region
Cedar Creek Anticline	11,150	13,046	11,988	11,485	11,433
Other(2)	1,118	1,105	1,069	979	969
Total Rocky Mountain region	12,268	14,151	13,057	12,464	12,402
Total non-tertiary production	15,889	18,324	16,862	16,192	15,925
Total continuing production	47,357	55,185	50,190	49,686	48,805
Property sales
Gulf Coast Working Interests Sale(3)	—	780	—	—	—
Total production	47,357	55,965	50,190	49,686	48,805

(1)Other Gulf Coast properties primarily consist of mature properties (Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb and Soso fields) and West Yellow Creek Field.

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

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

Total production during the first quarter of 2021 averaged 47,357 BOE/d, including 31,468 Bbls/d from tertiary properties and 15,889 BOE/d from non-tertiary properties. This production level represents a decrease of 1,448 BOE/d (3%) compared to production levels in the fourth quarter of 2020 and a decrease of 7,828 BOE/d (14%) compared to first quarter of 2020 continuing production, which is adjusted to exclude production related to our Gulf Coast Working Interests Sale in March 2020. The decreases on a sequential-quarter and year-over-year period basis included the impact of weather-related downtime of approximately 1,400 BOE/d resulting from the February 2021 winter storms that impacted the Gulf Coast region, with the year-over-year decline more significantly impacted by reduced capital investment and declines at Delhi Field due to lower CO2 purchases between late-February and late-October 2020 as a result of the Delta-Tinsley pipeline being down for repair. The

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

sequential-quarter production decline was partially offset by production increases from Wind River Basin enhanced oil recovery fields acquired on March 3, 2021. Wind River Basin production averaged approximately 2,700 BOE/d from the March 3, 2021 acquisition date through March 31, 2021, contributing 871 BOE/d to first quarter of 2021 average daily production.

Our production during the three months ended March 31, 2021 was 97% oil, slightly lower than our 98% oil production during the prior-year period.

Oil and Natural Gas Revenues

Our oil and natural gas revenues during the three months ended March 31, 2021 increased 3% compared to these revenues for the same period in 2020. 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
	March 31,
	2021 vs. 2020
In thousands	Increase (Decrease) in Revenues		Percentage Increase (Decrease) in Revenues
Change in oil and natural gas revenues due to:
Decrease in production	$	(37,455)	(16)	%
Increase in realized commodity prices	43,276		19	%
Total increase in oil and natural gas revenues	$	5,821	3	%

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


	Three Months Ended
	March 31,
	2021		2020
Average net realized prices
Oil price per Bbl	$	56.28	$	45.96
Natural gas price per Mcf	3.29		1.46
Price per BOE	55.24		45.09
Average NYMEX differentials
Gulf Coast region
Oil per Bbl	$	(1.37)	$	1.18
Natural gas per Mcf	0.68		(0.06)
Rocky Mountain region
Oil per Bbl	$	(1.80)	$	(2.78)
Natural gas per Mcf	0.49		(0.91)
Total Company
Oil per Bbl	$	(1.54)	$	(0.38)
Natural gas per Mcf	0.58		(0.41)

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 $1.37 per Bbl during the first quarter of 2021, compared to a positive $1.18 per Bbl during the first quarter of 2020 and a negative

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

$1.85 per Bbl during the fourth quarter of 2020. For both the first quarter of 2020 and for many years prior, our Gulf Coast region differentials have generally been positive to NYMEX due to historically higher prices received for Gulf Coast crudes, such as Light Louisiana Sweet crude oil. As a result of the market disruptions, storage constraints and weak demand caused by the COVID-19 coronavirus (“COVID-19”) pandemic, these differentials weakened significantly during 2020 and the first quarter of 2021.

•Rocky Mountain Region. NYMEX oil differentials in the Rocky Mountain region averaged $1.80 per Bbl and $2.78 per Bbl below NYMEX during the first quarters of 2021 and 2020, respectively, and $2.30 per Bbl below NYMEX during the fourth quarter of 2020. Differentials in the Rocky Mountain region tend to fluctuate with regional supply and demand trends and can fluctuate significantly on a month-to-month basis due to weather, refinery or transportation issues, and Canadian and U.S. crude oil price index volatility.

CO2 Revenues and Expenses

We sell 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 table summarizes the impact our crude oil derivative contracts had on our operating results for the three months ended March 31, 2021 and 2020:


	Successor		Predecessor

In thousands	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
Receipt (payment) on settlements of commodity derivatives	$	(38,453)	$	24,638
Noncash fair value gains (losses) on commodity derivatives	(77,290)		122,133
Total income (expense)	$	(115,743)	$	146,771

Changes in our commodity derivatives expense were primarily related to the expiration of commodity derivative contracts, new commodity derivative contracts entered into for future periods, and to the changes in oil futures prices between the first quarter of 2020 and 2021. The period-to-period change reflects the very large fluctuations in oil prices between March 2020 ($30.45 per barrel), when worldwide financial markets were first beginning to absorb the potential impact of a global pandemic, and March 2021 oil prices ($62.36 per barrel) as prospects for increased economic activity and oil demand continue to improve.

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

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derivative contracts as of March 31, 2021, and Item 3, Quantitative and Qualitative Disclosures about Market Risk below for additional discussion. In addition, the following table summarizes our commodity derivative contracts as of May 5, 2021:


		2Q 2021	2H 2021	1H 2022	2H 2022
WTI NYMEX	Volumes Hedged (Bbls/d)	29,000	29,000	15,500	8,000
Fixed-Price Swaps	Swap Price(1)	$43.86	$43.86	$49.01	$55.85
WTI NYMEX	Volumes Hedged (Bbls/d)	4,000	4,000	8,000	7,000
Collars	Floor / Ceiling Price(1)	$46.25 / $53.04	$46.25 / $53.04	$49.69 / $62.16	$49.64 / $61.66
	Total Volumes Hedged (Bbls/d)	33,000	33,000	23,500	15,000

(1)Averages are volume weighted.

Based on current contracts in place and NYMEX oil futures prices as of May 5, 2021, which averaged approximately $64 per Bbl, we currently expect that we would make cash payments of approximately $175 million upon settlement of our April through December 2021 contracts, the amount of which is primarily dependent upon fluctuations in future NYMEX oil prices in relation to the prices of our 2021 fixed-price swaps which have a weighted average NYMEX oil price of $43.69 per Bbl. Changes in commodity prices, expiration of contracts, and new commodity contracts entered into cause fluctuations in the estimated fair value of our oil derivative contracts. Because we do not utilize hedge accounting for our commodity derivative contracts, the period-to-period changes in the fair value of these contracts, as outlined above, are recognized in our statements of operations.

Production Expenses

Lease Operating Expenses


	Successor		Predecessor

In thousands, except per-BOE data	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
Total lease operating expenses	$	81,970	$	109,270

Total lease operating expenses per BOE	$	19.23	$	21.46

Total lease operating expenses decreased $27.3 million (25%) on an absolute-dollar basis, or $2.23 (10%) on a per-BOE basis, during the three months ended March 31, 2021, compared to the same prior-year period. The decrease on an absolute-dollar basis was primarily due to lower expenses across nearly all expense categories, with the largest decreases attributable to power and fuel ($16.0 million), workovers ($3.2 million), and an approximate $4.4 million decrease due to the Gulf Coast Working Interests Sale in March 2020. The significant reduction in power and fuel costs is associated with the severe winter storm in February 2021 which created significant power outages in Texas and disrupted the Company’s operations. Under certain of the Company’s power agreements the Company is compensated for its reduced power usage, which resulted in a benefit to the Company of approximately $14.9 million ($4.2 million included in “Trade and other receivables, net” and $10.7 million included in “Other assets” in our Unaudited Condensed Consolidated Balance Sheets). When netting the impacts on our production and revenues and other incremental costs from the winter storm with this benefit, we estimate the overall impact to our first quarter results was a positive $6 million. Lease operating expenses in periods subsequent to the first quarter will return to higher levels as this adjustment is not expected to reoccur. Compared to the fourth quarter of 2020, lease operating expenses decreased $7.8 million (9%) on an absolute-dollar basis and $0.76 (4%) on a per-BOE basis, due to the utility benefit mentioned above, partially offset by minor increases across various expense categories, as well as to the acquisition of the Big Sand Draw and Beaver Creek fields in March 2021.

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 $7.8 million and $9.6 million for the three months ended March 31, 2021 and 2020. The decrease between periods was primarily due to lower marketing expenses.

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

Taxes Other Than Income

Taxes other than income includes production, ad valorem and franchise taxes. Taxes other than income were relatively unchanged during the three months ended March 31, 2021, compared to the same prior-year period, as the increase in production taxes resulting from higher oil and natural gas revenues was offset by the decrease in ad valorem taxes.

General and Administrative Expenses (“G&A”)


	Successor		Predecessor

In thousands, except per-BOE data and employees	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
Cash administrative costs	$	14,303	$	7,280
Stock-based compensation	17,680		2,453
G&A expense	$	31,983	$	9,733

G&A per BOE
Cash administrative costs	$	3.35	$	1.43
Stock-based compensation	4.15		0.48
G&A expenses	$	7.50	$	1.91

Employees as of period end	677		718

Our net G&A expense on an absolute-dollar basis was $32.0 million during the three months ended March 31, 2021, an increase of $22.3 million from the same prior-year period, primarily due to cash and noncash performance-based compensation. Net cash administrative costs increased during the three months ended March 31, 2021 primarily due to a $13.2 million increase in our bonus expense, compared to no expense for bonuses during the first quarter of 2020, partially offset by lower employee-related costs due to lower headcount. During the first quarter of 2021, certain performance-based equity awards with vesting parameters tied to the Company’s common stock trading prices became fully vested, resulting in $15.3 million of stock-based compensation expense. The awards were granted on December 4, 2020, and although the performance measures for vesting of these awards have been achieved, the shares underlying these awards are not currently outstanding as actual delivery of the shares is not scheduled to occur until after the end of the performance period, December 4, 2023.

Interest and Financing Expenses


	Successor			Predecessor
In thousands, except per-BOE data and interest rates	Three Months Ended March 31, 2021			Three Months Ended March 31, 2020
Cash interest(1)	$	1,934		$	45,826
Less: interest not reflected as expense for financial reporting purposes(1)	—			(21,354)
Noncash interest expense	685			1,031
Amortization of debt discount(2)	—			3,895
Less: capitalized interest	(1,083)			(9,452)
Interest expense, net	$	1,536		$	19,946
Interest expense, net per BOE	$	0.36		$	3.92
Average debt principal outstanding(3)	$	135,396		$	2,187,615
Average cash interest rate(4)	5.7		%	8.4		%

(1)Cash interest during the Predecessor period includes the portion of interest on certain debt instruments accounted for as a reduction of debt for GAAP financial reporting purposes in accordance with FASC 470-60, Troubled Debt Restructuring

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by Debtors. The portion of interest treated as a reduction of debt related to the Predecessor’s 9% Senior Secured Second Lien Notes due 2021 (the “2021 Notes”) and 9¼% Senior Secured Second Lien Notes due 2022 (the “2022 Notes”). Amounts related to the 2021 Notes and 2022 Notes remaining in future interest payable were written-off on July 30, 2020 (the “Petition Date”).

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

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

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

Cash interest during the three months ended March 31, 2021 was $1.9 million, compared to $45.8 million in the same prior-year period. The decrease between periods was primarily due to a decrease in the average debt principal outstanding, with the Successor period reflecting the full extinguishment of all outstanding obligations under our previously outstanding senior secured second lien notes, convertible senior notes, and senior subordinated notes on the Emergence Date, pursuant to the terms of the prepackaged joint plan of reorganization, relieving us of approximately $2.1 billion of debt by issuing equity and/or warrants in the Successor period to the holders of that debt.

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


	Successor		Predecessor

In thousands, except per-BOE data	Three Months Ended March 31, 2021		Three Months Ended March 31, 2020
Oil and natural gas properties	$	32,015	$	42,569
CO2 properties, pipelines, plants and other property and equipment	7,435		16,925
Accelerated depreciation charge(1)	—		37,368
Total DD&A	$	39,450	$	96,862

DD&A per BOE
Oil and natural gas properties	$	7.51	$	8.36
CO2 properties, pipelines, plants and other property and equipment	1.75		3.32
Accelerated depreciation charge(1)	—		7.34
Total DD&A cost per BOE	$	9.26	$	19.02

Write-down of oil and natural gas properties	$	14,377	$	72,541

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

The decrease in DD&A expense during the three months ended March 31, 2021, when compared to the same period in 2020, was primarily due to accelerated depreciation of $37.4 million related to unevaluated properties that were transferred to the full cost pool during the prior-year period and lower depletable costs due to the step down in book value resulting from fresh start accounting as of September 18, 2020.

Full Cost Pool Ceiling Test Write-Downs

Under full cost accounting rules, we are required each quarter to perform a ceiling test calculation. Under these rules, the full cost ceiling value is calculated using the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period prior to the end of a particular reporting period. We recognized a full cost pool ceiling test write-down of $14.4 million during the three months ended March 31, 2021, with first-day-of-the-month NYMEX oil prices for the preceding 12 months averaging $36.40 per Bbl, after adjustments for market differentials and transportation expenses by field. The write-down was primarily a result of the recent acquisition (see Overview – March 2021 Acquisition of Wyoming CO2 EOR

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Fields) which was recorded based on a valuation that utilized NYMEX strip oil prices at the acquisition date, which were significantly higher than the average first-day-of-the-month NYMEX oil prices used to value the cost ceiling. We also recognized a full cost pool ceiling test write-down of $72.5 million during the three months ended March 31, 2020.

Income Taxes


	Successor			Predecessor

In thousands, except per-BOE amounts and tax rates	Three Months Ended March 31, 2021			Three Months Ended March 31, 2020
Current income tax benefit	$	(191)		$	(6,407)
Deferred income tax benefit	(51)			(4,209)
Total income tax benefit	$	(242)		$	(10,616)
Average income tax benefit per BOE	$	(0.05)		$	(2.09)
Effective tax rate	0.3		%	(16.7)		%
Total net deferred tax liability	$	1,224		$	406,021

We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. Our income taxes are based on an estimated combined federal and state statutory rate of approximately 25% in 2021 and 2020. Our effective tax rate for the Successor period ended March 31, 2021 was significantly lower than our estimated statutory rate, primarily due to our overall deferred tax asset position and the valuation allowance offsetting those assets. As we had a pre-tax loss for the first quarter of 2021, the income tax benefit resulting from that loss is fully offset by the change in valuation allowance, resulting in essentially no tax provision.

The tax basis of our assets, primarily our oil and gas properties, is in excess of their carrying value, as adjusted in fresh start accounting, therefore we are currently in a net deferred tax asset position. Based on all available evidence, both positive and negative, we continue to record a valuation allowance on our underlying deferred tax assets as of March 31, 2021, as we believe our deferred tax assets are not more-likely-than-not to be realized and, as such, we have a total valuation allowance of $122.5 million recorded at March 31, 2021. We intend to maintain the valuation allowances on our deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of the allowances, which will largely be determined based on oil prices and the Company’s ability to generate positive pre-tax income. A $1.2 million state deferred tax liability is recorded on the Successor balance sheet.

The current income tax benefits for the Predecessor period represent amounts estimated to be receivable resulting from alternative minimum tax credits and certain state tax obligations.

As of March 31, 2021, we had $0.6 million of alternative minimum tax credits, which under the Tax Cut and Jobs Act will be refunded in 2021 and are recorded as a receivable on the balance sheet. Our state net operating loss carryforwards expire in various years, starting in 2025.

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Denbury Inc.

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

Per-BOE Data

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


	Three Months Ended
	March 31,
Per-BOE data	2021		2020
Oil and natural gas revenues	$	55.24	$	45.09
Receipt (payment) on settlements of commodity derivatives	(9.02)		4.84
Lease operating expenses	(19.23)		(21.46)
Production and ad valorem taxes	(4.20)		(3.53)
Transportation and marketing expenses	(1.83)		(1.89)
Production netback	20.96		23.05
CO2 sales, net of operating and discovery expenses	1.94		1.43
General and administrative expenses(1)	(7.50)		(1.91)
Interest expense, net	(0.36)		(3.92)

Stock compensation and other	3.85		1.92
Changes in assets and liabilities relating to operations	(6.54)		(8.43)
Cash flows from operations	12.35		12.14
DD&A – excluding accelerated depreciation charge	(9.26)		(11.68)
DD&A – accelerated depreciation charge(2)	—		(7.34)
Write-down of oil and natural gas properties	(3.37)		(14.24)
Deferred income taxes	0.01		0.83
Gain on extinguishment of debt	—		3.73
Noncash fair value gains (losses) on commodity derivatives	(18.14)		23.98

Other noncash items	2.07		7.11
Net income (loss)	$	(16.34)	$	14.53

(1)General and administrative expenses include $15.3 million of performance stock-based compensation related to the full vesting of outstanding performance awards during the three months ended March 31, 2021, resulting in a significant non-recurring expense in the current quarter, which if excluded, would have caused these expenses to average $3.92 per BOE.

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

CRITICAL ACCOUNTING POLICIES

For additional discussion of our critical accounting policies, see Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Form 10-K. Any new accounting policies 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”),

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

that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, the timing and sustainability of the recent recovery in worldwide oil prices from their COVID-19 coronavirus caused downturn, financial forecasts, future hydrocarbon prices and their volatility, current or future liquidity sources or their adequacy to support our anticipated future activities, statement or predictions related to the scope, timing and economic aspects of the carbon capture, use and storage industry, 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, including Cedar Creek Anticline (“CCA”), or the availability of capital for CCA pipeline construction, or its ultimate cost or date of completion, timing of CO2 injections and initial production responses in tertiary flooding projects, development activities, finding costs, anticipated future cost savings, capital budgets, interpretation or prediction of formation details, production rates and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO2 reserves and supply and their availability, potential reserves, barrels or percentages of recoverable original oil in place, 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 March 31, 2021, we had $75.0 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 March 31, 2021.


In thousands	2021		2022		2023		2024		Total		Fair Value
Variable rate debt:
Senior Secured Bank Credit Facility (weighted average interest rate of 4.0% at March 31, 2021)	$	—	$	—	$	—	$	75,000	$	75,000	$	75,000

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

Commodity Derivative Contracts

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

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

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

At March 31, 2021, our commodity derivative contracts were recorded at their fair value, which was a net liability of $136.1 million, a $77.3 million increase from the $58.8 million net liability recorded at December 31, 2020. These changes are primarily related to the expiration of commodity derivative contracts during the three months ended March 31, 2021, new commodity derivative contracts entered into during 2021 for future periods, and to the changes in oil futures prices between December 31, 2020 and March 31, 2021.

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Commodity Derivative Sensitivity Analysis

Based on NYMEX crude oil futures prices as of March 31, 2021, and assuming both a 10% increase and decrease thereon, we would expect to make payments on our crude oil derivative contracts outstanding at March 31, 2021 as shown in the following table:


	Receipt / (Payment)
In thousands	Crude Oil Derivative Contracts
Based on:
Futures prices as of March 31, 2021	$	(135,517)
10% increase in prices	(208,279)
10% decrease in prices	(64,848)

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 March 31, 2021, to ensure that information that is required to be disclosed in the reports the Company files and submits under the Securities Exchange Act of 1934 is recorded, that it is processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and that information that is required to be disclosed under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

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

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

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

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

None.

Item 5. Other Information

None.

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Item 6. Exhibits


Exhibit No.						Exhibit
31(a)*						Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b)*						Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32**						Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*						Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH*						Inline XBRL Taxonomy Extension Schema Document
101.CAL*						Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*						Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*						Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE*						Inline XBRL Taxonomy Extension Presentation Linkbase Document
104						The cover page from the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2021, has been formatted in Inline XBRL.

* Included herewith.

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

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SIGNATURES

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


						DENBURY INC.

May 6, 2021						/s/ Mark C. Allen
						Mark C. Allen Executive Vice President and Chief Financial Officer

May 6, 2021						/s/ Nicole Jennings
						Nicole Jennings Vice President and Chief Accounting Officer

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Denbury (DNRWW) 10-Q2021 Q1 Quarterly report

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