DENBURY INC - Quarter Report: 2022 March (Form 10-Q)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2022

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

For the transition period from _______ to ________

Commission file number: 001-12935

DENBURY INC.

(Exact name of registrant as specified in its charter)

Delaware

20-0467835

(State or other jurisdiction of incorporation or organization)

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

5851 Legacy Circle,

Plano,

75024

(Address of principal executive offices)

(Zip Code)


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

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


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

Not applicable

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

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

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

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

Large accelerated filer

☑

Accelerated filer

☐

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

(Do not check if a smaller reporting company)

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

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

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

The number of shares outstanding of the registrant’s Common Stock, $.001 par value, as of April 30, 2022, was 50,369,023.

Denbury Inc.

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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)



	March 31, 2022		December 31, 2021
Assets
Current assets
Cash and cash equivalents	$	517	$	3,671
Accrued production receivable	216,161		143,365
Trade and other receivables, net	17,571		19,270

Prepaids	10,175		9,099
Total current assets	244,424		175,405
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved properties	1,149,762		1,109,011
Unevaluated properties	131,677		112,169
CO2 properties	184,043		183,369
Pipelines	226,766		224,394
CCUS storage sites and related assets	20,949		—
Other property and equipment	94,993		93,950
Less accumulated depletion, depreciation, amortization and impairment	(210,537)		(181,393)
Net property and equipment	1,597,653		1,541,500
Operating lease right-of-use assets	18,595		19,502
Derivative assets	265		—
Deferred tax assets, net	4,306		—
Intangible assets, net	85,966		88,248
Restricted cash for future asset retirement obligations	46,695		46,673
Other assets	33,445		31,625
Total assets	$	2,031,349	$	1,902,953
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	201,598	$	191,598
Oil and gas production payable	99,247		75,899
Derivative liabilities	223,598		134,509

Operating lease liabilities	4,683		4,677
Total current liabilities	529,126		406,683
Long-term liabilities
Long-term debt, net of current portion	35,000		35,000
Asset retirement obligations	282,792		284,238
Derivative liabilities	10,837		—
Deferred tax liabilities, net	—		1,638
Operating lease liabilities	16,095		17,094
Other liabilities	19,850		22,910
Total long-term liabilities	364,574		360,880
Commitments and contingencies (Note 8)
Stockholders’ equity
Preferred stock, $.001 par value, 50,000,000 shares authorized, none issued and outstanding	—		—
Common stock, $.001 par value, 250,000,000 shares authorized; 50,349,390 and 50,193,656 shares issued, respectively	50		50
Paid-in capital in excess of par	1,133,127		1,129,996
Retained earnings	4,472		5,344
Total stockholders’ equity	1,137,649		1,135,390
Total liabilities and stockholders’ equity	$	2,031,349	$	1,902,953

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)


	Three Months Ended March 31,
	2022		2021
Revenues and other income
Oil, natural gas, and related product sales	$	384,911	$	235,445
CO2 sales and transportation fees	13,422		9,228
Oil marketing revenues	13,276		6,126
Other income	250		360
Total revenues and other income	411,859		251,159
Expenses
Lease operating expenses	117,828		81,970
Transportation and marketing expenses	4,645		7,797
CO2 operating and discovery expenses	2,817		993
Taxes other than income	31,381		18,963
Oil marketing purchases	13,040		6,085
General and administrative expenses	18,692		31,983
Interest, net of amounts capitalized of $1,158 and $1,083, respectively	657		1,536
Depletion, depreciation, and amortization	35,345		39,450
Commodity derivatives expense	192,719		115,743

Write-down of oil and natural gas properties	—		14,377
Other expenses	2,112		2,146
Total expenses	419,236		321,043
Loss before income taxes	(7,377)		(69,884)
Income tax benefit	(6,505)		(242)
Net loss	$	(872)	$	(69,642)

Net loss per common share
Basic	$	(0.02)	$	(1.38)
Diluted	$	(0.02)	$	(1.38)

Weighted average common shares outstanding
Basic	51,602		50,319
Diluted	51,602		50,319

See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.

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Denbury Inc.

Unaudited Condensed Consolidated Statements of Cash Flows

(In thousands)


	Three Months Ended March 31,
	2022		2021
Cash flows from operating activities
Net loss	$	(872)	$	(69,642)
Adjustments to reconcile net loss to cash flows from operating activities
Depletion, depreciation, and amortization	35,345		39,450
Write-down of oil and natural gas properties	—		14,377
Deferred income taxes	(5,944)		(51)
Stock-based compensation	2,971		17,680
Commodity derivatives expense	192,719		115,743
Payment on settlements of commodity derivatives	(93,057)		(38,453)
Debt issuance costs	685		685
Other, net	(1,267)		727
Changes in assets and liabilities, net of effects from acquisitions
Accrued production receivable	(72,795)		(36,750)
Trade and other receivables	1,644		865
Other current and long-term assets	189		(2,542)
Accounts payable and accrued liabilities	11,410		(1,402)
Oil and natural gas production payable	23,348		12,795
Other liabilities	(4,233)		(826)
Net cash provided by operating activities	90,143		52,656

Cash flows from investing activities
Oil and natural gas capital expenditures	(58,707)		(19,627)
CCUS storage sites and related capital expenditures	(14,900)		—
Acquisitions of oil and natural gas properties	—		(10,665)
Pipelines and plants capital expenditures	(15,204)		(458)

Other	(1,396)		(2,913)
Net cash used in investing activities	(90,207)		(33,663)

Cash flows from financing activities
Bank repayments	(274,000)		(202,000)
Bank borrowings	274,000		207,000

Pipeline financing repayments	—		(16,509)
Other	(3,068)		(3,013)
Net cash used in financing activities	(3,068)		(14,522)
Net increase (decrease) in cash, cash equivalents, and restricted cash	(3,132)		4,471
Cash, cash equivalents, and restricted cash at beginning of period	50,344		42,248
Cash, cash equivalents, and restricted cash at end of period	$	47,212	$	46,719

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)
	Shares	Amount						Total Equity
Balance – December 31, 2021	50,193,656	$	50	$	1,129,996	$	5,344		$	1,135,390











Issued pursuant to stock compensation plans	141,581	0		—		—			0
Stock-based compensation	—	—		3,142		—			3,142
Tax withholding for stock compensation plans	—	—		(58)		—			(58)
Issued pursuant to exercise of warrants	14,153	0		47		—			47
Net loss	—	—		—		(872)			(872)
Balance – March 31, 2022	50,349,390	$	50	$	1,133,127	$	4,472		$	1,137,649


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

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., a Delaware corporation, is an independent energy company with operations focused in the Gulf Coast and Rocky Mountain regions of the United States. The Company is differentiated by its focus on CO2 enhanced oil recovery (“EOR”) and the emerging carbon capture, use, and storage (“CCUS”) industry, supported by the Company’s CO2 EOR technical and operational expertise and its extensive CO2 pipeline infrastructure.

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, 2021 (the “Form 10-K”). Unless indicated otherwise or the context requires, the terms “we,” “our,” “us,” “Company” or “Denbury,” refer to Denbury Inc. and its subsidiaries.

Accounting measurements at interim dates inherently involve greater reliance on estimates than at year end, and the results of operations for the interim periods shown in this report are not necessarily indicative of results to be expected for the year. In management’s opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for a fair presentation of our consolidated financial position as of March 31, 2022, our consolidated results of operations for the three months ended March 31, 2022 and 2021, our consolidated cash flows for the three months ended March 31, 2022 and 2021, and our consolidated statements of changes in stockholders’ equity for the three months ended March 31, 2022 and 2021.

Reclassifications

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

Cash, Cash Equivalents, and Restricted Cash

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


In thousands	March 31, 2022		December 31, 2021
Cash and cash equivalents	$	517	$	3,671

Restricted cash for future asset retirement obligations	46,695		46,673
Total cash, cash equivalents, and restricted cash shown in the Unaudited Condensed Consolidated Statements of Cash Flows	$	47,212	$	50,344

Restricted cash for future asset retirement obligations in the table above consists of escrow accounts that are legally restricted for certain of our asset retirement obligations.

Net Income (Loss) per Common Share

Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Basic weighted average common shares exclude shares of nonvested restricted stock (although nonvested restricted stock is issued and outstanding upon grant). As these restricted shares vest, they will be included in the shares outstanding used to calculate basic net income (loss) per common share. Restricted stock units and performance stock units are also excluded from basic weighted

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

average common shares outstanding until the vesting date. Basic weighted average common shares during the three months ended March 31, 2022 includes 1,404,649 performance-based and restricted stock units which are fully vested as of March 31, 2022. Although vesting criteria for these awards have been achieved, the shares underlying these awards are not currently issued or outstanding as actual delivery of the shares is not scheduled to occur until December 4, 2023.

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

For each of the three months ended March 31, 2022 and 2021, there were no adjustments to net income (loss) for purposes of calculating basic and diluted net income (loss) per common share.

For the three months ended March 31, 2022 and 2021, the weighted average common shares outstanding used to calculate basic earnings per share and diluted earnings per share were the same, since the Company recorded net losses each period. Assuming the Company had recorded net income during the three months ended March 31, 2022 and 2021, the weighted average diluted shares outstanding would have been 55.0 million (including the impact of 0.6 million restricted stock units and 2.8 million shares with respect to warrants) and 51.2 million (including the impact of 0.5 million restricted stock units and 0.4 million shares with respect to warrants), respectively.

The following outstanding securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss) per share for the three months ended March 31, 2022 and 2021, as their effect would have been antidilutive, as of the respective dates:


	March 31,
In thousands	2022	2021
Restricted stock, restricted stock units and performance stock units	1,005	1,276

Warrants	5,162	5,520

At March 31, 2022, the Company had approximately 5.2 million warrants outstanding that can be exercised for shares of our common stock, at an exercise price of $32.59 per share for the 2.6 million series A warrants outstanding and at an exercise price of $35.41 per share for the 2.6 million series B warrants outstanding. The series A warrants are exercisable until September 18, 2025, and the series B warrants are exercisable until September 18, 2023, at which time the warrants expire. As of March 31, 2022, 12,294 series A warrants and 352,442 series B warrants have been exercised for a total of 207,810 shares, as the warrants may be exercised for cash or on a cashless basis.

Oil and Natural Gas Properties

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 CO2 capital costs to develop the proved oil and natural gas reserves. Therefore, we include in the ceiling test, as a reduction of future net revenues, that portion of our capitalized CO2 costs related to CO2 reserves and CO2 pipelines that we estimate will be consumed in the process of producing our proved oil and natural gas reserves. The fair value of our oil and natural gas derivative contracts is not included in the ceiling test, as we do not designate these contracts as hedge instruments for accounting purposes. The cost center ceiling test is prepared quarterly.

We recognized a full cost pool ceiling test write-down of $14.4 million during the three months ended March 31, 2021, with first-day-of-the-month NYMEX oil prices for the preceding 12 months averaging $36.40 per Bbl, after adjustments for market differentials and transportation expenses by field. The write-down was primarily a result of the March 2021 acquisition of Wyoming property interests (see Note 2, Acquisition) which was recorded based on a valuation that utilized NYMEX strip

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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 did not record a ceiling test write-down during the three months ended March 31, 2022.

CCUS Storage Sites and Related Assets

Capitalized Costs. Beginning with our financial statements for the three months ended March 31, 2022, we have capitalized various costs that we incur to acquire and develop storage sites for the injection of CO2. These costs generally include, or are expected to include, expenditures for acquiring surface and subsurface rights; third-party acquisition costs; permitting; drilling; facilities; environmental monitoring equipment for groundwater and storage site gas; engineering; capitalized interest; on-site road construction and other capital infrastructure costs. If a storage site is no longer deemed probable of being developed, all previously capitalized costs are expensed.

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

Note 2. Acquisition

Acquisition of Wyoming CO2 EOR Fields

On March 3, 2021, we acquired a nearly 100% working interest (approximately 83% net revenue interest) in the Big Sand Draw and Beaver Creek EOR fields located in Wyoming from a subsidiary of Devon Energy Corporation, including surface facilities and a 46-mile CO2 transportation pipeline to the acquired fields. The acquisition purchase price was $10.9 million (after final closing adjustments) plus two contingent $4 million cash payments if NYMEX WTI oil prices average at least $50 per Bbl during each of 2021 and 2022. We made the first contingent payment in January 2022 and if the price condition is met, the second $4 million payment will be due in January 2023. The fair value of the contingent consideration recorded on our Unaudited Condensed Consolidated Balance Sheets was $3.9 million as of March 31, 2022.

The fair values allocated to our assets acquired and liabilities assumed for the acquisition, based on significant inputs not observable in the market and considered level 3 inputs, were finalized during the third quarter of 2021, after consideration of final closing adjustments and evaluation of reserves and liabilities assumed. The following table presents a summary of the fair value of assets acquired and liabilities assumed in the acquisition:


In thousands
Consideration:
Cash consideration	$	10,906

Less: Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	60,101
Other property and equipment	1,685
Asset retirement obligations	(39,794)
Contingent consideration	(5,320)
Other liabilities	(5,766)
Fair value of net assets acquired	$	10,906

Note 3. Revenue Recognition

We record revenue in accordance with Financial Accounting Standards Board (“FASB”) Codification (“FASC”) Topic 606, Revenue from Contracts with Customers. The core principle of FASC Topic 606 is that an entity should recognize revenue for the transfer of goods or services equal to the amount of consideration that it expects to be entitled to receive for those goods or services. Once we have delivered the volume of commodity to the delivery point and the customer takes delivery and possession, we are entitled to payment and we invoice the customer for such delivered production. Payment under most oil and

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

CO2 contracts is received within one 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. In certain situations, the Company enters into marketing arrangements for the purchase and subsequent sale of crude oil from third parties. We recognize the revenues received and the associated expenses incurred on these sales on a gross basis, as “Oil marketing revenues” and “Oil marketing purchases” in our Unaudited Condensed Consolidated Statements of Operations, since we act as a principal in the transaction by assuming control of the commodities purchased and responsibility to deliver the commodities sold. Revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser.

Disaggregation of Revenue

The following table summarizes our revenues by product type for the three months ended March 31, 2022 and 2021:


	Three Months Ended
	March 31,
In thousands	2022		2021
Oil sales	$	381,242	$	233,044
Natural gas sales	3,669		2,401
CO2 sales and transportation fees	13,422		9,228
Oil marketing revenues	13,276		6,126
Total revenues	$	411,609	$	250,799

Note 4. Long-Term Debt

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


In thousands	March 31, 2022		December 31, 2021
Senior Secured Bank Credit Agreement	$	35,000	$	35,000



Long-term debt	$	35,000	$	35,000

Senior Secured Bank Credit Agreement

On September 18, 2020, we entered into a $575 million credit agreement for a senior secured revolving credit facility with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the “Bank Credit Agreement”). On May 4, 2022, we entered into a Second Amendment to the Bank Credit Agreement, which among other things:

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

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

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

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

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, 2022. The borrowing base is adjusted at the lenders’ discretion and is based, in part, upon external factors over which we have no control. If our outstanding debt under the Bank Credit Agreement exceeds the then-effective borrowing base, we would be required to repay the excess amount over a period not to exceed six months. The weighted average interest rate on borrowings outstanding

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

as of March 31, 2022 under the Bank Credit Agreement was 5.5%. 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 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. Our Bank Credit Agreement required certain minimum commodity hedge levels in connection with our emergence from bankruptcy; however, these conditions were met as of December 31, 2020, and we currently have no ongoing hedging requirements under the Bank Credit Agreement.

The Bank Credit Agreement 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.

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.

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

Note 5. Income Taxes

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

At March 31, 2022, we assessed the valuation allowance recorded on our deferred tax assets, which was $125.5 million at December 31, 2021. This valuation allowance on our federal and certain state deferred tax assets was recorded in September 2020 after the application of fresh start accounting, as (1) the tax basis of our assets, primarily our oil and gas properties, was in excess of the carrying value, as adjusted for fresh start accounting and (2) our historical pre-tax income reflected a three-year cumulative loss primarily due to ceiling test write-downs and reorganization items that were recorded in 2020. While we continued to be in a cumulative three-year-loss position during the first quarter of 2022, we determined that there is sufficient positive evidence, primarily related to a substantial increase in worldwide oil prices, to conclude that $64.9 million of our federal and certain state deferred tax assets are more likely than not to be realized. Accordingly, we currently expect to reverse $64.9 million of this valuation allowance during the year ended December 31, 2022 as follows: (1) $5.9 million during the three months ended March 31, 2022, and (2) $59.0 million during the second through fourth quarters of 2022, resulting in a change to our annualized effective tax rate. We will continue to maintain a valuation allowance of $60.6 million for certain state tax benefits that we currently do not expect to realize before their expiration.

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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” 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.

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, 2022, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.

The following table summarizes our commodity derivative contracts as of March 31, 2022, none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic:


Months	Index Price	Volume (Barrels per day)	Contract Prices ($/Bbl)
			Range(1)				Weighted Average Price
							Swap		Floor		Ceiling
Oil Contracts:
2022 Fixed-Price Swaps
Apr – June	NYMEX	15,500	$	42.65	–	58.15	$	49.01	$	—	$	—
July – Dec	NYMEX	9,500		50.13	–	78.53	57.52		—		—
2022 Collars
Apr – June	NYMEX	11,000	$	47.50	–	70.75	$	—	$	49.77	$	64.31
July – Dec	NYMEX	11,500		47.50	–	91.60	—		52.39		67.29
2023 Fixed-Price Swaps
Jan – June	NYMEX	4,500	$	71.50	–	78.10	$	74.88	$	—	$	—
July – Dec	NYMEX	2,000		75.50	–	78.10	76.80		—		—
2023 Collars
Jan – June	NYMEX	7,500	$	60.00	–	104.60	$	—	$	64.00	$	88.83
July – Dec	NYMEX	4,000		65.00	–	104.60	—		65.00		93.23

(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.

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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 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.

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

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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

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


	Fair Value Measurements Using:
In thousands	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
March 31, 2022
Assets

Oil derivative contracts – long-term	$	—	$	265	$	—	$	265
Total Assets	$	—	$	265	$	—	$	265

Liabilities
Oil derivative contracts – current	$	—	$	(223,598)	$	—	$	(223,598)
Oil derivative contracts – long-term	—		(10,837)		—		(10,837)
Total Liabilities	$	—	$	(234,435)	$	—	$	(234,435)

December 31, 2021




Liabilities
Oil derivative contracts – current	$	—	$	(134,509)	$	—	$	(134,509)

Total Liabilities	$	—	$	(134,509)	$	—	$	(134,509)

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” 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, 2022 and December 31, 2021, excluding pipeline financing obligations, was $35.0 million and $35.0 million, respectively. 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.

Note 8. Commitments and Contingencies

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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Denbury Inc.

Notes to Unaudited Condensed Consolidated Financial Statements

Note 9. Subsequent Event

Common Share Repurchase Program

On May 5, 2022, we announced Board authorization of a common share repurchase program for up to $250 million of outstanding Denbury common stock. The program has no pre-established ending date and may be suspended or discontinued at any time. The Company is not obligated to repurchase any dollar amount or specific number of shares of its common stock under the program. As of May 5, 2022, there have been no repurchases of common stock under this share repurchase program.

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Denbury Inc.

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

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

The following discussion and analysis should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and Notes thereto included herein and our Consolidated Financial Statements and Notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2021 (the “Form 10-K”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K. Any terms used but not defined herein have the same meaning given to them in the Form 10-K.

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 the Form 10-K, along with Forward-Looking Information at the end of this section for information on the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

OVERVIEW

Denbury is an independent energy company with operations focused in the Gulf Coast and Rocky Mountain regions. The Company is differentiated by its focus on CO2 enhanced oil recovery (“EOR”) and the emerging carbon capture, use, and storage (“CCUS”) industry, supported by the Company’s CO2 EOR technical and operational expertise and its extensive CO2 pipeline infrastructure. The utilization of captured industrial-sourced CO2 in EOR significantly reduces the carbon footprint of the oil that Denbury produces, making the Company’s Scope 1 and 2 CO2 emissions negative today, with a goal to be net-zero on its Scope 1, 2, and 3 CO2 emissions by 2030, primarily through increasing the amount of captured industrial-sourced CO2 used in its operations.

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


	Three Months Ended
In thousands, except per-unit data	March 31, 2022		Dec. 31, 2021		Sept. 30, 2021		June 30, 2021		March 31, 2021
Oil, natural gas, and related product sales	$	384,911	$	333,348	$	308,454	$	282,708	$	235,445
Receipt (payment) on settlements of commodity derivatives	(93,057)		(97,774)		(77,670)		(63,343)		(38,453)
Oil, natural gas, and related product sales and commodity settlements, combined	$	291,854	$	235,574	$	230,784	$	219,365	$	196,992

Average daily sales (BOE/d)	46,925		48,882		49,682		49,133		47,357

Average net realized oil prices
Oil price per Bbl - excluding impact of derivative settlements	$	93.17	$	75.68	$	68.88	$	64.70	$	56.28
Oil price per Bbl - including impact of derivative settlements	70.43		53.21		51.35		50.10		47.00

Average NYMEX WTI oil prices increased from the mid-$70s per Bbl range in the fourth quarter of 2021 to approximately $95 per Bbl during the first quarter of 2022, reaching highs of over $123 per Bbl in early-March 2022. This increase in oil prices was due in large part to concerns around potential worldwide oil supply disruptions associated with the Russian invasion of Ukraine during the first quarter of 2022.

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Denbury Inc.

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

As shown in the table above, our oil and natural gas revenues increased significantly over the last four quarters as oil prices increased. However, the benefit of the increase in revenues over this time period was offset in part by the impact of higher cash payments on our commodity derivative contracts, which were largely required to be entered into during the fourth quarter of 2020 under the terms of our September 18, 2020 bank credit facility. During the first quarter of 2022, we paid $93.1 million related to the expiration of commodity derivative contracts and expect to make additional payments on the settlement of our contracts expiring during the remainder of 2022. In the second half of 2022, less of our production is hedged, and our hedges are at more favorable prices and with a greater mix of collars, allowing us to realize additional upside of currently anticipated higher oil prices.

First Quarter 2022 Financial Results and Highlights. We recognized a net loss of $0.9 million, or $0.02 per diluted common share, during the first quarter of 2022, compared to a net loss of $69.6 million, or $1.38 per diluted common share, during the first quarter of 2021. The primary drivers of the comparative operating results include the following:

•Oil and natural gas revenues increased $149.5 million (63%) due to an increase in commodity prices;

•Lease operating expenses increased $35.9 million (44%), offset in part by reductions in other expense categories; and

•Commodity derivatives expense increased by $77.0 million consisting of a $54.6 million increase in cash payments upon contract settlements and a $22.4 million loss on noncash fair value changes.

Commencement of Cedar Creek Anticline (“CCA”) CO2 Injection. In early February 2022, we commenced CO2 injection in the first phase of our CCA EOR project, and during April 2022 we increased CO2 injections to approximately 115 MMcf/d of industrial-sourced CO2 into the field. We continue to anticipate tertiary oil production response from this new project in the second half of 2023.

Carbon Capture, Use and Storage. CCUS is a process that captures CO2 from industrial sources and reuses it or stores the CO2 in geologic formations in order to prevent its release into the atmosphere. We utilize CO2 from industrial sources in our EOR operations, and our extensive CO2 pipeline infrastructure and operations, particularly in the Gulf Coast, are strategically located in close proximity to large sources of industrial emissions. We believe that the assets and technical expertise required for CCUS are highly aligned with our existing CO2 EOR operations, providing us with a significant advantage and opportunity to participate in the emerging CCUS industry, as the building of a permanent carbon sequestration business requires both time and capital to build assets such as those we own and have been operating for years. During the first quarter of 2022, approximately 36% of the CO2 utilized in our oil and gas operations was industrial-sourced CO2, and we anticipate this percentage will increase in the future as supportive U.S. government policy and public pressure on industrial CO2 emitters will provide strong incentives for these entities to capture their CO2 emissions.

As we seek to grow our CCUS business and pursue new CCUS opportunities, we have been engaged in discussions with existing and potential third-party industrial CO2 emitters regarding transportation and storage solutions, while also identifying potential future sequestration sites and landowners of those locations. We continue to make progress in these discussions and thus far have signed agreements securing the rights to future sequestration sites which we believe have the potential to store up to 1.4 billion metric tons of CO2. In addition, we have executed several term sheets for the future transportation and sequestration of CO2. During the first quarter of 2022, we capitalized $20.9 million in “CCUS storage sites and related assets” in our Unaudited Condensed Consolidated Balance Sheets, primarily consisting of acquisition costs associated with sequestration sites. While EOR is the only CCUS operation reflected in our historical financial and operational results (as a cost), we believe the incentives offered under Section 45Q of the Internal Revenue Code (“Section 45Q”) or otherwise will drive demand for CCUS and will allow us to collect a fee for the transportation and storage of captured industrial-sourced CO2, including CO2 utilized in our EOR operations. As the enhanced Section 45Q regulations are relatively new, it will likely take several years to construct new capture facilities and for dedicated storage sites to be developed. We believe our existing CO2 pipeline infrastructure, EOR operations, and experience and expertise in working with CO2 all position us to be a leader in this rapidly developing industry.

May 2022 Amendment to Senior Secured Bank Credit Agreement. In early May 2022, we amended our bank credit facility to among other things, (1) increase the borrowing base and lender commitments to $750 million, (2) extend the maturity date to May 4, 2027, (3) modify certain interest rate provisions, and (4) provide additional flexibility regarding our ability to make restricted payments and investments. See further discussion of this amendment under Capital Resources and Liquidity – Senior Secured Bank Credit Agreement.

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Denbury Inc.

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

Common Share Repurchase Program. On May 5, 2022, we announced Board authorization of a common share repurchase program for up to $250 million of outstanding Denbury common stock. The program has no pre-established ending date and may be suspended or discontinued at any time. The Company is not obligated to repurchase any dollar amount or specific number of shares of its common stock under the program. As of May 5, 2022, there have been no repurchases of common stock under this share repurchase program.

CAPITAL RESOURCES AND LIQUIDITY

Overview. Our cash flows from operations and availability under our senior secured bank credit facility are our primary sources of capital and liquidity. Our most significant cash capital outlays relate to our oil and gas development capital expenditures and CCUS initiatives.

As of March 31, 2022, we had $35.0 million of outstanding borrowings and $11.9 million of outstanding letters of credit under our $575 million senior secured bank credit facility, leaving us with $528.1 million of borrowing base availability and approximately $528.6 million of total liquidity including our cash position at March 31, 2022. This liquidity is more than adequate to meet our currently planned operating and capital needs as we currently project our cash flow from operations to significantly exceed our planned capital expenditures in 2022. In early May 2022, we amended our bank credit facility to among other things, increase the borrowing base availability and lender commitments to $750 million (see further discussion of this amendment under Senior Secured Bank Credit Agreement below).

2022 Sources and Uses. During the first quarter of 2022, we generated cash flows from operations of $90.1 million, while incurring capital costs of $79.7 million, consisting of oil and gas development capital expenditures of $57.6 million, CCUS storage sites and related capital expenditures of $20.9 million, and capitalized interest of $1.2 million.

As further discussed below, based on oil price futures as of early May 2022, we currently anticipate funding all of our 2022 capital budget from projected operating cash flow while also generating excess cash flow. As the level of excess cash we expect to generate in 2022 and future periods has increased with the rise in oil prices during the first part of 2022, our Board of Directors recently adopted a share repurchase program for up to $250 million of Denbury’s outstanding common stock. The ultimate level of excess cash we may generate in 2022 and future periods will be highly dependent on oil prices and many other factors, but we currently believe our level of cash flow generation will be adequate to fund our EOR and CCUS strategic priorities while returning capital to our shareholders through our recently announced share repurchase program.

2022 Plans and Capital Budget. Based on our original 2022 budget, we estimated that our full-year 2022 oil and gas development capital spending, excluding capitalized acquisitions and capitalized interest, would be in the range of $290 million to $320 million, which at the midpoint includes approximately $115 million for CCA’s new EOR development (inclusive of an estimated $25 million of pre-production CO2 costs) and $190 million for other tertiary and non-tertiary oil-focused development projects, capitalized internal costs and CO2 sources and pipelines. In addition to our budgeted oil and natural gas capital investments, our budget assumed spending of approximately $50 million in connection with our CCUS strategic priorities, making our combined 2022 projected capital expenditures in the range of $340 million to $370 million. Based on recent cost increases and inflationary pressures, we now expect that our 2022 capital expenditures will be toward the upper end of our budgeted range.

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Denbury Inc.

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

Capital Expenditure Summary. The following table reflects incurred capital expenditures for the three months ended March 31, 2022 and 2021:


	Three Months Ended
	March 31,
In thousands	2022		2021
Capital expenditure summary(1)
CCA EOR field expenditures(2)	$	17,722	$	9
CCA CO2 pipelines	2,191		48
CCA tertiary development	19,913		57
Non-CCA tertiary and non-tertiary fields	29,363		12,422
CO2 sources and other CO2 pipelines	730		—

Capitalized internal costs(3)	7,600		7,600
Oil & gas development capital expenditures	57,606		20,079
CCUS storage sites and related capital expenditures	20,949		—
Acquisitions of oil and natural gas properties(4)	371		10,665

Capitalized interest	1,158		1,083
Total capital expenditures	$	80,084	$	31,827

(1)Capital expenditures in this summary are presented on an as-incurred basis (including accruals), and are $8.7 million lower than the capital expenditures in the Unaudited Condensed Consolidated Statements of Cash Flows which are presented on a cash basis.

(2)Includes pre-production CO2 costs associated with the CCA EOR development project totaling $2.8 million during the first quarter of 2022.

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

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

Supply Chain Issues and Potential Cost Inflation. Recent worldwide and U.S. supply chain issues, together with rising commodity prices and tight labor markets in the U.S., have increased our costs during 2022 and may continue to do so in future periods. Most of the cost inflation pressures we experienced during late 2021 were tied to rising fuel and power costs in our operations, but were not material to our 2021 financial results. Our 2022 operational budget considered anticipated inflation and we have taken steps to build our on-hand supply stock for items frequently used in our operations to address possible supply chain disruptions. Based on cost increases and shortages experienced across the industry thus far in 2022, we anticipate additional increases in the cost of, and demand for, goods and services and wages in our operations during the remainder of 2022 which could negatively impact our results of operations and cash flows in future periods.

Senior Secured Bank Credit Agreement. In September 2020, we entered into a $575 million bank credit agreement for a senior secured revolving credit facility with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the “Bank Credit Agreement”). On May 4, 2022, we entered into a Second Amendment to the Bank Credit Agreement, which among other things:

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

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

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Denbury Inc.

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

Availability under the Bank Credit Agreement is subject to a borrowing base, which is redetermined semiannually on or around May 1 or November 1 of each year, with our next scheduled redetermination around November 1, 2022. The borrowing base is adjusted at the lenders’ discretion and is based, in part, upon external factors over which we have no control. If our outstanding debt under the Bank Credit Agreement exceeds the then-effective borrowing base, we would be required to repay the excess amount over a period not to exceed six months.

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.

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, 2022, our ratio of consolidated total debt to consolidated EBITDAX was 0.09 to 1.0 (with a maximum permitted ratio of 3.5 to 1.0) and our current ratio was 2.53 to 1.0 (with a required ratio of not less than 1.0 to 1.0). Based upon our currently forecasted levels of production and costs, hedges in place as of May 4, 2022, and current oil commodity futures prices, we currently anticipate continuing to be in compliance with our financial performance covenants during the foreseeable future.

The above description of our Bank Credit Agreement is qualified by the express language and defined terms contained in the Bank Credit Agreement and amendments thereto, each of which is filed as an exhibit to our periodic reports filed with the SEC. The Second Amendment to the Credit Agreement, which is attached as Exhibit 10(d) to this Form 10-Q, contains the full text of the current version of the Bank Credit Agreement inclusive of all changes made by virtue of both the First and Second Amendments thereto.

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

Our commitments and obligations consist of those detailed as of December 31, 2021, in our Form 10-K under Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Commitments, Obligations and Off-Balance Sheet Arrangements.

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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Denbury Inc.

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

RESULTS OF OPERATIONS

Certain of our operating results and statistics for the comparative three months ended March 31, 2022 and 2021 are included in the following table:


	Three Months Ended
	March 31,
In thousands, except per-share and unit data	2022		2021
Financial results
Net loss(1)	$	(872)	$	(69,642)
Net loss per common share – basic(1)	(0.02)		(1.38)
Net loss per common share – diluted(1)	(0.02)		(1.38)
Net cash provided by operating activities	90,143		52,656
Average daily sales volumes
Bbls/d	45,466		46,007
Mcf/d	8,753		8,102
BOE/d(2)	46,925		47,357
Oil and natural gas sales
Oil sales	$	381,242	$	233,044
Natural gas sales	3,669		2,401
Total oil and natural gas sales	$	384,911	$	235,445
Commodity derivative contracts(3)
Payment on settlements of commodity derivatives	$	(93,057)	$	(38,453)
Noncash fair value losses on commodity derivatives	(99,662)		(77,290)
Commodity derivatives expense	$	(192,719)	$	(115,743)
Unit prices – excluding impact of derivative settlements
Oil price per Bbl	$	93.17	$	56.28
Natural gas price per Mcf	4.66		3.29
Unit prices – including impact of derivative settlements(3)
Oil price per Bbl	$	70.43	$	47.00
Natural gas price per Mcf	4.66		3.29
Oil and natural gas operating expenses
Lease operating expenses	$	117,828	$	81,970
Transportation and marketing expenses	4,645		7,797
Production and ad valorem taxes	30,443		17,895
Oil and natural gas operating revenues and expenses per BOE
Oil and natural gas revenues	$	91.14	$	55.24
Lease operating expenses	27.90		19.23
Transportation and marketing expenses	1.10		1.83
Production and ad valorem taxes	7.21		4.20
CO2 – revenues and expenses
CO2 sales and transportation fees	$	13,422	$	9,228
CO2 operating and discovery expenses	(2,817)		(993)
CO2 revenue and expenses, net	$	10,605	$	8,235

(1)Includes a pre-tax full cost pool ceiling test write-down of our oil and natural gas properties of $14.4 million during the first quarter of 2021.

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

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

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Denbury Inc.

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

Sales Volumes

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


	Average Daily Sales Volumes (BOE/d)
	First Quarter	Fourth Quarter	Third Quarter	Second Quarter	First Quarter
Operating Area	2022	2021	2021	2021	2021
Tertiary oil sales volumes
Gulf Coast region
Delhi	2,675	2,731	2,859	2,931	2,925
Hastings	4,430	4,212	4,343	4,487	4,226
Heidelberg	3,653	3,797	3,895	3,942	4,054
Oyster Bayou	3,745	4,039	3,942	3,791	3,554
Tinsley	3,015	3,353	3,390	3,455	3,424
Other(1)	5,498	5,801	5,907	6,074	6,098
Total Gulf Coast region	23,016	23,933	24,336	24,680	24,281
Rocky Mountain region
Bell Creek	4,474	4,331	4,330	4,394	4,614
Other(2)	4,746	4,551	4,703	4,378	2,573
Total Rocky Mountain region	9,220	8,882	9,033	8,772	7,187
Total tertiary oil sales volumes	32,236	32,815	33,369	33,452	31,468
Non-tertiary oil and gas sales volumes
Gulf Coast region
Total Gulf Coast region	3,630	3,929	3,763	3,415	3,621
Rocky Mountain region
Cedar Creek Anticline	9,721	10,784	11,182	10,918	11,150
Other(3)	1,338	1,354	1,368	1,348	1,118
Total Rocky Mountain region	11,059	12,138	12,550	12,266	12,268
Total non-tertiary sales volumes	14,689	16,067	16,313	15,681	15,889



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

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

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

(3)Includes non-tertiary sales volumes from Wind River Basin, as well as Hartzog Draw and Bell Creek fields.

Total sales volumes during the first quarter of 2022 averaged 46,925 BOE/d, including 32,236 Bbls/d from tertiary properties and 14,689 BOE/d from non-tertiary properties. This sales volume represents a decrease of 1,957 BOE/d (4%) compared to sales levels in the fourth quarter of 2021 and was essentially flat with first quarter of 2021 sales volumes. The decrease on a sequential-quarter basis was primarily attributable to (a) weather-related downtime and downtime coinciding with activities to progress our tertiary development at CCA and (b) production decline due to low levels of capital investment and development spending in recent years (excluding the new EOR development at CCA).

Our sales volumes during the three months ended March 31, 2022 were 97% oil, consistent with our sales during the same prior-year period.

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Denbury Inc.

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

Oil and Natural Gas Revenues

Our oil and natural gas revenues during the three months ended March 31, 2022 increased 63% compared to these revenues for the same period in 2021. The changes in our oil and natural gas revenues are due to higher realized commodity prices (excluding any impact of our commodity derivative contracts), as reflected in the following table:


	Three Months Ended
	March 31,
	2022 vs. 2021
In thousands	Increase (Decrease) in Revenues		Percentage Increase (Decrease) in Revenues
Change in oil and natural gas revenues due to:
Decrease in sales volumes	$	(2,146)	(1)	%
Increase in realized commodity prices	151,612		64	%
Total increase in oil and natural gas revenues	$	149,466	63	%

Excluding any impact of our commodity derivative contracts, our average net realized commodity prices and NYMEX differentials were as follows during each of the three months ended March 31, 2022 and 2021:


	Three Months Ended
	March 31,
	2022		2021
Average net realized prices
Oil price per Bbl	$	93.17	$	56.28
Natural gas price per Mcf	4.66		3.29
Price per BOE	91.14		55.24
Average NYMEX differentials
Gulf Coast region
Oil per Bbl	$	(1.37)	$	(1.37)
Natural gas per Mcf	0.16		0.68
Rocky Mountain region
Oil per Bbl	$	(1.38)	$	(1.80)
Natural gas per Mcf	0.08		0.49
Total Company
Oil per Bbl	$	(1.37)	$	(1.54)
Natural gas per Mcf	0.11		0.58

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 2022, consistent with the first quarter of 2021 and a slight improvement from a negative $1.41 per Bbl during the fourth quarter of 2021. NYMEX WTI oil prices continued to strengthen during 2022, including the pricing for our Gulf Coast grades relative to NYMEX WTI index prices. For our crude oil sold under Light Louisiana Sweet (“LLS”) index prices, the LLS-to-NYMEX differential averaged a positive $2.16 per Bbl on a trade-month basis for the first quarter of 2022, compared to a positive $2.02 per Bbl differential in the first quarter of 2021 and a positive $0.88 per Bbl in the fourth quarter of 2021.

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

•Rocky Mountain Region. NYMEX oil differentials in the Rocky Mountain region averaged $1.38 per Bbl and $1.80 per Bbl below NYMEX during the first quarters of 2022 and 2021, respectively, and $0.95 per Bbl below NYMEX during the fourth quarter of 2021. Differentials in the Rocky Mountain region tend to fluctuate with regional supply and demand trends and can fluctuate significantly on a month-to-month basis due to weather, refinery or transportation issues, and Canadian and U.S. crude oil price index volatility.

CO2 Revenues and Expenses

We sell a portion of the CO2 we own to third-party industrial users at various contracted prices primarily under long-term contracts. We recognize the revenue received on these CO2 sales as “CO2 sales and transportation fees” with the corresponding costs recognized as “CO2 operating and discovery expenses” in our Unaudited Condensed Consolidated Statements of Operations. CO2 sales and transportation fees were $13.4 million during the three months ended March 31, 2022, compared to $9.2 million during the three months ended March 31, 2021. The increase from the prior-year period was primarily due to new contracts and an increase in CO2 sales volumes.

Oil Marketing Revenues and Purchases

In certain situations, we purchase and subsequently sell oil from third parties. We recognize the revenue received and the associated expenses incurred on these sales on a gross basis as “Oil marketing revenues” and “Oil marketing purchases” in our Unaudited Condensed Consolidated Statements of Operations.

Commodity Derivative Contracts

The following table summarizes the impact our crude oil derivative contracts had on our operating results for the three months ended March 31, 2022 and 2021:


	Three Months Ended
	March 31,
In thousands	2022		2021
Payment on settlements of commodity derivatives	$	(93,057)	$	(38,453)
Noncash fair value losses on commodity derivatives	(99,662)		(77,290)
Total expense	$	(192,719)	$	(115,743)

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 2021 and 2022. The benefit of the significant increase in our oil sales during 2022 over 2021 sales levels due to rising oil prices has been offset by payments on settlements of commodity derivative contracts, principally due to the strike prices of our fixed-price swaps. During the first quarter of 2022, we paid $93.1 million upon expiration of commodity derivative contracts, reflecting the very large fluctuations in oil prices preceding and after the invasion by Russia of Ukraine heightening supply uncertainty and oil market volatility.

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 2023 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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Management’s Discussion and Analysis of Financial Condition and Results of Operations

derivative contracts as of March 31, 2022, and Item 3, Quantitative and Qualitative Disclosures about Market Risk below for additional discussion. In addition, the following table summarizes our commodity derivative contracts as of May 4, 2022:


		2Q 2022	2H 2022	1H 2023	2H 2023
WTI NYMEX	Volumes Hedged (Bbls/d)	15,500	9,500	4,500	2,000
Fixed-Price Swaps	Swap Price(1)	$49.01	$57.52	$74.88	$76.80
WTI NYMEX	Volumes Hedged (Bbls/d)	11,000	11,500	12,500	7,000
Collars	Floor / Ceiling Price(1)	$49.77 / $64.31	$52.39 / $67.29	$66.40 / $96.58	$66.43 / $99.30
	Total Volumes Hedged (Bbls/d)	26,500	21,000	17,000	9,000

(1)Averages are volume weighted.

Based on current contracts in place and NYMEX oil futures prices as of May 4, 2022, which averaged approximately $102 per Bbl, we currently expect that we would make cash payments of approximately $265 million upon settlement of our April through December 2022 contracts, the amount of which is primarily dependent upon fluctuations in future NYMEX oil prices in relation to the prices of our remaining 2022 fixed-price swaps which have a weighted average NYMEX oil price of $53.72 per Bbl and weighted average ceiling prices of our 2022 collars of $66.33 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


	Three Months Ended
	March 31,
In thousands, except per-BOE data	2022		2021
Total lease operating expenses	$	117,828	$	81,970

Total lease operating expenses per BOE	$	27.90	$	19.23

Total lease operating expenses increased $35.9 million (44%) on an absolute-dollar basis, or $8.67 (45%) on a per BOE basis, during the three months ended March 31, 2022, compared to the same prior-year period. The increases on an absolute-dollar basis and per-BOE basis were primarily due to (a) a benefit of $14.9 million in the prior-year period resulting from compensation under the Company’s power agreements for power interruption during the severe winter storm in February 2021 which related to power outages in Texas and disrupted the Company’s operations; (b) a $7.9 million increase in CO2 and power and fuel expenses correlated with higher oil and natural gas prices; (c) an additional $6.6 million of expense as the 2022 period reflects an entire quarter’s worth of lease operating expenses from our March 2021 acquisition of Wind River Basin properties; and (d) inflationary impacts and an increase in workover activity contributing to increases across numerous cost categories such as workovers, repair and maintenance parts, and contract labor. Compared to the fourth quarter of 2021, lease operating expenses in the most recent quarter increased $2.0 million (2%) on an absolute-dollar basis and $2.15 (8%) on a per-BOE basis, due primarily to higher workover and power and fuel costs and lower sales volumes.

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 $4.6 million and $7.8 million for the three months ended March 31, 2022 and 2021, respectively. The decrease during the comparative three-month periods was primarily due to a change in the sales point of certain of our production, which reduced our transportation expense.

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Denbury Inc.

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

Taxes Other Than Income

Taxes other than income includes production, ad valorem and franchise taxes. Taxes other than income increased $12.4 million (65%) during the three months ended March 31, 2022, compared to the same prior-year period, due primarily to an increase in production taxes resulting from higher oil and natural gas revenues.

General and Administrative Expenses (“G&A”)


	Three Months Ended
	March 31,
In thousands, except per-BOE data and employees	2022		2021
Cash G&A costs	$	15,721	$	14,303
Stock-based compensation	2,971		17,680
G&A expense	$	18,692	$	31,983

G&A per BOE
Cash G&A costs	$	3.72	$	3.35
Stock-based compensation	0.71		4.15
G&A expenses	$	4.43	$	7.50

Employees as of period end	724		677

Our G&A expense on an absolute-dollar basis was $18.7 million during the three months ended March 31, 2022, a decrease of $13.3 million from the same prior-year period, primarily due to a $14.7 million decrease in stock-based compensation expense in the 2022 period, as the first quarter of 2021 included stock-based compensation expense resulting from the accelerated performance achievement and vesting of performance-based equity awards granted in late 2020.

Interest and Financing Expenses


	Three Months Ended
	March 31,
In thousands, except per-BOE data and interest rates	2022			2021
Cash interest(1)	$	1,130		$	1,934

Noncash interest expense	685			685

Less: capitalized interest	(1,158)			(1,083)
Interest expense, net	$	657		$	1,536
Interest expense, net per BOE	$	0.16		$	0.36
Average debt principal outstanding	$	34,278		$	135,396
Average cash interest rate(2)	5.5		%	4.0		%

(1)Includes commitment fees paid on the Company’s bank credit facility but excludes debt issue costs.

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

Cash interest during the three months ended March 31, 2022 decreased $0.8 million (42%) when compared to the same prior-year period. The decrease between periods was primarily due to repayment of our pipeline financings in October 2021 and a decrease in the average debt principal outstanding on our senior secured bank credit facility.

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

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


	Three Months Ended
	March 31,
In thousands, except per-BOE data	2022		2021
Oil and natural gas properties	$	28,668	$	32,015
CO2 properties, pipelines, plants and other property and equipment	6,677		7,435

Total DD&A	$	35,345	$	39,450

DD&A per BOE
Oil and natural gas properties	$	6.79	$	7.51
CO2 properties, pipelines, plants and other property and equipment	1.58		1.75

Total DD&A cost per BOE	$	8.37	$	9.26

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

The decrease in DD&A expense during the three months ended March 31, 2022, when compared to the same period in 2021, was primarily due to a lower depletion rate as a result of an increase in our estimate of proved reserves between the periods based on higher commodity pricing.

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 March 2021 acquisition of Wyoming property interests (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 did not record a ceiling test write-down during the three months ended March 31, 2022.

Income Taxes


	Three Months Ended
	March 31,
In thousands, except per-BOE amounts and tax rates	2022			2021
Current income tax benefit	$	(561)		$	(191)
Deferred income tax benefit	(5,944)			(51)
Total income tax benefit	$	(6,505)		$	(242)
Average income tax benefit per BOE	$	(1.54)		$	(0.05)
Effective tax rate	88.2		%	0.3		%
Total net deferred tax asset (liability)	$	4,306		$	(1,224)

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

and cumulative losses, as well as historical and forecasted financial results, the overall business environment, our industry’s historic cyclicality, the reversal of existing deferred tax assets and liabilities, and tax planning strategies.

We 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 2022 and 2021. Our effective tax rate for the three months ended March 31, 2022 was significantly higher than our estimated statutory rate primarily due to the release of $5.9 million of the valuation allowance that was recorded discretely in the quarter. Our annualized effective tax rate for the year ended December 31, 2022 is currently estimated to be approximately 15%, as it includes the impact of the release of an additional $59.0 million of valuation allowances. This rate could move higher or lower based on our ultimate level of income.

As of March 31, 2022, we had $0.6 million of alternative minimum tax credits, which under the Tax Cut and Jobs Act will be refundable by 2022 and are recorded as a receivable on the balance sheet. Our significant state net operating loss carryforwards expire in various years, starting in 2025.

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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.



	March 31,
Per-BOE data	2022		2021
Oil and natural gas revenues	$	91.14	$	55.24
Payment on settlements of commodity derivatives	(22.03)		(9.02)
Lease operating expenses	(27.90)		(19.23)
Production and ad valorem taxes	(7.21)		(4.20)
Transportation and marketing expenses	(1.10)		(1.83)
Production netback	32.90		20.96
CO2 sales, net of operating and discovery expenses	2.51		1.94
General and administrative expenses(1)	(4.43)		(7.50)
Interest expense, net	(0.16)		(0.36)
Stock compensation and other	0.09		3.85
Changes in assets and liabilities relating to operations	(9.57)		(6.54)
Cash flows from operations	21.34		12.35
DD&A	(8.37)		(9.26)

Write-down of oil and natural gas properties	—		(3.37)
Deferred income taxes	1.41		0.01

Noncash fair value gains (losses) on commodity derivatives	(23.60)		(18.14)
Other noncash items	9.01		2.07
Net loss	$	(0.21)	$	(16.34)

(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, which if excluded, would have caused these expenses to average $3.92 per BOE.

CRITICAL ACCOUNTING POLICIES

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

FORWARD-LOOKING INFORMATION

The data and/or statements contained in this Quarterly Report on Form 10-Q that are not historical facts, including, but not limited to, statements found in the section Management’s Discussion and Analysis of Financial Condition and Results of Operations, regarding possible or assumed future results of operations, cash flows, production and capital expenditures, and other plans and objectives for the future operations of Denbury, projections or assumptions as to general economic conditions and the economics of a carbon capture, use and storage industry (“CCUS”), are forward-looking statements, as that term is defined in Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, the level and sustainability of the recent increases in worldwide oil prices, financial forecasts, the extent of future oil price volatility, current or future liquidity sources or their adequacy to support our anticipated future activities, statements or predictions related to the ultimate nature, timing and economic aspects of our current or proposed carbon capture, use and storage arrangements, together with assumptions based on current and projected production levels, oil and natural gas revenues, oil and gas prices and oilfield costs, the impact of current supply chain and inflationary pressures or expectations on our operations or costs, current or future

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

expectations or estimations of our cash flows or the impact of changes in commodity prices on cash flows, price and availability of advantageous commodity derivative contracts or their predicted downside cash flow protection or cash settlement payments required, forecasted drilling activity or methods, including the timing and location thereof, estimated timing of commencement of CO2 injections in particular fields or areas, or initial production responses in tertiary flooding projects, other development activities, finding costs, interpretation or prediction of formation details, 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 changes or proposed changes in Federal or state tax or environmental laws or regulations or outcomes of any pending litigation, and overall worldwide or U.S. economic conditions, and other variables surrounding operations and future plans. Such forward-looking statements generally are accompanied by words such as “plan,” “estimate,” “expect,” “predict,” “forecast,” “to our knowledge,” “anticipate,” “projected,” “preliminary,” “should,” “assume,” “believe,” “may” or other words that convey, or are intended to convey, the uncertainty of future events or outcomes. Such forward-looking information is based upon management’s current plans, expectations, estimates, and assumptions that could significantly and adversely affect current plans, anticipated outcomes, the timing of such actions and our financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by us or on our behalf. Among the factors that could cause actual results to differ materially are fluctuations in worldwide oil prices, especially as oil prices are affected by the war in Ukraine, and consequently on the prices received or demand for our produced oil; geopolitical actions and economic consequences of such war and recently imposed financial sanctions; decisions as to production levels and/or pricing by OPEC or U.S. producers in future periods; the impact of COVID-19 on oil demand and economic activity levels; to what degree inflation impacts future expenses; success of our risk management techniques; the uncertainty of drilling results and reserve estimates; operating hazards and remediation costs; disruption of operations and damages from cybersecurity breaches, or from well incidents, climate events such as hurricanes, tropical storms, floods, forest fires, or other natural occurrences; conditions in the worldwide financial, trade and credit markets; 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, 2022, we had $35.0 million of outstanding borrowings under our Bank Credit Agreement. At this level of variable-rate debt, an increase or decrease of 10% in interest rates would have an immaterial effect on our interest expense. Our Bank Credit Agreement does not have any triggers or covenants regarding our debt ratings with rating agencies. The following table presents the principal and fair values of our outstanding debt as of March 31, 2022:


In thousands	2022		2023		2024		Total		Fair Value
Variable rate debt:
Senior Secured Bank Credit Facility (weighted average interest rate of 5.5% at March 31, 2022)	$	—	$	—	$	35,000	$	35,000	$	35,000

See Note 4, Long-Term Debt, to the Unaudited Condensed Consolidated Financial Statements for details regarding our long-term debt and May 2022 amendment to our senior secured bank credit facility which extended the maturity date to May 4, 2027.

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, expectation of future commodity prices, and occasionally requirements under our bank credit facility. As of March 31, 2022, we do not have any hedging requirements under our Bank Credit Agreement. In order to provide a level of price protection to a portion of our oil production, we have hedged a portion of our estimated oil production through 2023 using NYMEX fixed-price swaps and costless collars. Depending on market conditions, we may continue to add to our existing 2022 and 2023 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, 2022, the fair value of our commodity derivative contracts was a net liability of $234.2 million, a $99.7 million increase from the $134.5 million net liability recorded at December 31, 2021. This change is primarily related to the increase in oil futures prices between December 31, 2021 and March 31, 2022 and new commodity derivative contracts entered into during 2022 for future periods, offset in part by the expiration of commodity derivative contracts during the three months ended March 31, 2022.

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Commodity Derivative Sensitivity Analysis

Based on NYMEX crude oil futures prices and derivative contracts in place as of March 31, 2022, and assuming both a 10% increase and decrease thereon, we would expect to make payments on our crude oil derivative contracts as shown in the following table:


In thousands	Receipt / (Payment)
Based on:
Futures prices as of March 31, 2022	$	(223,868)
10% increase in prices	(302,088)
10% decrease in prices	(155,267)

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, 2022, to ensure that information that is required to be disclosed in the reports the Company files and submits under the Securities Exchange Act of 1934 is recorded, that it is processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and that information that is required to be disclosed under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

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

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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, 2021. There have been no material changes to our risk factors contained in our Annual Report on Form 10-K for the year ended December 31, 2021.

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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
10(a)*						2022 Form of Restricted Stock Award under the 2020 Omnibus Stock and Incentive Plan for Denbury Inc.
10(b)*						2022 Form of Deferred Stock Unit Award under the 2020 Omnibus Stock and Incentive Plan for Denbury Inc.
10(c)*						2022 Form of TSR Performance Award under the 2020 Omnibus Stock and Incentive Plan for Denbury Inc.
10(d)*						Second Amendment to Credit Agreement, dated as of May 4, 2022, by and among Denbury Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders party thereto.
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, 2022, has been formatted in Inline XBRL.

* Included herewith.

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

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SIGNATURES

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


						DENBURY INC.

May 6, 2022						/s/ Mark C. Allen
						Mark C. Allen Executive Vice President and Chief Financial Officer

May 6, 2022						/s/ Nicole Jennings
						Nicole Jennings Vice President and Chief Accounting Officer