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Basis of Presentation (Policies)

9 Months Ended

Sep. 30, 2020

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

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

Interim Financial Statements - Basis of Accounting, Policy

Interim Financial Statements

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

Interim Financial Statements - Use of Estimates

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

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

Cash, Cash Equivalents, and Restricted Cash

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



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

Restricted cash, current in the table above represents restricted escrow funds maintained by the Successor as required by certain contractual arrangements in accordance with the Plan. Other restricted cash amounts represent escrow accounts that are legally restricted for certain of our asset retirement obligations, and are included in “Other assets” in the accompanying Unaudited Condensed Consolidated Balance Sheets.

Net Income (Loss) per Common Share

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

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



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

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



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

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


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

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

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

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



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

Oil and Natural Gas Properties

Unevaluated Costs. Under full cost accounting, we exclude certain unevaluated costs from the amortization base and full cost ceiling test pending the determination of whether proved reserves can be assigned to such properties. These costs are transferred to the full cost amortization base as these properties are developed, tested and evaluated. At least annually, we test these assets for impairment based on an evaluation of management’s expectations of future pricing, evaluation of lease expiration terms, and planned development activities. Given the significant declines in NYMEX oil prices in March and April 2020 due to the oil supply and demand imbalance precipitated by the dramatic fall in demand associated with the COVID-19 pandemic combined with the concurrent OPEC+ decision to increase oil supply, we reassessed our development plans and recognized an impairment of $244.9 million of our unevaluated costs during the three months ended March 31, 2020 (Predecessor), whereby these costs were transferred to the full cost amortization base. Upon emergence from bankruptcy, the Company adopted fresh start accounting which resulted in our oil and natural gas properties, including unevaluated properties, being recorded at their fair values at the Emergence Date (see Note 2, Fresh Start Accounting, for additional information).

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

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

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

Impairment Assessment of Long-Lived Assets

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

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

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

Recent Accounting Pronouncements

Recently Adopted

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

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

Not Yet Adopted

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

Leases

We evaluate contracts for leasing arrangements at inception. We lease office space, equipment, and vehicles that have non-cancelable lease terms. Leases with a term of 12 months or less are not recorded on our balance sheet. Lease costs for operating leases or leases with a term of 12 months or less are recognized on a straight-line basis over the lease term. For finance leases, interest on the lease liability and the amortization of the right-of-use asset are recognized separately, with the depreciable life reflective of the expected lease term.

Revenue Recognition

We record revenue in accordance with FASC Topic 606, Revenue from Contracts with Customers. The core principle of FASC Topic 606 is that an entity should recognize revenue for the transfer of goods or services equal to the amount of consideration that it expects to be entitled to receive for those goods or services. Once we have delivered the volume of commodity to the delivery

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

Income Taxes

We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. Our income taxes are based on an estimated statutory rate of approximately 25% in 2020 and 2019.

Commodity Derivative Contracts

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

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

consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength and expectation of future commodity prices. Under the terms of our Successor Bank Credit Agreement, at any point in time within the initial measurement period of August 1, 2020 through July 31, 2021, we are required to have hedges in place covering a minimum of 65% of our anticipated crude oil production and 35% of our anticipated crude oil production for the second measurement period of August 1, 2021 through July 31, 2022. We have until December 31, 2020 to enter into transactions for the initial measurement period to be in compliance.

We manage and control market and counterparty credit risk through established internal control procedures that are reviewed on an ongoing basis. We attempt to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and diversification, and all of our commodity derivative contracts are with parties that are lenders under our Successor Bank Credit Agreement (or affiliates of such lenders). As of September 30, 2020, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to enforceable master netting arrangements.

Fair Value Measurements

The FASC Fair Value Measurement topic defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (often referred to as the “exit price”). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the income approach for recurring fair value measurements

and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:


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

•

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

•

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

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