UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

20202021 FORM 10-K
(Mark One)
☑   Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 20202021
OR

☐   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
den-20211231_g1.jpg
DENBURY INC.
(Exact name of Registrant as specified in its charter)
Delaware 20-0467835
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
5851 Legacy Circle,
Plano,TX 75024
(Address of principal executive offices) (Zip Code)

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

Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class:Trading Symbol:Name of Each Exchange on Which Registered:
Common Stock $.001 Par ValueDENNew York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes ☑   No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐   No ☑

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 pursuant to Rule 405 (§232.405 of this chapter) of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit 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 12-b2 of the Exchange Act.
Large accelerated filer☐☑Accelerated filer☑☐Non-accelerated filer☐Smaller reporting company☑☐Emerging growth 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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the 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 aggregate market value of the registrant’s common stock held by non-affiliates, based on the closing price of the registrant’s common stock as of the last business day of the registrant’s most recently completed second fiscal quarter was $138,886,832.$3,839,619,307.

The number of shares outstanding of the registrant’s Common Stock as of January 31, 2021,2022, was 49,999,999.50,199,676.

DOCUMENTS INCORPORATED BY REFERENCE
Document: Incorporated as to:
1. Notice and Proxy Statement for the Annual Meeting of Stockholders to be held May 26, 2021.2022. 1.  Part III, Items 10, 11, 12, 13, 14





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Glossary and Selected Abbreviations
BblOne stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
Bbls/dBarrels of oil or other liquid hydrocarbons produced per day.
Bcf
One billion cubic feet of natural gas or CO2.
BOEOne barrel of oil equivalent, using the ratio of one barrel of crude oil, condensate or natural gas liquids to 6 Mcf of natural gas.
BOE/dBOEs produced per day.
BtuBritish thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit (°F).
CCUSCarbon Capture, Use, and Storage.
CO2
Carbon dioxide.
EOR
Enhanced oil recovery. In the context of our oil production, EOR is also referred to as tertiary recovery. Primary types of EOR include thermal, gas injection (such as natural gas, nitrogen, or CO2) and chemical injection (such as the use of polymers).
Finding and development costsThe average cost per BOE to find and develop proved reserves during a given period. It is calculated by dividing (a) costs, which include the sum of (i) the total acquisition, exploration and development costs incurred during the period plus (ii) future development and abandonment costs related to the specified property or group of properties, by (b) the sum of (i) the change in total proved reserves during the period plus (ii) total production during that period.
GAAPAccounting principles generally accepted in the United States of America.
MBblsOne thousand barrels of crude oil or other liquid hydrocarbons.
MBOEOne thousand BOEs.
Mcf
One thousand cubic feet of natural gas or CO2 at a temperature base of 60 degrees Fahrenheit (°F) and at the legal pressure base (14.65 to 15.025 pounds per square inch absolute) of the state or area in which the reserves are located or sales are made.
Mcf/d
One thousand cubic feet of natural gas or CO2 per day.
MMBOEOne million BOEs.
MMBtuOne million Btus.
MMcf
One million cubic feet of natural gas or CO2.
MMcf/d
One million cubic feet of natural gas or CO2 produced per day.
Noncash fair value gains (losses) on commodity derivatives
The net change during the period in the fair market value of commodity derivative positions. Noncash fair value gains (losses) on commodity derivatives is a non-GAAP measure and makes up only a portion of “Commodity derivatives expense (income)” in the Consolidated Statements of Operations, which also includes the impact of settlements on commodity derivatives during the period. Its use is further discussed in
Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Financial and Operating Results Tables.
NYMEXThe New York Mercantile Exchange. In the context of prices received for oil and natural gas, NYMEX prices represent the West Texas Intermediate benchmark price for crude oil and Henry Hub benchmark price for natural gas.
Probable Reserves*Reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
Proved Developed Reserves*Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved Reserves*Reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

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Denbury Inc.
Proved Undeveloped Reserves*Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells, in each case where a relatively major expenditure is required.
PV-10 Value
The estimated future gross revenue to be generated from the production of proved reserves, net of estimated future production, development and abandonment costs, and before income taxes, discounted to a present value using an annual discount rate of 10%. PV-10 Values were prepared using average hydrocarbon prices equal to the unweighted arithmetic average of hydrocarbon prices on the first day of each month within the 12-month period preceding the reporting date. PV-10 Value is a non-GAAP measure and does not purport to represent the fair value of our oil and natural gas reserves; its use is further discussed in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – Non-GAAP Financial Measure and Reconciliation.
Tcf
One trillion cubic feet of natural gas or CO2.
Tertiary RecoveryA term used to represent techniques for extracting incremental oil out of existing oil fields (as opposed to primary and secondary recovery or “non-tertiary” recovery). See also “EOR.”
* This definition is an abbreviated version of the complete definition set forth in Rule 4-10(a) of Regulation S-X. For the complete definition see:
http://www.ecfr.gov/cgi-bin/text-idx?SID=2d916841db86d079fa060fa63b08d34e&mc=true&node=se17.3.210_14_610&rgn=div8.


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PART I

Item 1. Business and Properties

GENERAL

Denbury Inc., a Delaware corporation, is an independent energy company with 143.1 MMBOE of estimated proved oil and natural gas reserves as of December 31, 2020, of which 98% is oil.  Our operations are focused in two key operating areas: the Gulf Coast and Rocky Mountain regions.regions of the United States.  The Company is differentiated by its focus on CO2 EOR and the emerging 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, underpinningmaking the Company’s Scope 1 and 2 CO2 emissions negative today, with a goal to also fully offset its Scope 1, 2, and 3 CO2 emissions within this decade, primarily through increasing the decade.amount of captured industrial-sourced CO2 used in its operations. Throughout this Annual Report on Form 10-K (“Form 10-K”) we use the terms “Denbury,” “Company,” “we,” “our” and “us” to refer to Denbury Inc. and, as the context may require, its subsidiaries.

Our CO2 EOR oil recovery operations result in the associated underground storage of CO2. This means that Denbury’s activities are supporting and advancing the national energy transition today through the increasing use of industrially sourced CO2 in EOR operations, as well as building out a dedicated CCUS platform for long-term carbon management at scale.

As part of our corporate strategy, we are committed to creating long-term value for our shareholders through the following key principles:

•target specific regions where we either have, or believe we can create, a competitive advantage as a result ofleverage our ownership or use ofextensive CO2 reserves, oil fieldspipeline assets and CO2 infrastructure;
•increaseEOR expertise to expand our operations and leadership position in the value of our assets through applying our technical expertise in CO2 tertiary recovery, together with a combination of other exploration, development, exploitation and marketing skills and practices;emerging CCUS industry;
•seek to expand the use of industrial-sourced CO2 in our tertiary recovery operations, with an ultimate objective of producing oil with a negative carbon footprint;
•leverageincrease the value of our extensiveassets by applying our technical expertise in CO2 pipeline assetstertiary recovery and CO2 EOR expertise to expand our operations and leadership position in the emerging CCUS industry;
•acquire properties that give us a majority working interest and operational control ortarget specific regions where we either have, or believe we can ultimately obtain it;
•maximize the value and cash flow generated from our operations by increasing production and reserves while controlling costs;create, a competitive advantage;
•optimize the timing and allocation of capital among our investment opportunities to maximize the rates of return on our investments;
•exercise financial discipline and maintain a strong balance sheet; and
•attract and maintain a highly competitive team of experienced and incentivized personnel.

As further described in Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code below, Denbury Inc. became the successor reporting company (the “Successor”) of Denbury Resources Inc. (the “Predecessor”) upon the Predecessor’s emergence from bankruptcy on September 18, 2020. On September 18, 2020, Denbury filed the Third Restated Certificate of Incorporation with the Delaware Secretary of State to effect a changeAs part of the Company’s corporate nameplan of reorganization, upon emergence from Denbury Resources Inc.bankruptcy, all of the Predecessor’s previously authorized and/or issued common stock or stock equivalents were cancelled, and new common stock was issued to Denbury Inc.the Predecessor’s debt holders and equity holders upon cancellation of approximately $2.1 billion principal amount of debt and all of the Predecessor’s equity instruments, respectively. On September 21, 2020, the Successor’s new common stock commenced trading on the New York Stock Exchange under the ticker symbol DEN, as distinguished from, Denbury Resources Inc.’s common stock having been publicly traded on the New York Stock Exchange since 1997. Our corporate headquarters is located at 5851 Legacy Circle, Plano, Texas 75024, and our phone number is 972-673-2000.

We make our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports, filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, available free of charge on or through our website, www.denbury.com, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (“SEC”).  The SEC also maintains a website, http://www.sec.gov, which contains periodic reports on Forms 8-K, 10-Q and 10-K filed with the SEC, along with other reports, proxy and information statements and other information filed by Denbury.

Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code

On July 30, 2020, (the “Petition Date”), Denbury Resources Inc. and its subsidiaries filed petitions for reorganization in a “prepackaged” voluntary bankruptcy (the “Chapter 11 Restructuring”) under chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”) under the caption “In re Denbury Resources Inc., et al., Case No. 20-33801”. On September 2, 2020, the Bankruptcy Court entered an order (the “Confirmation

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Order”)2, 2020, the Bankruptcy Court entered an order confirming the chapter 11prepackaged joint plan of reorganization (the “Plan”) and approving the Disclosure Statement, and on September 18, 2020 (the “Emergence Date”), the Plan became effective in accordance with its terms and the Company emerged from Chapter 11 as the successor reporting company of Denbury Resources Inc. On April 23, 2021, the Bankruptcy Court entered a final decree closing the Chapter 11 bankruptcy proceedings. Key accomplishments of the Chapter 11 Restructuring included the following:

•case captioned “Adopted an amended and restated certificate of incorporation and bylaws with authorized capitalization of 250,000,000 shares of common stock, par value $0.001 per share, ofIn re Denbury (the “New Common Stock”) and 50,000,000 shares of preferred stock, par value $0.001 per share;
•Cancelled all outstanding senior secured second lien notes, convertible senior notes, and senior subordinated notes issued by the Predecessor. In accordance with the Plan, claims against and interests in the Predecessor were treated as follows:

◦Holders of senior secured second lien notes claims received their pro rata share of 47,499,999 shares representing 95% of the New Common Stock issued on the Emergence Date, subject to dilution on account of warrants and a management incentive plan;
◦Holders of convertible senior notes claims received their pro rata share of (a) 2,500,000 shares representing 5% of the New Common Stock issued on the Emergence Date, subject to dilution on account of warrants and a management incentive plan and (b) 100% of the series A warrants (see below)Resources Inc., reflecting up to a maximum of 5% ownership stake in the reorganized company’s equity interests;
◦Holders of subordinated notes claims received their pro rata share of 54.55% of the series B warrants (see below), reflecting up to a maximum of 3% of the reorganized company’s equity interests after giving effect to the exercise of the series A warrants;
◦Holders of existing equity interests received their pro rata share of 45.45% of the series B warrants (see below), reflecting up to a maximum of 2.5% of the reorganized company’s equity interests after giving effect to the exercise of the series A warrants;
◦Issued 2,631,579 five-year series A warrants at an exercise price of $32.59 per share to former holders of the Predecessor’s convertible senior notes and 2,894,740 three-year series B warrants at an exercise price of $35.41 per share to former holders of the Predecessor’s senior subordinated notes and Predecessor’s equity interests; and
◦Holders of general unsecured claims received payment in full in cash, reimbursement, or such other treatment rendering such general unsecured claim unimpaired.
•Reduced ongoing annual interest expense by approximately $165 million, significantly lowering our cash flow breakeven level;
•Established a new $575 million senior secured bank credit facility with $482.0 million of availability at December 31, 2020 after outstanding letters of credit; and
•Appointed a new board of directors (the “Board”) consisting of four new independent members: Anthony Abate, Caroline Angoorly, Brett Wiggs and James N. “Jim” Chapman, and three continuing members: Dr. Kevin O. Meyers (Chairman of the Board), Lynn A. Peterson and Chris Kendall, Denbury’s President and Chief Executive Officer.

For more information on the Chapter 11 Restructuring and related matters, refer to Note 1, Nature of Operations and Summary of Significant Accounting Policies – Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Codeet al., and Note 8, Long-Term Debt,Case No. 20-33801”; therefore, we have no remaining obligations related to the consolidated financial statements.this reorganization.

Fresh Start Accounting

Upon emergence from bankruptcy, we met the criteria and were required to adopt fresh start accounting in accordance with Financial Accounting Standards Board Codification (“FASC”) Topic 852, Reorganizations, which on. Fresh start accounting requires that new fair values be established for the Company’s assets, liabilities and equity as of the Emergence Date, resulted in a new entity, the Successor, for financial reporting purposes, with no beginning retained earnings or deficit asand therefore certain values and operational results of the fresh start reporting date.condensed consolidated financial statements subsequent to September 18, 2020 are not comparable to those in the Company’s condensed consolidated financial statements prior to, and including September 18, 2020. The Emergence Date fair values of the Successor’s assets and liabilities differ materially from their recorded values as reflected on the historical balance sheets of the Predecessor contained in periodic reports previously filed with the Securities and Exchange Commission. References to “Successor” relate to the financial position and results of operations of the Company subsequent to the Company’s emergence from bankruptcy on September 18, 2020, and references to “Predecessor” relate to the financial position and results of operations of the Company prior to, and including, September 18, 2020. In order to assist investors in understanding the comparability of our financial results for the applicable periods, we have provided certain comparative analysis on a combined basis, which management believes provides meaningful information to assist investors in understanding our financial results for the applicable period, but should not be considered in isolation, as a substitute for, or more meaningful than, independent results of the Predecessor and Successor periods for the year reported in accordance with GAAP.

Fresh start accounting requires that new fair values be establishedBUSINESS ENVIRONMENT AND 2021 DEVELOPMENTS

Oil prices generally constitute the single largest variable in our operating results. Over the last several years, oil prices have been extremely volatile, with NYMEX WTI oil prices averaging approximately $57 per barrel in 2019, $39 per barrel in 2020 and $68 per barrel in 2021. The impact of the COVID-19 coronavirus (“COVID-19”) pandemic caused a rapid and precipitous drop in oil demand during 2020, which worsened an already deteriorated oil market caused by a concurrent decision among the group of oil producing nations known as OPEC+ to increase oil supply. In 2021, global economies generally began to recover from the impacts of COVID-19 and worldwide oil demand slowly began to increase to near pre-pandemic levels, as oil and gas companies significantly reduced capital investments due to lower oil prices, and OPEC+ proactively worked to reduce excess oil inventories around the world. As we approached the end of 2021, the fundamentals for global oil supply and demand were very tight, with inventory levels in the U.S. rebounding from five-year lows, and a near-term outlook for increasing oil demand as global economies and worldwide travel continued to recover. As oil prices strengthened during 2021, from around $50 per barrel in early 2021 to around $80 per barrel near the end of 2021, the Company’s financial results also improved, although the positive oil price impact was offset in large part by the commodity hedges we were obligated to have in place under our bank credit facility shortly after we emerged from bankruptcy in September 2020.

The following include some of our key 2021 business developments:

•Completed our 105-mile CO2 pipeline from Bell Creek Field to Cedar Creek Anticline (“CCA”).
•Acquired a nearly 100% working interest in the Big Sand Draw and Beaver Creek oil fields (collectively “Wind River Basin”) located in Wyoming, including surface facilities and a 46-mile CO2 pipeline.
•Sold non-producing surface acreage in the Houston area for $15.2 million and divested undeveloped deep mineral rights in Wyoming for $18 million.
•Reduced the Company’s total debt by $103.0 million and exited 2021 with $531.8 million of financial liquidity and total debt of $35.0 million.

In addition to the items listed above, the Company advanced its evolving CCUS business in 2021 through the following:

•Established an executive leadership team for Denbury Carbon Solutions.
•Executed a term sheet with Mitsubishi Corporation covering a 20-year period for the Company’stransport and storage of CO2 captured from Mitsubishi’s proposed ammonia project along the U.S. Gulf Coast.
•Commenced a joint evaluation with Mitsui E&P USA LLC of potential opportunities across the U.S. Gulf Coast to develop carbon-negative oil assets liabilities and equity asutilizing industrial-sourced CO2.
•Announced joint development of the datea Texas Gulf Coast sequestration site with Gulf Coast Midstream Partners, with potential to store up to 400 million metric tons of emergence from bankruptcy, September 18, 2020, and therefore certain values and operational results of theCO2.


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

Impact of the COVID-19 Pandemic
In March 2020, the World Health Organization declared the ongoing COVID-19 coronavirus (“COVID-19”) outbreak a pandemic, and the President of the United States declared the COVID-19 pandemic a national emergency. The COVID-19 pandemic has caused a rapid and precipitous drop in oil demand, which worsened an already deteriorated oil market that followed the early-March 2020 failure by the group of oil producing nations known as OPEC+ to reach an agreement over proposed oil production cuts. Uncertainty about the duration of the COVID-19 pandemic and its resulting economic consequences has resulted in abnormally high worldwide inventories of produced oil. While oil prices as of mid-February 2021 have improved to the low-$60s per barrel, which is significantly higher than the low points experienced during the second quarter of 2020, the concerns and uncertainties around the balance of supply and demand for oil are expected to continue for some time. Because the realized oil prices we received during 2020 were significantly reduced, our operating cash flow and liquidity were adversely affected.

2020 BUSINESS DEVELOPMENTS

Since our production is 97% oil, oil prices generally constitute the single largest variable in our operating results. Over the last several years, NYMEX oil prices have been extremely volatile, declining from a three-year peak of $76 per Bbl in October 2018 to lows averaging $17 per Bbl in April 2020due to the significant interruption in worldwide economic activity and reduction in oil demand amid the COVID-19 pandemic, plus OPEC supply pressures, before gradually increasing to an average of $47 per Bbl in December 2020. Throughout this time, we have focused primarily on preservation of cash and liquidity, together with cost reductions and debt management, rather than concentration on expansion and growth. Our 2020 key business developments included the following:

•Completed financial restructuring and emerged from Chapter 11 reorganization on September 18, 2020 with a strong balance sheet and liquidity position (refer to Note 1, Nature of Operations and Summary of Significant Accounting Policies – Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code, and Note 8, Long-Term Debt, to the consolidated financial statements).

•Reduced our originally planned capital expenditures in March 2020, deferred the CO2 pipeline extension to Cedar Creek Anticline and implementation of the enhanced oil recovery development project beyond 2020; implemented cost reduction measures including shutting down compressors, negotiating reductions with vendors, and delaying uneconomic well repairs and workovers.

•Restructured our CO2 pipeline financing arrangements with Genesis Energy, L.P. (“Genesis”), whereby we (1) reacquired the NEJD pipeline system from Genesis in exchange for $70 million to be paid in four equal payments during 2021, representing full settlement of all remaining obligations under the NEJD secured financing lease; and (2) reacquired the Free State Pipeline from Genesis in exchange for a one-time payment of $22.5 million on October 30, 2020. As a result, we reduced debt by $25 million and lowered interest expense while maximizing flexibility for future CCUS operations on these lines.

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

•Continued the monetization of valuable surface land with no active oil and natural gas operations, including the sale of multiple parcels primarily around Houston, Texas in transactions totaling $29 million in 2020.


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•Entered into an agreement in December 2020 to acquire a nearly 100% working interest (approximately 83% net revenue interest) in the Big Sand Draw and Beaver Creek oil fields located in Wyoming for $12 million cash, including surface facilities and a 46-mile CO2 transportation pipeline to the acquired fields. The agreement provides for us to make two contingent cash payments of $4 million each in 2021 and 2022 if NYMEX WTI oil prices average at least $50 per Bbl during the respective calendar years. The acquisition closed on March 3, 2021.

•Settled the Riley Ridge helium supply contract claim with APMTG Helium, LLC for $52.1 million, which was previously accrued as a liability in our Consolidated Balance Sheets.
2021 BUSINESS OUTLOOK

Oil prices continued to strengthen during the first two months of 2021, reaching the low-$60s per barrel in mid-February. Considering the current oil price environment and strategic importance of the CO2 flood at Cedar Creek Anticline (“CCA”), we plan to move forward in 2021 with the development of this significant long-term project. We expect to allocate approximately $150 million of capital in 2021 to this CCA development, consisting of approximately $100 million dedicated to the 105-mile extension of the Greencore CO2 pipeline from Bell Creek to CCA, with the remainder dedicated to facilities, well work and field development at CCA. In total, we estimate that our total development capital expenditures in 2021, excluding acquisitions and capitalized interest, will be in a range of $250 million to $270 million. Based on current oil prices and the Company’s hedge positions, we estimate that our 2021 cash flows from operations will exceed our budgeted level of planned development capital expenditures. In addition to our 2021 planned development capital, we acquired the Big Sand Draw and Beaver Creek oil fields in Wyoming in early March 2021 for a cash purchase price of $12 million before closing adjustments. Also, we plan to settle the remaining debt obligation to Genesis for the NEJD CO2 pipeline, with $70 million in payments to be made over the course of 2021. We expect to fulfill these remaining obligations from cash flow and borrowings under our bank credit facility. At December 31, 2020, we had $482 million of availability under our bank credit facility, which we believe is more than adequate to cover any near-term liquidity needs. To supplement our liquidity, we may seek other sources of funding for all or a portion of the CCA CO2 Pipeline expenditure.

Based on our capital spending plans, we currently anticipate 2021 average daily production to be between 47,500 BOE/d and 51,500 BOE/d, including the Big Sand Draw and Beaver Creek working interests acquisition expected to close in early March 2021. Our anticipated 2021 production level compares to 2020 average continuing production of 50,957 BOE/d, after reduction for 2020 property divestitures.

HUMAN CAPITAL RESOURCES

Our employees are our greatest resource, and each individual helps shape Denbury into a unique and exceptional place to work. We recognize that our employees are crucial to Denbury’s future, and we care about our employees’ and their families’ well-being beyond the work environment. As of December 31, 2020, we had 657 employees, of whom 365 were employed in our field operations or at our field offices and 292 were employed at our headquarters in Plano, TX.

Workforce Health and Safety

We continuously seek to improve our health and safety performance by fostering a culture that prioritizes safe work, then ensuring that this culture is exemplified in all levels of leadership. We provide our employees with tools to succeed, including relevant and timely training, and we monitor our performance using established measurement statistics. Each year, Denbury establishes corporate goals specifically related to employee and contractor safety performance and monitors progress toward those goals throughout the year using performance metrics. Results are regularly reported to our Board of Directors, senior management and all employees to ensure accountability and to reinforce their importance. Two safety performance metrics Denbury closely monitors are the Total Recordable Incident Rate (“TRIR”) and the Significant Injury or Fatality Rate (“SIFR”), which also captures near misses that may not have resulted in an injury. As detailed in our Corporate Responsibility Report available on our website at www.denbury.com under the “Responsibility” link, Denbury has set new record lows for TRIR over the last four consecutive years and our 2020 SIFR was our second lowest ever.

In March 2020, the World Health Organization declared the ongoing COVID-19 outbreak a pandemic, and the President of the United States declared the COVID-19 pandemic a national emergency. In response to the COVID-19 pandemic, we formed a COVID-19 task force comprised of members of senior management and other key employees. The task force developed a systematic, data-based approach to monitor national, state and local orders and guidelines related to the COVID-19 pandemic,

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established internal processes, training and communications, conducted contract tracing, and engaged a third-party medical consulting firm to identify and clear COVID-19 cases and exposures. Additionally, we provided voluntary COVID-19 testing for all employees and their dependents and ensured that necessary sanitation supplies are available at all Denbury offices and locations.

Compensation and Benefits

As part of our compensation philosophy, we believe that we must offer and maintain competitive compensation and benefit programs for our employees in order to attract and retain outstanding talent. In addition to competitive base wages, other programs include an annual bonus plan, long-term incentive plan, Company matched 401(k) plan, healthcare and insurance benefits, health savings and flexible spending accounts and employee assistance programs.

Diversity and Inclusion

We are committed to increasing diversity and fostering an inclusive work environment that supports the workforce and the communities where we operate. Denbury aims to ensure equal opportunity in recruitment, and we reach a pool of diverse candidates by utilizing a digital recruiting program that posts available employment opportunities to websites worldwide, several of which are specifically targeted to reach diverse candidates. In 2020, women and minorities accounted for 21% and 14% of our workforce, respectively, and 46% and 23% of our new hires, respectively.

Our diversity, equity and inclusion principles are also reflected in our employee training and policies. To foster a diverse and collaborative workplace, Denbury requires all employees to complete annual training to raise awareness and encourage diversity and inclusion. Each year, our employee training program includes courses related to diversity, anti-discrimination, and anti-harassment to help employees understand diversity, cultural differences, recognize unconscious bias, and increase collaboration. We continue to enhance our diversity, equity and inclusion policies which are guided by our Board and executive leadership team.

Talent Acquisition, Retention and Development

Our success depends to a significant degree upon our ability to hire, develop, and retain highly skilled and experienced personnel, including our executive officers as well as other key management and technical specialists, such as geologists, geophysicists, engineers and other oil and gas industry professionals. Denbury provides employees with many ways to expand their skills and advance their careers through training and development initiatives. We believe this is critical to each employee’s professional growth and success, as well as to our success as a company.

Human Rights

Denbury is committed to protecting human rights in the workplace. This commitment includes respecting the dignity and worth of all individuals, encouraging all individuals to reach their full potential, encouraging the initiative of each employee, and providing equal opportunity for development to all employees. Specifically, Denbury recognizes its responsibility with regards to: workplace health and safety, the prohibition of forced and child labor, a workplace free from harassment or any form of discrimination, freedom of association, complying with all laws regarding hours and wages and employee privacy. Denbury respects international human rights principles and our commitments to human rights are guided by the United National Global Compact and the International Labor Organization’s Declaration of Fundamental Principals and Rights at Work. Our Code of Conduct and Human Rights Policy require employees to report any suspected human rights abuses. Denbury’s Human Rights Policy is available on our website at www.denbury.com under the “Responsibility” link.


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ESTIMATED NET QUANTITIES OF PROVED OIL AND NATURAL GAS RESERVES AND PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES

Oil and Natural Gas Reserve Estimates

DeGolyer and MacNaughton (“D&M”) prepared estimates of our net proved oil and natural gas reserves as of December 31, 2020, 2019 and 2018 (see the summary of D&M’s report as of December 31, 2020, included as an exhibit to this Form 10-K). These estimates of reserves were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices on the first day of each month within the 12-month period in accordance with rules and regulations of the SEC.  These oil and natural gas reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage.  The reserve estimates represent our net revenue interest in our properties.


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The following table provides estimated proved reserve information prepared by D&M as of December 31, 2020, 2019 and 2018, as well as PV-10 Values and Standardized Measures for each period. The Company’s December 31, 2020 proved oil and natural gas reserve quantities and PV-10 Values declined significantly from December 31, 2019 due largely to the decrease in oil prices used in preparing the December 31, 2019 and 2020 reserve information, whereby the average NYMEX oil price used in estimating our proved reserves declined from $55.69 per Bbl at December 31, 2019, to $39.57 per Bbl at December 31, 2020. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and their values, including many factors beyond our control, which are further discussed in Item 1A, Risk Factors – Estimating our reserves, production and future net cash flows is difficult to do with any certainty.  See also Oil and Natural Gas Operations–Field Summary Table and Supplemental Oil and Natural Gas Disclosures (Unaudited) to the consolidated financial statements for further discussion of reserve inputs and changes between periods.
 December 31,
 202020192018
Estimated proved reserves   
Oil (MBbls)140,499 226,133 255,042 
Natural gas (MMcf)15,604 24,334 43,008 
Oil equivalent (MBOE)143,100 230,189 262,210 
Reserve volumes categories   
Proved developed producing   
Oil (MBbls)123,802 178,538 200,852 
Natural gas (MMcf)14,132 21,627 39,562 
Oil equivalent (MBOE)126,158 182,143 207,446 
Proved developed non-producing   
Oil (MBbls)12,600 24,278 21,884 
Natural gas (MMcf)1,472 2,706 3,350 
Oil equivalent (MBOE)12,845 24,729 22,442 
Proved undeveloped   
Oil (MBbls)4,097 23,317 32,306 
Natural gas (MMcf)— 1 96 
Oil equivalent (MBOE)4,097 23,317 32,322 
Percentage of total MBOE   
Proved developed producing88 %79 %79 %
Proved developed non-producing9 %11 %9 %
Proved undeveloped3 %10 %12 %
Representative oil and natural gas prices(1)
   
Oil (NYMEX price per Bbl)$39.57 $55.69 $65.56 
Natural gas (Henry Hub price per MMBtu)1.99 2.58 3.10 
Present values (in thousands)(2)
  
Discounted estimated future net cash flows before income taxes (PV-10 Value)(3)
$703,080 $2,615,668 $4,025,139 
Standardized measure of discounted estimated future net cash flows after income taxes (“Standardized Measure”)$654,734 $2,261,039 $3,351,385 

(1)The reference prices were based on the arithmetic average of the first-day-of-the-month NYMEX commodity prices for each month during the respective year. These prices do not reflect adjustments for market differentials and transportation expenses by field that are utilized in the preparation of our reserve report to arrive at the appropriate net price we receive. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Financial and Operating Results Tables for details of oil and natural gas prices received, both including and excluding the impact of derivative settlements.


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(2)Determined based on the average first-day-of-the-month prices for each month, adjusted to prices received by field in accordance with standards set forth in the FASC. PV-10 Values and the Standardized Measure are significantly impacted by the oil prices we receive relative to NYMEX oil prices (our NYMEX oil price differential). The weighted-average oil price differentials utilized were $3.73 per Bbl below representative NYMEX oil prices as of December 31, 2020, compared to $0.14 per Bbl below NYMEX oil prices as of December 31, 2019, and $0.24 per Bbl below NYMEX oil prices as of December 31, 2018.

(3)PV-10 Value is a non-GAAP measure and is different from the Standardized Measure in that PV-10 Value is a pre-tax number and the Standardized Measure is an after-tax number. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – Non-GAAP Financial Measure and Reconciliation for further discussion.

Our proved developed non-producing reserves primarily consist of (1) reserves within a proved tertiary flood in areas that have not yet experienced a response from CO2 injection, (2) reserves that will be recovered from currently productive zones utilizing minor modifications to manage the flow of CO2 or water within the reservoir, and (3) reserves that will be recovered through recompletions to other intervals above or below the currently producing interval.

As of December 31, 2020, our estimated proved undeveloped reserves totaled approximately 4.1 MMBOE, or approximately 3% of our estimated total proved reserves.  Approximately 83% (3.4 MMBOE) of our proved undeveloped oil reserves relate to planned future development within our CO2 tertiary operating fields.  We generally consider the CO2 tertiary proved undeveloped reserves to be lower risk than other proved undeveloped reserves that require drilling at locations offsetting existing production, because all of these proved undeveloped reserves are associated with tertiary recovery operations in fields and reservoirs that historically produced substantial volumes of oil under primary production. As of December 31, 2020, 3.2 MMBOE of our total proved undeveloped reserves are not scheduled to be developed within five years of initial booking, all of which are part of CO2 EOR projects. We believe these reserves satisfy the conditions to be included as proved reserves because (1) we have established and continue to follow the previously adopted development plan for each of these projects; (2) we have significant ongoing development activities in each of these CO2 EOR projects and (3) we have a historical record of completing the development of comparable long-term projects.

Our proved undeveloped reserves at December 31, 2020 were 19.2 MMBOE (82%) lower than at December 31, 2019. During 2020, we spent approximately $10 million to convert 1.5 MMBOE of proved undeveloped reserves to proved developed reserves, primarily related to continued tertiary development activities at Oyster Bayou Field. The primary changes in our proved undeveloped reserves during 2020 were related to recognizing net downward revisions of our proved undeveloped reserves of 17.7 MMBOE, primarily the result of the significant decline in commodity prices between December 31, 2019 and 2020.

During 2020, we provided oil and natural gas reserve estimates for 2019 to the United States Energy Information Agency that were substantially the same as the reserve estimates included in our Form 10-K for the year ended December 31, 2019.

Internal Controls Over Reserve Estimates

Reserve information in this report is based on estimates prepared by D&M, independent petroleum engineers located in Dallas, Texas, utilizing data provided by our internal reservoir engineering team and is the responsibility of management. We rely on D&M’s expertise to ensure that our reserve estimates are prepared in compliance with SEC rules and regulations and that appropriate geologic, petroleum engineering, and evaluation principles and techniques are applied in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of June 2019)”.  The person responsible for the preparation of the reserve report is a Senior Vice President and Division Manager of North America at D&M. He received a Bachelor of Science degree in Petroleum Engineering in 2003 from Istanbul Technical University and a Master’s degree and Doctorate in Petroleum Engineering in 2005 and 2010, respectively, from Texas A&M University, and he has in excess of 10 years of experience in oil and gas reservoir studies and evaluations.  Our Senior Vice President – Business Development and Technology is primarily responsible for overseeing the independent petroleum engineers during the process.  Our Senior Vice President – Business Development and Technology has a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines and over 35 years of industry experience working with petroleum engineering and reserve estimates.  D&M relies on various data provided by our internal reservoir engineering team in preparing its reserve estimates, including such items as oil and natural gas prices, ownership interests, production information, operating costs, planned capital expenditures and other technical data. Our internal reservoir engineering team consists of

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qualified petroleum engineers who maintain the Company’s internal evaluation of reserves and compare the Company’s information to the reserves prepared by D&M. Management is responsible for designing the internal control procedures used in the preparation of our oil and gas reserves, which include verification of data input into reserve forecasting and economics evaluation software, as well as multi-discipline management reviews.  The internal reservoir engineering team reports directly to our Senior Vice President – Business Development and Technology.  In addition, our Audit Committee of the Board of Directors oversees the qualifications, independence, performance and hiring of our independent petroleum engineers and reviews the final report and subsequent reporting of our oil and natural gas reserve estimates.  The Chairman of the Board holds a Ph.D. in Chemical Engineering from the Massachusetts Institute of Technology and bachelor’s degrees in Chemistry and Mathematics from Capital University in Ohio. He has more than 40 years of industry experience, with responsibilities including reserves preparation and approval.

CARBON CAPTURE, USE AND STORAGE

In additionCCUS is a process that captures CO2 from industrial sources and reuses it or stores the CO2 in geologic formations in order to avoid its release into the atmosphere. We utilize CO2 from industrial sources in our oilEOR operations, and natural gas operations, our strategically located and extensive CO2 pipeline infrastructure provide a meaningful opportunity to grow our businessand operations, particularly in the emerging CCUS industry.Gulf Coast, are strategically located in close proximity to one of the nation’s highest concentrations of power generation, industrial and petrochemical plants. We believe that the assets and technical expertise required for CCUS are highly aligned with Denbury’sour existing CO2 EOR operations, providing Denbury with an advantage, particularly in the Gulf Coast region, where our COwhich have been a significant focus for us for over 22 years.
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infrastructure is located in close proximity to multiple large sources of industrial emissions. We also believe that supportiveSupportive U.S. government policy and public pressure on industrial CO2 emitters could provide strong incentives for these entitiesthem to capture their CO2 emissions. In earlyemissions; for example, in January 2021, the U.S. Treasury and the IRS issued final regulations under Section 45Q of the Internal Revenue Code (“Section 45Q”) on the expanded carbon capture tax credit, implementing a number of changes and clarifications to previously proposed regulations, including (1) simplifying the definition of carbon capture equipment; (2) allowing smaller carbon capture facilities to be aggregated for purposes of meeting minimum capture requirements; (3) reducing the tax credit recapture period to three years; and (4) extending the beginning construction date to January 1, 2026 for carbon capture projects.previous regulations. The tax credit structure provides the capturing parties a tax credit that escalates until 2026, when it reaches $35 per ton for CO2 used in EOR operations or other qualified uses, and $50 per ton for CO2 directly stored in geologic formations.formations, annually escalating for inflation thereafter. The tax credit is available for a 12-year period for qualifying facilities that begin construction before January 1, 2026. Several enhancements to Section 45Q have been discussed and proposed, including increases to the tax credit, a direct pay feature and extensions to the construction commencement deadline. In addition to the Section 45Q tax credits, some entities may be eligible for other financial incentives or benefits for products that are created through CCUS.

We believe the incentives offered under Section 45Q will drive demand for CCUS and will allow us to collect a fee for the transportation and storage of captured industrial-sourced CO2, including its utilization in our EOR operations. While a portion of the CO2 we currently utilize in our EOR operations is captured from industrial sources and qualifies as CCUS, we have historically paid a proven technologyfee for that CO2 as those arrangements were entered into many years ago. As the enhanced Section 45Q regulations are relatively new, it will likely take several years for new capture facilities to be built and for dedicated storage sites to be developed.

As we seek to grow our CCUS business and pursue new CCUS opportunities, we have focused on the following strategic priorities:

•securing transportation and storage agreements with existing and new-build industrial emitters for the potentialtransport and storage of captured CO2;
•adding safe, reliable, uninterruptible and secure permanent storage capacity through development of a diverse portfolio of subsurface sequestration sites;
•increasing our carbon-negative oil production by seeking to replace the use of naturally-sourced CO2 in our EOR operations;
•preparing for safe, long-term, deep underground containmenta capital efficient expansion of industrial-sourcedour Green Pipeline capacity to meet expected rapid growth in demand from Gulf Coast industrial facility owners; and
•pursuing strategic partnerships throughout the CCUS value chain.

Since mid-2021, we have executed several term sheets for the future transportation and sequestration of CO2, and we believe Denbury is well positionedcontinue to leveragework with numerous third parties on definitive agreements and collaborative discussions for the transportation and storage of CO2 and development of storage sites. We believe our existing CO2 pipeline infrastructure, EOR operations, and EORexperience and expertise in working with CO2 positions us well to be a leader in this rapidly developing industry.

OIL AND NATURAL GAS OPERATIONS

Summary.Our oil and natural gas properties are concentrated in the Gulf Coast and Rocky Mountain regions of the United States.  Currently our properties with proved and producing reserves in the Gulf Coast region are situated in Mississippi, Texas, and Louisiana, and in the Rocky Mountain region are situated in Montana, Wyoming and North DakotaDakota. Approximately 97% of our production is oil, and Wyoming. The Companyover two-thirds of our production is differentiated by itsfrom CO2 EOR. Over time, we have grown primarily through the acquisition of mature oil fields, where we focus on increasing the value of those properties through a combination of exploitation, drilling and proven engineering extraction processes, with our most significant emphasis relating to CO2 EOR and the emerging CCUS industry, supported by the Company’s CO2 EOR technical and operational expertise and its extensive CO2 pipeline infrastructure. The utilization of captured industrial-sourced CO2 in EOR significantly reduces the carbon footprint of the oil that Denbury produces, underpinning the Company’s goal to fully offset its Scope 1, 2, and 3 CO2 emissions within the decade.operations. Our current portfolio of CO2 EOR projects provides us significant oil production and reserve growth potential, in the future, assuming crude oil prices are at levels that support the development of those projects.


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We have been conducting and expanding EOR operations on our assetsproperties in the Gulf Coast region since 1999, and as a result, we currently have many more CO2 EOR projects in this region than in the Rocky Mountain region. We began operations in the Rocky Mountain region in 2010 in connection with, and following, our merger with Encore Acquisition Company (“Encore”). In 2012, as part of a significant sale and exchange transaction with Exxon Mobil Corporation (“ExxonMobil”), we sold to ExxonMobil our Bakken area assets in North Dakota and Montana in exchange for (1) $1.3 billion in cash, (2) operating interests in Hartzog Draw and Webster fields in Wyoming and Texas, respectively, and (3) an overriding royalty interest equivalent to an approximate one-third ownership interest in ExxonMobil’s CO2 reserves in LaBarge Field in Wyoming (the “Bakken Exchange Transaction”). In the Gulf Coast region, we own what is, to our knowledge, the region’s only significant naturally occurring source of CO2, and these large volumes of naturally occurring CO2 give us a significant competitive advantage in this area. In addition to this naturally occurring CO2 source, we utilize CO2 captured from industrial sources which would otherwise be released into the atmosphere (sometimes referred to as anthropogenic, man-made or industrial-sourced CO2) in our tertiary operations, including CO2 from the LaBarge Field in Wyoming, which is captured in conjunction with processing helium from the LaBarge Field gas stream at ExxonMobil’s Shute Creek gas plant. These industrial sources of CO2 help us recover additional oil from mature oil fields and, we believe, also provide an economical way to reduce

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atmospheric CO2 emissions through the associated underground storage of CO2 which incidentally occurs as part of our oil-producing EOR operations.

We own and operate more than 1,300 miles of CO2 transportation pipelines. Our extensive CO2 pipeline infrastructure in the Gulf Coast and Rocky Mountain regions gives us the ability to deliver CO2 from our natural and industrial CO2 sources for use in our CO2 EOR fields, as well as to deliver CO2 to our customers who are industrial end-users of CO2 or EOR customers. In the future, we plan to utilize these same pipelines for the transportation and sequestration of CO2 in our emerging CCUS business. Our Green Pipeline currently has ample capacity to handle additional volumes, and we can further expand capacity by adding pump stations or looping sections of the pipeline.

Oil and Natural Gas Reserve Estimates

DeGolyer and MacNaughton (“D&M”) prepared estimates of our net proved oil and natural gas reserves as of December 31, 2021, 2020 and 2019 (see the summary of D&M’s report as of December 31, 2021 included as an exhibit to this Form 10-K). These estimates of reserves were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices on the first day of each month within the 12-month period in accordance with rules and regulations of the SEC.  These oil and natural gas reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage.  The reserve estimates represent our net revenue interest in our properties.

The following table provides estimated proved reserve information prepared by D&M as of December 31, 2021, 2020 and 2019, as well as PV-10 Values and Standardized Measures for each period. The Company’s December 31, 2021 proved oil and natural gas reserve quantities and PV-10 Values increased significantly from December 31, 2020 due largely to the increase in oil prices used in preparing the December 31, 2020 and 2021 reserve information, whereby the average NYMEX oil price used in estimating our proved reserves increased from $39.57 per Bbl at December 31, 2020, to $66.56 per Bbl at December 31, 2021. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and their values, including many factors beyond our control, which are further discussed in Item 1A, Risk Factors – Estimating our reserves, production and future net cash flows is difficult to do with any certainty.  See also Field Summary Table below within this

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section and Supplemental Oil and Natural Gas Disclosures (Unaudited) to the consolidated financial statements for further discussion of reserve inputs and changes between periods.
 December 31,
 202120202019
Estimated proved reserves   
Oil (MBbls)188,938 140,499 226,133 
Natural gas (MMcf)16,506 15,604 24,334 
Oil equivalent (MBOE)191,689 143,100 230,189 
Reserve volumes categories   
Proved developed producing   
Oil (MBbls)164,744 123,802 178,538 
Natural gas (MMcf)14,844 14,132 21,627 
Oil equivalent (MBOE)167,218 126,158 182,143 
Proved developed non-producing   
Oil (MBbls)14,403 12,600 24,278 
Natural gas (MMcf)1,662 1,472 2,706 
Oil equivalent (MBOE)14,680 12,845 24,729 
Proved undeveloped   
Oil (MBbls)9,791 4,097 23,317 
Natural gas (MMcf)— — 1 
Oil equivalent (MBOE)9,791 4,097 23,317 
Percentage of total MBOE   
Proved developed producing87 %88 %79 %
Proved developed non-producing8 %9 %11 %
Proved undeveloped5 %3 %10 %
Representative oil and natural gas prices(1)
   
Oil (NYMEX price per Bbl)$66.56 $39.57 $55.69 
Natural gas (Henry Hub price per MMBtu)3.60 1.99 2.58 
Present values (in thousands)(2)
  
Discounted estimated future net cash flows before income taxes (PV-10 Value)(3)
$2,673,822 $703,080 $2,615,668 
Standardized measure of discounted estimated future net cash flows after income taxes (“Standardized Measure”)$2,187,051 $654,734 $2,261,039 

(1)The reference prices were based on the arithmetic average of the first-day-of-the-month NYMEX commodity prices for each month during the respective year. These prices do not reflect adjustments for market differentials and transportation expenses by field that are utilized in the preparation of our reserve report to arrive at the appropriate net price we receive. Further, we do not designate our oil and natural gas derivative contracts as hedging instruments for accounting purposes under the Derivatives and Hedging topic of the FASC, and as a result, the impact of these contracts is not included in the prices used in determining our reserve quantities or values. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Financial and Operating Results Tables for details of oil and natural gas prices received, both including and excluding the impact of derivative settlements.

(2)Determined based on the average first-day-of-the-month prices for each month, adjusted to prices received by the field in accordance with standards set forth in the FASC. PV-10 Values and the Standardized Measure are significantly impacted by the oil prices we receive relative to NYMEX oil prices (our NYMEX oil price differential). The weighted average oil price differentials utilized were $2.70 per Bbl below representative NYMEX oil prices as of December 31, 2021, compared to $3.73 per Bbl below NYMEX oil prices as of December 31, 2020, and $0.14 per Bbl below NYMEX oil prices as of December 31, 2019.

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(3)PV-10 Value is a non-GAAP measure and is different from the Standardized Measure in that PV-10 Value is a pre-tax number and the Standardized Measure is an after-tax number. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – Non-GAAP Financial Measure and Reconciliation for further discussion.

Our proved developed non-producing reserves primarily consist of (1) reserves within a proved tertiary flood in areas that have not yet experienced a response from CO2 injection, (2) reserves that will be recovered from currently productive zones utilizing minor modifications to manage the flow of CO2 or water within the reservoir, and (3) reserves that will be recovered through recompletions to other intervals above or below the currently producing interval.

As of December 31, 2021, our estimated proved undeveloped reserves totaled approximately 9.8 MMBOE, or approximately 5% of our estimated total proved reserves.  Approximately 98% (9.6 MMBOE) of our proved undeveloped oil reserves relate to planned future development within our CO2 tertiary operating fields.  We generally consider the CO2 tertiary proved undeveloped reserves to be lower risk than other proved undeveloped reserves that require drilling at locations offsetting existing production, because all of these proved undeveloped reserves are associated with tertiary recovery operations in fields and reservoirs that historically produced substantial volumes of oil under primary production. As of December 31, 2021, 0.8 MMBOE of our total proved undeveloped reserves are not scheduled to be developed within five years of initial booking, all of which are part of CO2 EOR projects. We believe these reserves satisfy the conditions to be included as proved reserves because (1) we have established and continue to follow the previously adopted development plan for each of these projects; (2) we have significant ongoing development activities in each of these CO2 EOR projects and (3) we have a historical record of completing the development of comparable long-term projects.

Our proved undeveloped reserves at December 31, 2021 were 5.7 MMBOE (139%) higher than at December 31, 2020. During 2021, we spent approximately $5 million to convert 0.7 MMBOE of proved undeveloped reserves to proved developed reserves, primarily related to non-tertiary development activities at CCA. The primary changes in our proved undeveloped reserves during 2021 were related to adding an additional 3.0 MMBOE primarily related to tertiary operations at Hastings, Eucutta and Cranfield fields and 1.0 MMBOE related to the acquisition of our Wind River Basin properties, as well as recognizing net upward revisions of our proved undeveloped reserves of 2.4 MMBOE, primarily the result of the significant improvement in commodity prices between December 31, 2020 and 2021.

During 2021, we provided oil and natural gas reserve estimates for 2020 to the United States Energy Information Agency that were substantially the same as the reserve estimates included in our Form 10-K for the year ended December 31, 2020.

Internal Controls Over Reserve Estimates

Reserve information in this report is based on estimates prepared by D&M, independent petroleum engineers located in Dallas, Texas, utilizing data provided by our internal reservoir engineering team and is the responsibility of management. We rely on D&M’s expertise to ensure that our reserve estimates are prepared in compliance with SEC rules and regulations and that appropriate geologic, petroleum engineering, and evaluation principles and techniques are applied in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of June 2019)”.  The person responsible for the preparation of the reserve report is a Senior Vice President and Division Manager of North America at D&M. He received a Bachelor of Science degree in Petroleum Engineering in 2003 from Istanbul Technical University and a Master’s degree and Doctorate in Petroleum Engineering in 2005 and 2010, respectively, from Texas A&M University, and he has in excess of 11 years of experience in oil and gas reservoir studies and evaluations.  Our Senior Vice President – Business Development and Technology is primarily responsible for overseeing the independent petroleum engineers during the process.  Our Senior Vice President – Business Development and Technology has a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines and over 35 years of industry experience working with petroleum engineering and reserve estimates.  D&M relies on various data provided by our internal reservoir engineering team in preparing its reserve estimates, including such items as oil and natural gas prices, ownership interests, production information, operating costs, planned capital expenditures and other technical data. Our internal reservoir engineering team consists of qualified petroleum engineers who maintain the Company’s internal evaluation of reserves and compare the Company’s information to the reserves prepared by D&M. Management is responsible for designing the internal control procedures used in the preparation of our oil and gas reserves, which include verification of data input into reserve forecasting and economics evaluation software, as well as multi-discipline management reviews.  The internal reservoir engineering team reports directly to our Senior Vice President – Business Development and Technology.  In addition, our Audit Committee of the Board of

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Directors oversees the qualifications, independence, performance and hiring of our independent petroleum engineers and reviews the final report and subsequent reporting of our oil and natural gas reserve estimates.  The Chairman of the Board holds a Ph.D. in Chemical Engineering from the Massachusetts Institute of Technology and bachelor’s degrees in Chemistry and Mathematics from Capital University in Ohio. He has more than 40 years of industry experience, with responsibilities including reserves preparation and approval.

Field Summary Table. The following table provides a summary by field and region of selected proved oil and natural gas reserve information, including total proved reserve quantities as of December 31, 2020,2021, and average daily productionsales volumes for 2020,2021, all based on Denbury’s net revenue interest (“NRI”).  The reserve estimates presented were prepared by D&M, independent petroleum engineers located in Dallas, Texas.  We serve as operator of nearly all of our significant properties, in which we also own most of the interests, although typically less than a 100% working interest, and a lesser NRI due to royalties and other burdens. For additional oil and natural gas reserves information, see Estimated Net Quantities of Proved Oil and Natural Gas Reserves and Present Value of Estimated Future Net RevenuesReserve Estimates above and Supplemental Oil and Natural Gas Disclosures (Unaudited) toin the consolidated financial statements.
Proved Reserves as of December 31, 2020(1)
2020 Average Daily Production
Proved Reserves as of December 31, 2021(1)
2021 Average Daily Sales Volumes
Oil
(MBbls)		Natural Gas
(MMcf)		MBOEs% of Company Total
MBOEs		Oil
(Bbls/d)		Natural Gas
(Mcf/d)		Average 2020 NRIOil
(MBbls)		Natural Gas
(MMcf)		MBOEs% of Company Total
MBOEs		Oil
(Bbls/d)		Natural Gas
(Mcf/d)		Average 2021 NRI
Tertiary oil and gas propertiesTertiary oil and gas propertiesTertiary oil and gas properties
Gulf Coast regionGulf Coast regionGulf Coast region
DelhiDelhi8,540 — 8,540 6.0 %3,419 — 57.8 %Delhi11,007 — 11,007 5.7 %2,861 — 58.5 %
HastingsHastings19,722 — 19,722 13.8 %4,755 — 79.9 %Hastings19,832 — 19,832 10.3 %4,317 — 80.0 %
HeidelbergHeidelberg14,217 — 14,217 9.9 %4,297 — 81.0 %Heidelberg15,071 — 15,071 7.9 %3,921 — 81.2 %
Oyster BayouOyster Bayou13,691 — 13,691 9.6 %3,818 — 87.3 %Oyster Bayou15,780 — 15,780 8.2 %3,833 — 87.4 %
TinsleyTinsley6,916 — 6,916 4.8 %3,959 — 81.9 %Tinsley14,879 — 14,879 7.8 %3,405 — 81.9 %
West Yellow Creek135 — 135 0.1 %668 — 36.8 %
Mature properties(2)
7,356 — 7,356 5.1 %5,759 — 80.0 %
Other(2)
Other(2)
12,795 — 12,795 6.7 %5,969 — 74.4 %
Total Gulf Coast regionTotal Gulf Coast region70,577 — 70,577 49.3 %26,675 — 75.9 %Total Gulf Coast region89,364 — 89,364 46.6 %24,306 — 76.8 %
Rocky Mountain regionRocky Mountain regionRocky Mountain region
Bell CreekBell Creek9,616 — 9,616 6.7 %5,518 — 84.7 %Bell Creek11,265 — 11,265 5.9 %4,416 — 84.1 %
Salt Creek2,002 — 2,002 1.4 %1,928 — 17.6 %
Grieve— — — — %14 — 20.5 %
Other(3)
Other(3)
14,328 — 14,328 7.5 %4,059 — 33.9 %
Total Rocky Mountain regionTotal Rocky Mountain region11,618 — 11,618 8.1 %7,460 — 41.9 %Total Rocky Mountain region25,593 — 25,593 13.4 %8,475 — 49.2 %
Total tertiary propertiesTotal tertiary properties82,195 — 82,195 57.4 %34,135 — 64.6 %Total tertiary properties114,957 — 114,957 60.0 %32,781 — 67.0 %
Non-tertiary oil and gas propertiesNon-tertiary oil and gas propertiesNon-tertiary oil and gas properties
Gulf Coast regionGulf Coast regionGulf Coast region
Texas10,481 5,548 11,406 8.0 %2,729 2,313 58.4 %
Mississippi and other1,245 7,926 2,566 1.8 %347 2,071 7.9 %
Total Gulf Coast regionTotal Gulf Coast region11,726 13,474 13,972 9.8 %3,076 4,384 31.7 %Total Gulf Coast region16,985 15,888 19,633 10.2 %3,068 3,690 34.0 %
Rocky Mountain regionRocky Mountain regionRocky Mountain region
Cedar Creek Anticline(3)
45,217 4 45,218 31.6 %11,745 1,439 80.6 %
Other1,361 2,126 1,715 1.2 %681 2,095 64.7 %
Cedar Creek Anticline(4)
Cedar Creek Anticline(4)
55,047 6 55,048 28.7 %10,745 1,578 81.2 %
Other(5)
Other(5)
1,949 612 2,051 1.1 %687 3,665 66.4 %
Total Rocky Mountain regionTotal Rocky Mountain region46,578 2,130 46,933 32.8 %12,426 3,534 79.4 %Total Rocky Mountain region56,996 618 57,099 29.8 %11,432 5,243 79.9 %
Total non-tertiary propertiesTotal non-tertiary properties58,304 15,604 60,905 42.6 %15,502 7,918 59.7 %Total non-tertiary properties73,981 16,506 76,732 40.0 %14,500 8,933 61.4 %
Total continuing properties140,499 15,604 143,100 100.0 %49,637 7,918 63.0 %
Property sales
Property divestitures(4)
— — — — %191 20 
Company TotalCompany Total140,499 15,604 143,100 100.0 %49,828 7,938 Company Total188,938 16,506 191,689 100.0 %47,281 8,933 65.2 %

(1)Reserve estimates were prepared in accordance with FASC Topic 932, Extractive Industries – Oil and Gas, using the arithmetic averages of the first-day-of-the-month NYMEX commodity price for each month during 2020,2021, which were $39.57$66.56 per Bbl for crude oil and $1.99$3.60 per MMBtu for natural gas.

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

(3)Includes tertiary operations from Wind River Basin, as well as Salt Creek and Grieve fields.


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

(3)(4)The Cedar Creek Anticline consists of a series of 13 different operating areas.

(4)(5)Includes non-tertiary production related to the March 2020 sale of 50% of our working interests in Webster, Thompson, Manvel,operations from Wind River Basin, as well as Hartzog Draw and East HastingsBell Creek fields.

Enhanced Oil Recovery Overview. EOR using CO2 used in EOR is one of the most efficient tertiary recovery mechanisms for producing crude oil. When injected under pressure into underground, oil-bearing rock formations, CO2 acts somewhat like a solvent as it travels through the reservoir rock, mixing with and modifying the characteristics of the oil so it can be produced and sold. The terms “tertiary flood,” “CO2 flood” and “CO2 EOR” are used interchangeably throughout this document.

While enhanced oil recovery projects utilizing CO2 have been successfully performed by numerous oil and gas companies in a wide range of oil-bearing reservoirs in different oil-producing basins, we believe our investments, experience and acquired knowledge give us a strategic and competitive advantage in the areas in which we operate. We apply what we have learned and developed over the years to improve and increase sweep efficiency within the CO2 EOR projects we operate.

We began our CO2 operations in August 1999, when we acquired Little Creek Field, followed by our acquisition of Jackson Dome CO2 reserves and the NEJD pipeline in 2001. Based upon our success at Little Creek and the ownership of the CO2 reserves, we began to transition our capital spending and acquisition efforts to focus more heavily on CO2 EOR and, over time, transformed our strategy to focus primarily on owning and operating oil fields that are well suited for CO2 EOR projects. Prior to tertiary flooding, we strive to maximize the currently sizeable primary and secondary production from our prospective tertiary fields and from fields in which tertiary floods have commenced but still contain significant non-tertiary production. Our asset base today almost entirely consists of, or otherwise relates to, oil fields that we are currently flooding with CO2 or plan to flood with CO2 in the future, or assets that produce CO2.

Our tertiary operations have grown so that (1) 57% of our proved reserves at December 31, 2020 are proved tertiary oil reserves; (2) 67% of our 2020 total production was related to tertiary oil operations (on a BOE basis); and (3) 59% of our 2020 capital expenditures (excluding acquisitions) were related to our tertiary oil operations.  At year-end 2020, the proved oil reserves in our tertiary recovery oil fields had an estimated PV-10 Value of approximately $449.9 million, or 64% of our total PV-10 Value.  In addition, there are significant probable and possible reserves at several other fields for which tertiary operations are underway or planned.

Although the up-front cost of tertiary production infrastructure and time to construct pipelines and production facilities is greater than in primary oil recovery in most circumstances, we believe tertiary recovery has several favorable, offsetting and unique attributes, including (1) including:
•a lower exploration risk, as we are operating oil fields that have significant historical production and reservoir and geological data, (2) data;
•lower production decline rates than unconventional development, (3) development;
•reasonable return metrics at ourcurrently anticipated long-term prices, (4) prices;
•limited competition for this recovery method in our geographic regions and a strategic advantage due to our ownership of the CO2 reserves and CO2 pipeline infrastructure, (5) our EOR operations areinfrastructure;
•being generally less disruptive to new habitats in comparison to other oil and natural gas development because we further develop existing (as opposed to new) oil fields,fields; and (6) through our oil-producing EOR operations, we
•allowing us to concurrently store CO2 captured from industrial sources in the same underground formations that previously trapped and stored oil and natural gas.

Tertiary Oil PropertiesOur tertiary operations represent 67% of our 2021 total production (on a BOE basis). At year-end 2021, the proved oil reserves in our tertiary recovery oil fields had an estimated PV-10 Value of approximately $1.8 billion, or 66% of our total PV-10 Value, and represented 60% of our total proved reserves. In addition, there are significant probable and possible reserves at several other fields for which tertiary operations are underway or planned.

Gulf Coast Region Assets

CO2 Sources and Pipelines

Natural CO2 Sources

Jackson Dome. Our primary Gulf Coast CO2 source, Jackson Dome, located near Jackson, Mississippi, was discovered during the 1970s by oil and gas companies that were exploring for hydrocarbons. This large and relatively pure source of naturally occurring CO2 (98% CO2) is, to our knowledge, the only significant underground deposit of CO2 in the United States east of the Mississippi River. Together with the related CO2 pipeline infrastructure, Jackson Dome provides us a significant

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strategic advantage in the acquisition of properties in Mississippi, Louisiana and southeastern Texas that are well suited for CO2 EOR.

We acquired Jackson Dome in February 2001 in a purchase that also gave us ownership and control of the NEJD CO2 pipeline and provided us with a reliable supply of CO2 at a reasonable and predictable cost for our Gulf Coast CO2 tertiary recovery operations. Together with its related CO2 pipeline infrastructure, Jackson Dome provides us a significant competitive advantage in the acquisition and development of properties in Mississippi, Louisiana and southeastern Texas that are well suited for CO2 EOR.

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Since February 2001, we have acquired and drilled numerous CO2-producing wells, significantly increasing our estimated proved Gulf Coast CO2 reserves at Jackson Dome from approximately 800 Bcf at the time of acquisition of Jackson Dome to approximately 4.64.5 Tcf as of December 31, 2020.2021.  The proved CO2 reserve estimates are based on a gross (8/8ths) basis, of which our net revenue interest is approximately 3.73.6 Tcf, and is included in the evaluation of proved CO2 reserves prepared by D&M, independent petroleum engineers.  In discussing our available CO2 reserves, we make reference to the gross amount of proved and probable reserves, as this is the amount that is available both for our own tertiary recovery programs and for industrial usersour customers who are customersindustrial end-users of Denbury and others,CO2 or EOR customers, as we are responsible for distributing the entire CO2 production stream.

In addition to our proved reserves, we estimate that we have 910.1 Bcf, on a gross (8/8ths) basis, of probable CO2 reserves at Jackson Dome. While the majority of these probable reserves are located in structures that have been drilled and tested, such reserves are still considered probable reserves because (1) the original well is plugged; (2) they are located in fault blocks that are immediately adjacent to fault blocks with proved reserves; or (3) they are reserves associated with increasing the ultimate recovery factor from our existing reservoirs with proved reserves. In addition, a significant portion of these probable reserves at Jackson Dome are located in undrilled structures where we have sufficient subsurface and seismic data indicating geophysical attributes that, coupled with our historically high drilling success rate, provide a reasonably high degree of certainty that CO2 is present.

Industrial-sourced CO2

In addition to our drillingnaturally occurring CO2 source at Jackson Dome, in our tertiary operations we have the capability to expand our processing and dehydration capacities and install additional pipelines and/or pumping stations necessary to transport theutilize CO2 through our controlled pipeline network. We expect our current proved reserves of CO2, coupled with a risked drilling program at Jackson Dome and CO2 expected to be captured from industrial sources which would otherwise be released into the atmosphere. Industrial sources of CO2 help us recover additional oil from mature oil fields and, we believe, also provide an economical way to provide sufficient quantitiesreduce CO2 emissions through the associated underground storage of CO2 which occurs as part of our oil-producing EOR operations (see Carbon Capture, Use and Storage below). In the Gulf Coast, we are currently party to two long-term contracts to purchase CO2: an industrial facility in Port Arthur, Texas and an industrial facility in Geismar, Louisiana, which combined supplied an average of approximately 63 MMcf/d of CO2 for us to develop our proved and probable EOR reserves inoperations during 2021. During the Gulf Coast region. In the future, we believe that once a CO2 flood in a field reaches its productive economic limit, we could recycle a portionyear ended December 31, 2021, approximately 15% of the CO2 that remainsutilized in that field’s reservoirour Gulf Coast oil and utilize it for oil production in another field’s tertiary flood.gas operations was industrial-sourced CO2.

In the Gulf Coast region, approximately 78%77% of our average daily CO2 produced from Jackson Dome or captured from industrial sources in 20202021 was used in our tertiary recovery operations, compared to 78% in 2020 and 84% in 2019, and 83% in 2018, with the balance delivered to third-party industrial users.end-users or EOR customers. During 2020,2021, we used an average of 358407 MMcf/d of CO2 (including CO2 captured from industrial sources) for our tertiary activities.

Gulf Coast CO2Captured from IndustrialSources.  In addition to our natural source of CO2, we are currently party to two long-term contracts to purchase CO2 from industrial plants.  We have purchased CO2 from an industrial facility in Port Arthur, Texas since 2012 and from an industrial facility in Geismar, Louisiana since 2013, which supplied an average of approximately 57 MMcf/d of CO2 to our EOR operations during 2020.  Additionally, we are in ongoing discussions with other parties that are planning to capture CO2 from currently existing industrial facilities or proposed new industrial facilities near the Green Pipeline. In order to capture such volumes, we (or the plant owner) would need to install additional equipment, which includes, at a minimum, compression and dehydration facilities.

Gulf Coast CO2 Pipelines. We acquired the 183-mile NEJD CO2 pipeline that runs from Jackson Dome to near Donaldsonville, Louisiana, as part of the 2001 acquisition of our Jackson Dome CO2 source. Since 2001, we have acquired or constructed nearly 750 miles of CO2 pipelines in the Gulf Coast, and as of December 31, 2020,2021, we own nearly 925 miles of CO2 pipelines, which gives us the ability to deliver CO2 throughout the Gulf Coast region.  In addition to the NEJD CO2 pipeline, the major pipelines in the Gulf Coast region are the Free State Pipeline (90 miles), Delta Pipeline (110 miles), Green Pipeline Texas (120 miles), and Green Pipeline Louisiana (200 miles). In late October 2020, we restructured our NEJD and Free State CO2 pipeline agreements with Genesis (see 2020 Business Developments above).

Completion of the Green Pipeline allowed for the first CO2 injection into Hastings Field, located near Houston, Texas, in 2010, and gives us the ability to deliver CO2 to oil fields all along the Gulf Coast from Baton Rouge, Louisiana, to Alvin, Texas. At the present time, most of the CO2 flowing in the Green Pipeline is delivered from the Jackson Dome area, but also includes the CO2 we are receiving from the industrial facilities in Port Arthur, Texas and Geismar, Louisiana, and we are

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currently transporting a third party’s CO2 for a fee to the sales point at Hastings Field. We currently have ample capacity within the Green Pipeline to handle additional volumes that may be required to develop our inventory of CO2 EOR projects in this

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area, as well as to support the transportation of CO2 for the emerging CCUS business. The following table summarizes our most significant CO2 pipelines owned and operated in the Gulf Coast region as of December 31, 2021:
CO2 pipelines
Completion DatePipeline Diameter
(in inches)		Pipeline MileageService Area
Green Pipeline201024”320
Gulf Coast corridor from near Donaldsonville, Louisiana to Hastings Field in Texas; including connections to 2 industrial-source CO2 providers
NEJD Pipeline198620”183
Jackson Dome CO2 source to Green Pipeline connection
Delta Pipeline200924”111
Jackson Dome CO2 source to Delhi Field in Louisiana
Free State Pipeline200520”91
Jackson Dome CO2 source to West Yellow Creek in Mississippi
West Gwinville
1959/2008(1)
18”51NEJD Pipeline to Cranfield Field

(1)Repurposed from a natural gas pipeline to a CO2 pipeline in 2008.

Tertiary Properties with Tertiary Production and Proved Tertiary Reserves at December 31, 2020Oil Fields

Delhi Field. Delhi Field is located east of Monroe, Louisiana. In May 2006, we purchased our initial interest in Delhi for $50 million. We began well and facility development in 2008, began delivering CO2 to the field in 2009 via the Delta Pipeline, which runs from Tinsley Field to Delhi Field, and first tertiary production occurred at Delhi Field in 2010. During 2016, we completed construction of a natural gas liquids extraction plant, which provides us with the ability to sell natural gas liquids from the produced stream, improveimproves the efficiency of the CO2 flood, and utilizeutilizes extracted methane to power the plant and reduce field operating expenses. Production from Delhi Field inOur 2022 development plans include the fourth quarterpurchase and installation of 2020 averaged 3,132 Bbls/d, comparedan inlet heat exchanger to 4,085 Bbls/d in the fourth quarter of 2019.increase production reliability and reduce costs.

Hastings Field. Hastings Field is located south of Houston, Texas. We acquired a majority interest in this field in February 2009 for $247 million. We initiated CO2 injection in the West Hastings Unit during 2010 upon completion of the construction of the Green Pipeline. Due to the large vertical oil column that exists in the field, we are developing the Frio reservoir using dedicated CO2 injection and producing wells for each of the major sand intervals. We began producing oil from our EOR operations at Hastings Field in 2012, and we booked initial proved tertiary reserves for the West Hastings Unit in 2012.  The Company also has future plans for continued tertiary development of existing proved undeveloped reserves at the field. During the fourth quarter of 2020, tertiary production from Hastings Field averaged 4,598 Bbls/d, compared to 5,097 Bbls/d in the fourth quarter of 2019.

Heidelberg Field. Heidelberg Field is located in Mississippi off of the Free State Pipeline and consists of an East Unit and a West Unit. Construction of the CO2 facility, connecting pipeline and well work commenced on the West Heidelberg Unit during 2008, with our first CO2 injections into the Eutaw zone. Our first tertiary oil production occurred in 2009, and we began flooding the Christmas and Tuscaloosa zones in 2013 and 2014, respectively. During 2019, we expanded our tertiary flood of the Christmas zone and invested in non-tertiary behind pipe projects. DuringOur 2022 development plans include developing the fourth quarter of 2020, tertiary production at Heidelberg Field averaged 4,198 Bbls/d, compared to 4,409 Bbls/dremaining CO2 flood in the fourth quarter of 2019.Tuscaloosa reservoir at East Heidelberg.

Oyster Bayou Field. We acquired a majority interest in Oyster Bayou Field in 2007. The field is located in southeast Texas, east of Galveston Bay, and is somewhat unique when compared to our other CO2 EOR projects because the field covers a relatively small area of 3,912 acres. We began CO2 injections into Oyster Bayou Field in 2010, commenced tertiary production in 2011 from the Frio A-1 zone, and booked initial proved tertiary reserves for the field in 2012. In 2014, we completedOur 2022 development of the Frioplans include additional A-2 zone and we further expanded the A-2 flood and increased compression capacity during 2020. During the fourth quarter of 2020, tertiary production at Oyster Bayou Field averaged 3,880 Bbls/d, compared to 4,261 Bbls/d in the fourth quarter of 2019.development.

Tinsley Field.We acquired Tinsley Field in 2006. This Mississippi field was discovered and first developed in the 1930s and is separated by different fault blocks. As is the case with the majority of fields in Mississippi, Tinsley Field produces from multiple reservoirs. Our CO2 enhanced oil recovery operations at Tinsley Field have thus far targeted the Woodruff formation, although there is additional potential in the Perry sandstone and other smaller reservoirs. We commenced tertiary oil production from Tinsley Field in 2008 and substantially completed development of the Woodruff formation during 2014. During the fourth quarter of 2020, tertiary oil production from the field averaged 3,654 Bbls/d, compared to 4,343 Bbls/d in the fourth quarter of 2019. Although production from Tinsley Field peaked in 2015 and is generally on decline, we continue to evaluate future potential investment opportunities in this field.

West Yellow Creek Field. We acquired an approximate 48% non-operated working interest in West Yellow Creek Field in Mississippi in March 2017 for approximately $16 million, a field in which the operator had previously invested significant capital converting the field to a CO2 EOR flood. Under our arrangement with the operator, we supply CO2 to the field for a fee. West Yellow Creek Field is in close proximity and analogous to Eucutta Field, a very successful CO2 flood that we developed and continue to operate. We booked initial proved tertiary oil reserves at West Yellow Creek Field as of year-end 2017 and commenced tertiary production in early 2018. During the fourth quarter of 2020, tertiary oil production from the field averaged 614 Bbls/d, compared to 807 Bbls/d in the fourth quarter of 2019.


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Mature properties.Future Gulf Coast Tertiary Opportunities. Mature propertiesFuture development projects beyond 2022 may include additional opportunities at Tinsley Field’s Perry sandstone reservoir and expansion of our longest-producing properties which are generally located along our NEJDexisting CO2 pipeline in southwest Mississippi and Louisiana andfloods. In addition to our Free State Pipeline in east Mississippi.  This group of properties includes our initialexisting CO2 field, Little Creek, as well as several other fields (Brookhaven, Cranfield, Eucutta, Mallalieu, Martinville, McComb and Soso fields).  These fields accounted for 17% of our total 2020 CO2 EOR production and approximately 5% of our year-end proved reserves.  These fields have been producing under CO2 flood for more than a decade, and their production is generally declining, thoughfloods, we continue to evaluate futuretertiary potential investment opportunities in these fields.

Potential Future Tertiary Properties with No Tertiary Production or Proved Tertiary Reserves at December 31, 2020

our non-tertiary properties such as Webster, Field. We acquired our interest in Webster Field in 2012 as part of the Bakken Exchange Transaction. The field is located southeast of Houston, Texas, approximately eight miles northeast of our Hastings Field which we are currently flooding with CO2. At December 31, 2020, Webster Field had estimated proved non-tertiary reserves of approximately 1.3 MMBOE, net to our interest, all of which are proved developed.  During the fourth quarter of 2020, non-tertiary production at Webster Fieldaveraged 442 BOE/d, compared to 923 BOE/d in the fourth quarter of 2019. In March 2020, we sold half of our working interest in Webster Field as part of our Gulf Coast Working Interests Sale (see Gulf Coast Working Interest Partner below).  Webster Field is geologically similar to our Hastings Field, producing oil from the Frio zone at similar depths; as a result, we believe it is well suited for CO2 EOR. In 2014, we completed a nine-mile lateral between the Green PipelineConroe and Webster Field, which we plan will eventually deliver CO2 to the field. Although we sold half of our working interest in Webster Field in 2020, we retained the right to execute a future CO2 flood in this field, the timing of which is primarily dependent upon capital availability and priorities and future oil prices.

Conroe Field.  Conroe Field, our largest potential tertiary flood in the Gulf Coast region, is located north of Houston, Texas.  We acquired a majority interest in this field in 2009 for $271 million in cash and 11.6 million shares of Denbury common stock, for a total aggregate value of $439 million.  Conroe Field had estimated proved non-tertiary reserves of approximately 7.8 MMBOE at December 31, 2020, net to our interest, all of which are proved developed.  During the fourth quarter of 2020, non-tertiary production at Conroe Field averaged 1,624 BOE/d, compared to 1,861 BOE/d in the fourth quarter of 2019.

To initiate a CO2 flood at Conroe Field, a pipeline must be constructed so that CO2 can be delivered to the field.  This pipeline, which is planned as an extension of our Green Pipeline, is preliminarily estimated to cover approximately 90 miles. The timing ofThompson fields, the development of a CO2 flood at Conroe Fieldwhich is primarily dependent upon capital availability and priorities, future oil prices and in some cases pipeline construction.

In addition to the currently-producing oil-bearing formations at Conroe Field, we are evaluating exploitation opportunities in other formations. We currently do not have any additional wells planned for 2021 but continue to evaluate additional opportunities and plan to de-risk other areas of the field in the future.

Thompson Field. We acquired our interest in Thompson Field in June 2012 for $366 million. The field is located in Texas, approximately 18 miles west of our Hastings Field. Thompson Field had estimated proved non-tertiary reserves of approximately 1.7 MMBOE at December 31, 2020, net to our interest, all of which are proved developed.  During the fourth quarter of 2020, non-tertiary production at Thompson Field averaged 455 BOE/d, compared to 1,008 BOE/d in the fourth quarter of 2019. In March 2020, we sold half of our working interest in Thompson Field as part of our Gulf Coast Working Interests Sale (see Gulf Coast Working Interest Partner below).  Thompson Field is geologically similar to Hastings Field, producing oil from the Frio zone at similar depths, and we therefore believe it has CO2 EOR potential. Under the terms of the Thompson Field acquisition agreement, after the initiation of CO2 injection, the seller will retain approximately a 5% gross revenue interest (less severance taxes) once average monthly oil production exceeds 3,000 Bbls/d. The timing of the development of a CO2 flood at Thompson Field is primarily dependent upon capital availability and priorities and future oil prices.

Gulf Coast Working Interest Partner.In March 2020, we sold half of our nearly 100% working interest positions in four conventional southeast Texas oil fields (consisting of Webster, Thompson, Manvel and East Hastings) for $40 million net cash and a carried interest in ten wells to be drilled by the purchaser. Under the agreement, the purchaser is committed to funding 100% of the capital required to drill and complete an initial ten horizontal wells across the fields within 18 months after closing. On these initial ten wells, Denbury will receive a 6.25% overriding royalty interest prior to the combined payout of the wells in a specified field and subsequent to payout, Denbury will receive production revenues from, and bear the cost of, its

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50% working interest in each well. As part of the agreement, we will retain 100% ownership of the future Webster Unit CO2 flood, wherein (1) the purchaser may elect to participate in the future CO2 flood through reimbursement to Denbury of the purchaser’s working interest share of project costs incurred to date, or (2) if the purchaser declines to participate in the CO2 flood, we have the right to repurchase the purchaser’s working interest in Webster Field under a contractually agreed valuation mechanism.

Rocky Mountain Region Assets

CO2 Sources and Pipelines

LaBarge Field. We acquired an overriding royalty interest equivalent to an approximate one-third ownership interest in ExxonMobil’s CO2 reserves in LaBarge Field in the fourth quarter of 2012 as part of the Bakken Exchange Transaction. LaBarge Field is located in southwestern Wyoming, and as of December 31, 2020,2021, our interest in LaBarge Field consisted ofheld approximately 1.11.0 Tcf of proved CO2 reserves.

During 2020,2021, we received an average of approximately 85110 MMcf/d of CO2 from the Shute Creek gas processing plant at LaBarge Field that we used in our Rocky Mountain region CO2 floods.floods or sold to another third-party operator. Based on current capacity, and subject to availability of CO2, we currently expect our CO2 volumes from Shute Creek to increase in future years. We pay ExxonMobil a fee to process and deliver the CO2, which we use in our RockyMountain region CO2 floods.

Other Rocky Mountain CO2 Sources. Sources.We have a contract in place to receive all of the CO2 from the ConocoPhillips-operated Lost Cabin gas plant in central Wyoming, which we estimate has the capability to provide us as much as 30 MMcf/d of CO2 for use in our Rocky Mountain region CO2 floods, although wefloods. We did not receive any CO2 volumes for the period May 2020 through December 2020.from this source in 2021 but expect to receive CO2 from this source in 2022. We currently estimate that our existing CO2 sources, plus additional CO2 from those or other CO2 sources in the region, are sufficient to carry out our base Rocky Mountain region EOR development plans.

Rocky Mountain CO2 Pipelines. The 20-inch Greencore pipelinePipeline in Wyoming is the first CO2 pipeline we constructed in the Rocky Mountain region. We plan to use the pipeline as our trunk line in the Rocky Mountain region, eventually connecting our various Rocky Mountain region CO2 sources to the Cedar Creek Anticline in eastern Montana and western North Dakota. The 232-mile pipeline begins at the ConocoPhillips-operated Lost Cabin gas plant in Wyoming and terminates at Bell Creek Field in Montana. We completed construction of the pipeline in 2012 and received our first CO2 deliveries from the ConocoPhillips-operated Lost Cabin gas plant during 2013. During 2014, we completed construction of an interconnect between our Greencore pipelinePipeline and an existing third-party CO2 pipeline in Wyoming, which enables us to transport CO2 from LaBarge Field to our Bell Creek Field.

The CO2 enhanced oil recovery development project at Cedar Creek Anticline requires a 105-mile extension In 2021, we completed construction of the GreencoreCCA CO2 pipeline, to CCA from Bell Creek Field. The capital outlay for the pipeline is projected to be approximately $150 million, of which we have incurred approximately $50 million through December 31, 2020 (see also Cedar Creek Anticlinedelivers CO2 EOR Projectto our new tertiary development project at CCA. The following table summarizes our most significant CO2 below for further discussion).pipelines owned and operated in the Rocky Mountain region as of December 31, 2021:

Tertiary Properties with Tertiary Production and Proved Tertiary Reserves at December 31, 2020
CO2 pipelines
Completion DatePipeline Diameter
(in inches)		Pipeline MileageService Area
Greencore Pipeline201220”232Lost Cabin gas plant in Wyoming to Bell Creek Field in Montana
CCA Pipeline202116”105Bell Creek Field in Montana to CCA
Beaver Creek Pipeline20088”46Wyoming Wind River Basin properties

Bell Creek Field.  We acquired our interest in Bell Creek Field in southeast Montana as part of the Encore merger in 2010.  The oil-producing reservoir in Bell Creek Field is a sandstone reservoir with characteristics similar to those we have successfully flooded with CO2 in the Gulf Coast region. During 2013, we began first CO2 injections into Bell Creek Field, recorded our first tertiary oil production, and booked initial proved tertiary reserves. During 2018, we completed the phase five expansion at the field, and in April 2019, commenced CO2 injection into phase six of the field development. Tertiary production during the fourth quarter of 2020 averaged 5,079 Bbls/d of oil, compared to 5,618 Bbls/d in the fourth quarter of 2019.

Grieve Field. Under a 2011 farm-in agreement, we obtained a 65% working interest in Grieve Field, located in Natrona County, Wyoming, in exchange for developing the Grieve Field CO2 flood. During 2016, the Company and its joint venture partner in Grieve Field revised their development arrangement for the field so that our partner funded development of the facility and fieldwork in exchange for a 14% higher working interest and a disproportionate sharing of revenue from the first 2 million barrels of production. We commenced tertiary production from Grieve Field during the fourth quarter of 2018 and

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booked initial proved tertiary reserves during 2019. In October 2020, we foreclosed on the joint venture partner’s interest, and we obtained record title to their interest in February 2021.

Salt Creek Field.  We acquired our 23% non-operated working interest in Salt Creek Field in Wyoming for approximately $72 million in June 2017. Tertiary production during the fourth quarter of 2020 averaged 2,007 Bbls/d of oil, compared to 2,223 Bbls/d in the fourth quarter of 2019.

March 2021 Acquisition of Wyoming CO2 EOROil Fields

Wyoming CO2 EOR Fields. In December 2020, we entered into an agreement to acquire a nearly 100% working interest (approximately 83% net revenue interest) in the Big Sand Draw and Beaver Creek oil fields located in Wyoming for $12 million cash, including surface facilities and a 46-mile CO2 transportation pipeline to the acquired fields. The agreement provides for us to make two contingent cash payments of $4 million each in 2021 and 2022 if NYMEX WTI oil prices average at least $50 per Bbl during the respective calendar years. Net production from the acquired fields was approximately 2,800 BOE/d for the third quarter of 2020, of which approximately 85% was oil production. Based on December 1, 2020 oil and natural gas futures strip prices, net proved reserves for the acquired fields, which are 93% oil, were estimated at approximately 13.7 MMBOE, including 5.5 MMBOE of proved undeveloped reserves. The acquisition closed on March 3, 2021.

Future Tertiary Properties with No Tertiary Production or Proved Tertiary Reserves at December 31, 2020

Cedar Creek Anticline.CCA is the largest potential EOR property that we own and currently our largest producing property, contributing approximately 23% of our 20202021 total production.sales volumes. Historical production from the property has primarily been from the Red River interval. The field is primarily located in Montana but extends over such a large area (approximately 126 miles) that it also extends into North Dakota. CCA is a series of 13 different operating areas on a common geological trend, each of which could be considered a field by itself. We acquired our initial interest in CCA as part of the Encore merger in 2010 and acquired additional interests from a wholly-owned subsidiary of ConocoPhillips in 2013 for $1.0 billion, adding 42.2 MMBOE of incremental proved reserves at that date. Production from CCA averaged 11,433 BOE/d during the fourth quarter of 2020, compared to production during the fourth quarter of 2019 of 13,730 BOE/d. The non-tertiary proved reserves associated with CCA were 45.2 MMBOE, net to our interest, as of December 31, 2020.

In addition to the Red River interval, CCA contains other oil-bearing intervals including Mission Canyon and Charles B. We began pursuing these additional exploitation opportunities in late 2017. We have drilled nine successful Mission Canyon exploitation wells and a successful initial test well in Cabin Creek’s Charles B formation over the last few years. We continue to evaluate the Charles B formation and believe it has characteristics that would make it a good candidate for secondary or tertiary flooding.

Cedar Creek Anticline CO2 EOR Project. CCA is located approximately 110 miles north of Bell Creek Field, and our current plan is to extend the Greencore pipeline to CCA by the end of 2021, with first CO2 injection planned during the first half of 2022. During November 2021, we plan to spend approximately $100 million to complete thecompleted a 105-mile extension of the Greencore CO2 pipeline and an additional $50 million on facilities, well work and field developmentfrom Bell Creek Field to prepare both the Cedar Hills South Unit and East Lookout Butte for initialCCA. Our first CO2 injections in theCCA’s Red River formation. Firstformation commenced in early February 2022, and tertiary oil production response is currently expectedanticipated in the latter part of 2023, or approximately 18 to 24 months after first injection, with additional phases of development expected to target the Interlake, Stony Mountain and Red River formations at Cabin Creek Field.

Hartzog Draw Field. We acquired our interest in Hartzog Draw Field in 2012 as part of the Bakken Exchange Transaction. The field is located in the Powder River Basin of northeastern Wyoming, approximately 12 miles from our Greencore pipeline. Hartzog Draw Field had estimated proved reserves of approximately 1.7 MMBOE at December 31, 2020, net to our interest, 0.3 MMBOE of which relate to the natural gas producing Big George coal zone.  During the fourth quarter of 2020, non-tertiary production averaged 955 BOE/d, compared to 1,172 BOE/d in the fourth quarter of 2019. Industry activity around this field has been increasing for the last several years, with several operators testing various formations such as the Turner, Niobrara, Shannon, Parkman and Mowry for potential development. We believe the oil reservoir characteristics of Hartzog Draw Field make it well suited for CO2 EOR in the future. The timing of development of a CO2 flood at Hartzog Draw Field is primarily dependent upon capital availability and priorities and future oil prices.


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Other Non-Tertiary Oil Propertiessecond half of 2023. Our CCA EOR development utilizes 100% industrial-sourced CO2. Incremental peak production from phase 1 development is expected to range from 7,500 BOE/d to 12,500 Bbls/d, net to our interest. During 2022, we currently plan for a CO2 pilot project targeting the Interlake formation and to drill additional non-tertiary wells in other oil-bearing intervals including Mission Canyon and the Charles B formation. Future phases of CCA CO2 EOR development are expected to target the Interlake, Stony Mountain and Red River formations across the various fields within CCA, with full development at CCA potentially spanning multiple decades.

DespiteWind River Basin. During March 2021, we acquired a nearly 100% working interest (approximately 83% net revenue interest) in the majority of our oilBig Sand Draw and natural gas properties discussed above consisting of either existing or planned future tertiary floods, we also produce oilBeaver Creek EOR fields located in Wyoming, including surface facilities and natural gas from fields in both our Gulf Coast and Rocky Mountain regions that are either not amenable to EOR or from specific reservoirs (within an existing tertiary field) that are not amenable to EOR. For example, at Heidelberg Field, we produce natural gas from the Selma Chalk reservoir, which is separate from the Christmas and Eutaw reservoirs currently being flooded witha 46-mile CO2. Continuing production from these other non-tertiary properties totaled 1,016 transportation pipeline to the acquired fields. The acquisition purchase price was $10.9 million cash (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. Wind River Basin sales averaged approximately 2,879 BOE/d during the fourth quarter of 2020, compared2021 utilizing 100% industrial-sourced CO2. During 2022, we plan to 1,362 BOE/d duringfurther develop the fourth quarter of 2019.Beaver Creek Madison EOR flood expansion.

Bell Creek Field. The oil-producing reservoir in Bell Creek Field is a sandstone reservoir with characteristics similar to those we have successfully flooded with CO2 in the Gulf Coast region. We began first CO2 injections into Bell Creek Field in 2013, completed the phase five expansion in 2018, and commenced CO2 injection in the phase six field development in April 2019. Although production from Bell Creek Field peaked during the second quarter of 2019 and is generally on decline, we continued to see new production from the phase six expansion during 2021. During 2022, we intend to drill a new phase six horizontal well, along with additional wells in other areas.
OIL AND GAS ACREAGE, PRODUCTIVE WELLS AND DRILLING ACTIVITY
Future Rocky Mountain Tertiary Opportunities. In addition to the oil fields described above, we continue to evaluate tertiary potential in Hartzog Draw Field located in the Powder River Basin of northeastern Wyoming, the development of which is primarily dependent upon capital availability and priorities and future oil prices. The field is located approximately 12 miles from our Greencore Pipeline.

Oil and Gas Acreage, Productive Wells and Drilling Activity

In the data below, “gross” represents the total acres or wells in which we own a working interest and “net” represents the gross acres or wells multiplied by our working interest percentage.  For the wells that produce both oil and gas, the well is typically classified as an oil or natural gas well based on the ratio of oil to natural gas production.

Oil and Gas Acreage

The following table sets forth our acreage position at December 31, 2020:2021:
DevelopedUndevelopedTotal DevelopedUndevelopedTotal
GrossNetGrossNetGrossNet GrossNetGrossNetGrossNet
Gulf Coast regionGulf Coast region188,850 147,855 286,842 18,228 475,692 166,083 Gulf Coast region188,978 147,860 286,700 17,980 475,678 165,840 
Rocky Mountain regionRocky Mountain region362,327 314,948 118,521 26,655 480,848 341,603 Rocky Mountain region385,858 343,711 110,390 22,862 496,248 366,573 
TotalTotal551,177 462,803 405,363 44,883 956,540 507,686 Total574,836 491,571 397,090 40,842 971,926 532,413 

The percentage of our net undeveloped acreage that is subject to expiration over the next three years, if not renewed, is approximately 10% in 2021, 6%less than 1% in 2022, approximately 5% in 2023 and 4%none in 2023.2024.


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Productive Wells

The following table sets forth our gross and net productive oil and natural gas wells as of December 31, 2020:2021:
Producing Oil WellsProducing Natural Gas WellsTotal Producing Oil WellsProducing Natural Gas WellsTotal
GrossNetGrossNetGrossNet GrossNetGrossNetGrossNet
Operated wellsOperated wells      Operated wells      
Gulf Coast regionGulf Coast region1,041 913 125 116 1,166 1,029 Gulf Coast region1,032 907 125 116 1,157 1,023 
Rocky Mountain regionRocky Mountain region872 833 268 186 1,140 1,019 Rocky Mountain region948 914 267 236 1,215 1,150 
TotalTotal1,913 1,746 393 302 2,306 2,048 Total1,980 1,821 392 352 2,372 2,173 
Non-operated wellsNon-operated wells      Non-operated wells      
Gulf Coast regionGulf Coast region43 18 1 — 44 18 Gulf Coast region46 19 — — 46 19 
Rocky Mountain regionRocky Mountain region581 130 2 — 583 130 Rocky Mountain region583 131 77 28 660 159 
TotalTotal624 148 3 — 627 148 Total629 150 77 28 706 178 
Total wellsTotal wells      Total wells      
Gulf Coast regionGulf Coast region1,084 931 126 116 1,210 1,047 Gulf Coast region1,078 926 125 116 1,203 1,042 
Rocky Mountain regionRocky Mountain region1,453 963 270 186 1,723 1,149 Rocky Mountain region1,531 1,045 344 264 1,875 1,309 
TotalTotal2,537 1,894 396 302 2,933 2,196 Total2,609 1,971 469 380 3,078 2,351 


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Drilling Activity

The following table sets forth the results of our drilling activities over the last three years.  As of December 31, 2020,2021, we did not have any wells in progress.
Year Ended December 31, Year Ended December 31,
202020192018 202120202019
GrossNetGrossNetGrossNet GrossNetGrossNetGrossNet
Exploratory wells(1)
Exploratory wells(1)
      
Exploratory wells(1)
      
Productive(2)
Productive(2)
— — 1 1 2 2 
Productive(2)
— — — — 1 1 
Non-productive(3)
Non-productive(3)
— — — — — — 
Non-productive(3)
— — — — — — 
Development wells(1)(4)
Development wells(1)(4)
      
Development wells(1)(4)
      
Productive(2)
Productive(2)
5 3 19 18 14 12 
Productive(2)
12 4 5 3 19 18 
Non-productive(4)(5)
Non-productive(4)(5)
— — — — 3 3 
Non-productive(4)(5)
1 — — — — — 
TotalTotal5 3 20 19 19 17 Total13 4 5 3 20 19 

(1)An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.  Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well.  A development well is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(2)A productive well is an exploratory or development well drilled and completed during the year and found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

(3)A non-productive well is an exploratory or development well that is not a productive well.

(4)Includes 8 productive gross wells and 1 non-productive gross well during 2021, and 2 productive gross wells during 2020, in which we incurred no cost but have an overriding royalty interest prior to the combined payout of the wells. Subsequent to payout, Denbury will hold and bear the cost of its working interest in each well.

(5)During 2019, and 2018, an additional 7 and 4 wells respectively, were drilled for water or CO2 injection purposes. There were no wells drilled during 2021 or 2020 for water or CO2 injection purposes.


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Sales Volumes and Unit Prices

The following table summarizes sales volumes, sales prices and production cost information for our net oil and natural gas production for the years ended December 31, 2021, 2020 2019 and 2018:2019:
Year Ended December 31, Year Ended December 31,
202020192018 202120202019
Net sales volume   
Net sales volumesNet sales volumes   
Gulf Coast regionGulf Coast region   Gulf Coast region   
Oil (MBbls)Oil (MBbls)10,958 12,638 13,484 Oil (MBbls)9,991 10,958 12,638 
Natural gas (MMcf)Natural gas (MMcf)1,612 1,779 1,973 Natural gas (MMcf)1,347 1,612 1,779 
Total Gulf Coast region (MBOE)Total Gulf Coast region (MBOE)11,227 12,935 13,813 Total Gulf Coast region (MBOE)10,216 11,227 12,935 
Rocky Mountain regionRocky Mountain region   Rocky Mountain region   
Oil (MBbls)Oil (MBbls)7,278 8,047 7,880 Oil (MBbls)7,266 7,278 8,047 
Natural gas (MMcf)Natural gas (MMcf)1,293 1,595 1,988 Natural gas (MMcf)1,914 1,293 1,595 
Total Rocky Mountain region (MBOE)Total Rocky Mountain region (MBOE)7,494 8,313 8,211 Total Rocky Mountain region (MBOE)7,585 7,494 8,313 
Total Company (MBOE)(1)Total Company (MBOE)(1)18,721 21,248 22,024 Total Company (MBOE)(1)17,801 18,721 21,248 
Average sales prices – excluding impact of derivative settlementsAverage sales prices – excluding impact of derivative settlements   Average sales prices – excluding impact of derivative settlements   
Gulf Coast regionGulf Coast region   Gulf Coast region   
Oil (per Bbl)Oil (per Bbl)$38.44 $60.32 $67.75 Oil (per Bbl)$66.48 $38.44 $60.32 
Natural gas (per Mcf)Natural gas (per Mcf)1.98 2.49 3.16 Natural gas (per Mcf)3.97 1.98 2.49 
Rocky Mountain regionRocky Mountain region   Rocky Mountain region   
Oil (per Bbl)Oil (per Bbl)$36.79 $55.02 $63.30 Oil (per Bbl)$66.58 $36.79 $55.02 
Natural gas (per Mcf)Natural gas (per Mcf)0.77 1.57 2.01 Natural gas (per Mcf)3.44 0.77 1.57 
Total CompanyTotal Company   Total Company   
Oil (per Bbl)Oil (per Bbl)$37.78 $58.26 $66.11 Oil (per Bbl)$66.52 $37.78 $58.26 
Natural gas (per Mcf)Natural gas (per Mcf)1.44 2.06 2.58 Natural gas (per Mcf)3.66 1.44 2.06 
Average production cost (per BOE sold)(1)(2)
Average production cost (per BOE sold)(1)(2)
   
Average production cost (per BOE sold)(1)(2)
   
Gulf Coast region(2)(3)
Gulf Coast region(2)(3)
$18.20 $22.49 $22.22 
Gulf Coast region(2)(3)
$22.50 $18.20 $22.49 
Rocky Mountain regionRocky Mountain region19.63 22.40 22.27 Rocky Mountain region25.67 19.63 22.40 
Total Company(2)(3)
Total Company(2)(3)
18.78 22.46 22.24 
Total Company(2)(3)
23.85 18.78 22.46 

(1)Total Company sales volumes include 71 MBOE and 474 MBOE related to properties divested during 2020 and 2019, respectively.
(2)Excludes oil and natural gas ad valorem and production taxes.
(2)(3)Production costs during 2021 include a $16.1 million benefit resulting from compensation under certain of the Company’s power agreements for power interruption during the severe weather storm in February 2021 which created widespread power outages in Texas and disrupted the Company’s operations. If these amounts were excluded, production cost per BOE for the Gulf Coast region and total Company would have averaged $24.07 and $24.75, respectively, for the year ended December 31, 2021. In addition, production costs during 2020 include Delhi insurance reimbursements.reimbursements of $15.4 million related to recovery of prior years’ expenses. If these amounts were excluded, production cost per BOE for the Gulf Coast region and total Company would have averaged $19.58 and $19.60, respectively, for the year ended December 31, 2020.

PRODUCTION AND UNIT PRICES

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Further information regarding average production rates,sales volumes, unit sales prices and unit costs per BOE are set forth under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Financial and Operating Results Tables, included herein.

TITLE TO PROPERTIES

As is customary in the oil and natural gas industry, Denbury conducts a limited title examination at the time of its acquisition of properties or leasehold interests targeted for enhanced recovery, and curative work is performed with respect to significant defects on higher-value properties of the greatest significance.  We believe that title to our oil and natural gas

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properties is good and defensible, subject only to such exceptions that we believe do not materially interfere with the use of such properties, including encumbrances, easements, restrictions and royalty, overriding royalty and other similar interests.

SIGNIFICANT OIL AND GAS PURCHASERS AND PRODUCT MARKETING

Oil and natural gas sales are made on a day-to-day basis or under short-term contracts at the current area market price. We would not expect the loss of any single purchaser to have a material adverse effect upon our operations; however, the loss of a large single purchaser could potentially reduce the competition for our oil and natural gas production, which in turn could negatively impact the prices we receive.  For the Successor period September 19, 2020 throughyear ended December 31, 2020, three2021, four purchasers each accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP (30%(28%), Marathon Petroleum Corporation (13%) and Hunt Crude Oil Supply Company (12%), and for the Predecessor period January 1, 2020 through September 18, 2020, three purchasers accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP (30%), Hunt Crude Oil Supply Company (12%) and Marathon Petroleum Corporation (12%). For the year ended December 31, 2019 (Predecessor), three purchasers accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP (32%), Hunt Crude Oil Supply Company (11%) and Sunoco Inc. (11%). For the year ended December 31, 2018 (Predecessor), two purchasers accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP (24%) and Hunt Crude Oil Supply Company (10%).

Our ability to market oil and natural gas depends on many factors beyond our control, including the extent of domestic production and imports of oil and natural gas, available oil storage at Cushing, Oklahoma, and other inventory hubs, the proximity of our oil and natural gas production to pipelines and corresponding markets, the available capacity in such pipelines, the demand for oil and natural gas, the effects of weather, and the effects of state and federal regulation.  While we have not experienced significant difficulty in finding a market for our production as it becomes available or in transporting our production to those markets, during 2020, we experienced some level of disruption in off-take capacity as a result of storage constraints during the initial stages of the COVID-19 pandemic. Therethere is no assurance that we will always be able to market all of our production or obtain favorable prices.

Oil Marketing and Differentials

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. The oil differentials we received in the Gulf Coast and Rocky Mountain regions are discussed in further detail below.

With the recent exception of 2020 and 2021, our crude oil prices in the Gulf Coast region have generally been positive to NYMEX and highly correlated to the changes in prices of crude oil sold under Light Louisiana Sweet. Our average NYMEX oil differential in the Gulf Coast region was a negative $1.14 per Bbl during 2020, compared to a positive $3.30 per Bbl and a positive $2.94 per Bbl during 2019 and 2018, respectively.Sweet (“LLS”) index. Our current markets at various sales points along the Gulf Coast have sufficient demand to accommodate our production, but there can be no assurance of future demand.

The marketing of our Rocky Mountain region oil production is dependent on transportation through local pipelines to our primary market centers in Guernsey, Wyoming and Cushing, Oklahoma, although some of our production may ultimately be transported by third parties to Wood River, Illinois.  Shipments on some of the pipelines are at or near capacity and may be subject to apportionment.  We currently have access to, or have contracted for, sufficient pipeline capacity to move our oil production; however, there can be no assurance that we will be allocated sufficient pipeline capacity to move all of our oil production in the future.  Because local demand for production is small in comparison to current production levels, much of the production in the Rocky Mountain region is transported to markets outside of the region. Therefore, prices in the Rocky Mountain region are further influenced by fluctuations in prices (primarily Brent and LLS) in coastal markets and by available pipeline capacity in the Midwest and Cushing markets.  For the year ended December 31, 2020, the discount for our oil production relative to NYMEX in the Rocky Mountain region averaged $2.80 per Bbl, compared to $2.01 per Bbl during 2019 and $1.50 per Bbl during 2018.

COMPETITION AND MARKETS

We face competition from other oil and natural gas companies in all aspects of our business, including acquisition of producing properties, oil and gas leases, drilling rights, and CO2 properties; marketing of oil and natural gas; and obtaining and maintaining goods, services and labor.  Many of our competitors have substantially larger financial and other

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resources.  Factors that affect our ability to acquire producing properties include available liquidity, available information about prospective properties and our expectations for earning a minimum projected return on our investments.  Because of the primary nature of our core assets (our tertiary operations) and our ownership of relatively uncommon significant natural sources

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of CO2 in the Gulf Coast and Rocky Mountain regions, we believe that we are effective in competing in the market and have less competition than our peers in certain aspects of our business.

CLIMATE CHANGE AND ENVIRONMENTAL CONSIDERATIONS

Climate change is a continuing global concern for governments, businesses, and society. The reduction of carbon emissions is important, and we take the responsibility of protecting our environment seriously. Part of our obligation is to report greenhouse gas emissions and develop procedures and methods to collect data critical for calculating these emissions. In addition, our operating strategy, which focuses on CO2 EOR and CCUS, has measurable environmental benefits. We are committed to utilizing emerging technologies, where feasible, to capture or reduce emissions and to improve our carbon efficiency.

We strive to be environmentally responsible in all aspects of our operations. Our operations have been subject to federal, state and local environmental compliance for many years, the costs of which are well integrated into our budgeting and our operating results. With our focus on CO2 EOR, we offer environmental benefits not generally associated with oil and gas operations. We utilize technology and techniques that reduce the risks to, and impacts on, the environment. Our programs include measures to prevent spills and releases and to quickly respond to incidents if they do occur; efforts to manage, minimize and remediate our environmental impacts; and an operating strategy that is conscious of our carbon footprint.

As the world demands energy to fuel tomorrow’s economy and provide a better quality of life, we must meet the demand with a focus on reducing CO2 emissions. The Greenhouse Gas Protocol Corporate Accounting and Reporting Standard classifies a company’s greenhouse gas emissions into three scopes: Scope 1 emissions are direct emissions from owned or controlled sources; Scope 2 emissions are indirect emissions from the generation of purchased energy; and Scope 3 emissions are all indirect emissions (not included in Scope 2) that occur in the value chain of the reporting company, including both upstream and downstream emissions. The utilization of industrial-sourced CO2 in EOR significantly reduces the carbon footprint of our oil production, making our Scope 1 and 2 CO2 emissions negative today. We have set a target to fully offset our emissions, including Scope 3 emissions associated with the refining and combustion of our produced hydrocarbons, within this decade.

In our Corporate Responsibility Report, which is published on our website, we report in detail our direct greenhouse gas emissions resulting from our operations, as well as indirect greenhouse gas emissions associated with the consumption of electricity.

In addition, we are committed to engaging with stakeholders, policy makers, regulators, and our industry on climate change issues and to addressing our impact on the environment. The Sustainability and Governance Committee of the Board of Directors oversees our health and safety, climate change, environmental, social and community policies, practices and procedures. The Committee focuses upon climate change risk management and strategy, CCUS activities, sustainability targets, operating efficiencies and asset retirement obligations, along with broader community climate change concerns.

HUMAN CAPITAL RESOURCES

We recognize that our employees are crucial to Denbury’s future, and we care about our employees’ and their families’ well-being beyond the work environment. As of December 31, 2021, we had 716 employees, of whom 402 were employed in our field operations or at our field offices and 314 were employed at our headquarters in Plano, TX, none of whom are currently covered by a labor union or other collective bargaining arrangement.

Workforce Health and Safety

We continuously seek to improve our health and safety performance by fostering a culture that prioritizes safe work, then ensuring that this culture is exemplified in all levels of leadership. We provide our employees with tools to succeed, including relevant and timely training, and we monitor our performance using established measurement statistics. With oversight from the Sustainability and Governance Committee of the Company’s Board of Directors, each year, Denbury establishes corporate goals specifically related to employee and contractor safety performance and monitors progress toward those goals throughout the year using performance metrics. Results are regularly reported to our Board of Directors, senior management and all employees to ensure accountability and to reinforce their importance. Two safety performance metrics Denbury closely monitors are the Total Recordable Incident Rate (“TRIR”) and the Significant Injury or Fatality Rate (“SIFR”), which also

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captures near misses that may not have resulted in an injury. We have set new record lows for qualifiedTRIR over the last five consecutive years and our 2021 SIFR was our lowest ever.

We have implemented numerous health and safety protocols in response to the COVID-19 pandemic. Our COVID-19 task force, comprised of members of senior management and other key employees, has developed a systematic, data-based approach to monitor national, state and local orders and guidelines related to the COVID-19 pandemic, established internal processes, training and communications, conducted contact tracing, and engaged a third-party medical consulting firm to identify and clear COVID-19 cases and exposures. Additionally, we continue to provide voluntary COVID-19 testing for all employees and their dependents and ensure that necessary sanitation supplies are available at all Denbury offices and locations.

Compensation and Benefits

As part of our compensation philosophy, we believe that we must offer and maintain competitive compensation and benefit programs for our employees in order to attract and retain outstanding talent. In addition to competitive base wages, other benefit programs include an annual bonus plan, long-term incentive plan, Company matched 401(k) plan, healthcare and insurance benefits, health savings and flexible spending accounts and employee assistance programs.

Diversity and Inclusion

We understand the importance of, and are committed to increasing, diversity and fostering an inclusive work environment that supports the workforce and the communities where we operate. Denbury strives to ensure equal opportunity in recruitment and reaching a pool of diverse candidates by utilizing a digital recruiting program that posts available employment opportunities to websites worldwide, several of which are specifically targeted to reach diverse candidates. In 2021, women and minorities accounted for 21% and 16% of our workforce, respectively, and 20% and 26% of our new hires, respectively.

Our diversity, equity and inclusion principles are also reflected in our employee training and policies. To foster a diverse and collaborative workplace, Denbury requires all employees to complete annual training to raise awareness and encourage diversity and inclusion. Each year, our employee training program includes courses related to diversity, anti-discrimination, and anti-harassment to help employees better appreciate diversity, cultural differences, recognize unconscious biases, and increase collaboration. We continue to enhance our diversity, equity and inclusion policies which are guided by our Board of Directors and executive leadership team.

Talent Acquisition, Retention and Development

Our success depends to a significant degree upon our ability to hire, develop, and retain highly skilled and experienced field personnel, to drill wellsincluding our executive officers as well as other key management and conduct field operations and fortechnical specialists, such as geologists, geophysicists, engineers and other professionals in the oil and gas industry can fluctuate significantly, oftenprofessionals. Denbury provides employees with many ways to expand their skills and advance their careers through training and development initiatives. We believe this is critical to each employee’s professional growth and success, as well as to our success as a company.

Human Rights

Denbury is committed to protecting human rights in correlationthe workplace. This commitment includes respecting the dignity and worth of all individuals, encouraging all individuals to reach their full potential, encouraging the initiative of each employee, and providing equal opportunity for development to all employees. Specifically, Denbury recognizes its responsibility with commodity prices, causing periodic shortages in such personnel.  Priorregards to: workplace health and safety, the prohibition of forced and child labor, a workplace free from harassment or any form of discrimination, freedom of association, complying with all laws regarding hours and wages and employee privacy. Denbury respects international human rights principles and our commitments to human rights are guided by the downturn in oil prices that began in late 2014,United National Global Compact and the competition for qualified technical personnel had been extensiveInternational Labor Organization’s Declaration of Fundamental Principals and personnel costs escalated. There were also periods with shortagesRights at Work. Our Code of drilling rigsConduct and other equipment, as demand for rigs and equipment increased along withHuman Rights Policy require employees to report any suspected human rights abuses. Denbury’s Human Rights Policy is available on our website at www.denbury.com under the number of wells being drilled.  These factors also cause significant increases in costs for equipment, services and personnel.  We cannot be certain when we will experience these issues, and these types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results and cause significant delays in our development operations.“Sustainability” link.

FEDERAL AND STATE REGULATIONS

Numerous federal, state and local laws and regulations govern the oil and gas industry.  Additions or changes to these laws and regulations are often made in response to the current political or economic environment. Compliance with the evolving

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regulatory landscape is often difficult, and noncompliance can result in substantial penalties or the potential shutdown of operations. Compliance has also been complicated by an increasing trend for litigation challenging policy and regulatory changes, with judicial decisions increasing regulatory uncertainty, often delaying necessary approvals from agencies that may be the subject of conflicting injunctions, rulings or appeals. Additionally, the future annual cost of complying with all laws and regulations applicable to our operations is uncertain and will be ultimately determined by several factors, including future changes to legal and regulatory requirements. Management believes that continued compliance with existing laws and regulations applicable to our operations and future compliance therewith will not have a materially adverse effect on our consolidated financial position, results of operations or cash flows, although such laws and regulations, and compliance therewith, could cause significant delays or otherwise impede operations, which may, among other things, cause our expected production rates and cash flows to be less than anticipated.

The following sections describe some specific laws and regulations that may affect us.  We cannot predict the cost or impact of these or other future legislative or regulatory initiatives.

Regulation of Oil and Gas Exploration and Production

Our operations are subject to various types of regulationlaws and regulations at the federal, state and local levels.  Such regulation includes requiring sometimes lengthy environmental review prior to approval of potential leasing, drilling, or other development projects; permits for drilling wells; maintaining bonding requirements in order to drill or operate wells and regulating the location of wells; the method of drilling and casing wells; the surface use and restoration of properties upon which wells are drilled; the compensation due to surface, and potentially pore space, owners for mineral development, enhanced oil recovery, and fluid disposal activities; the plugging and abandoning of wells; and the composition or disposal of chemicals and fluids used in connection with operations.  Our operations are also subject to various environmental and conservation laws and regulations.  These include regulation of the size of drilling, spacing or proration units and the density of wells that may be drilled in those units, and the unitization or pooling of oil and gas properties.  In addition, federal and state environmental and conservation laws, which establish maximum rates of production from oil and gas wells, generally prohibit or restrict the venting or flaring of natural gas and impose certain requirements regarding the ratability of production.  The effect of these laws and regulations may delay proposed development projects, limit the amount of oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill.  Regulatory requirements and compliance relative to the oil and gas industry increase our costs of doing business and, consequently, affect our profitability.

Federal Energy and Climate Change Legislation and Regulation

The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, among other things, updated federal pipeline safety standards, increased penalties for violations of such standards, gave the Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (the “PHMSA”) authority for new damage prevention and incident notification, and directed the PHMSA to prescribe new minimum safety standards for CO2 pipelines, which safety standards could affect our operations and the costs thereof. While thepipelines. In late 2021, PHMSA has adopted or proposed to adopt a number of new regulations related to implement this act, there has not been a substantial overhaul asincident and annual reporting and safety requirements for onshore, rural natural gas gathering lines. The new regulations extend PHMSA’s jurisdiction to the regulation of CO2 pipelines.previously unregulated rural gathering lines.

Both federal and state authorities have in recent years proposed and enacted new regulations and policies to limit the emission of pollutants, including greenhouse gas emissions, as part of climate change initiatives and the Clean Air Act.  For example,During the last ten years, both the EPA and Bureau of Land Management (“BLM”) have proposed and issued such regulations and policies for the oil and gas industry. Those proposed and final regulations and policies were the subject of extensive administrative, judicial, and Congressional consideration during the Obama and Trump Administrations, which caused significant difficulty in determining which regulations were in force at any given time. The Biden Administration, through various executive orders and other policy statements, has made climate change a primary priority. On January 20, 2021, the Biden Administration issued Executive Order 13990, directing agencies to review all agency actions related to emissions and climate change taken under the Trump Administration. On June 30, 2021, President Biden signed into law a joint Congressional resolution disapproving the EPA’s 2020 policy rules related to greenhouse gas emissions from oil and gas industry activities under the Clean Air Act. On November 2, 2021, the EPA proposed new regulations for greenhouse gas emissions. The comment period for the new proposed rule closed on January 31, 2022, with a potential final rule to be published thereafter. BLM has also announced plans to introduce a new proposed rule related to venting and flaring in the oil and gas industry. While BLM’s proposal is listed on its regulatory agenda, the agency has not yet issued a proposed rule. Any resulting regulations adopted by the EPA or BLM could possibly be similar to, or even more stringent than, those promulgated by the agencies under the Obama Administration. Enforcement of such regulations may impose additional costs related to

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and Bureau of Land Management (“BLM”) have issued regulations for the control of methane emissions from the oil and gas industry. The EPA has promulgated regulations requiring permitting for certain sources of greenhouse gas emissions, and in May 2016, during the Obama Administration, the EPA promulgated final regulations to reduce methane and volatile organic compound emissions from the oil and gas sector. In July 2017, a federal appeals court rejected an attempt by the EPA under the Trump Administration to delay implementation of the rule. In September 2018, the EPA proposed amendments to the rule that were targeted at reducing regulatory requirements and streamlining the rule’s implementation. In September 2019, the EPA also issued a notice of proposed rulemaking to remove the methane specific regulations imposed by the 2016 final rule and to remove certain other emission limitations placed on new or reconstructed transmission and storage facilities. In August 2020, the EPA released final rules that, among other things, eliminated standards for methane emissions and adjusted requirements for fugitive emissions. Those rules went into effect in the last quarter of 2020. Immediate legal challenges ensued, and while the rules were initially stayed in light of the legal challenges, the stay has been dissolved and the rules are currently in effect. The Biden Administration recently directed the EPA to consider additional regulations to establish comprehensive standards of performance and guidelines for methane and volatile organic compound emissions from existing operations in the oil and gas sector. Any resulting regulations adopted by the EPA could possibly be similar to, or even more stringent than, those promulgated by the EPA in 2016. Enforcement of such regulations may impose additional costs related to compliance with these new emission limits, as well as inspections and maintenance of several types of equipment used in our operations.

Federal, State or Indian Leases

As of December 31, 2020,2021, approximately 25%30% of our net developed acreage and 12%22% of our fourth quarter of 2020December 2021 production related to oil and natural gas operations performed on federal acreage, including portions of CCA. Our operations on federal, state or Indian oil and gas leases, especially those in the Rocky Mountain region, are subject to numerous restrictions, including nondiscrimination statutes. Such operations must be conducted pursuant to certain on-site security regulations and other permits and authorizations issued by the BLM, the Bureau of Ocean Energy Management, the Bureau of Safety and Environmental Enforcement, the Bureau of Indian Affairs, and other federal and state stakeholder agencies. TheOn January 27, 2021, the Biden Administration, has, through executive action, recently suspended new leasing and other oil and natural gas approvals on federal lands. InThe executive action was challenged in court by a number of States and industry trade associations. A federal court in Louisiana granted a nationwide preliminary injunction against the executive action. While BLM has stated it will resume its oil and gas leasing program, the executive order, judicial challenge, and related additional environmental review have caused significant delay and caused some potentially available parcels to be delayed for bidding. On January 20, 2021, in addition, the Department of the Interior recentlyissued a secretarial order rescinding the ability for state and local offices of BLM and other Department of the Interior Bureaus to approve various oil and gas development activities – including permits to drill, certain surface distributing activities, resource management plans, and amendments to existing federal leases. The secretarial order instead consolidated that approval authority to the bureaus’ respective assistant secretaries and higher-ranked management. The secretarial order dissolved by its own terms in March 2021, but, on March 19, 2021, the Department of the Interior issued a memorandum that retained certain authority for approvals related to oil and gas development with the assistant secretary. Also, on January 20, 2021, the Biden Administration, through executive action, mandated that agencies calculate the social cost of potential emissions when considering approval for permits, development, leasing, or related approvals. This executive action was challenged in court by a number of states, and on February 11, 2022, a federal court in Louisiana granted a preliminary injunction preventing federal agencies from using the social cost metric. In subsequent filings with the court, the Department of the Interior stated that the court’s injunction will suspend and delay regulatory consideration of pending permits, development, leasing, and related approvals. While the courts have enjoined the executive actions and the secretarial order has rescindedexpired, the actions have caused and continue to cause considerable delay related to the ability to issue permits to drill on existing federal leases.obtain new leases and necessary approvals for oil and gas development. The inability to secure new leases or permits to drill on existing leases could prevent us from expanding our oil and gas operations, in both new locations and in areas currently leased for which permits have not yet been obtained. In addition, any action by the federal government to rescind previously issued permits on the Company’s existing leases could significantly disrupt our existing and future operations.

BLM has also announced plans to introduce a new proposed rule to update its oil and gas leasing process. The proposed rule may include increases to the fees, rents, royalty rates, and bonding requirements for new federal oil and gas leases. While BLM’s proposal is listed on its regulatory agenda, the agency has not yet issued a proposed rule. If such a rule is finalized, any increase in the fees related to oil and gas development on federal lands will increase our costs of doing business and, consequently, affect our profitability.

In September 2021, the Office of Natural Resources Revenue (“ONRR”), the agency primarily responsible for collecting and ensuring correct federal and Indian royalty payments, withdrew a 2020 Trump Administration regulation regarding the valuation of oil and gas products and potential civil penalties for incorrect valuation related to federal royalties. ONRR’s action largely returns the valuation of oil and gas products and potential civil penalties for incorrect payment to the regulations in effect prior to 2020 and is ultimately expected to increase the amount of royalties collected by the federal government and potential civil penalties for incorrect payment, increasing our costs of doing business.

Environmental Regulations

Our oil and natural gas production, saltwater disposal operations, injection of CO2, and the processing, handling and disposal of materials such as hydrocarbons and naturally occurring radioactive materials (“NORM”) are subject to stringent regulation.  We could incur significant costs, including cleanup costs resulting from a release of product, third-party claims for property damage and personal injuries, or penalties and other sanctions as a result of any violations or liabilities under environmental laws and regulations or other laws and regulations applicable to our operations.  Changes in, or more stringent enforcement of, environmental laws and other laws applicable to our operations could also result in delays or additional operating costs and capital expenditures.

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Various federal, state and local laws and regulations controlling the discharge of materials into the environment, or otherwise relating to the protection of the environment and human health, directly impact our oil and gas exploration, development and production operations.  These include, among others, (1) regulations adopted by the EPA and various state agencies regarding approved methods of disposal for certain hazardous and nonhazardous wastes; (2) the Comprehensive Environmental Response, Compensation, and Liability Act and analogous state laws that regulate the removal or remediation of previously disposed wastes (including wastes disposed of or released by prior owners or operators), property contamination (including groundwater contamination), and remedial plugging operations to prevent future contamination; (3) the Clean Air Act and comparable state and local requirements already applicable to our operations and new restrictions on air emissions from our operations, including greenhouse gas emissions and those that could discourage the production of fossil fuels that, when used, ultimately release CO2; (4) the Clean Water Act and comparable state and local requirements already applicable to our operations and new restrictions on wastewater discharges from our operations; (5) the Oil Pollution Act of 1990, which contains numerous requirements relating to the prevention of, and response to, oil spills into waters of the United States; (6) the Resource Conservation and Recovery Act, which is the principal federal statute governing the treatment, storage and disposal of hazardous wastes; (7) the Endangered Species Act and counterpart state legislation, which protects certain species (and their

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related habitats), including certain species that could be present on our leases, as threatened or endangered; (8) the Migratory Bird Treaty Act and (8)Bald and Golden Eagle Protection Act, which protects certain bird species, including certain species that could be present on our leases, from intentional and unintentional killing and other disturbances; and (9) state regulations and statutes governing the handling, treatment, storage and disposal of NORM and other wastes.

In the Rocky Mountain region, federal agencies’ actions based upon their environmental review responsibilities under the National Environmental Policy Act can significantly impact the scope and timing of hydrocarbon development by slowing the timing of individual applications for permits to drill and requests for rights-of-way and delaying large scale planning associated with region-level resource management plans, oil and gas lease sales, and project-level master development plans. TheIn 2020, the Trump Administration enacted new regulations designed to streamline the federal environmental review process. In June 2021, the Biden Administration, has signaled an intentacting through the Council on Environmental Quality (“CEQ”) responsible for enacting National Environmental Policy Act regulations, postponed federal agencies’ compliance with the 2020 regulations. On October 7, 2021, CEQ issued a notice of proposed rulemaking to bolster agency review pursuant tolargely return the National Environmental Policy Act includingregulations to those that existed prior to 2020 and to ensure federal agencies are adequately analyzing the potential of requiring climate change assessments forimpacts from proposed projects. If such a rule is finalized, the federal environmental review process is expected to continue or even increase delay in federal decision making related to oil and gas development.

Management believes that we are currently in substantial compliance with existing applicable environmental laws and regulations, and does not currently anticipate that future compliance will have a materially adverse effect on our consolidated financial position, results of operations or cash flows, although such laws and regulations, and compliance therewith, could cause significant delays or otherwise impede operations, which may, among other things, cause our expected production rates and cash flows to be less than anticipated.

Hydraulic Fracturing

During 2020, we fracture stimulated three wells, at Bell Creek Field, consisting primarily of small skin fractures that are utilized to remove contaminants caused by drilling muds and increase permeability near the wellbore, utilizing water-based fluids. We currently have plans to potentially hydraulically fracture up to five wells of a similar nature during 2021. We are familiar with the laws and regulations applicable to hydraulic fracturing operations and take steps to ensure compliance with these requirements.

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Item 1A.  Risk Factors

The risks described below fall into sixfive broad categories related to (1) oil price volatility and demand, (2) future executive, legislative or regulatory actions, (3) financial risks, (4) risks of owning our common stock, (5) cybersecurity risks, and (6)(5) those related to our operations and industry. These are not the only onesrisks we face but are considered to be the most material. There may be other unknown or unpredictable economic, business, competitive, regulatory or other factors that could have material adverse effects on our future results. Past financial performance is not a reliable indicator of future performance, and historical trends should not be used to anticipate results or trends in future periods.

Risks Relating to Volatility in Oil Pricing and Demand for Oil

Low oilOil prices have been very volatile in recent years, have ledwhich is expected to continue or increase, which may lead to significant periods of reduced cash flows and negatively affectedaffect our financial condition and results of operations.

Oil prices are the most important determinant of our operational and financial success. Oil prices are highly impacted by worldwide oil supply, demand and prices and have historically been subject to significant price changes over short periods of time. Over the last several years, NYMEX oil prices have been extremely volatile, declining fromreaching a three-year peak of $76over $84 per Bbl in October 20182021 compared to lows averaging $17 per Bbl in April 20202020. The year-to-year volatility has been due to the reduction in worldwide economic activity and oil demand amid the COVID-19 pandemic, plus OPEC supply pressures, before gradually increasing topressures. More recently, oil prices plunged in late November 2021 upon identification of the low-$60snew Omicron variant of COVID-19, with NYMEX oil prices ranging between $65.57 and $95.46 per barrel in mid-February 2021. Based on rising COVID-19 case levelsbetween December 1, 2021 and their impact on worldwide economic activity,February 23, 2022.

Oil price volatility will remain, andremain. Although global petroleum demand is currently rising faster than petroleum supply, driving higher prices towards the end of 2021, factors beyond our control could cause prices to move downward on a rapid or repeated basis, which makesmaking planning and budgeting, acquisition transactions, capital raising, and sustaining business strategies more difficult. For example, Iran is currently reported to have sizeable oil reserves in storage; if talks underway regarding Iran’s nuclear program lead to reduction or removal of current oil sanctions on Iran, Iran’s stored oil reserves could be released onto the market, depressing oil prices. Our cash flow from operations is highly dependent on the prices that we receive for oil, as oil comprised approximately 97% of our 2020 production2021 average daily sales volumes and approximately 98%99% of our proved reserves at December 31, 2020.2021. The prices for oil and natural gas are subject to a variety of factors that are beyond our control.  These factors include:

•the level of worldwide demand for oil and natural gas, which has been negatively affected by the economic impact of the worsening COVID-19 pandemic;gas;
•worldwide economic conditions;
•the degree to which members of OPEC maintain oil price and production controls;
•the degree to which domestic oil and natural gas production affects worldwide supply of crude oil or its price;price, which has been negatively affected by the economic impact of the worsening COVID-19 pandemic;
•the scope, duration, and severity of the COVID-19 pandemic and any related variants; and
•worldwide political events, conditions and policies, including actions taken by foreign oil and natural gas producing nations.

Negative movements in oil prices could harm us in a number of ways, including:

•lower cash flows from operations may require reduced levels of capital expenditures; which in turn could lower our present and future production levels and lower the quantities and value of our oil and gas reserves, which constitute our major asset;
•we could be forced to increase our level of indebtedness, issue additional equity, or sell assets; and/or
•we could be required to impair various assets, including a write-down of our oil and natural gas assets or the value of other tangible or intangible assets.

Furthermore, some or all of our tertiary projects could become or remain uneconomical. We may also decide to suspend future expansion projects, and if prices were to drop below our operating cash break-even points for an extended period of time, we may decide to shut-in existing production, both of which could have a material adverse effect on our operations and financial condition and reduce our production.


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The continued COVID-19 pandemic is likely to continue to suppresssignificantly affect worldwide economic activity, which in turn could negatively affect our cash flow.demand for oil.

The spread and emergence of new variants of the COVID-19 virus continues to evolve, both in the United States and abroad. ItsThe ultimate impact on our operational and financial performance will depend on future developments, including (1) the timing and effectiveness of administration of available vaccines and other therapeutics related to the treatment of COVID-19 and its variants domestically and around the world, which is currently thought to be the most important factor affecting the duration and intensity of the pandemic, (2) the actionscontinued efforts to contain the virus or

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mitigate its impact, and (3) related restrictions on business activity and travel, all of which have had a direct impact on continued lower levels of domestic and global oil demand.

As described above,Geopolitical tensions from the February 2022 Russian troop movements surrounding Ukraine may rise, and create heightened oil prices are the most important determinant of our operational and financial success. The possibility of a continued reduction in cash flows for an indeterminant period of timemarket volatility that could impairnegatively affect both our ability to developexecute our properties2020 business plan and grow our production and oil and gas reserve values.

A continuing financial downturn in one or more of the world’s major markets could negatively affect our business and financial condition.

In additionMovement of Russian military units into provinces in Eastern Ukraine, and trade and monetary sanctions in response to the current impact of the COVID-19 pandemic on thefuture developments, could significantly affect worldwide oil prices and demand for oil, regional or worldwide increases in tariffs or other trade restrictions, significant international currency fluctuations, evolving political and military tensions in the Middle East and Asia, a sustained credit crisis, a severe economic contraction either regionally or worldwide orcause turmoil in the global financial systemsystem. This could materially affect our business and financial condition, or impactalong with our abilityoperating and development costs, making it difficult to finance operations. Negative credit market conditions could inhibitexecute our lenders from funding our senior secured bank credit facility or cause them to restrict our borrowing base or make the terms of our senior secured bank credit facility more costly and more restrictive. Negative economic conditions2022 business plan in a very volatile market. These Eastern European tensions could also adversely affectincrease China/Taiwan political tensions and U.S./China trade and other relations, with a further effect on world oil markets and the collectability ofprices we receive for our trade receivables or performance by our suppliers or cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform their obligations.oil production.

Risks Relating to Any Future Executive, Legislative or Regulatory Actions

Any future climate change initiatives by the Biden Administration, by Congress or by state regulatory or legislative bodies could negatively affect our business and operations, especially in the Rocky Mountain region.

The newIn early 2021, the Biden Administration recommitted the United States to the Paris Climate Agreement and targeted a reduction of 50-52% greenhouse gas emissions by the year 2030. In order to achieve such goal, in 2021, the Biden Administration introduced initiatives, which include policies to address climate change, energy efficiency, and clean energy. If the Biden Administration and Congress may adopt stricter standards for, and increase oversight and regulation over, the exploration and production industry at the federal level, whichthese measures could lead to increased costs or additional operating restrictions. Also, there is the potential for climate change legislation which could affect demand for oil on a long-term basis.

Our operations on federal, state or Indian oil and natural gas leases in the Rocky Mountain region, must be conducted pursuant to permits and authorizations issued by the Bureau of Land Management, the Bureau of Ocean Energy Management, the Bureau of Safety and Environmental Enforcement, the Bureau of Indian Affairs, and other federal and state stakeholder agencies. In late January 2021, the Biden Administration, through executive action, suspended for a 60-day period new leasing and other oil and natural gas approvals on federal lands, pending review of such activity. Also, the Department of Interior recently has rescinded the ability to issue new permits to drill oil and natural gas wells on existing federal leases. Extension of these actions over a longer period could prevent us from expanding our oil and natural gas operations, in both new locations and in areas currently leased for which permits have not yet been obtained. In addition, any actionagencies, may be impacted by the federal government to rescind previously issued permits on the Company’s existing leases, or actions to restrict our ability to access public lands or to obtain permits, including permits for additional pipeline infrastructure to transport CO2, could significantly disrupt our existing and future operations, including our planned 105-mile CO2risks outlined above (See pipeline extension in the Cedar Creek Anticline area in MontanaFederal and North Dakota.State Regulations – Federal Leases).

TaxA number of governmental bodies have introduced or are contemplating regulatory changes in response to various proposals under discussion within the Biden Administration, if enacted,to combat climate change and how it should be dealt with. Legislation and increased regulation regarding climate change could change or remove long-time tax benefits available to the oilimpose significant costs on us and gas industry for drillingpossibly affect our financial condition and production activities.operating performance.

As part of its budgetary planning, the Biden Administration has discussed a number of changes to certain provisions of federal tax law applicable to the exploration and production industry, including imposing a tax on carbon emissions, as well as eliminating long-standing deductions that benefit the fossil fuel industry. Among the specific provisions being focused upon are Internal Revenue Code (“IRC”) Section 263, which allows expensing of exploration, development and intangible drilling costs, and IRC Section 613, which allows use of percentage depletion instead of cost depletion to recover drilling and development costs of oil and gas wells. Any such changes would require the U.S. Congress to pass new legislation and are likely to be part of a broader set of tax revisions. It is currently anticipated that new tax legislation will be proposed by the Administration later in 2021, the timing and specifics of which are yet to be determined, and the likelihood of passage of which is not assured.


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Environmental laws and regulations applicable to our industry are costly and stringent.

Our exploration, production, and marketing operations are subject to complex and stringent federal, state, and local laws and regulations governing, among other things, the discharge of substances into the environment or otherwise relating to the protection of human health and the protection of endangered species. These laws and regulations and related public policy considerations affect the costs, manner, and feasibility of our operations and require us to make significant expenditures in order to comply. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial obligations, and the issuance of injunctions that could limit or prohibit our operations. Some of these laws and regulations may impose joint and several, strict liability for contamination resulting from spills, discharges, and releases of substances, including petroleum hydrocarbons and other wastes, without regard to fault or the legality of the original conduct. Under such laws and regulations, we could be required to remove or remediate previously disposed substances and property contamination, including wastes disposed or released by prior owners or operators.

Risks Relating to Financial Results and Condition

On September 18, 2020, weemerged from bankruptcy, which could adversely affect our business and relationships.

It is possible that our having filed for bankruptcy and our third-quarter 2020 emergence from the Chapter 11 bankruptcy proceedings could adversely affect our business and relationships with customers, employees and suppliers in the following ways:

•key suppliers could terminate their relationship or require financial assurances or enhanced performance;
•the ability to renew existing contracts and compete for new business may be adversely affected;
•the ability to attract, motivate and/or retain key executives and employees may be adversely affected;
•employees may be distracted from performance of their duties or more easily attracted to other employment opportunities; and
•competitors may take business away from us, and our ability to attract and retain customers may be negatively impacted.

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

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

Upon our emergence from bankruptcy, we adopted fresh start accounting. Accordingly, certain values and financial measures of the Company’s consolidated financial statements subsequent to September 18, 2020 are not comparable to those in its consolidated financial statements prior to, and including September 18, 2020, although numerous operational measures are roughly comparable to those in our historical financial statements and other disclosures.

In connection with proceedings in the Bankruptcy Court, and the late third-quarter 2020 hearing to consider confirmation of the plan of reorganization, we prepared projected financial information to demonstrate to the Bankruptcy Court the feasibility of the plan of reorganization and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared at that time solely for the purpose of the bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis. The projections were prepared based upon then-current prevailing economic assumptions at that time, are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks, and the assumptions underlying the projections and/or valuation estimates may prove to be wrong in material respects. Actual results will likely vary significantly from those contemplated by the projections. As a result, investors should not rely on those projections.

We may be unable to access the equity or debt capital markets to raise sufficient capital to fund our development activities or other obligations.

Recent reluctance of traditional capital sources to invest in the exploration and production sector based on market volatility, perceived underperformance and environmental, social and governance trends, has raised concerns regarding capital availability

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for the sector. The cost of obtaining money from the credit markets has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards and reduced (and in some cases ceased to provide) funding to borrowers. If those markets are unavailable, or if we are unable to access them or alternative financing sources on acceptable terms, we may be unable to carry out our business strategy, with an accompanying negative impact on our financial condition and results of operations.Financial Risks

Commodity derivative contracts may expose us to potential financial loss.

To reduce our exposure to fluctuations in the prices of oil and natural gas, we enter into commodity derivative contracts in order to economically hedge a portion of our forecasted oil and natural gas production. As of February 24, 2021,23, 2022, we have oil derivative contracts in place covering approximately 32,500 Bbls/d for 2021, 10,50026,500 Bbls/d for the first half of 2022, and 2,00021,000 Bbls/d for the second half of 2022.2022, 10,000 Bbls/d for the first half of 2023, and 4,000 Bbls/d for the second half of 2023. Such derivative contracts expose us to risk of financial loss, including when there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received, when the cash benefit from hedges including a sold put is limited to the extent oil prices fall below the price of any sold puts in our derivative portfolio, or when the counterparty to the derivative contract is financially constrained and defaults on its contractual obligations. In addition, these derivative contracts may limit the benefit we would otherwise receive from increases in the prices for oil and natural gas.

Risks Relating to Ownership of Denbury Securitiesfuture participation in significant CCUS activities.

SalesDenbury’s successful future participation in the developing CCUS industry utilizing our technical expertise in injection of CO2 and our significant CO2 pipeline system is dependent upon a number of factors, including: (i) the speed with which current and potential third party emitters are able to finance and build (often over a multi-year period) the equipment to capture CO2 emissions from various industrial processes; (ii) continued support of CO2 capture and sequestration by the federal and state governments; and (iii) the pace at which we can bring together captured CO2 emissions, and pipelines to transport those emissions to appropriately tested and prepared sequestration sites. These activities will require significant capital investment by emitting entities or other third parties, and require us to generate or raise capital to build interconnecting CO2 pipelines and fund the testing, drilling and installation of facilities at various sequestration sites. These activities subject us to the financial risks of rising costs of equipment and capital, possible delays in acquiring them, along with the financial impact of our expending capital on these activities well before realizing CCUS cash flows, any of which could negatively impact our financial condition and operational results in future periods.

Continuing or worsening inflationary or supply chain issues could lower our margins and operational efficiency.

Although our 2021 results reflected oilfield cost inflation only toward the end of the year, our 2022 budget anticipates cost increases in specific fields and for specific equipment, supplies, and third-party labor costs. Expectations of lingering or increasing inflationary pressures in our industry are becoming widespread (including anticipated double digit percentage price increases in certain expense categories). In addition to price increases by third-party service companies, it may become more costly for us to recruit and retain key employees, particularly specialized/technical personnel, in the face of increased competition for specialized and experienced oilfield workers.

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. We have increased our 2022 operational budget for anticipated inflation and have taken steps to build our on-hand supply stock for items frequently used in our operations to address possible supply chain disruptions. Supply chain issues could cause operational delays in availability of goods and materials necessary to drill new wells or perform workovers or repairs on existing wells or infrastructure.

Government and societal reaction to climate change could drive down our stock price and increase our costs, while pressure to meet environment, social and governance (“ESG”) standards may impact our business.

Increasing attention to climate change and public and investor demands that companies address climate change may increase our costs, reduce demand for oil or negatively impact our stock price and access to capital markets. Furthermore, organizations that advise many institutional investors on corporate governance and investment and voting decisions have developed ratings processes for evaluating companies related to ESG matters. Negative ratings by these organizations, together with ESG advocates’ pressure for investors to divest fossil fuel equities and for lenders to limit funding to oil and gas producers, may lead to negative investor sentiment toward the oil and gas industry, including the Company, which could have a negative impact on our stock price and cause us reputational harm.


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Tax proposals under discussion within the Biden Administration, if enacted, could change or remove long-time tax benefits available to the oil and gas industry for drilling and production activities.

As part of its 2021 budgetary planning, the Biden Administration discussed a number of changes to certain provisions of federal tax law applicable to the exploration and production industry, including imposing a tax on carbon emissions, as well as eliminating long-standing deductions that benefit the fossil fuel industry. Among the specific provisions focused upon were Internal Revenue Code (“IRC”) Section 263, which allows expensing of exploration, development and intangible drilling costs, and IRC Section 613, which allows use of percentage depletion instead of cost depletion to recover drilling and development costs of oil and gas wells. Any such changes would require the U.S. Congress to pass new legislation and are likely to be part of a broader set of tax revisions.

Open-market sales of a substantial number of shares of our common stock in the public market, including both those issuableacquired upon exercise by holders of our outstanding warrants, and those registrable for resale under a registration rights agreement, could cause the market price of our common stock to drop significantly, even if our business is doing well.

Approximately 40% of our currently issued and outstanding shares of common stock, currently held by five shareholders, are entitled to be registered for resale under a registration rights agreement (see Note 10, Stockholders’ Equity,to the consolidated financial statements), for the benefit of the largest holders of our pre-emergence debt, as agreed as part of our bankruptcy plan of reorganization. Sales of a substantial number of shares of our common stock by these holders, or the perception that such sales could occur, could reduce the market price of our common stock and might also impair our ability to raise capital through future sale of our equity. Additionally, inIn connection with our plan of reorganization, we issued series A and series B warrants to holders of our pre-emergence debt and equity, entitling the warrant holders to exercise the warrants for up toat prices of either $32.59 or $35.41 per share, respectively, of which outstanding warrants may convert into approximately 5.55.2 million shares (approximately 10%9%) of our currently outstanding common stock on a fully diluted basis. See Note 1, Natureoutstanding as of Operations and Summary of Significant Accounting Policies – Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code, to the consolidated financial statements regarding the specific terms of the warrants.December 31, 2021. The future exercise of a large number of warrants, followed by the subsequent sale of the acquired stock into the market, could also negatively affect our common stock price. We cannot predict the likelihood of exercise of the warrants or sales of shares by these two groups of holders of our common stock or their amounts,acquired upon exercise, or the effect of any such sales on the prevailing market price of our common stock.

The trading market for our common stock and its market price may be affected by our limited trading volume.

Upon our emergence from bankruptcy, our old common stock was canceled and we issued new common stock. The market price and trading volume of our common stock is affected by numerous factors, many of which are beyond our control. These factors include, among other things, the overhang of shares of our common stockregistered for resale under a registration statement as discussed above, the concentration of holdings of our common stock, and on a longer-term basis, the potential future dilution of up to 5.5 million shares of our common stock acquirable upon exercise of our series A or series B warrants, which dilution from exercise of the series A or series B warrants could be reduced to the extent warrants are exercised on a cashless basis. No assurance can be given as to the liquidity of the trading market for the common stock.

Risks Relating to a Cybersecurity Breach

A cyber breach could occur and result in information theft, data corruption, operational disruption, and/or financial loss.

Our business has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain of our exploration, development and production activities. We depend on digital technology, among other things, to process and record financial and operating data; analyze seismic and drilling information; monitor and control pipeline and

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plant equipment; and process and store personally identifiable information of our employees, industry partners and royalty owners. Cyberattacks on businesses have escalated in recent years, exemplified by the recent delayed discovery of the Russian-sponsored hack of U.S. governmental agencies and hundreds of U.S. corporations which did not affect our systems.years. Our technologies, systems and networks, or those of software providers that we use, may become the target of cyberattacks or information security breaches that could compromise our process control networks or other critical systems and infrastructure, resulting in disruptions to our business operations, harm to the environment or our assets, disruptions in access to our financial reporting systems, or loss, misuse or corruption of our critical data and proprietary information, including our business information and that of our employees, partners and other third parties. Successful attacks which disable third-party pipelines or processing facilities upon which we depend could materially adversely affect our operations. Any of the foregoing may be exacerbated by a delay or failure to detect a cyber incident. Although we have not incurred any material losses from cyberattacks, future cyberattacks could result in significant financial losses, legal or regulatory violations, reputational harm, and legal liability.

Although we utilize various procedures and controls to monitor and protect against these threats and to mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing successful attacks from the increasing number of sophisticated intrusions based on technological advances. In addition, in connection with COVID-19 precautions, many of our employees and those of our service providers, vendors and industry partners have been working, and some may continue to work, from home or other remote-work locations, where cybersecurity protections may be less robust and cybersecurity procedures and safeguards may be less effective. We may be required to expend significant additional resources to continue to modify or enhance our procedures and controls or to upgrade our digital and operational systems, related infrastructure, technologies and network security, which could increase our costs. The Audit Committee’s duties and responsibilities include reviewing and discussing the Company’s guidelines and policies with respect to risk assessment and risk management, as well as the Company’s major financial and cybersecurity risk exposures and the steps that management has taken to monitor and control such exposures.


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Risks Relating to Our Operations and Industry

Our future performance depends upon our ability to effectively develop our existing oil and natural gas reserves and find or acquire additional oil and natural gas reserves that are economically recoverable.

Unless we can successfully develop our existing reserves and/or replace the reserves that we produce, our reserves will decline, resulting eventually in a decrease in oil and natural gas production and lower revenues and cash flows from operations. We have historically replaced reserves through both acquisitions and internal organic growth activities. For internal organic growth activities, the magnitude of proved reserves that we can book in any given year depends on our progress with new floods and the timing of the production response, as well asespecially our development of fields in the success of exploitation projects.CCA area in the Rocky Mountains. In the future, we may not be able to continue to replace reserves at acceptable costs. The business of exploring for, developing or acquiring reserves is capital intensive. We may not be able to make the necessary capital investment to maintain or expand our oil and natural gas reserves if our cash flows from operations are reduced, whether due to current oil or natural gas prices or otherwise, or if external sources of capital become limited or unavailable. Further, the process of using CO2 for tertiary recovery, and the related infrastructure, requires significant capital investment prior to any resulting and associated production and cash flows from these projects, heightening potential capital constraints. If our capital expenditures are restricted, or if outside capital resources become limited, we will not be able to maintain our current production levels.

Estimating our reserves, production and future net cash flows is difficult to do with any certainty.

Estimating quantities of proved oil and natural gas reserves requires interpretations of available technical data and various assumptions, including future production rates, production costs, severance and excise taxes, capital expenditures and workover and remedial costs, and the assumed effect of governmental rules and regulations. There are numerous uncertainties about when a property may have proved reserves as compared to potential or probable reserves, particularly relating to our tertiary recovery operations. Forecasting the amount of oil reserves recoverable from tertiary operations, and the production rates anticipated therefrom, requires estimates, one of the most significant being the oil recovery factor. Actual results most likely will vary from our estimates. Also, the use of a 10% discount factor for reporting purposes, as prescribed by the SEC, may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business, and the oil and natural gas industry in general, are subject. Any significant inaccuracies in these interpretations or assumptions, or changes of conditions, could result in a revision of the quantities and net present value of our reserves.

The reserves data included in documents incorporated by reference represents estimates only.  Quantities of proved reserves are estimated based on economic conditions, including first-day-of-the-month average oil and natural gas prices for the 12-month period preceding the date of the assessment.  The representative oil and natural gas prices used in estimating our

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December 31, 2020 reserves, after adjustments for market differentials and transportation expenses by field, were $35.84 per Bbl for crude oil and $1.70 per Mcf for natural gas. Our reserves and future cash flows may be subject to revisions based upon changes in economic conditions, including oil and natural gas prices, as well as due to production results, results of future development, operating and development costs, and other factors.  Downward revisions of our reserves could have an adverse effect on our financial condition and operating results.  Actual future prices and costs may be materially higher or lower than the prices and costs used in our estimates.

Our production will decline if our access to sufficient amounts of carbon dioxide is limited.

Our long-term strategy is primarily focused on our CO2 tertiary recovery operations.operations are a critical component of our long-term strategy. The crude oil production from our tertiary recovery projects depends, in large part, on having access to sufficient amounts of naturally occurring and industrial-sourced CO2. Our ability to produce oil from these projects would be hindered if our supply of CO2 was limited due to, among other things, problems with our current CO2 producing wells and facilities, including compression equipment, catastrophic pipeline failure or our ability to economically purchase CO2 from industrial sources. This could have a material adverse effect on our financial condition, results of operations and cash flows. Our anticipated future crude oil production from tertiary operations is also dependent on the timing, volumes and location of CO2 injections and, in particular, on our ability to increase our combined purchased and produced volumes of CO2 and inject adequate amounts of CO2 into the proper formation and area within each of our tertiary oil fields.

The development of our naturally occurring CO2 sources involves the drilling of wells to increase and extend the CO2 reserves available for use in our tertiary fields. These drilling activities are subject to many of the same drilling and geological risks of drilling and producing oil and gas wells (see Oil and natural gas development and producing operations involve various risks below). Furthermore, recent market conditions and government and/or public pressure may cause the delay or cancellation of construction of plants that produce industrial-sourced CO2 as a byproduct that we can purchase, thus limitinglimit the amount of industrial-sourced CO2 available for our use in our tertiary operations. In addition, U.S. government policy and public pressure on industrial CO2 emitters could provide stronger incentives for these entities to capture their CO2 emissions and permanently sequester the CO2 underground rather than making it available for use in our EOR operations.

Certain of our operations may be limited during certain periods due to severe weather conditions and otheror government regulations.

Our operations in the Gulf Coast region may be subjected to adverse weather conditions such as hurricanes, flooding and tropical storms in and around the Gulf of Mexico, as well as freezing temperatures, ice and snow, that can damage oil and natural gas facilities and delivery systems and disrupt operations, which can also increase costs and have a negative effect on our results of operations. Certain of our operations in Montana, Wyoming and North Dakota, Montana and Wyoming, including the construction of CO2 pipelines, the drilling of new wells and production from existing wells, are conducted in areas subject to extreme weather conditions including severe cold, snow and rain, which conditions may cause such operations to be hindered or delayed or otherwise require that they be conducted only during non-winter months, and depending on the severity of the weather, could have a negative effect on our results of operations in these areas. Further, the potential impacts of climate change on our operations may include unusually intense rainfall and storm patterns, rising sea levels and increased high temperatures, the last of which imposes certain physical constraints on our CO2 injections in our operations in the Gulf Coast.

Certain of our operations in the Rocky Mountain region are confined to certain time periods due to environmental regulations, federal restrictions on when drilling can take place on federal lands, and lease stipulations designed to protect certain wildlife, which regulations, restrictions and limitations could slow down our operations, cause delays, increase costs and have a negative effect on our results of operations. In addition, a number of governmental bodies have introduced or are contemplating regulatory changes in response to various proposals to combat climate change and how it should be dealt with. Legislation and increased regulation regarding climate change could impose significant costs on us and possibly affect our financial condition and operating performance.


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Oil and natural gas development and producing operations involve various risks.

Our operations are subject to all of the risks normally incident and inherent to the operation and development of oil and natural gas properties and the drilling of oil and natural gas wells, including, without limitation, pipe failure; fires; formations with abnormal pressures; uncontrollable flows of oil, natural gas, brine or well fluids; release of contaminants into the environment and other environmental hazards and risks; and well blowouts, cratering or explosions. In addition, our operations are sometimes near populated commercial or residential areas, which adds additional risks. The nature of these risks is such that some liabilities could exceed our insurance policy limits or otherwise be excluded from, or limited by, our insurance

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coverage, as in the case of environmental fines and penalties, for example, which are excluded from coverage as they cannot be insured.

We could incur significant costs related to these risks that could have a material adverse effect on our results of operations, financial condition and cash flows or could have an adverse effect upon the profitability of our operations. Additionally, a portion of our production activities involves CO2 injections into fields with wells plugged and abandoned by prior operators. It is often difficult (or impracticable) to determine whether a well has been properly plugged prior to commencing injections and pressuring the oil reservoirs. We may incur significant costs in connection with remedial plugging operations to prevent environmental contamination and to otherwise comply with federal, state and local regulations relative to the plugging and abandoning of our oil, natural gas and CO2 wells. In addition to the increased costs, if wells have not been properly plugged, modification to those wells may delay our operations and reduce our production.

Development activities are subject to many risks, including the risk that we will not recover all or any portion of our investment in such wells. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Further, our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including:

•unexpected drilling conditions;
•pressure or irregularities in formations;
•equipment failures or accidents;
•adverse weather conditions, including hurricanes and tropical storms in and around the Gulf of Mexico, as well as freezing temperatures, ice and snow, that can damage oil and natural gas facilities and delivery systems and disrupt operations, and winter conditions and forest fires in the Rocky Mountain region that can delay or impede operations;
•compliance with environmental and other governmental requirements;
•the cost of, or shortages or delays in the availability of, drilling rigs, equipment, pipelines and services; and
•title problems.

Our planned tertiary and CCUS operations and the related construction of necessary CO2 pipelines could be delayed by difficulties in obtaining pipeline rights-of-way and/or permits and/or by the listing of certain species as threatened or endangered.

The production of crude oil from our planned tertiary operations is dependent upon having access to pipelines to transport available CO2 to our oil fields at a cost that is economically viable. Our futureFuture extensions of our Green Pipeline, construction ofto connect third-party CO2 pipelines willemitters to sequestration sites, and preparation for CCUS activities require us to obtain rights-of-way from private landowners, state and local governments and the federal government in certain areas. Certain states where we operate have considered or may again consider the adoption of laws or regulations that could limit or eliminate the ability of a pipeline owner or of a state, state’s legislature or its administrative agencies to exercise eminent domain over private property, in addition to possible judicially imposed constraints on, and additional requirements for, the exercise of eminent domain. We also often conduct Rocky Mountain operations on federal and other oil and natural gas leases inhabited by species that couldmay be listed as threatened or endangered under the Endangered Species Act, which listing couldmay lead to tighter restrictions as to federal land use and other land use where federal approvals are required. These laws and regulations, together with any other changes in law related to the use of eminent domain or the listing of certain species as threatened or endangered, could inhibit or eliminate our ability to secure rights-of-way or otherwise access land for current or future pipeline construction projects and may require additional regulatory and environmental compliance, and increased costs in connection therewith, which could delay our CO2 pipeline construction schedule and initiation of our pipelineEOR or CCUS operations.


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Estimating our reserves, production and future net cash flows is difficult to do with any certainty.

Estimating quantities of proved oil and natural gas reserves requires interpretations of available technical data and various assumptions, including future production rates, production costs, severance and excise taxes, capital expenditures and workover and remedial costs, and the assumed effect of governmental rules and regulations. There are numerous uncertainties about when a property may have proved reserves as compared to potential or probable reserves, particularly relating to our tertiary recovery operations. Forecasting the amount of oil reserves recoverable from tertiary operations, and/and the production rates anticipated therefrom, requires estimates, one of the most significant being the oil recovery factor. Actual results most likely will vary from our estimates. Also, the use of a 10% discount factor for reporting purposes, as prescribed by the SEC, may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business, and the oil and natural gas industry in general, are subject. Any significant inaccuracies in these interpretations or increaseassumptions, or changes of conditions, could result in a revision of the quantities and net present value of our reserves.

The reserves data included in documents incorporated by reference represents estimates only.  Quantities of proved reserves are estimated based on economic conditions, including first-day-of-the-month average oil and natural gas prices for the 12-month period preceding the date of the assessment.  The representative oil and natural gas prices used in estimating our December 31, 2021 reserves, after adjustments for market differentials and transportation expenses by field, were $63.86 per Bbl for crude oil and $3.39 per Mcf for natural gas. Our reserves and future cash flows may be subject to revisions based upon changes in economic conditions, including oil and natural gas prices, as well as due to production results, results of future development, operating and development costs, and other factors.  Downward revisions of constructing our pipelines.reserves could have an adverse effect on our financial condition and operating results.  Actual future prices and costs may be materially higher or lower than the prices and costs used in our estimates.

The marketability of our production is dependent upon transportation lines and other facilities, most of which we do not control. When these facilities are unavailable, our operations can be interrupted and our revenues reduced.

The marketability of our oil and natural gas production depends, in part, upon the availability, proximity and capacity of transportation lines owned by third parties. In general, we do not control these transportation facilities, and our access to them may be limited or denied. A significant disruption in the availability of, and access to, these transportation lines or other production facilities could adversely impact our ability to deliver to market or produce our oil and thereby cause a significant interruption in our operations.


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We may lose key executive officers or specialized technical employees, which could endanger the future success of our operations.

Our success depends to a significant degree upon the continued contributions of our executive officers, other key management and specialized technical personnel. Our employees, including our executive officers, are employed at will and do not have employment agreements. We believe that our future success depends, in large part, upon our ability to hire and retain highly skilled personnel.

The loss of one or more of our large oil and natural gas purchasers could have an adverse effect on our operations.

For the year ended December 31, 2020, three2021, four purchasers individually accounted for 10% or more of our oil and natural gas revenues and, in the aggregate, for 54%62% of such revenues.  The loss of a large single purchaser could adversely impact the prices we receive or the transportation costs we incur.

Item 1B.  Unresolved Staff Comments

There are no unresolved written SEC staff comments regarding our periodic or current reports under the Securities Exchange Act of 1934 received 180 days or more before the end of the fiscal year to which this annual report on Form 10-K relates.

Item 2.  Properties

Information regarding the Company’s properties called for by this item is included in Item 1, Business and Properties – Oil and Natural Gas Operations.  We also have various operating leases for rental of office space, office and field equipment, and

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land easements.  See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity – Commitments, Obligations and Off-Balance Sheet Arrangements, and Note 5, Leases, to the consolidated financial statements for the future minimum rental payments.  Such information is incorporated herein by reference.

Item 3.  Legal Proceedings

We are involved in various lawsuits, claims and regulatory proceedings incidental to our businesses. While we currently believe that the ultimate outcome of these proceedings, individually and in the aggregate, will not have a material adverse effect on our business or finances, 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.

Chapter 11 Proceedings

The information under Note 14,
On July 30, 2020, Denbury Resources Inc.Commitments and each of its wholly-owned subsidiaries filed for relief under chapter 11 of the Bankruptcy Code. The chapter 11 cases were administered jointly under the caption “In re Denbury Resources Inc., et al.Contingencies, Case No. 20-33801”. On September 2, 2020,to the Bankruptcy Court entered the Confirmation Order and on the Emergence Date, all of the conditions of the Plan were satisfied or waived and the Plan became effective and was implemented in accordance with its terms. On September 30, 2020, the Bankruptcy Court closed the chapter 11 cases of each of Denbury Inc.’s wholly-owned subsidiaries. The chapter 11 case captioned “In re Denbury Resources Inc., et al., Case No. 20-33801” will remain pending until the final resolution of all outstanding claims.consolidated financial statements is incorporated herein by reference.

Riley Ridge Helium Supply Contract Claim

As part of our 2010 and 2011 acquisitions of the Riley Ridge Unit and associated gas processing facility that was under construction, the Company assumed a 20-year helium supply contract under which we agreed to supply the helium separated from the full well stream by operation of the gas processing facility to a third-party purchaser, APMTG Helium, LLC (“APMTG”).

As the gas processing facility was shut-in during mid-2014 due to significant technical issues, we were not able to supply helium under the helium supply contract.  In a case filed in November 2014 in the Ninth Judicial District Court of Sublette County, Wyoming, APMTG claimed multiple years of liquidated damages for non-delivery of volumes of helium specified

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under the helium supply contract. The Company claimed that its contractual obligations were excused by virtue of events that fall within the force majeure provisions in the helium supply contract.

On March 11, 2019, the trial court entered a final judgment that a force majeure condition did exist, but such condition only excused the Company’s performance for a 35-day period in 2014, and as a result the Company should pay APMTG liquidated damages and interest thereon for all other time periods for performance from contract commencement to the close of evidence (November 29, 2017). On December 4, 2020, the Wyoming Supreme Court entered a judgment affirming the trial court’s ruling on all counts and, as a result, the Company paid total liquidated damages (including interest) of $52.1 million to APMTG on December 23, 2020 in full satisfaction of all claims. The Company had previously recorded an accrual for these costs in “Accounts payable and accrued liabilities” in our Consolidated Balance Sheets.

Item 4.  Mine Safety Disclosures

Not applicable.

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PART II

Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Information and Holders of Record

On September 18, 2020, upon emergence from bankruptcy, all existing shares of Predecessor common stock were cancelledand new shares of common stock in the Successor were issued to former holders of debt cancelled in bankruptcy. On September 21, 2020 the Successor’s common stock commenced trading on the New York Stock Exchange (“NYSE”) under the symbol “DEN.” As of January 31, 2021,2022, based on information from the Company’s transfer agent, Broadridge Stock Transfer Agent, there was one holderwere two holders of record of Denbury’s common stock.

The Predecessor’s common stock was listed on the NYSE under the symbol “DNR”, but the NYSE indefinitely suspended trading of the Predecessor stock on July 31, 2020 as a result of Denbury Resources Inc. and its subsidiaries filing voluntary positions for reorganization under chapter 11 of the Bankruptcy Code. From July 31, 2020 until September 21, 2020, during the Company’s Chapter 11 reorganization, trading of the Predecessor common stock occurred on the OTC Pink Open Market.

Dividends

We have not paid dividends on our Successor common stock and have no current plans to declare common stock dividends. Our credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto requires us to meet certain financial covenants at the time dividend payments are made. For further discussion, see Note 8, Long-Term Debt, to the consolidated financial statements.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

We did not repurchase any shares of our Successor common stock during the fourth quarter of 2020.2021.


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Stock Performance Graphs

The following Performance Graphs and related information shall not be deemed “soliciting material” or to be “filed” with the Securities and Exchange Commission (“SEC”), nor shall such information be incorporated by reference into any future filings under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filings.

The following graph illustrates changes over the period September 21, 2020 through December 31, 2020,2021, in cumulative total stockholder return on the Successor common stock as measured against the cumulative total return of the S&P 500 Index and the Dow Jones U.S. Exploration and Production Index.  The graph tracks the performance of a $100 investment in our common stock and in each index (with the reinvestment of all dividends for the index securities) from September 21, 2020 to December 31, 2020.2021.

SEPTEMBER 21, 2020 to DECEMBER 31, 20202021
COMPARISON OF CUMULATIVE TOTAL RETURN – POST BANKRUPTCY EMERGENCE
den-20201231_g2.jpg
 9/21/209/30/2010/31/2011/30/2012/31/20
Denbury Inc.$100 $97 $92 $124 $142 
S&P 500100 96 94 104 108 
Dow Jones U.S. Exploration & Production100 84 79 106 114 

den-20211231_g2.jpg
 9/21/209/30/2012/31/203/31/216/30/219/30/2112/31/21
Denbury Inc.$100 $97 $142 $265 $424 $388 $423 
S&P 500100 96 108 115 124 125 139 
Dow Jones U.S. Exploration & Production100 84 114 152 176 180 194 

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The following graph illustrates changes over the period December 31, 2015 through September 18, 2020, in cumulative total stockholder return on the Predecessor common stock as measured against the cumulative total return of the S&P 500 Index and the Dow Jones U.S. Exploration and Production Index.  The graph tracks the performance of a $100 investment in our common stock and in each index (with the reinvestment of all dividends for the index securities) from December 31, 2015 to September 18, 2020.

DECEMBER 31, 2015 to SEPTEMBER 18, 2020
COMPARISON OF CUMULATIVE TOTAL RETURN – PRE-BANKRUPTCY EMERGENCE
den-20201231_g3.jpg
 12/31/1512/31/1612/31/1712/31/1812/31/199/18/20
Denbury Resources Inc.$100 $182 $109 $85 $70 $1 
S&P 500100 112 136 130 171 188 
Dow Jones U.S. Exploration & Production100 124 126 104 116 67 


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Item 6. Selected Financial Data

Not included based upon the Company voluntarily early adopting the SEC’s amendments to Item 301 of Regulation S-K which became effective on February 10, 2021.[Reserved]


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

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our consolidated financial statements and Notes thereto included in Item 8, Financial Statements and Supplementary Information.  Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Risk Factors under Item 1A of this Form 10-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 from our forward-looking statements. For a discussion of the financial results for the fiscal year ended December 31, 2018,2019, see Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, of our Annual Report on Form 10-K for the fiscal year ended December 31, 2019,2020, as filed with the SECSecurities and Exchange Commission (“SEC”) on February 27,March 5, 2021.

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

OVERVIEW

Denbury is an independent energy company with operations focused on producing oil from mature oil fields in the Gulf Coast and Rocky Mountain regions. The Company is differentiated by itsour focus on CO2 EOR and the emerging 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, underpinningmaking the Company’s Scope 1 and 2 CO2 emissions negative today, with a goal to also fully offset itsour Scope 1, 2, and 3 CO2 emissions within this decade, primarily through increasing the decade.amount of captured industrial-sourced CO2 used in our operations.

EmergenceOil 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 Voluntary Reorganization Under Chapter 11 ofoperations, revenues, capital and budgeting decisions, and oil and natural gas reserves volumes. The table below outlines selected financial items and sales volumes, along with our realized oil prices, before and after commodity derivative impacts, over the Bankruptcy Code. last three years:On July 30, 2020 (the “Petition Date”), Denbury Resources Inc. and its subsidiaries filed petitions for reorganization in a “prepackaged” voluntary bankruptcy (the “Chapter 11 Restructuring”) under chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”) under the caption “In re Denbury Resources Inc., et al., Case No. 20-33801”. On September 2, 2020, the Bankruptcy Court entered an order (the “Confirmation Order”) confirming the chapter 11 plan of reorganization (the “Plan”) and approving the Disclosure Statement, and on September 18, 2020 (the “Emergence Date”), the Plan became effective in accordance with its terms and the Company emerged from Chapter 11. Key accomplishments of the Chapter 11 Restructuring included the following:
Year Ended December 31,
In thousands, except per-unit data202120202019
Oil, natural gas, and related product sales$1,159,955 $693,209 $1,212,020 
Receipt (payment) on settlements of commodity derivatives(277,240)102,485 23,606 
Oil, natural gas, and related product sales and commodity settlements, combined$882,715 $795,694 $1,235,626 
Average daily sales (BOE/d)48,770 51,15158,213 
Average net realized prices   
Oil price per Bbl - excluding impact of derivative settlements$66.52 $37.78 $58.26 
Oil price per Bbl - including impact of derivative settlements50.46 43.40 59.40 

•Eliminated approximately $2.1 billion of bond debt by issuing equity and/or warrantsOver the last several years, NYMEX oil prices have been extremely volatile, reaching a three-year peak over $84 per Bbl in October 2021 compared to lows averaging $17 per Bbl in April 2020. The year-to-year volatility has been due to the holdersreduction in worldwide economic activity and oil demand amid the COVID-19 coronavirus (“COVID-19”) pandemic, plus OPEC supply pressures. NYMEX WTI oil prices strengthened from an average of that debt;
•Significantly improved leverage ratios;
•Reduced ongoing annual interest expenseapproximately $39 per Bbl in 2020 to $68 per Bbl during 2021, reaching highs over $84 per Bbl in late-October 2021, followed by approximately $165 million, significantly lowering our cash flow breakeven level;
•Eliminated approximately $9 million from ongoing general and administrative expenses by terminating certain office leases and relocating our corporate headquarters; and
•Established a new $575 million senior secured bank credit facility with $482.0 million of availability at December 31, 2020 after outstanding letters of credit.

For more information on the Chapter 11 Restructuring and related matters, refer to Note 1, Nature of Operations and Summary of Significant Accounting Policies – Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code, and Note 8, Long-Term Debt, to the consolidated financial statements.

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

Fresh start accounting requires that new fair values be established for the Company’s assets, liabilities and equity as of the date of emergence from bankruptcy, September 18, 2020, and therefore certain values and operational results of thelate November 2021 upon

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

consolidated financial statements subsequent to September 18, 2020 are not comparable to the Company’s consolidated financial statements prior to, and including September 18, 2020, principally due to the Emergence Date re-evaluationidentification of the fair valuenew Omicron variant of COVID-19, with NYMEX oil prices recovering in early 2022 to new seven year highs of $95.46 per barrel as of February 23, 2022.

As reflected in the table above, in 2021, our oil and natural gas properties, CO2 properties, and pipelines, together withsales increased by $466.7 million, or 67%, over 2020 levels due to rising oil prices; however, after considering the conversion of over $2 billion of previously outstanding debt into new common stock and/or warrants in the Successor. The reorganization value derived from the range of enterprise values associated with the Plan was allocated to the Company’s identifiable tangible and intangible assets and liabilities based on their fair values. The Emergence Date fair values of the Successor’s assets and liabilities differ materially from their recorded values as reflected on the historical balance sheet of the Predecessor and may materially affectsignificant payments made upon settlements under our results of operations in Successor reporting periods.

Oil Price Impact on Our Business. Our financial results are significantly impacted by changes in oil prices, as 97% ofcommodity derivative contracts, our production is oil. Changes in oil prices impact all aspects of our business, most notably our cash flows from operations, revenues, capital allocation and budgeting decisions, and oil and natural gas reserves volumes. The table below outlines changessales net of hedging settlements increased only $87.0 million. Upon emergence from bankruptcy in September 2020, we were required to hedge through mid-2022 certain levels of estimated production under our realizedpost-emergence bank credit facility, which significantly limited our ability to fully benefit from the significant oil prices, before and after commodity hedging impacts, over the last three years:
Year Ended December 31,
 202020192018
Average net realized prices   
Oil price per Bbl - excluding impact of derivative settlements$37.78 $58.26 $66.11 
Oil price per Bbl - including impact of derivative settlements43.40 59.40 57.91 

Responseprice recovery in 2021. Although we were required to 2020 Oil Price Declines. In January and February 2020, NYMEX WTI oil prices averagedhedge a certain percentage of our production in the mid-$50s per Bbl range beforefirst half of 2022, that percentage is less than in 2021. Additionally, our hedges in 2022, on average, are at more favorable prices and with a precipitous decline in oil prices that began in early March 2020 due to the combinationgreater mix of the COVID-19 coronavirus (“COVID-19”) pandemic and the failure of the group of oil producing nations known as OPEC+ to reach an agreement over proposed oil production cuts. While oil pricescollars, providing us more upside price exposure. We currently have improved from the low points experienced during the second quarter of 2020, the concerns and uncertainties around the balance of supply and demand for oil are expected to continue for some time.

The precipitous decline in oil prices that began in the latter part of the first quarter of 2020 caused us to reassessno further hedging requirements under our original plans for 2020, and as a result the Company adopted the following operational and financial measures:

•Reduced budgeted 2020 capital spending by $80 million, or 44%, to a range of $95 million to $105 million;
•Deferred the CO2 pipeline to Cedar Creek Anticline and the Cedar Creek Anticline CO2 tertiary flood development project beyond 2020;
•Implemented cost reduction measures including shutting-in production, shutting down compressors, negotiating reductions with vendors, delaying uneconomic well repairs and workovers and reducing our workforce;
•Restructured approximately 50% of our three-way collars covering 14,500 Bbls/d into fixed-price swaps for the second quarter through the fourth quarter of 2020 in order to increase downside oil price protection; and
•Evaluated production economics at each field and shut-in production beginning in late March 2020 that was uneconomic to produce or repair based on then-prevailing oil prices.bank credit facility.

Comparative Financial Results and Highlights. We recognized net income of $56.0 million, or $1.04 per diluted common share, during 2021. As a result of Denbury filing for bankruptcy and emerging from bankruptcy during September 2020, our 2020 financial results are broken out between the Predecessor period (January 1, 2020 through September 18, 2020) and the Successor period (September 19, 2020 through December 31, 2020). For the Predecessor period from January 1, 2020 through September 18, 2020, we recognized a net loss of $1.4 billion, and for the Successor period from September 19, 2020 through December 31, 2020, we recognized a net loss of $50.7 million. The primary driversprincipal determinants of our significant financialcomparative annual results between 2020 and 2021 were (a) an $850.0 million charge for reorganization items, net, loss forduring the prior-year Predecessor period, included the following:

•Aprimarily consisting fresh start accounting adjustments and (b) a $996.7 million full cost pool ceiling test write-down during the prior-year Predecessor period as a resultperiod. Additional drivers of the declinecomparative operating results between full-year 2021 and 2020 include the following:

•Oil and natural gas revenues increased by $466.7 million (67%), with 72% of the increase due to higher commodity prices, slightly offset by lower sales volumes;
•Commodity derivative expense increased by $393.1 million consisting of a $379.7 million decrease in NYMEX oil prices (seecash receipts upon contract settlements ($277.2 million in payments during 2021 compared to $102.5 million in receipts upon settlements during 2020) and a $13.4 million increase in noncash fair value losses between periods;
•Depletion, Depreciation,depreciation, and Amortization (“DD&A”) – Full Cost Pool Ceiling Test below);amortization expense decreased $83.8 million primarily due to lower depletable costs due to the step down in book value resulting from fresh start accounting as of September 18, 2020 and an accelerated depreciation charge of $39.2 million during 2020 related to unevaluated properties; and
•Reorganization items,Lease operating expenses increased by $73.0 million (21%), primarily due to an increase of $25.9 million related to the March 2021 Wind River Basin acquisition and higher expenses across nearly all lease operating expense categories, largely driven by higher commodity prices and increased workover activity.

March 2021 Acquisition of Wyoming CO2 EOR Fields. On March 3, 2021, we acquired a nearly 100% working interest (approximately 83% net resultedrevenue interest) in an $850.0the Big Sand Draw and Beaver Creek EOR fields (collectively “Wind River Basin”) located in Wyoming, including surface facilities and a 46-mile CO2 transportation pipeline to the acquired fields. The acquisition purchase price was $10.9 million chargecash (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. As of December 31, 2021, the contingent consideration was recorded on our Consolidated Balance Sheets at its fair value of $7.7 million, a $2.4 million increase from the March 2021 acquisition date fair value. This $2.4 million increase at December 31, 2021 was the result of higher NYMEX WTI oil prices and was recorded to “Other expenses” in our Consolidated Statements of Operations. Wind River Basin sales averaged approximately 2,879 BOE/d during the Predecessor period, due to fresh start accounting adjustmentsfourth quarter of $1.9 billion to decrease2021 and the carrying valueCO2 flood utilizes 100% industrial-sourced CO2.

Cedar Creek Anticline CO2 Pipeline Completion. During 2021, we spent $123.4 million, approximately 49% of our assets, partially offset by a gaindevelopment capital expenditures, on settlementsCedar Creek Anticline (“CCA”) pipeline construction and tertiary development. We completed the 105-mile CO2 pipeline from Bell Creek to CCA, along with an additional pipeline lateral that will service the initial EOR development and additional future phases. First CO2 injections in CCA’s Red River formation commenced in early February 2022, and tertiary oil production response is anticipated in the second half of liabilities subject to compromise of $1.0 billion, primarily representing the net impact of approximately $2.1 billion of debt elimination offset by the new equity value in Denbury.2023.


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Divestiture of Hartzog Draw Deep Mineral Rights. On a comparative basis,June 30, 2021, we recognized net income of $217.0 million, or $0.45 per diluted share, during 2019. The following reflects some of the primary drivers for our change in operating results between full-year 2020 and 2019:

•Oil and natural gas revenues decreased by $518.8 million (43%), with 31% of the decrease due to lower commodity prices and 12% due to lower production;
•Lease operating expenses decreased by $125.7 million (26%), primarily due to cost reduction measures in light of the low oil price environment, as well asclosed the sale of a portionundeveloped, unconventional deep mineral rights in Hartzog Draw Field in Wyoming. The cash proceeds of $18 million reduced our working interest in four southeast Texas oil fields (see March 2020 Sale of Working Interests in Certain Texas Fields below) and Delhi insurance reimbursements (see Delhi Insurance Recovery below);
•Commodity derivative expense decreased by $110.2 million ($40.1 million of income during 2020 compared to $70.1 million of expense during 2019), resulting from a $78.9 million increase in cash receipts upon settlement and an incremental $31.3 million decrease in noncash fair value losses between periods;
•A noncashfull cost pool; therefore, no gain on debt extinguishment of $156.0 million during 2019 compared to $19.0 million during 2020; and
•Reductions across numerous expense categories including $33.6 million in taxes other than income and $15.0 million in general and administrative expenses.

March 2021 Acquisition of Wyoming CO2 EOR Fields. In December 2020, we entered into an agreement to acquire a nearly 100% working interest (approximately 83% net revenue interest) in the Big Sand Draw and Beaver Creek oil fields located in Wyoming for $12 million cash, including surface facilities and a 46-mile CO2 transportation pipeline to the acquired fields. The agreement provides for us to make two contingent cash payments of $4 million each in 2021 and 2022 if NYMEX WTI oil prices average at least $50 per Bbl during the respective calendar years. The acquisition closed on March 3, 2021.

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

Delhi Insurance Recovery. During 2020, we received insurance reimbursements totaling $16.1 million ($15.4 million net to Denbury’s interest) for previously-incurred well control costs, cleanup costs, and damages associated with a 2013 incident at Delhi Field. Denbury’s portion of the insurance recovery of $15.4 millionor loss was recorded as a reduction to lease operating expenses.on the transaction, and the sale had no impact on our production or reserves.

Houston Area Land Sales. As part of ourSales. marketing non-producing surface acreage primarily aroundDuring the Houston area for sale,second half of 2021, we completed the salesales of a portion of thiscertain non-producing surface acreage for grossin the Houston area. We received cash proceeds of approximately $29$15.2 million during 2020. To date, we have closed acreagefrom the sales for total gross proceedsand recognized a $10.3 million gain to “Other income” in our Consolidated Statements of approximately $49 million, and we currently have an additional $4 million under contract which is expected to close in the third quarter of 2021.Operations.

March 2020 SaleAdvancing 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 avoid 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 Working Interestsindustrial 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 Certain Texas Fields.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 year ended December 31, 2021, approximately 33% of the CO2 On March 4, 2020,utilized in our oil and gas operations was industrial-sourced CO2, and we sold halfanticipate this percentage could increase in the future as supportive U.S. government policy and public pressure on industrial CO2 emitters will provide strong incentives for these entities to capture their CO2 emissions.

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 have executed several term sheets for the future transportation and sequestration of CO2. While EOR is the only CCUS operation reflected in our nearly 100% working interest positionscurrent and 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 four southeast Texas oil fields (consisting of Webster, Thompson, Manvelour EOR operations. As the enhanced Section 45Q regulations are relatively new, it will likely take several years to construct new capture facilities and East Hastings) for $40 million net cash and a carried interest in ten wellsdedicated storage sites to be drilled by the purchaser (the “Gulf Coast Working Interests Sale”).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.

CAPITAL RESOURCES AND LIQUIDITY

Overview. Our primary sources of capital and liquidity are our cash flows from operations and availability of borrowing capacity under our Successorsenior secured bank credit facility. Our most significant cash outlays relate to our development capital expenditures, and current periodin 2021 the repayment of $70.0 million of pipeline financing obligations associated with the NEJD pipeline system. At December 31, 2021, we had $35.0 million of borrowings outstanding on our $575 million senior secured bank credit facility, leaving us with $528.1 million of borrowing capacity after consideration of $11.9 million of letters of credit outstanding. Our borrowing base availability, coupled with unrestricted cash of $3.7 million provides us total liquidity of $531.8 million as of December 31, 2021, which is more than adequate to meet our anticipated near-term operating expenses. The most significant changes during 2020 to ourand capital resources and liquidity resulted from our financial restructuring and emergence from Chapter 11 reorganization in which we eliminated approximately $2.1 billion of bond debt and reduced ongoing annual interest expense by approximately $165 million, significantly improving our cash flow on a go-forward basis.needs.

As further discussed below, based on oil price futures as of the middle of February 2022, we currently anticipate funding all of our 2022 capital budget from projected operating cash flow while also generating excess cash flow. The ultimate level of excess cash we may generate will be highly dependent on oil prices and many other factors, but we currently plan to utilize our excess cash to build cash for anticipated CCUS capital needs over the next several years, as we believe that the potential exists for our CCUS business to grow to a significant scale. During 2022, we will continue to evaluate anticipated capital needs for our CCUS business in relation to our excess cash flow, and therefore, at the current time, our first priority is to utilize and build cash for CCUS growth rather than returning capital to stockholders.
2020
2021 Cash Sources and Uses. NYMEX oil prices decreased significantly during 2020, directly reducing our operating cash flow; however, we took significant actions to reduce capital expenditures and operating expenses in order to adjust our spending levels such that our spending for ongoing operations was below our cash flow generated from operations. During 2020,2021, we generated cash flows from operations of $153.7$317.2 million, while incurring development capital expenditures of $95.2$252.2 million and capitalized interest of $4.6 million, resulting in approximately $55 million of cash flow in excess of capital expenditures (excluding working capital changes). In addition, we paid $70.0 million to Genesis Energy, L.P. in accordance with the October 2020 restructuring of the financing arrangements of our NEJD CO2 pipeline system and acquired our Wind River Basin properties in Wyoming for $10.9 million during 2021. These supplemental cash outflows were partially offset with $18 million of proceeds from the sale of undeveloped, unconventional deep mineral

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capitalized interest of $24.1 million, resultingrights at Hartzog Draw Field in approximately $50 million of cash flow in excess of capital expenditures (excluding working capital changes, but including $46.4 million of interest payments treated as repayment of debt in our financial statements). During 2020, we further supplemented our cash flowJune 2021 and liquidity with proceeds from asset sales, including $40$15.2 million of proceeds from our March 2020 saleduring the second half of working interests in four southeast Texas fields and by $29 million of proceeds2021 from sales of non-producing surface acreage primarily around the Houston area. These supplemental cash inflowsAverage outstanding borrowings under our bank credit facility during 2021 were offset with a similar amount of debt reduction and repurchase of the NEJD and Free State CO2 pipelines from Genesis.$85.0 million.

Capital Expenditure Summary.  Our 2021 capital expenditures for CCA tertiary development and pipeline construction totaled $123.4 million, or 49% of our 2021 development capital expenditures. The following table reflects incurred capital expenditures (including accrued capital) for the years ended December 31, 2021, 2020 2019 and 2018:2019:
Year Ended December 31,
In thousands202020192018
Capital expenditures by project   
Tertiary oil fields$26,402 $93,331 $142,560 
Non-tertiary fields25,666 71,014 104,811 
Capitalized internal costs(1)
32,956 46,031 46,599 
Oil and natural gas capital expenditures85,024 210,376 293,970 
CO2 pipelines, sources and other
10,144 26,545 28,700 
Capital expenditures, before acquisitions and capitalized interest95,168 236,921 322,670 
Acquisitions of oil and natural gas properties176 284 541 
Capital expenditures, before capitalized interest95,344 237,205 323,211 
Capitalized interest24,146 36,671 37,079 
Capital expenditures, total$119,490 $273,876 $360,290 
Year Ended December 31,
In thousands202120202019
Capital expenditure summary(1)
   
CCA EOR field expenditures$35,754 $810 $2,424 
CCA CO2 pipelines
87,688 10,942 23,843 
CCA tertiary development123,442 11,752 26,267 
Non-CCA tertiary and non-tertiary fields97,085 49,800 161,921 
CO2 sources and other CO2 pipelines
1,657 660 2,702 
Development excluding CCA tertiary98,742 50,460 164,623 
Capitalized internal costs(2)
29,987 32,956 46,031 
Development capital expenditures252,171 95,168 236,921 
Acquisitions of oil and natural gas properties(3)
10,979 176 284 
Capital expenditures, before capitalized interest263,150 95,344 237,205 
Capitalized interest4,585 24,146 36,671 
Capital expenditures, total$267,735 $119,490 $273,876 

(1)Capital expenditures in this summary are presented on an as-incurred basis (including accruals), and are $36.6 million higher than the capital expenditures in the Consolidated Statements of Cash Flows which are presented on a cash paid basis.
(2)Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.
(3)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 U.S. supply chain constraints, together with tight labor markets, could increase our costs in 2022 and 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. We have increased our 2022 operational budget for anticipated inflation and have taken steps to build our on-hand supply stock for items frequently used in our operations to address possible supply chain disruptions.

2022 Plans and Capital Budget. Oil prices continued to strengthen during the first two months of 2021, reaching the low-$60s per barrel in mid-February. Considering the current oil price environment and strategic importance of the CO2 flood at Cedar Creek Anticline (“CCA”), we plan to move forward in 2021 with the development of this significant long-term project. We expect to allocate approximately $150 million of capital in 2021 to this CCA development, consisting of approximately $100 million dedicated to the 105-mile extension of the Greencore CO2 pipeline from Bell Creek to CCA, with the remainder dedicated to facilities, well work and field development at CCA. In total, we estimate that our total oil and natural gas development capital expenditures in 2021,2022, excluding acquisitions and capitalized interest, will be in a range of $250$290 million to $270$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. This compares to total oil and natural gas development expenditures of $252.2 million in 2021, of which $123.4 million was for CCA’s new EOR development and $128.8 million for our other tertiary and non-tertiary development, capitalized internal costs, and CO2 sources and other CO2 pipelines. We continue to work on the timing of development plans at CCA and have increased our 2022 planned activities over our previously anticipated level to now include a CO2 pilot in the Pennel area of CCA.

In addition to our budgeted oil and natural gas capital investments, we anticipate spending approximately $50 million in connection with our CCUS strategic priorities, potentially raising our 2022 total estimated capital range to between $340 million and $370 million. Based on current oil prices andas of the middle of February 2022, the Company’s hedge positions and other projections, we estimate that our 20212022 cash flows from operations willshould exceed our budgeted level of planned development capital expenditures. In addition to our 2021 planned development capital, we acquired the Big Sand Draw and Beaver Creek oil fields in Wyoming in early March 2021 for a cash purchase price of $12 million before closing adjustments. Also, we plan to settle the remaining debt obligation to Genesis for the NEJD CO2 pipeline, with $70 million in payments to be made over the course of 2021. We expect to fulfill these remaining obligations from cash flow and borrowings under our bank credit facility. At December 31, 2020, we had $482 million of availability under our bank credit facility, which we believe is more than adequate to cover any near-term liquidity needs. To supplement our liquidity, we may seek other sources of funding for all or a portion of the CCA CO2 Pipeline expenditure.

The 2021 capital budget, excluding capitalized interest and acquisitions, provides for approximate spending of $260 million at the midpoint of our guidance as follows:

•$100 million for the 105-mile extension of the Greencore CO2 pipeline to CCA
•$50 million for CCA tertiary well work, facilities, and field development;
•$50 million allocated for other tertiary oil field development;
•$35 million allocated for non-tertiary oil field development; and
•$25 million for other capital items such as capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs.


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Also, at December 31, 2021, we had $528.1 million of availability under our bank credit facility, which we believe is more than adequate to cover any near-term liquidity needs.

Based on our capital spending plans, we currently anticipate 20212022 average daily production towill be between 47,50046,000 BOE/d and 51,50049,000 BOE/d, including the Big Sand Draw and Beaver Creek working interests acquisition expected to close in early March 2021.d. Our anticipated 20212022 production level compares to 20202021 average continuing production of 50,95748,770 BOE/d, after reduction for 2020 property divestitures.d.

New Senior Secured Bank Credit Agreement. In connection with our emergence from Chapter 11 proceedings on September 18, 2020, we entered into a bank credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the “Bank Credit Agreement”). The Bank Credit Agreement is a senior secured revolving credit facility with an initial borrowing base and lender commitments of $575 million, under which we had $70.0$35.0 million borrowed as of December 31, 2020,2021, leaving us with $482.0$528.1 million of availability after consideration of $23.0$11.9 million of outstanding letters of credit. 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 May 1, 2021.2022. The borrowing base is adjusted at the lenders’ discretion and is based, in part, upon external factors over which we have no control. The borrowing base is subject to a reduction by twenty-five percent (25%) of the principal amount of any unsecured or subordinated debt issued or incurred. The borrowing base may also be reduced if we sell borrowing base properties and/or cancel commodity derivative positions with an aggregate value in excess of 5% of the then-effective borrowing base between redeterminations. The Bank Credit Agreement matures on January 30, 2024.

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

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

•A Consolidated Total Debt to Consolidated EBITDAX covenant (as defined in the 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 at least 1.0 times.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 December 31, 2020,2021, our ratio of consolidated total debt to consolidated EBITDAX was 0.450.10 to 1.0 (with a maximum permitted ratio of 3.5 to 1.0) and our current ratio was 3.732.58 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 February 24, 2021,23, 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, which is filed as an exhibit to our Form 8-K Report filed with the SEC on September 18, 2020.

Commitments, Obligations and Off-Balance Sheet Arrangements. As of December 31, 2020,2021, we had a total of $23.0$11.9 million of letters of credit outstanding under our senior secured bank credit facility. Additionally, we have obligations for 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. These obligationsCertain of these capital spending plans are further described in 20212022 Plans and Capital Budget above. 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. For a further discussion of our future development costs, see Supplemental Oil and Natural Gas Disclosures (Unaudited) to the consolidated financial statements.


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Our periodic obligations include operational expenses that we anticipate being paid out of our cash flow from sale of production, plus the capital expenditures detailed above. In addition to these periodic expenditures, we have various future cash

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commitments under contracts in place as of December 31, 2020.2021. The most material of these commitments to be settled within the next 12 months include:

•Pipeline financing obligations of $70.0Approximately $46 million associated with the NEJD pipeline system, which is to be repaid in four equal payments during 2021, with the first payment made on January 31, 2021;
•Contractsunder contracts for the purchase of CO2 captured from industrial sources that is used in our tertiary recovery activities and for processing fees related to our overriding royalty interest in the CO2 at LaBarge Field, both of which are used in our tertiary recovery activities, assuming a $70 per Bbl NYMEX oil price. The commitment level declines in 2023 and again in 2028 due to the expiration of certain industrial-CO2 purchase commitments (see Note 14, Commitments and Contingencies, to the consolidated financial statements for further discussion); and
•OperatingApproximately $6 million in operating lease obligations (see Note 5, Leases, to the consolidated financial statements for further discussion).

In addition to these commitments, we have recurring expenditures for such things as accounting, engineering and legal fees; software maintenance; subscriptions; and other overhead-type items. Normally these expenditures do not change materially on an aggregate basis from year to year and are part of our general and administrative expenses. Most of these recurring expenditures could be quickly canceled with regard to any specific vendor, even though the expense itself may be required for our ongoing normal operations. Other commitments include certain transportation agreements and well-related costs. Our longer-term commitments that extend beyond the next 12 months include the following:

•Obligations and periodic interest payments under our senior secured bank credit facility, which matures on January 30, 2024, and of which $70.0$35.0 million was outstanding as of December 31, 2020;2021; and
•Asset retirement obligations related to future costs associated with plugging and abandoning our oil, natural gas and CO2 wells, removing equipment and facilities from leased acreage, and returning land to its original condition (see Note 6, Asset Retirement Obligations, to the consolidated financial statements).

As detailed throughout this report, the largest determinant of our cash flow is the oil price we receive. Oil prices and cash flow are highly impacted by worldwide oil supply and fluctuations in demand due to economic activity, which volatility we attempt to offset to some extent with our hedging program. The variability of proceeds from the sale of our production is partially offset to some extent by similar directional variances in certain expenses, including a portion of our lease operating expenses and production taxes, as these expenses experiencecorrelate to some variabilitydegree with changes in oil prices. Because revenues and expenses do not rise and fall at the same rate, the continuing volatility of the oil market in recent years often results in variances when comparing period-to-period revenues and expense items. Additionally, events in world oil markets can affect cash flow, which we attempt to offset to some extent with our hedging program.

FINANCIAL OVERVIEW OF TERTIARY OPERATIONS

As discussed in Item 1, Business and Properties – Oil and Natural Gas Operations – Enhanced Oil Recovery Overview, ourOur tertiary operations represent a significant portion of our overall operations and have become our primary strategic focus.operations. The economics of a tertiary field and the related impact on our financial statements differ from a conventional oil and gas play and are explained further below.

While it is difficult to accurately forecast future production, we believe our tertiary recovery operations provide significant long-term production growth potential at reasonable return metrics, with relatively low risk, assuming crude oil prices are at levels that support the development of those projects. We have been developing tertiary oil properties for over 2122 years, and the financial impact of such operations is reflected in our historical financial statements. The summary below highlights our observations regarding how tertiary operations have impacted our financial statements.

Finding and Development Costs. We currently expect finding and development costs (including future development and abandonment costs but excluding CO2 pipeline infrastructure capital expenditures) over the life of each field to be competitive with the industry average costs for other oil properties. See the definition of finding and development costs in the Glossary and Selected Abbreviations.

Timing of Capital Costs.  When initiating a new tertiary flood, there generally is a delay between the initial capital expenditures and the resulting production increases.  We must build facilities, and often a CO2 pipeline to the field, before CO2 flooding can commence, and it usually takes six to twelve months before the field responds to the injection of CO2 (i.e., oil production commences). For certain fields such as those in CCA, we estimate it could take up to 18 months or longer for a tertiary production response to occur.  Further, we may spend significant amounts of capital before we can recognize any proved reserves from fields we flood and, even after a field has proved reserves, significant amounts of additional capital will usually be required to fully develop the field.


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from fields we flood and, even after a field has proved reserves, significant amounts of additional capital will usually be required to fully develop the field.

Recognition of Proved Reserves. In order to recognize proved tertiary oil reserves, we must either demonstrate production resulting from the tertiary process or the field must be analogous to an existing tertiary flood.  The magnitude of proved reserves that we can book in any given year will depend on our progress with new floods, the timing of the production response from new floods and the performance of our existing floods.

Production Rates. The production rate at a tertiary flood can vary from quarter to quarter, as a tertiary field’s production may increase rapidly when wells respond to the CO2, plateau temporarily, and then resume growth as additional areas of the field are developed.  During a tertiary flood life cycle, facility capacity is increased from time to time, which occasionally requires temporary shutdowns during installation, thereby causing temporary declines in production.  We also find it difficult to precisely predict when any given well will respond to the injected CO2, as the CO2 seldom travels through the rock consistently due to heterogeneity in the oil-bearing formations.  With the lower level of oil prices over the past several years, our pace of development has generally slowed, thereby reducing our Company-wide production rates.  We find all of these fluctuations to be normal and generally expect oil production at a tertiary field to increase over time until the field is fully developed, albeit sometimes in inconsistent patterns.  

Operating Costs. Tertiary projects may be more expensive to operate than traditional industry operations because of the cost of injecting and recycling the CO2 (primarily due to the cost of the CO2 and the significant energy requirements to re-compress the CO2 back into a near-liquid state for re-injection purposes).  The costs of our CO2 and the electricity required to recycle and inject this CO2 comprise over half of our typical tertiary operating expenses.  Since these costs vary along with commodity and commercial electricity prices, they are highly variable and will increase in a high-commodity-price environment and decrease in a low-price environment.  The cost of purchasing and/or producing CO2 for use in tertiary floods is allocated to our tertiary oil fields and recorded as lease operating expenses (following the commencement of tertiary oil production) at the time the CO2 is injected. These costs have historically represented approximately 20% to 25% of the total operating costs for our tertiary operations.  Since we expense all of the operating costs to produce and inject our CO2 (following the commencement of tertiary oil production), operating costs per barrel for a new flood will be higher at the inception of CO2 injection projects because of minimal related oil production at that time.

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RESULTS OF OPERATIONS

Financial and Operating Results Tables

Certain of our financial results for our Successor and Predecessor periods are included in the following table.
SuccessorPredecessorSuccessorPredecessor
Period from
Sept. 19, 2020 through
Dec. 31, 2020		Period from
Jan. 1, 2020 through
Sept. 18, 2020		Year Ended December 31, Year Ended
Dec. 31, 2021		Period from
Sept. 19, 2020 through
Dec. 31, 2020		Period from
Jan. 1, 2020 through
Sept. 18, 2020		Year Ended
Dec. 31, 2019
In thousands, except per-share dataIn thousands, except per-share data20192018In thousands, except per-share data
Financial resultsFinancial results   Financial results   
Net income (loss)(1)
Net income (loss)(1)
$(50,658)$(1,432,578)$216,959 $322,698 
Net income (loss)(1)
$56,002 $(50,658)$(1,432,578)$216,959 
Net income (loss) per common share – basic(1)
Net income (loss) per common share – basic(1)
(1.01)(2.89)0.47 0.75 
Net income (loss) per common share – basic(1)
1.10 (1.01)(2.89)0.47 
Net income (loss) per common share – diluted(1)
Net income (loss) per common share – diluted(1)
(1.01)(2.89)0.45 0.71 
Net income (loss) per common share – diluted(1)
1.04 (1.01)(2.89)0.45 
Net cash provided by operating activitiesNet cash provided by operating activities40,326 113,408 494,143 529,685 Net cash provided by operating activities317,158 40,326 113,408 494,143 

(1)Includes a pre-tax full cost pool ceiling test write-down of our oil and natural gas properties of $14.4 million for the year ended December 31, 2021, $1.0 million for the Successor period September 19, 2020 through December 31, 2020, and $996.7 million for the Predecessor period January 1, 2020 through September 18, 2020. In addition, the Predecessor period January 1, 2020 through September 18, 2020 includes reorganization adjustments, net totaling $850.0 million.






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Certain of our financial and operating results and statistics for each of the last three years are included in the following table.
Year Ended December 31, Year Ended December 31,
In thousands, except per-share and unit data202020192018
Average daily production volumes  
In thousands, except per-unit dataIn thousands, except per-unit data202120202019
Average daily sales volumesAverage daily sales volumes  
Bbls/dBbls/d49,828 56,672 58,532 Bbls/d47,281 49,828 56,672 
Mcf/dMcf/d7,938 9,246 10,854 Mcf/d8,933 7,938 9,246 
BOE/dBOE/d51,151 58,213 60,341 BOE/d48,770 51,151 58,213 
Operating revenues   
Oil and natural gas salesOil and natural gas sales   
Oil salesOil sales$689,020 $1,205,083 $1,412,358 Oil sales$1,148,022 $689,020 $1,205,083 
Natural gas salesNatural gas sales4,189 6,937 10,231 Natural gas sales11,933 4,189 6,937 
Total oil and natural gas salesTotal oil and natural gas sales$693,209 $1,212,020 $1,422,589 Total oil and natural gas sales$1,159,955 $693,209 $1,212,020 
Commodity derivative contracts(1)
Commodity derivative contracts(1)
   
Commodity derivative contracts(1)
   
Receipt (payment) on settlements of commodity derivativesReceipt (payment) on settlements of commodity derivatives$102,485 $23,606 $(175,248)Receipt (payment) on settlements of commodity derivatives$(277,240)$102,485 $23,606 
Noncash fair value gains (losses) on commodity derivatives(2)
(62,355)(93,684)196,335 
Noncash fair value losses on commodity derivativesNoncash fair value losses on commodity derivatives(75,744)(62,355)(93,684)
Commodity derivatives income (expense)Commodity derivatives income (expense)$40,130 $(70,078)$21,087 Commodity derivatives income (expense)$(352,984)$40,130 $(70,078)
Unit prices – excluding impact of derivative settlementsUnit prices – excluding impact of derivative settlements   Unit prices – excluding impact of derivative settlements   
Oil price per BblOil price per Bbl$37.78 $58.26 $66.11 Oil price per Bbl$66.52 $37.78 $58.26 
Natural gas price per McfNatural gas price per Mcf1.44 2.06 2.58 Natural gas price per Mcf3.66 1.44 2.06 
Unit prices – including impact of derivative settlements(1)
Unit prices – including impact of derivative settlements(1)
  
Unit prices – including impact of derivative settlements(1)
  
Oil price per BblOil price per Bbl$43.40 $59.40 $57.91 Oil price per Bbl$50.46 $43.40 $59.40 
Natural gas price per McfNatural gas price per Mcf1.44 2.06 2.58 Natural gas price per Mcf3.66 1.44 2.06 
Oil and natural gas operating expensesOil and natural gas operating expenses  Oil and natural gas operating expenses  
Lease operating expensesLease operating expenses$351,505 $477,220 $489,720 Lease operating expenses$424,550 $351,505 $477,220 
Transportation and marketing expensesTransportation and marketing expenses37,759 41,810 43,942 Transportation and marketing expenses28,817 37,759 41,810 
Production and ad valorem taxesProduction and ad valorem taxes53,708 86,820 96,589 Production and ad valorem taxes88,468 53,708 86,820 
Oil and natural gas operating revenues and expenses per BOEOil and natural gas operating revenues and expenses per BOE  Oil and natural gas operating revenues and expenses per BOE  
Oil and natural gas revenuesOil and natural gas revenues$37.03 $57.04 $64.59 Oil and natural gas revenues$65.16 $37.03 $57.04 
Lease operating expensesLease operating expenses18.78 22.46 22.24 Lease operating expenses23.85 18.78 22.46 
Transportation and marketing expensesTransportation and marketing expenses2.02 1.97 2.00 Transportation and marketing expenses1.62 2.02 1.97 
Production and ad valorem taxesProduction and ad valorem taxes2.87 4.09 4.39 Production and ad valorem taxes4.97 2.87 4.09 
CO2 sources – revenues and expenses
CO2 sources – revenues and expenses
  
CO2 sources – revenues and expenses
  
CO2 sales and transportation fees
CO2 sales and transportation fees
$30,468 $34,142 $31,145 
CO2 sales and transportation fees
$44,175 $30,468 $34,142 
CO2 operating and discovery expenses
CO2 operating and discovery expenses
(4,568)(2,922)(2,816)
CO2 operating and discovery expenses
(6,678)(4,568)(2,922)
CO2 revenue and expenses, net
CO2 revenue and expenses, net
$25,900 $31,220 $28,329 
CO2 revenue and expenses, net
$37,497 $25,900 $31,220 

(1)See also Commodity Derivative Contracts below and Market Risk Management for information concerning our commodity derivative transactions.
(2)Noncash fair value gains (losses) on commodity derivatives is a non-GAAP measure and is different from “Commodity derivatives expense (income)” in the Consolidated Statements of Operations in that the noncash fair value gains (losses) on commodity derivatives represent only the net changes between periods of the fair market values of commodity derivative positions, and exclude the impact of settlements on commodity derivatives during the period, which were receipts on settlements of $102.5 million and $23.6 million for the years ended December 31, 2020 and 2019, respectively, compared to payments on settlements of $175.2 million for the year ended December 31, 2018. We believe that noncash fair value gains (losses) on commodity derivatives is a useful supplemental disclosure to “Commodity derivatives expense (income)” in order to differentiate noncash fair market value adjustments from receipts or payments upon settlements on commodity derivatives during the period. This supplemental disclosure is widely used within the industry and by securities analysts, banks and credit rating agencies in calculating EBITDA and in adjusting net income (loss) to present those measures on a comparative basis across companies, as well as to assess compliance with certain debt covenants. Noncash fair value gains (losses) on commodity derivatives is not a measure of financial or operating performance under GAAP, nor should it be

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considered in isolation or as a substitute for “Commodity derivatives expense (income)” in the Consolidated Statements of Operations. See also the Glossary and Selected Abbreviations for the definition of noncash fair value gains (losses) on commodity derivatives.

ProductionSales Volumes

Average daily productionsales volumes by area for 2021, 2020 2019 and 2018,2019, and for each of the quarters of 2020,2021, is shown below:
Average Daily Production (BOE/d) Average Daily Sales Volumes (BOE/d)
2020 QuartersYear Ended December 31, 2021 QuartersYear Ended December 31,
Operating AreaOperating AreaFirst
Quarter		Second
Quarter		Third
Quarter		Fourth
Quarter		202020192018Operating AreaFirst
Quarter		Second
Quarter		Third
Quarter		Fourth
Quarter		202120202019
Tertiary oil production
Tertiary oil sales volumesTertiary oil sales volumes
Gulf Coast regionGulf Coast regionGulf Coast region
DelhiDelhi3,813 3,529 3,208 3,132 3,419 4,324 4,368 Delhi2,925 2,931 2,859 2,731 2,861 3,419 4,324 
HastingsHastings5,232 4,722 4,473 4,598 4,755 5,403 5,596 Hastings4,226 4,487 4,343 4,212 4,317 4,755 5,403 
HeidelbergHeidelberg4,371 4,366 4,256 4,198 4,297 4,195 4,355 Heidelberg4,054 3,942 3,895 3,797 3,921 4,297 4,195 
Oyster BayouOyster Bayou3,999 3,871 3,526 3,880 3,818 4,345 4,843 Oyster Bayou3,554 3,791 3,942 4,039 3,833 3,818 4,345 
TinsleyTinsley4,355 3,788 4,042 3,654 3,959 4,608 5,530 Tinsley3,424 3,455 3,390 3,353 3,405 3,959 4,608 
West Yellow Creek775 695 588 614 668 640 205 
Mature properties(1)
6,386 5,249 5,683 5,718 5,759 6,422 6,702 
Other(1)
Other(1)
6,098 6,074 5,907 5,801 5,969 6,427 7,062 
Total Gulf Coast regionTotal Gulf Coast region28,931 26,220 25,776 25,794 26,675 29,937 31,599 Total Gulf Coast region24,281 24,680 24,336 23,933 24,306 26,675 29,937 
Rocky Mountain regionRocky Mountain regionRocky Mountain region
Bell CreekBell Creek5,731 5,715 5,551 5,079 5,518 5,228 4,113 Bell Creek4,614 4,394 4,330 4,331 4,416 5,518 5,228 
Salt Creek2,149 1,386 2,167 2,007 1,928 2,143 2,109 
Grieve50 7 — — 14 53 7 
Other(2)
Other(2)
2,573 4,378 4,703 4,551 4,059 1,942 2,196 
Total Rocky Mountain regionTotal Rocky Mountain region7,930 7,108 7,718 7,086 7,460 7,424 6,229 Total Rocky Mountain region7,187 8,772 9,033 8,882 8,475 7,460 7,424 
Total tertiary oil production36,861 33,328 33,494 32,880 34,135 37,361 37,828 
Non-tertiary oil and gas production
Total tertiary oil sales volumesTotal tertiary oil sales volumes31,468 33,452 33,369 32,815 32,781 34,135 37,361 
Non-tertiary oil and gas sales volumesNon-tertiary oil and gas sales volumes
Gulf Coast regionGulf Coast regionGulf Coast region
Mississippi748 713 629 655 686 970 960 
Texas3,419 3,087 3,095 2,860 3,115 3,225 3,418 
Other6 5 4 8 6 6 13 
Total Gulf Coast regionTotal Gulf Coast region4,173 3,805 3,728 3,523 3,807 4,201 4,391 Total Gulf Coast region3,621 3,415 3,763 3,929 3,683 3,807 4,201 
Rocky Mountain regionRocky Mountain regionRocky Mountain region
Cedar Creek AnticlineCedar Creek Anticline13,046 11,988 11,485 11,433 11,985 14,090 14,837 Cedar Creek Anticline11,150 10,918 11,182 10,784 11,008 11,985 14,090 
Other1,105 1,069 979 969 1,030 1,262 1,431 
Other(3)
Other(3)
1,118 1,348 1,368 1,354 1,298 1,030 1,262 
Total Rocky Mountain regionTotal Rocky Mountain region14,151 13,057 12,464 12,402 13,015 15,352 16,268 Total Rocky Mountain region12,268 12,266 12,550 12,138 12,306 13,015 15,352 
Total non-tertiary production18,324 16,862 16,192 15,925 16,822 19,553 20,659 
Total continuing production55,185 50,190 49,686 48,805 50,957 56,914 58,487 
Total non-tertiary sales volumesTotal non-tertiary sales volumes15,889 15,681 16,313 16,067 15,989 16,822 19,553 
Total continuing sales volumesTotal continuing sales volumes47,357 49,133 49,682 48,882 48,770 50,957 56,914 
Property salesProperty salesProperty sales
Property divestitures(2)
780 — — — 194 1,299 1,854 
Total production55,965 50,190 49,686 48,805 51,151 58,213 60,341 
Gulf Coast Working Interests Sale(4)
Gulf Coast Working Interests Sale(4)
— — — — — 194 1,299 
Total sales volumesTotal sales volumes47,357 49,133 49,682 48,882 48,770 51,151 58,213 
(1)Mature properties includeIncludes Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb, Soso and SosoWest Yellow Creek fields.
(2)Includes tertiary sales volumes related to our working interest positions in the Wind River Basin properties acquired on March 3, 2021, as well as Salt Creek and Grieve fields.
(3)Includes non-tertiary productionsales volumes from Wind River Basin, as well as Hartzog Draw and Bell Creek fields.
(4)Includes non-tertiary sales related to the March 2020 sale of 50% of our working interests in Webster, Thompson, Manvel, and East Hastings fields Citronelle Field sold(the “Gulf Coast Working Interests Sale”).

Total sales volumes during 2021 averaged 48,770 BOE/d, including 32,781 Bbls/d from tertiary properties and 15,989 BOE/d from non-tertiary properties. This sales volume represents a decrease of 2,187 BOE/d (4%) compared to 2020 continuing sales volumes which excludes sales volumes related to our Gulf Coast Working Interests Sale in July 2019March 2020. The year-over-year decline was primarily impacted by (1) the carryover impact of exceptionally low levels of capital investment over the past several years and Lockhart Crossing Field solddevelopment spending in 2021 below levels required to hold production flat (excluding new EOR development at CCA) and (2) decreases at CCA due to the net profits interest of a third quarter of 2018.party, whereby increased oil prices have resulted in increased profitability and thus, reducing sales volumes net to Denbury by approximately 360 BOE/d when

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Total Production

Total continuing production during 2020 averaged 50,957 BOE/d, including 34,135 Bbls/d from tertiary properties and 16,822 BOE/d from non-tertiary properties. Total continuing production excludes sold production related to our Gulf Coast Working Interests Sale in March 2020 and, for prior-year periods, excludes production from Citronelle Field sold in July 2019 and Lockhart Crossing Field sold in the third quarter of 2018. Our 2020 total continuing production level represents a decrease of 5,957 BOE/d (10%) compared to 2019 levels, most significantly attributable to production that was shut-in due to wells that were uneconomic to produce or repair based2020, partially offset by sales increases from our Wind River Basin enhanced oil recovery fields acquired on NYMEX oil prices during the second through fourth quarters of 2020. In addition to shut-in production, the year-over-year production decline included production declines at Delhi Field due to the lack of CO2 purchases between late-February and late-October 2020 as a result of the Delta-Tinsley CO2 pipeline being down for repair during that period, reduced levels of workovers and capital investment due to lower oil prices and higher than normal declines resulting from such. During the fourth quarter of 2020, the Delta-Tinsley pipeline was brought back into service, allowing CO2 purchases to resume at Delhi Field.March 3, 2021. Our production during 20202021 was 97% oil, consistent with 20192020 and 2018.2019.

Oil and Natural Gas Revenues

Oil and natural gas revenues increased 67% between 2020 and 2021 and decreased 43% between 2019 and 2020 and decreased 15% between 2018 and 2019.2020. The changes in our oil and natural gas revenues are due to changes in production quantities and realized commodity prices (excluding any impact of our commodity derivative contracts), as reflected in the following table:
Year Ended December 31,
2020 vs. 2019		Year Ended December 31,
2019 vs. 2018		Year Ended December 31,
2021 vs. 2020		Year Ended December 31,
2020 vs. 2019
In thousandsIn thousandsDecrease in RevenuesPercentage Decrease in RevenuesDecrease in RevenuesPercentage Decrease in RevenuesIn thousandsIncrease (Decrease) in RevenuesPercentage Increase (Decrease) in RevenuesDecrease in RevenuesPercentage Decrease in Revenues
Change in oil and natural gas revenues due to:Change in oil and natural gas revenues due to:    Change in oil and natural gas revenues due to:    
Decrease in productionDecrease in production$(144,118)(12)%$(50,163)(4)%Decrease in production$(34,069)(5)%$(144,118)(12)%
Decrease in commodity prices(374,693)(31)%(160,406)(11)%
Total decrease in oil and natural gas revenues$(518,811)(43)%$(210,569)(15)%
Increase (decrease) in commodity pricesIncrease (decrease) in commodity prices500,815 72 %(374,693)(31)%
Total increase (decrease) in oil and natural gas revenuesTotal increase (decrease) in oil and natural gas revenues$466,746 67 %$(518,811)(43)%

Excluding any impact of our commodity derivative contracts, our average net realized commodity prices and NYMEX differentials were as follows during 2021, 2020 2019 and 2018:2019:
Year Ended December 31, Year Ended December 31,
202020192018 202120202019
Average net realized pricesAverage net realized prices   Average net realized prices   
Oil price per BblOil price per Bbl$37.78 $58.26 $66.11 Oil price per Bbl$66.52 $37.78 $58.26 
Natural gas price per McfNatural gas price per Mcf1.44 2.06 2.58 Natural gas price per Mcf3.66 1.44 2.06 
Price per BOEPrice per BOE37.03 57.04 64.59 Price per BOE65.16 37.03 57.04 
Average NYMEX differentialsAverage NYMEX differentials   Average NYMEX differentials   
Gulf Coast regionGulf Coast regionGulf Coast region
Oil per BblOil per Bbl$(1.14)$3.30 $2.94 Oil per Bbl$(1.42)$(1.14)$3.30 
Natural gas per McfNatural gas per Mcf(0.14)(0.04)0.09 Natural gas per Mcf0.26 (0.14)(0.04)
Rocky Mountain region Rocky Mountain region Rocky Mountain region
Oil per BblOil per Bbl$(2.80)$(2.01)$(1.50)Oil per Bbl$(1.32)$(2.80)$(2.01)
Natural gas per McfNatural gas per Mcf(1.36)(0.96)(1.06)Natural gas per Mcf(0.27)(1.36)(0.96)
Total CompanyTotal CompanyTotal Company
Oil per BblOil per Bbl$(1.81)$1.23 $1.30 Oil per Bbl$(1.38)$(1.81)$1.23 
Natural gas per McfNatural gas per Mcf(0.69)(0.47)(0.49)Natural gas per Mcf(0.05)(0.69)(0.47)

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

•Gulf Coast Region. Our average NYMEX oil differential in the Gulf Coast region was a negative $1.42 per Bbl in 2021 and a negative $1.14 per Bbl during 2020. NYMEX WTI oil prices continued to strengthen during 2021; however, the pricing for our Gulf Coast grades weakened 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 $1.49 per Bbl on a trade-month basis during 2021, compared to a positive $2.12 per Bbl differential during 2020.

•Rocky Mountain Region. NYMEX oil differentials in the Rocky Mountain region averaged $1.32 per Bbl below NYMEX during 2021, compared to an average differential of $2.80 per Bbl below NYMEX in 2020. Differentials in the Rocky Mountain region can fluctuate with regional supply and demand trends and can fluctuate significantly on a

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•Gulf Coast Region. Our average NYMEX oil differential in the Gulf Coast region was a negative $1.14 per Bbl in 2020 and a positive $3.30 per Bbl during 2019. With the recent exception of 2020, our Gulf Coast region differentials have generally been positive to NYMEX due to historically higher prices received for Gulf Coast crudes, such as Light Louisiana Sweet crude oil, though storage constraints and weak demand caused these differentials to weaken significantly during 2020.

•Rocky Mountain Region. NYMEX oil differentials in the Rocky Mountain region averaged $2.80 per Bbl below NYMEX during 2020, compared to an average differential of $2.01 per Bbl below NYMEX in 2019. Differentials in the Rocky Mountain region can fluctuate significantly on a month-to-month basis due to weather, refinery or transportation issues, and Canadian and U.S. crude oil price index volatility.

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

CO2 Revenues and Expenses

We sell a portion of the CO2 producedwe produce from Jackson Dome to third-party industrial users at various contracted prices primarily under long-term contracts. We recognize the revenue received on these CO2 sales as “CO2 sales and transportation fees” with the corresponding costs recognized as “CO2 operating and discovery expenses” in our Consolidated Statements of Operations. CO2 sales and transportation fees were $44.2 million during 2021, compared to $30.5 million during the combined Predecessor and Successor periods included within the year ended December 31, 2020. The increase from the prior-year period was primarily due to new contracts and an increase in CO2 sales volumes to our industrial CO2 customers.

Oil Marketing Revenues and ExpensesPurchases

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

Commodity Derivative Contracts

We have routinely enterentered 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.  These contracts have historically consisted of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps.

The following table summarizestables summarize the impact our commodity derivative contracts had on our operating results for the periods indicated:
Successor
Three Months Ended
In thousandsMarch 31June 30September 30December 31Full Year
2021
Payment on settlements of commodity derivatives$(38,453)$(63,343)$(77,670)$(97,774)$(277,240)
Noncash fair value gains (losses) on commodity derivatives(1)
(77,290)(109,321)35,925 74,942 (75,744)
Commodity derivatives expense$(115,743)$(172,664)$(41,745)$(22,832)$(352,984)
PredecessorSuccessor
Three Months EndedPeriod from July 1
through
September 18		Period from September 19
through
September 30		Three Months Ended
In thousandsMarch 31June 30December 31Full Year
2020
Receipt on settlements of commodity derivatives$24,638 $45,629 $11,129 $6,660 $14,429 $102,485 
Noncash fair value gains (losses) on commodity derivatives(1)
122,133 (85,759)(15,738)(2,625)(80,366)(62,355)
Commodity derivatives income (expense)$146,771 $(40,130)$(4,609)$4,035 $(65,937)$40,130 

Predecessor
Three Months Ended
In thousandsMarch 31June 30September 30December 31Full Year
2019
Receipt (payment) on settlements of commodity derivatives$8,206 $(1,549)$8,057 $8,892 $23,606 
Noncash fair value gains (losses) on commodity derivatives(91,583)26,309 35,098 (63,508)(93,684)
Commodity derivatives income (expense)$(83,377)$24,760 $43,155 $(54,616)$(70,078)

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Predecessor
Three Months Ended
In thousandsMarch 31June 30September 30December 31Full Year
2019
Receipt (payment) on settlements of commodity derivatives$8,206 $(1,549)$8,057 $8,892 $23,606 
Noncash fair value gains (losses) on commodity derivatives(1)
(91,583)26,309 35,098 (63,508)(93,684)
Commodity derivatives income (expense)$(83,377)$24,760 $43,155 $(54,616)$(70,078)
2018
Payment on settlements of commodity derivatives$(33,357)$(54,770)$(61,611)$(25,510)$(175,248)
Noncash fair value gains (losses) on commodity derivatives(1)
(15,468)(41,429)17,034 236,198 196,335 
Commodity derivatives income (expense)$(48,825)$(96,199)$(44,577)$210,688 $21,087 

(1)Noncash fair value gains (losses) onChanges in our commodity derivatives is a non-GAAP measure. See Financialexpense during 2021 were primarily related to the expiration of commodity derivative contracts, new commodity derivative contracts entered into for future periods, and Operating Results Tables above for a discussionto the changes in oil futures prices between December 31, 2020 and December 31, 2021. The benefit of the reconciliationsignificant increase in our oil sales during 2021 over 2020 sales levels due to rising oil prices has been offset by payments on settlement of commodity derivative contracts, principally due to the strike prices of our fixed-price swaps which were entered into in late 2020 based on the hedging requirements we were obligated to meet under our bank credit facility entered into upon emergence from Chapter 11 restructuring. During 2021, we paid $277.2 million upon expiration of commodity derivative contracts, compared to cash receipts upon settlement of $102.5 million during 2020. The period-to-period changes reflect the very large fluctuation in oil prices between noncash fair value gains (losses) on commodity derivativesMarch 2020 ($30.45 per barrel), when worldwide financial markets were beginning to “Commodity derivatives expense (income)” inabsorb the Consolidated Statementspotential impact of Operations. See also the Glossarya global pandemic, and Selected AbbreviationsDecember 2021 ($71.69 per barrel) as prospects for the definition of noncash fair value gains (losses) on commodity derivatives.increased economic activity and oil demand improved.

In order to provide a level of price protection to a portion of our oil production, and to meet certain hedging requirements under our Successor senior secured bank credit facility, we have hedged a portion of our estimated oil production in 2021 and 2022through 2023 using both NYMEX fixed-price swaps and costless collars. Relative to 2021, our current hedge levels are significantly lower in 2022 and 2023, and we are hedged at more favorable prices and with a greater mix of collars, allowing us to benefit from additional upside in oil prices to a greater degree. We have no further hedging requirements under our bank credit facility. See Note 12, Commodity Derivative Contracts, to the consolidated financial statements for additional details of our outstanding commodity derivative contracts as of December 31, 2020,2021, and Market Risk Management below for additional discussion. In addition, the following table summarizes our oil derivative contracts as of February 24, 2021:23, 2022:
Jan. 2021Feb. 2021March 20212Q 20213Q 20214Q 20211H 20222H 20221H 20222H 20221H 20232H 2023
WTI NYMEXWTI NYMEXVolumes Hedged (Bbls/d)26,00027,00029,00029,00029,00029,0009,5001,000WTI NYMEXVolumes Hedged (Bbls/d)15,5009,5004,5002,000
Fixed-Price SwapsFixed-Price Swaps
Swap Price(1)
$42.54$42.96$43.86$43.86$43.86$43.86$44.24$50.13Fixed-Price SwapsWeighted Average Swap Price$49.01$57.52$74.88$76.80
WTI NYMEXWTI NYMEXVolumes Hedged (Bbls/d)3,0004,0004,0004,0004,0004,0001,0001,000WTI NYMEXVolumes Hedged (Bbls/d)11,00011,5005,5002,000
CollarsCollars
 Floor / Ceiling Price(1)
$45.00 / $50.95$46.25 / $53.04$46.25 / $53.04$46.25 / $53.04$46.25 / $53.04$46.25 / $53.04$47.50 / $53.00$47.50 / $53.00CollarsWeighted Average Floor / Ceiling Price$49.77 / $64.31$52.39 / $67.29$63.64 / $84.77$65.00 / $86.47
Total Volumes Hedged (Bbls/d)29,00031,00033,00033,00033,00033,00010,5002,000Total Volumes Hedged (Bbls/d)26,50021,00010,0004,000

(1)Averages are volume weighted.

Commodity derivative contracts in place for 2021 include fixed-price swaps and collars. Based on current contracts in place and NYMEX oil futures prices as of February 24, 2021,23, 2022, which averaged approximately $61$87 per Bbl for the remainder of 2021,2022, we currently expect that we would make cash payments of approximately $185$250 million during 20212022 upon settlement of these contracts, the amount of which is dependent upon fluctuations in future NYMEX oil prices in relation to the prices of our 20212022 fixed-price swaps which have a weighted average NYMEX oil price of $43.69$52.28 per Bbl and weighted average ceiling prices of our 2022 collars of $65.85 per Bbl. See Note 12, Commodity Derivative Contracts, to the consolidated financial statements for further discussion. 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
SuccessorPredecessor
Year Ended
Dec. 31, 2021		Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended
Dec. 31, 2019
In thousands, except per-BOE data
Total lease operating expenses$424,550 $101,234 $250,271 $477,220 
Total lease operating expenses per BOE$23.85 $19.90 $18.36 $22.46 


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Production Expenses

Lease Operating Expenses
SuccessorPredecessor
Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended December 31,
In thousands, except per-BOE data20192018
Total lease operating expenses$101,234 $250,271 $477,220 $489,720 
Total lease operating expenses per BOE$19.90 $18.36 $22.46 $22.24 

Total lease operating expenses were $424.6 million, or $23.85 per BOE, during the year ended December 31, 2021, compared to $351.5 million, or $18.78 per BOE, for the combined Predecessor and Successor periods included within the year ended December 31, 2020, compared to $477.22020. The $73.0 million or $22.46 per BOE, during 2019. The decreasesincrease on an absolute-dollar basis and per-BOE basis werewas primarily due to lower expenses $25.9 million of expense during the 2021 period related to the Wind River Basin acquisition in March 2021, with the remainder largely spread across all expense categories withbut reflective of the largest decreasesdifferent oil price environments in labor,2020 and 2021. During 2020, we curtailed production for a short period of time and significantly reduced workover expense, and power and fuel costs as well as insurance reimbursements totaling $15.4 million recorded for previously-incurred well control costs, cleanup costs, and damages associated with a 2013 incident at Delhi Field. In responsedue to the significant decline inextremely low oil price environment. In 2021, workover activity increased as oil prices improved, and we returned to a more normal activity level. Lease operating expenses for the year ended December 31, 2021 included a $16.1 million benefit resulting from compensation under certain of the Company’s power agreements for power interruption during the severe winter storm in 2020, we implemented cost reduction measuresFebruary 2021 which included shutting down compressors, negotiating reductions with vendorscreated widespread power outages in Texas and curtailing well repairs and workovers as most were uneconomic atdisrupted the lower oil price levels experienced throughout most of 2020.Company’s operations.

Currently, our CO2 expense comprises approximately 20% to 25% of our typical tertiaryWe currently expect lease operating expenses during 2022 to increase on an absolute-dollar and consists of (1) CO2 production expenses for the CO2 reserves we own, and (2) our purchaseper-BOE basis as a result of CO2 from royalty and working interest ownerspower expenses correlated with higher oil and industrialnatural gas prices; inflationary impacts across numerous cost categories such as contract labor, chemicals, and workovers; the 2022 period reflecting a full year’s worth of operating expenses for our Wind River Basin properties; and the absence of a one-time $16.1 million benefit during the 2021 period related to power agreementssources for the CO2 reserves we do not own. During the year ended December 31, 2020, approximately 48% of the CO2 utilized in our CO2 floods consisted of CO2 owned and produced by us (our net revenue interest). The price we pay others for CO2 varies by source and is generally indexed to oil prices. When combining the production cost of the CO2 we own with what we pay third parties for CO2, our average cost of CO2 during 2020 was approximately $0.38 per Mcf, including taxes paid on CO2 production but excluding depletion, depreciation and amortization of capital expended at our CO2 source fields and industrial sources. This per-Mcf CO2 cost during 2020 was higher than the $0.36 per Mcf comparable measure during 2019 due primarily to higher utilization in our Gulf Coast operations of industrial-sourced CO2, which has a higher average cost than our naturally occurring CO2 source.

Transportation and Marketing Expenses

Transportation and marketing expenses primarily consist of amounts incurred related to the transportation, marketing, and processing of oil and natural gas production. Transportation and marketing expenses were $28.8 million during 2021, compared to $37.8 million for the combined Predecessor and Successor periods included within the year ended December 31, 2020, compared to $41.8 million during 2019.2020. The decrease between periods was primarily due to fewer third-party oil purchaseschanges to a portion of our transportation agreements in the Rocky Mountain region during the third quarter of 2021 to begin selling our production at Guernsey, Wyoming versus Cushing, Oklahoma and due to lower marketing expenses.sales volumes during 2021.

Taxes Other than Income

Taxes other than income, which includes production, ad valorem and franchise taxes, were $91.4 million during 2021, compared to $60.1 million for the combined Predecessor and Successor periods included within the year ended December 31, 2020, compared to $93.8 million for 2019.2020. The decreaseincrease between periods was primarily due to a decreasean increase in production taxes resulting from lowerhigher oil and natural gas revenues and production levels.revenues.

General and Administrative Expenses (“G&A”)
SuccessorPredecessor
 Year Ended
Dec. 31, 2021		Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended
Dec. 31, 2019
In thousands, except per-BOE data and employees
Cash G&A costs$53,936 $11,258 $41,096 $51,932 
Stock-based compensation25,322 8,212 4,111 12,470 
Severance-related costs— — 3,315 18,627 
G&A expense$79,258 $19,470 $48,522 $83,029 
G&A per BOE   
Cash G&A costs$3.03 $2.21 $3.02 $2.44 
Stock-based compensation1.42 1.62 0.30 0.59 
Severance-related costs— — 0.24 0.88 
G&A expenses$4.45 $3.83 $3.56 $3.91 
Employees as of period end716 657 662 806 

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General and Administrative Expenses (“G&A”)
SuccessorPredecessor
 Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended December 31,
In thousands, except per-BOE data and employees20192018
Net cash administrative costs$11,258 $41,096 $51,932 $59,544 
Net stock-based compensation8,212 4,111 12,470 11,951 
Severance-related costs— 3,315 18,627 — 
Net G&A expense$19,470 $48,522 $83,029 $71,495 
G&A per BOE   
Net cash administrative costs$2.21 $3.02 $2.44 $2.70 
Net stock-based compensation1.62 0.30 0.59 0.55 
Severance-related costs— 0.24 0.88 — 
Net G&A expense$3.83 $3.56 $3.91 $3.25 
Employees as of period end657 662 806 847 
Our net G&A expense on an absolute-dollar basis was $79.3 million during 2021, compared to $68.0 million for the combined Predecessor and Successor periods included within the year ended December 31, 2020, a decrease of $15.0 million (18%) from 2019. Excluding severance-related costs from both years results2020. The increase in netour G&A expenses during 2021 was primarily due to a $13.0 million increase in stock-based compensation expense resulting from the vesting of performance-based equity awards granted in late 2020, as well as being essentially even between 2020 and 2019. Severance-relateddue to a full year of expense of $18.6 million during 2019 was associated with our voluntary separation program,for restricted stock unit awards also granted in late 2020. Although the majority of which was paid outperformance criteria for these performance-based equity awards were met in 2021, the first quarter of 2020.

On the Emergence Date and pursuant to the termsshares are not currently outstanding as actual delivery of the Plan andshares is not scheduled to occur until after the Confirmation Order, a framework for a management incentive plan was adopted, which reserves for officers, other employees, directors and other service providers a poolend of shares of new common stock. The 2020 Omnibus Stock and Incentive Plan was adopted on December 2, 2020, and initial awards were granted onthe performance period, December 4, 2020. The initial award grants contained both time-based awards for senior management and directors, vesting over three years, and also contained performance-based awards for senior management, with vesting based upon achieving certain2023. We expect stock price levels over a consecutive 60-trading day period on a volume-weighted average price basis. It is currently estimated that full vesting of thecompensation expense will be lower in 2022 as future performance awards will be achievedmore traditional in early March 2021, which resulted in $8.1 million of performance-based stock compensation beingnature and will be expensed in the fourth quarter of 2020 and $16.6 million of performance-based stock compensation expected to be recognized in the first quarter of 2021.over a longer time period.


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Interest and Financing Expenses
SuccessorPredecessorSuccessorPredecessor
Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended December 31, Year Ended
Dec. 31, 2021		Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended
Dec. 31, 2019
In thousands, except per-BOE data and interest ratesIn thousands, except per-BOE data and interest rates20192018In thousands, except per-BOE data and interest rates
Cash interest(1)
Cash interest(1)
$2,277 $108,824 $191,454 $186,632 
Cash interest(1)
$5,992 $2,277 $108,824 $191,454 
Less: interest not reflected as expense for financial reporting purposes(1)
Less: interest not reflected as expense for financial reporting purposes(1)
— (49,243)(85,454)(86,111)
Less: interest not reflected as expense for financial reporting purposes(1)
— — (49,243)(85,454)
Noncash interest expenseNoncash interest expense799 2,439 4,554 6,246 Noncash interest expense2,740 799 2,439 4,554 
Amortization of debt discount(2)
Amortization of debt discount(2)
— 9,132 7,749 — 
Amortization of debt discount(2)
— — 9,132 7,749 
Less: capitalized interestLess: capitalized interest(1,261)(22,885)(36,671)(37,079)Less: capitalized interest(4,585)(1,261)(22,885)(36,671)
Interest expense, netInterest expense, net$1,815 $48,267 $81,632 $69,688 Interest expense, net$4,147 $1,815 $48,267 $81,632 
Interest expense, net per BOEInterest expense, net per BOE$0.36 $3.54 $3.84 $3.16 Interest expense, net per BOE$0.23 $0.36 $3.54 $3.84 
Average debt principal outstanding(3)
Average debt principal outstanding(3)
$123,120 $1,767,605 $2,433,245 $2,593,035 
Average debt principal outstanding(3)
$84,970 $123,120 $1,767,605 $2,433,245 
Average interest rate(4)
6.5 %8.6 %7.9 %7.2 %
Average cash interest rate(4)
Average cash interest rate(4)
7.1 %6.5 %8.6 %7.9 %

(1)Cash interest during the Predecessor periods includes the portion of interest on certain debt instruments accounted for as a reduction of debt for GAAP financial reporting purposes in accordance with FASCFinancial Accounting Standards Board Codification (“FASC”) 470-60, Troubled Debt Restructuring by Debtors. The portion of interest treated as a reduction of debt was related to the Predecessor’s 9% Senior Secured Second Lien Notes due 2021 (the “2021 Notes”) and 9¼% Senior Secured Second Lien Notes due 2022 (the “2022 Notes”) during the Predecessor period from January 1, 2020 through September 18, 2020 and yearsyear ended December 31, 2019 and 2018, as well as the Predecessor’s previously outstanding 3½% Convertible Senior Notes due 2024 and 5% Convertible Senior Notes due 2023 during 2018.2019. Amounts related to the 2021 Notes and 2022 Notes remaining in future interest payable were written-off to “Reorganization items, net” in the Consolidated Statements of Operations on the Petition Date.July 30, 2020 (the “Petition Date”).
(2)Represents amortization of debt discounts of $3.0 million related to the 7¾% Senior Secured Second Lien Notes due 2024 (the “7¾% Senior Secured Notes”) during the Predecessor period January 1, 2020 through September 18, 2020 and $6.1 million related to the 6⅜% Convertible Senior Notes due 2024 (the “2024 Convertible Notes”) during the Predecessor period January 1, 2020 through September 18, 2020. Remaining debt discounts were written-off to “Reorganization items, net” in the Consolidated Statements of Operations on the Petition Date.
(3)Excludes debt discounts related to ourthe Predecessor’s 7¾% Senior Secured Notes and 2024 Convertible Notes.
(4)Includes commitment fees but excludes debt issue costs and amortization of discount.

Cash interest was $6.0 million during 2021, compared to $111.1 million for the combined Predecessor and Successor periods included within the year ended December 31, 2020, compared to $191.5 million during 2019.2020. The decrease between periods was primarily due to a decrease in the average debt principal outstanding, with the Successor periodperiods reflecting the full extinguishment of all outstanding obligations under the senior secured second lien notes, convertible senior notes, and senior subordinated notes on the Emergence Date, pursuant to the terms of the Plan,prepackaged joint plan of reorganization (the “Plan”), relieving us of approximately $2.1 billion of debt by issuing equity and/or warrants in the Successor period to the holders of that debt.


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Depletion, Depreciation, and Amortization (“DD&A”)
SuccessorPredecessorSuccessorPredecessor
Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended December 31, Year Ended
Dec. 31, 2021		Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended
Dec. 31, 2019
In thousands, except per-BOE dataIn thousands, except per-BOE data20192018In thousands, except per-BOE data
Oil and natural gas propertiesOil and natural gas properties$37,188 $104,495 $159,478 $134,486 Oil and natural gas properties$119,997 $37,188 $104,495 $159,478 
CO2 properties, pipelines, plants and other property and equipment
CO2 properties, pipelines, plants and other property and equipment
8,624 44,939 74,338 81,963 
CO2 properties, pipelines, plants and other property and equipment
30,643 8,624 44,939 74,338 
Accelerated depreciation charge(1)
Accelerated depreciation charge(1)
— 39,159 — — 
Accelerated depreciation charge(1)
— — 39,159 — 
Total DD&ATotal DD&A$45,812 $188,593 $233,816 $216,449 Total DD&A$150,640 $45,812 $188,593 $233,816 
DD&A per BOEDD&A per BOE   DD&A per BOE   
Oil and natural gas propertiesOil and natural gas properties$7.31 $7.66 $7.51 $6.11 Oil and natural gas properties$6.74 $7.31 $7.66 $7.51 
CO2 properties, pipelines, plants and other property and equipment
CO2 properties, pipelines, plants and other property and equipment
1.69 3.30 3.49 3.72 
CO2 properties, pipelines, plants and other property and equipment
1.72 1.69 3.30 3.49 
Accelerated depreciation charge(1)
Accelerated depreciation charge(1)
— 2.87 — — 
Accelerated depreciation charge(1)
— — 2.87 — 
Total DD&A per BOE$9.00 $13.83 $11.00 $9.83 
Total DD&A cost per BOETotal DD&A cost per BOE$8.46 $9.00 $13.83 $11.00 
Write-down of oil and natural gas propertiesWrite-down of oil and natural gas properties$1,006 $996,658 $— $— Write-down of oil and natural gas properties$14,377 $1,006 $996,658 $— 

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

DD&A expense was $150.6 million during 2021, compared to $234.4 million for the combined Predecessor and Successor periods included within the year ended December 31, 2020,2020. The decrease during 2021 compared to $233.8 million during 2019, with the slight increase due to a $39.2 million accelerated depreciation charge during the Predecessorcomparable 2020 period from January 1, 2020 through September 18, 2020. The combined Predecessor and Successor period decreases in oil and natural gas properties depletion and CO2 properties, pipelines, plants and other property and equipment DD&A was primarily due to lower depletable costs due to the step down in book value resulting from fresh start accounting.accounting as of September 18, 2020 and an accelerated depreciation charge of $39.2 million during the Predecessor period from January 1, 2020 through September 18, 2020. Our oil and natural gas properties depletion rate was $7.37$6.71 per BOE during the fourth quarter of 2020.2021.

Full Cost Pool Ceiling Test

Under full cost accounting rules, we are required each quarter (as well as at the end of the Predecessor period) 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 priceprices for each month during a 12-month rolling period prior to the end of a particular reporting period. The average first-day-of-the-month NYMEX oil prices for the preceding 12 months,price used in estimating our proved reserves, after adjustments for market differentials and transportation expenses by field, averagedwas $63.86 at December 31, 2021, $35.84 per Bbl as ofat December 31, 2020, $40.08 per Bbl as ofat September 18, 2020 $44.74 per Bbl as of June 30, 2020 and $55.17 per Bbl as of March 31, 2020. While representative oil prices$55.55 at March 31, 2020 were roughly consistent with adjusted prices used to calculate the December 31, 2019 full cost ceiling value, the decline in NYMEX oil prices in late March 2020 due to OPEC supply pressures and a reduction in worldwide oil demand amid the COVID-19 pandemic contributed to the transfer of $244.9 million of our unevaluated costs to the full cost amortization base during the three months ended March 31, 2020. Primarily as a result of adding these additional costs to the amortization base, we2019. We recognized a full cost pool ceiling test write-down of $72.5$14.4 million during the threefirst quarter of 2021, with first-day-of-the-month NYMEX oil prices for the preceding 12 months endedaveraging $36.40 per Bbl, after adjustments for market differentials and transportation expenses by field. The write-down was primarily a result of the March 31, 2020. In addition,2021 acquisition of Wyoming property interests (see Note 3, Acquisition and Divestitures) 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. Primarily as a result of commodity price declines during 2020, the precipitous decline in NYMEX oil prices, wePredecessor recognized additional full cost pool ceiling test write-downs of $662.4 million during the three months ended June 30, 2020, $261.7$996.7 million during the period from JulyJanuary 1, 2020 through September 18, 2020, and an additional full cost pool ceiling test write-down of $1.0 million was recognized during the Successor period from September 19, 2020 through December 31, 2020.

Reorganization Items, Net
Based upon fresh start accounting, oil and gas properties were recorded at fair value as
“Reorganization items, net” in our Consolidated Statements of September 18, 2020. See Note 2, Fresh Start Accounting,Operations includes (i) expenses incurred during the Company’s “prepackaged” voluntary bankruptcy subsequent to the consolidated financial statements for further discussion.Petition Date as a direct result of the Plan, (ii) gains or

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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, and for the Successor period also included long-term contracts to sell CO2 to industrial customers. 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, to the consolidated financial statements for additional information). We performed a qualitative assessment as of December 31, 2020 (Successor period) and determined there were no material changes to our key cash flow assumptions and no triggering events since the Company’s assets were revalued in fresh start accounting as of September 18, 2020; therefore, no impairment test was performed for the fourth quarter of 2020.

Reorganization Items, Net

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


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The following table summarizes the losses (gains) on reorganization items, net:
Predecessor
Period from
Jan. 1, 2020 through
Sept. 18, 2020
In thousands
Gain on settlement of liabilities subject to compromise$(1,024,864)
Fresh start accounting adjustments1,834,423 
Professional service provider fees and other expenses11,267 
Success fees for professional service providers9,700 
Loss on rejected contracts and leases10,989 
Valuation adjustments to debt classified as subject to compromise757 
DIPDebtor-in-possession credit agreement fees3,107 
Acceleration of Predecessor stock compensation expense4,601 
Total reorganization items, net$849,980 

Other Expenses

Other expenses totaled $10.8 million during 2021 and primarily includes plant operating expenses, litigation accruals and noncash fair value adjustments for contingent consideration payments related to our March 2021 Wind River Basin CO2 EOR field acquisition, slightly offset by insurance reimbursements for previously-incurred costs associated with the February 2020 Delta-Tinsley CO2 pipeline repair. Other expenses totaled $43.9 million for the combined Predecessor and Successor periods included within the year ended December 31, 2020. Other expenses during 2020 primarily are comprised of $28.2 million of professional fees associated with restructuring activities, $5.1 million for the write-off of certain trade receivables, $4.3 million of costs associated with the Delta-Tinsley CO2 pipeline repair, and $0.9 million of costs associated with the APMTG Helium, LLC helium supply contract ruling (see Note 14, Commitments and Contingencies – Litigation, to the consolidated financial statements). The 2019 amounts are primarily comprised of $1.9 million of impairment expense, $1.8 million of costs associated with the Riley Ridge helium supply contract ruling, and $1.6 million of transaction costs associated with the Predecessor’s privately negotiated debt exchanges.ruling.

Income Taxes
SuccessorPredecessorSuccessorPredecessor
Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended December 31, Year Ended
Dec. 31, 2021		Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended
Dec. 31, 2019
In thousands, except per-BOE amounts and tax ratesIn thousands, except per-BOE amounts and tax rates20192018In thousands, except per-BOE amounts and tax rates
Current income tax expense (benefit)Current income tax expense (benefit)$30 $(7,260)$3,881 $(16,001)Current income tax expense (benefit)$403 $30 $(7,260)$3,881 
Deferred income tax expense (benefit)Deferred income tax expense (benefit)(2,556)(408,869)100,471 103,234 Deferred income tax expense (benefit)364 (2,556)(408,869)100,471 
Total income tax expense (benefit)Total income tax expense (benefit)$(2,526)$(416,129)$104,352 $87,233 Total income tax expense (benefit)$767 $(2,526)$(416,129)$104,352 
Average income tax expense (benefit) per BOEAverage income tax expense (benefit) per BOE$(0.49)$(30.52)$4.91 $3.96 Average income tax expense (benefit) per BOE$0.04 $(0.49)$(30.52)$4.91 
Effective tax rateEffective tax rate4.7 %22.5 %32.5 %21.3 %Effective tax rate1.4 %4.7 %22.5 %32.5 %
Total net deferred tax liabilityTotal net deferred tax liability$1,274 $410,230 $309,758 Total net deferred tax liability$1,638 $1,274 $410,230 

Our income tax provisions for the Predecessor were based on an estimated combined federal and state statutory tax rate of approximately 25% for 2021, 2020 2019 and 2018. 2019. Our effective tax rate for 2021 was lower than our estimated statutory rate, primarily due to our overall deferred tax asset position and the valuation allowance offsetting those assets. As we had pre-tax income for the year ended December 31, 2021, the income tax expense resulting from our income is substantially offset by a change in valuation allowance, resulting in essentially no tax provision.


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As of December 31, 2021, we are in a net deferred tax asset position primarily due to net operating loss and tax credit carryforwards and differences in the tax basis of accrued liabilities, including derivative contract liabilities. Based on all available evidence, both positive and negative, we continue to record a valuation allowance on our underlying deferred tax assets as of December 31, 2021, as we believe our deferred tax assets are not more-likely-than-not to be realized. We intend to maintain the valuation allowances on our deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of the allowances. It is reasonably possible that sufficient evidence required to release our valuation allowance will exist in the future if the current strength being observed in commodity prices is sustained. Such positive evidence may allow us to reach a conclusion that all, or a portion of, the valuation allowance associated with our federal net deferred tax assets, totaling $51.4 million as of December 31, 2021, will no longer be needed. Release of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense in the period the release is recorded. The exact timing and amount of the valuation allowance are subject to the level of profitability that we are able to actually achieve.

The current income tax benefit for the Predecessor period ended September 18, 2020 represents amounts expected to be realized from refundable alternative minimum tax credits and certain state tax obligations that we expect to be realized.

As provided for under FASC 740-270-35-2, we determined the actual effective tax rate for the Predecessor period from January 1, 2020 through September 18, 2020 was the best estimate of our annual effective tax rate. Our effective tax rate for the 2020 Predecessor period was lower than our estimated statutory rate, primarily due to the establishment of a valuation allowance on our federal and state deferred tax assets after the application of fresh start accounting. Our income tax provision for the Successor 2020 period was also based on the same estimated statutory rate of approximately 25% but is expected to bewas near zero, as any tax expense or benefit associated with pre-tax book income or loss will bewas offset with a change in valuation allowance on our federal and state deferred tax assets. The Successor’s effective tax rate of 4.7% was primarily due to adjustments related to our Texas net deferred tax liabilities.

We have evaluated the impact of the Plan, including the change in control, resulting from our emergence from bankruptcy. The cancellation of debt income (“CODI”) realized upon emergence is excludable from income and resulted in the elimination

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of all available federal net operating loss carryforwards and tax credit carryforwards, as well as a partial reduction in tax basis in assets, in accordance with the attribute reduction and ordering rules of Section 108 of the Internal Revenue Code of 1986 (the “Code”). The reduction in the Company’s tax attributes for excludable CODI did not occur until the last day of the Company’s tax year, December 31, 2020. Accordingly, the tax adjustments recorded in the Predecessor period represented our best estimate using all available information at September 30, 2020. The final tax impacts of the bankruptcy emergence, as well as the Plan’s overall effect on the Company’s tax attributes which were refined based on the Company’s final financial position at December 31, 2020 as required under the Code, resulted in the Company fully reducing its federal net operating loss carryforwards, enhanced oil recovery credits, and research and development tax credits, and reducing a portion of its tax basis in assets.

As the tax basis of our assets, primarily our oil and gas properties, is in excess of the carrying value, as adjusted in fresh start accounting, the Successor is in a net deferred tax asset position at December 31, 2020. We evaluated our deferred tax assets in light of all available evidence as of the balance sheet date, including the tax impacts of the Chapter 11 Restructuring and the full reduction of net operating losses and tax credits and partial reduction of tax basis in assets (collectively “tax attributes”). Given our cumulative loss position and the continued low oil price environment, we recorded a total valuation allowance of $129.4 million on our underlying deferred tax assets, consisting of $54.3 million on our federal deferred tax assets and $75.1 million on our state deferred tax assets as of December 31, 2020. Valuation allowances totaling $60.8 million, $10.2 million, and $4.1 million were recorded for our Louisiana, Mississippi, and other state deferred tax assets, respectively. A $1.3 million state deferred tax liability is recorded on the Successor balance sheet. For the Successor period, the income tax benefit associated with the Successor’s pre-tax book loss was substantially offset by a change in valuation allowance.

The current income tax benefit for the Predecessor period ended September 18, 2020 represents amounts estimated to be receivable resulting from alternative minimum tax credits and certain state tax obligations.

Our effective tax rate for 2019 was higher than our estimated statutory rate primarily due to the establishment of a valuation allowance against a portion of our business interest expense deduction that we estimate will be disallowed. Our 2018 effective tax rate was lower than our estimated statutory rate primarily due to tax benefits resulting from enhanced oil recovery income tax credits.

We have $0.6 million of alternative minimum tax credits, which under the Tax Cut and Jobs Act will be refunded in 20212022 and are recorded as a receivable on the balance sheet. Our state net operating loss carryforwards expire in various years, starting in 2025. The statutes of limitation for our income tax returns for tax years ending prior to 20172018 have lapsed and therefore are not subject to examination by respective taxing authorities.


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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.
Year Ended December 31, Year Ended December 31,
Per-BOE dataPer-BOE data202020192018Per-BOE data202120202019
Oil and natural gas revenuesOil and natural gas revenues$37.03 $57.04 $64.59 Oil and natural gas revenues$65.16 $37.03 $57.04 
Receipt (payment) on settlements of commodity derivativesReceipt (payment) on settlements of commodity derivatives5.47 1.11 (7.96)Receipt (payment) on settlements of commodity derivatives(15.57)5.47 1.11 
Lease operating expensesLease operating expenses(18.78)(22.46)(22.24)Lease operating expenses(23.85)(18.78)(22.46)
Production and ad valorem taxesProduction and ad valorem taxes(2.87)(4.09)(4.39)Production and ad valorem taxes(4.97)(2.87)(4.09)
Transportation and marketing expensesTransportation and marketing expenses(2.02)(1.97)(2.00)Transportation and marketing expenses(1.62)(2.02)(1.97)
Production netbackProduction netback18.83 29.63 28.00 Production netback19.15 18.83 29.63 
CO2 sales, net of operating and discovery expenses
CO2 sales, net of operating and discovery expenses
1.39 1.47 1.28 
CO2 sales, net of operating and discovery expenses
2.10 1.39 1.47 
General and administrative expenses(1)
General and administrative expenses(1)
(3.63)(3.91)(3.25)
General and administrative expenses(1)
(4.45)(3.63)(3.91)
Interest expense, netInterest expense, net(2.68)(3.84)(3.16)Interest expense, net(0.23)(2.68)(3.84)
Reorganization items settled in cashReorganization items settled in cash(2.08)— — Reorganization items settled in cash— (2.08)— 
Other(0.38)0.43 (2.01)
Stock compensation and otherStock compensation and other0.97 (0.38)0.43 
Changes in assets and liabilities relating to operationsChanges in assets and liabilities relating to operations(3.24)(0.52)3.19 Changes in assets and liabilities relating to operations0.28 (3.24)(0.52)
Cash flows from operationsCash flows from operations8.21 23.26 24.05 Cash flows from operations17.82 8.21 23.26 
DD&A – excluding accelerated depreciation chargeDD&A – excluding accelerated depreciation charge(10.43)(11.00)(9.83)DD&A – excluding accelerated depreciation charge(8.46)(10.43)(11.00)
DD&A – accelerated depreciation charge(2)
DD&A – accelerated depreciation charge(2)
(2.09)— — 
DD&A – accelerated depreciation charge(2)
— (2.09)— 
Write-down of oil and natural gas propertiesWrite-down of oil and natural gas properties(53.29)— — Write-down of oil and natural gas properties(0.81)(53.29)— 
Deferred income taxesDeferred income taxes21.98 (4.73)(4.69)Deferred income taxes(0.02)21.98 (4.73)
Gain on extinguishment of debtGain on extinguishment of debt1.01 7.34 — Gain on extinguishment of debt— 1.01 7.34 
Noncash fair value gains (losses) on commodity derivatives(3)
(3.33)(4.41)8.92 
Noncash fair value losses on commodity derivativesNoncash fair value losses on commodity derivatives(4.26)(3.33)(4.41)
Noncash reorganization items, netNoncash reorganization items, net(43.32)— — Noncash reorganization items, net— (43.32)— 
Other noncash itemsOther noncash items2.03 (0.25)(3.80)Other noncash items(1.12)2.03 (0.25)
Net income (loss)Net income (loss)$(79.23)$10.21 $14.65 Net income (loss)$3.15 $(79.23)$10.21 

(1)General and administrative expenses includesinclude (a) $15.3 million of performance stock-based compensation related to the full vesting of outstanding performance awards during the year ended December 31, 2021, resulting in a significant non-recurring expense, which if excluded, would have caused these expenses to average $3.60 per BOE and (b) an accrual for severance-related costs of $18.6 million associated with our voluntary separation program for the year ended December 31, 2019, which if excluded, would have averaged $3.03 per BOE.
(2)Represents an accelerated depreciation charge related to impaired unevaluated properties that were transferred to the full cost pool.
(3)Noncash fair value gains (losses) on commodity derivatives is a non-GAAP measure. See Financial and Operating Results Tables above for a discussion of the reconciliation between noncash fair value gains (losses) on commodity derivatives to “Commodity derivatives expense (income)” in the Consolidated Statements of Operations. See also the Glossary and Selected Abbreviations for the definition of noncash fair value gains (losses) on commodity derivatives.

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MARKET RISK MANAGEMENT

Debt and Interest Rate Sensitivity

At December 31, 2020,2021, we had $70.0$35.0 million of outstanding borrowing under our Bank Credit Agreement. At this level of variable-rate debt, an increase or decrease of 10% in interest rates would have an immaterial effect on our interest expense. Our Bank Credit Agreement does not have any triggers or covenants regarding our debt ratings with rating agencies. The following table presents the principal and fair values of our outstanding debt as of December 31, 2020:2021:
In thousandsIn thousands2021202220232024TotalFair
Value		In thousands2022202320242025TotalFair
Value
Variable rate debtVariable rate debt   Variable rate debt   
Senior Secured Bank Credit Facility (weighted average interest rate of 4.0% at December 31, 2020$— $— $— $70,000 $70,000 $70,000 
Senior Secured Bank Credit Facility (weighted average interest rate of 4.0% at December 31, 2021)Senior Secured Bank Credit Facility (weighted average interest rate of 4.0% at December 31, 2021)$— $— $35,000 $— $35,000 $35,000 

Commodity Derivative Contracts

We enter into oil derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil production and to provide more certainty to our future cash flows.  We do not hold or issue derivative financial instruments for trading purposes.  Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps.  The production that we hedge has varied from year to year depending on our levels of debt, financial strength, and expectation of future commodity prices.  prices, and occasionally requirements under our bank credit facility.  As of December 31, 2020, we were in compliance with the hedging requirements under our Bank Credit Agreement requiring certain non-recurring minimum commodity hedge levels covering anticipated crude oil production through July 31, 2022, and we have no further hedging requirements under our Bank Credit Agreement. In order to provide a level of price protection to 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 20212022 and 20222023 hedges. See also Note 12, Commodity Derivative Contracts, and Note 13, Fair Value Measurements, to the consolidated financial statements for additional information regarding our commodity derivative contracts. Under the terms of our Successor senior secured bank credit facility, by December 31, 2020, we were required to have hedges in place covering a minimum of 65% of our anticipated crude oil production for the first twelve calendar months between August 1, 2020 through July 31, 2021 and 35% of our anticipated crude oil production for the second twelve month period between August 1, 2021 through July 31, 2022. As of December 31, 2020, we were in compliance with the hedging requirements of our Successor Bank Credit Agreement.

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 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 December 31, 2020,2021, our commodity derivative contracts were recorded at their fair value, which was a net liability of $134.5 million, $75.7 million higher than the $58.8 million a $62.4 million decrease from the $3.6 million net assetliability recorded at December 31, 2019.2020.  This change is primarily related to the expiration of commodity derivative contracts during 2020,2021, new commodity derivative contracts entered into during 20202021 for future periods, and to the changes in oil futures prices between December 31, 20192020 and 2020.2021.


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Commodity Derivative Sensitivity Analysis

Based on NYMEX oil futures prices and derivative contracts in place as of December 31, 2020,2021, 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 thousandsReceipt / (Payment)
Based on: 
Futures prices as of December 31, 20202021$(59,242)(124,394)
10% increase in prices(114,559)(184,362)
10% decrease in prices(4,499)(70,439)

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.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in accordance with generally accepted accounting principles requires that we select certain accounting policies and make certain estimates and judgments regarding the application of those policies.judgments.  Our significant accounting policies are included in Note 1, Nature of Operations and Summary of Significant Accounting Policies, to the consolidated financial statements.  These policies, along with the underlying assumptions and judgments by our management in their application, have a significant impact on our consolidated financial statements.  Following is a discussion of our most critical accounting estimates, judgments and uncertainties that are inherent in the preparation of our financial statements.

Fresh Start Accounting

Upon emergence from bankruptcy, we met the criteria and were required to adopt fresh start accounting in accordance with FASC Topic 852, Reorganizations, which on the Emergence Date resulted in a new entity, the Successor, for financial reporting purposes, with no beginning retained earnings or deficit as of the fresh start reporting date. Fresh start accounting requires that new fair values be established for the Company’s assets, liabilities and equity as of the date of emergence from bankruptcy, September 18, 2020. The Emergence Date fair values of the Successor’s assets and liabilities differ materially from their recorded values as reflected on the historical balance sheet of the Predecessor and required a number of estimates and judgments to be made. All estimates, assumptions, valuations and financial projections, including the fair value adjustments, financial projections, enterprise value and equity value, are inherently subject to significant uncertainties and the resolution of contingencies beyond our control. Accordingly, there is no assurance that the estimates, assumptions, valuations or financial projections will be realized, and actual results could vary materially. Among the most material of these judgments and estimates that were made were the following:

•Reorganization Value – The reorganization value derived from the range of enterprise values associated with the Plan was allocated to the Company’s identifiable tangible and intangible assets and liabilities based on their fair values. The value of the reconstituted entity (i.e., Successor) was based on management projections and the valuation models as determined by the Company’s financial advisors in setting an estimated range of enterprise values. With the assistance of third-party valuation advisors, we determined the enterprise and corresponding equity value of the Successor using various valuation approaches and methods, including: (i) income approach using a calculation of the present value of future cash flows based on our financial projections, (ii) the market approach using selling prices of similar assets and (iii) the cost approach.

•Oil and Natural Gas Properties – The fair value of our oil and natural gas properties was determined based on the discounted cash flows expected to be generated from these assets. The computations were based on market conditions and reserves in place as of the Emergence Date.

The fair value analysis was based on the Company’s estimated future production rates of proved and probable reserves as prepared by the Company’s independent petroleum engineers. Discounted cash flow models were prepared using the estimated future revenues and operating costs for all developed wells and undeveloped properties comprising the proved

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estimated future revenues and operating costs for all developed wells and undeveloped properties comprising the proved and probable reserves. Future revenue estimates were based upon estimated future production rates and forward strip oil and natural gas prices as of the Emergence Date through 2024 and escalated for inflation thereafter, adjusted for differentials. Operating costs were adjusted for estimated inflation beginning in year 2025. A risk adjustment factor was applied to each reserve category, consistent with the risk of the category. The discounted cash flow models also included adjustments for income tax expenses.

Discount factors utilized were derived using a weighted average cost of capital computation, which included an estimated cost of debt and equity for market participants with similar geographies and asset development type and varying corporate income tax rates based on the expected point of sale for each property’s produced assets. Reserve values were also adjusted for any asset retirement obligations as well as for CO2 indirect costs not directly allocable to oil fields.

•CO2 Properties – The fair value of CO2 properties includes the value of CO2 mineral rights and associated infrastructure and was determined using the discounted cash flow method under the income approach. After-tax cash flows were forecast based on expected costs to produce and transport CO2 as providedestimated by management, and income was imputed using a gross-up of costs based on a five-year average historical EBITDA margin for publicly traded companies that primarily develop or produce natural gas. Cash flows were also adjusted for a market participant profit on CO2 costs, since Denbury charges oil fields for CO2 use on a cost basis. Cash flows were then discounted using a rate considering reduced risk associated with CO2 industrial sales.

•Pipelines – The fair values of our pipelines were determined using a combination of the replacement cost method under the cost approach and the discounted cash flow method under the income approach. The replacement cost method considers historical acquisition costs for the assets adjusted for inflation, as well as factors in any potential obsolescence based on the current condition of the assets and the ability of those assets to generate cash flow. For assets valued using the discounted cash flow method, after-tax cash flows were forecast based on expected costs providedestimated by management, and profits were imputed using a gross-up of costs based on a five-year average historical EBITDA margin for publicly traded companies that primarily transport natural gas.

Full Cost Method of Accounting, Depletion and Depreciation and Oil and Natural Gas Properties

Businesses involved in the production of oil and natural gas are required to follow accounting rules that are unique to the oil and gas industry.  We apply the full cost method of accounting for our oil and natural gas properties.  Another acceptable method of accounting for oil and natural gas production activities is the successful efforts method of accounting.  In general, the primary differences between the two methods are related to the capitalization of costs and the evaluation for asset impairment.  Under the full cost method, all geological and geophysical costs, exploratory dry holes and delay rentals are capitalized to the full cost pool, whereas under the successful efforts method such costs are expensed as incurred.  In the assessment of impairment of oil and natural gas properties, the successful efforts method follows the Accounting for the Impairment or Disposal of Long-Lived Assets topic of the FASC, under which the net book value of assets is measured for impairment against the undiscounted future cash flows using commodity prices consistent with management expectations.  Under the full cost method, the full cost pool (net book value of oil and natural gas properties) is measured against future cash flows discounted at 10% using the average first-day-of-the-month oil and natural gas price for each month during a 12-month rolling period through the end of each quarterly reporting period.  The financial results for a given period could be substantially different depending on the method of accounting that an oil and gas entity applies.  Further, we do not designate our oil and natural gas derivative contracts as hedging instruments for accounting purposes under the Derivatives and Hedging topic of the FASC (see below), and as a result, these contracts are not considered in the full cost ceiling test.

We make significant estimates at the end of each period related to accruals for oil and natural gas revenues, production, capitalized costs and operating expenses.  We calculate these estimates with our best available data, which includes, among other things, production reports, price posting, information compiled from daily drilling reports and other internal tracking devices, and analysis of historical results and trends.  While management is not aware of any required revisions to its estimates, there will likely be future adjustments resulting from such things as revisions in estimated oil and natural gas volumes, changes in ownership interests, payouts, joint venture audits, re-allocations by the purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which will require retroactive application.  These types of adjustments cannot be currently estimated or determined and will be recorded in the period during which the adjustment occurs.


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Under full cost accounting, the estimated quantities of proved oil and natural gas reserves used to compute depletion and the related present value of estimated future net cash flows therefrom used to perform the full cost ceiling test have a significant impact on the underlying financial statements.  The process of estimating oil and natural gas reserves is very complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data.  The data for a given field may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continued reassessment of the viability of production under varying economic conditions.  As a result, material revisions to existing reserve estimates may occur from time to time.  Although every reasonable effort is made to ensure the reported reserve estimates represent the most accurate assessments possible, including the hiring of independent engineers to prepare reported estimates, the subjective decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in our financial statement disclosures.  Over the last three years, annual revisions to our reserve estimates, excluding any revisions related to changes in commodity prices, have averaged approximately 2.2%3.9% of the previous year’s estimates and have been both positive and negative.

Changes in commodity prices also affect our reserve quantities.  These changes in quantities affect our DD&A rate, and the combined effect of changes in quantities and commodity prices impacts our full cost ceiling test calculation.  For example, we estimate that a 5% increase in our estimate of proved reserve quantities would have lowered our fourth quarter 20202021 oil and natural gas property DD&A rate from $7.37$6.71 per BOE to approximately $7.05$6.43 per BOE, and a 5% decrease in our proved reserve quantities would have increased our DD&A rate to approximately $7.72$7.01 per BOE.  Also, reserve quantities and their ultimate values, determined solely by our lenders, are the primary factors in determining the maximum borrowing base under our senior secured bank credit facility, particularly quantities and values of our proved developed producing reserves.

Under full cost accounting rules, we are required each quarter (as well as at the end of the Predecessor period) to perform a ceiling test calculation.  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 hedging instruments for accounting purposes. The cost center ceiling test is prepared quarterly.

The average first-day-of-the-month NYMEX oil price used in estimating our proved reserves, after adjustments for market differentials and transportation expenses by field, was $55.55$63.86 at December 31, 2019,2021, $35.84 at December 31, 2020, $40.08 at September 18, 2020, and $35.84$55.55 at December 31, 2020.2019. We recognized a full cost pool ceiling test write-down of $14.4 million during the first quarter of 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 3, Acquisition and Divestitures) 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. Primarily as a result of these commodity price declines during 2020, the Predecessor recognized full cost pool ceiling test write-downs of $996.7 million during the period from January 1, 2020 through September 18, 2020, and an additional full cost pool ceiling test write-down of $1.0 million was recognized during the Successor period from September 19, 2020 through December 31, 2020. We did not record any ceiling test write-downs during the Predecessor periods of 2018 or 2019.

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. The costs classified as unevaluated are transferred to the full cost amortization base as the 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 project 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 transferred $244.9 million of our unevaluated costs to the full cost pool during the Predecessor period from January 1, 2020 through September 18, 2020.


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million of our unevaluated costs to the full cost pool during the Predecessor period from January 1, 2020 through September 18, 2020. 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).

Tertiary Injection Costs

Our tertiary operations are conducted in reservoirs that have already produced significant amounts of oil over many years; however, in accordance with the rules for recording proved reserves, we cannot recognize proved reserves associated with enhanced recovery techniques, such as CO2 injection, until we can demonstrate production resulting from the tertiary process or unless the field is analogous to an existing flood.  Our costs associated with the CO2 we produce (or acquire) and inject are principally our cash out-of-pocket costs of production, transportation and acquisition, and to pay royalties.

We capitalize, as a development cost, injection costs in fields that are in their development stage, which means we have not yet seen incremental oil production due to the CO2 injections (i.e., a production response).  These capitalized development costs will be included in our unevaluated property costs until we are able to recognize proved oil reserves associated with the development project.  After we see a production response to the CO2 injections (i.e., the production stage), injection costs will be expensed as incurred, and any previously deferred unevaluated development costs will become subject to depletion.  We capitalized $2.3$7.6 million of tertiary injection costs associated with our tertiary projects during 2021, $2.3 million during the Successor period from September 19, 2020 through December 31, 2020 and $16.2 million during the Predecessor period from January 1, 2020 through September 18, 2020, and we capitalized an additional $19.1 million and $24.5 million during 2019 and 2018, respectively.2020.

Income Taxes

We make certain 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.  Our federal and state income tax returns are generally not prepared or filed before the consolidated financial statements are prepared; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits and net operating loss carryforwards.  Adjustments related to these estimates are recorded in our tax provision in the period in which we finalize our income tax returns.  Further, we must assess the likelihood that we will be able to recover or utilize our deferred tax assets.  If recovery is not likely, we must record a valuation allowance against such deferred tax assets for the amount we would not expect to recover, which would result in an increase to our income tax expense.  As of December 31, 2021 and 2020, we had tax valuation allowances totaling $125.5 million and $129.4 million, respectively, to reduce the carrying value of deferred tax assets related to our federal and state deferred tax assets. As of December 31, 2019, we had tax valuation allowances totaling $77.2 million to reduce the carrying value of2021 and 2020, our underlying deferred tax assets related to our disallowed business interest expensewere comprised of federal deferred tax assets of $51.4 million and $54.3 million and state deferred income tax assets of $74.1 million and as of December 31, 2018, valuation allowances totaling $51.1$75.1 million, to reduce the carrying value of our state deferred income tax assets.respectively. The valuation allowances will remain until the realization of future deferred tax benefits are more likely than not to become utilized.  Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes our cumulative loss position, the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies and judgment is required in considering the relative weight of negative and positive evidence. Significant judgment is involved in this determination as we are required to make assumptions about forecasted commodity prices and economics in the oil and gas industry that may impact our ability to generate future earnings. Such estimates are inherently subjective. Changes in judgment regarding future realization of deferred tax assets may result in a reversal of all or a portion of the valuation allowance in the period that determination is made, and our net income during that period would benefit from a lower effective tax rate. A 1% increase in our statutory tax rate would have increased our calculated income tax expense (benefit) by approximately $0.6 million for the year ended December 31, 2021, ($0.5 million) during the Successor period from September 19, 2020 through December 31, 2020, although any change would be offset by a corresponding change in our valuation allowance, and ($18.5 million) during the Predecessor period from January 1, 2020 through September 18, 2020, and $3.2 million and $4.1 million for the years ended December 31, 2019 and 2018, respectively.2020.  See Note 9, Income Taxes, to the consolidated financial statements and Results of Operations – Income Taxes above for further information concerning our income taxes.

Fair Value Estimates

The FASC defines fair value, establishes a framework for measuring fair value and requires disclosures about fair value measurements. It does not require us to make any new fair value measurements, but rather establishes a fair value hierarchy

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

that prioritizes the inputs to the valuation techniques used to measure fair value. Level 1 inputs are given the highest priority in the fair value hierarchy, as they represent observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date, while Level 3 inputs are given the lowest priority, as they represent unobservable inputs that are not corroborated by market data. Valuation techniques that maximize the use of observable inputs are favored. See Note 13, Fair Value Measurements, to the consolidated financial statements for disclosures regarding our recurring fair value measurements.

Significant uses of fair value measurements include:

•valuation of the Company’s assets, liabilities and equity upon application of fresh start accounting (see Fresh Start Accounting above);

•
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Management’s Discussionthe purchase price to assets acquired and Analysis of Financial Condition and Results of Operations

liabilities assumed in acquisitions;
•assessment of impairment of long-lived assets; and
•recorded value of commodity derivative instruments.

Impairment Assessment of Long-Lived Assets

We test long-lived assets that are not subject to our quarterly full cost pool ceiling test for impairment, including a portion of our capitalized CO2 properties and pipelines, and long-term contracts to sell CO2 to industrial customers, whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The factors we assess to determine if a long-lived asset impairment test is necessary include, among other factors, a significant adverse change in the business climate that could affect the value of a long-lived asset, a significant decrease in the market price of an asset group, a significant adverse change in the extent or manner in which a long-lived asset (asset group) is being used or in its physical condition, or a current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset (asset group).

We perform our long-lived asset impairment test by comparing the net carrying costs of our 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. 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. 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. 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 and Rocky Mountain region) as of March 31, 2020 (Predecessor). We performed a qualitative assessment as of June 30, 2020 and September 18, 2020 (Predecessor periods)December 31, 2021 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). We performed a qualitative assessment as of December 31, 2020 (Successor period) and determined there were no material changes to our key cash flow assumptions and no triggering events sincewhen the Company’s assets were revalued in fresh start accounting as of September 18, 2020;accounting; therefore, no impairment test was performed for the fourth quarter of 2020.2021.

Commodity Derivative Contracts

Historically, we have entered into 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.  Our derivative financial instruments are recorded on the balance sheet as either an asset or liability measured at fair value. The valuation methods used to measure the fair values of these assets and liabilities require considerable management judgment and estimates to derive the inputs necessary to determine fair value estimates, such as forward prices for commodities, interest rates, volatility factors and credit worthiness, as well as other relevant economic measures. We do not apply hedge accounting to our commodity derivative contracts under the FASC Derivatives and Hedging topic; accordingly, changes in the fair value of these instruments are recognized in earnings instead of charging the effective portion to other comprehensive income and the ineffective portion to earnings.  While we may experience more volatility in our net income (loss) than if we were to apply hedge accounting treatment as permitted by the FASC Derivatives and Hedging topic, we believe that for us, the benefits associated with applying hedge accounting do not outweigh the cost, time and effort to comply with hedge accounting. We estimate that a 10% increase in NYMEX oil futures prices as of December 31, 20202021 would increase our estimated payments on our crude oil derivative contracts by $55 million, and a 10% decrease in NYMEX oil futures prices would reduce our estimated payments by $55 million.


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

Use of Estimates

See Note 1, Nature of Operationsincrease our estimated payments on our crude oil derivative contracts by $60 million, and Summary of Significant Accounting Policies, to the consolidated financial statements for a discussion of10% decrease in NYMEX oil futures prices would reduce our use of estimates.estimated payments by $54 million.

Recent Accounting Pronouncements

See Note 1, Nature of Operations and Summary of Significant Accounting Policies, to the consolidated financial statements for a discussion of recent accounting pronouncements.

NON-GAAP FINANCIAL MEASURE AND RECONCILIATION

Reconciliation of Standardized Measure to PV-10 Value

PV-10 Value is a non-GAAP measure and is different from the Standardized Measure in that PV-10 Value is a pre-tax number and the Standardized Measure is an after-tax number.  The information used to calculate PV-10 Value is derived directly from data determined in accordance with FASC Topic 932.  We believe that PV-10 Value is a useful supplemental disclosure to the Standardized Measure because the Standardized Measure can be impacted by a company’s unique tax situation, and it is not practical to calculate the Standardized Measure on a property-by-property basis.  Because of this, PV-10 Value is a widely used measure within the industry and is commonly used by securities analysts, banks and credit rating agencies to evaluate the estimated future net cash flows from proved reserves on a comparative basis across companies or specific properties.  PV-10 Value is commonly used by us and others in our industry to evaluate properties that are bought and sold, to assess the potential return on investment in our oil and natural gas properties, and to perform our impairment testing of oil and natural gas properties. PV-10 Value is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for the Standardized Measure.  Our PV-10 Value and the Standardized Measure do not purport to represent the fair value of our oil and natural gas reserves. See also Glossary and Selected Abbreviations for the definition of “PV-10 Value” and Supplemental Oil and Natural Gas Disclosures (Unaudited) to the consolidated financial statements for additional disclosures about the Standardized Measure.

The following table provides a reconciliation of the Standardized Measure to PV-10 Value for the periods indicated:
Year Ended December 31, Year Ended December 31,
In thousandsIn thousands202020192018In thousands202120202019
Standardized Measure (GAAP measure)Standardized Measure (GAAP measure)$654,734 $2,261,039 $3,351,385 Standardized Measure (GAAP measure)$2,187,051 $654,734 $2,261,039 
Discounted estimated future income taxDiscounted estimated future income tax48,346 354,629 673,754 Discounted estimated future income tax486,771 48,346 354,629 
PV-10 Value (non-GAAP measure)PV-10 Value (non-GAAP measure)$703,080 $2,615,668 $4,025,139 PV-10 Value (non-GAAP measure)$2,673,822 $703,080 $2,615,668 


FORWARD-LOOKING INFORMATION

The data and/or statements contained in this Annual Report on Form 10-K that are not historical facts, including, but not limited to, statements found in the sections entitled “Business“Business and Properties”Properties,” “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” are forward-looking statements, as that term is defined in Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and are statements that involve a number of risks and uncertainties.  Such forward-looking statements may be or may concern, among other things, our ability to capitalize on emerging from bankruptcythe level and our ability to succeed on a long-term basis, the extent and lengthsustainability of the droprecent increases in worldwide oil demand due to theprices from their COVID-19 coronavirus caused downturn, financial forecasts, the extent of future hydrocarbon prices and theiroil price volatility, current or future liquidity sources or their adequacy to support our anticipated future activities, possible future write-downsstatements or predictions related to the ultimate nature, timing and economic impacts of oilproposed carbon capture, use and natural gas reserves,storage industry arrangements, together with assumptions based on current and projected production levels, 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 expectations or estimations of our cash flows or the impact of changes in commodity prices on cash flows, availability of capital, borrowing capacity, price and availability of advantageous commodity derivative contracts or thetheir predicted downside cash flow benefits therefrom,protection or cash settlement payments required, forecasted capital expenditures, drilling activity or methods, including the timing and location thereof, the nature of any future asset purchases or sales or the timing or proceeds thereof, estimated timing of commencement of CO2 flooding ofinjections in particular fields or areas, including Cedar Creek Anticline (“CCA”), or the availability of capital for CCA pipeline construction, or its ultimate cost or date of completion, timing of CO2 injections and initial production responses in tertiary flooding projects, 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 laws or outcomes of any

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

flooding projects, development activities, finding costs, anticipated future cost savings, capital budgets, interpretation or prediction of formation details, production rates and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO2 reserves and supply and their availability, potential reserves, barrels or percentages of recoverable original oil in place, the impact of regulatory rulings or changes, outcomes of pending litigation, prospective legislation, orders or regulations affecting the oil and gas industry or environmental regulations, mark-to-market values, competition, rates of return, estimated costs, changes in costs, future capital expenditures and overall economics, worldwide or U.S. economic conditions, and other variables surrounding operations and future plans.  Such forward-looking statements generally are accompanied by words such as “plan,” “estimate,” “expect,” “predict,” “forecast,” “to our knowledge,” “anticipate,” “projected,” “preliminary,” “should,” “assume,” “believe,” “may” or other words that convey, or are intended to convey, the uncertainty of future events or outcomes.  Such forward-looking information is based upon management’s current plans, expectations, estimates, and assumptions and is subject to a number of risks and uncertainties that could significantly and adversely affect current plans, anticipated actions, the timing of such actions and our financial condition and results of operations.  As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by us or on our behalf.  Among the factors that could cause actual results to differ materially are fluctuations in worldwide oil prices or in U.S. oil pricesprice differentials and consequently in the prices received or demand for our oil produced; geopolitical actions and natural gas;reactions to recent Russian troop movements surrounding Ukraine; relaxation or removal of oil sanctions against Iran as part of diplomatic negotiations about Iran’s nuclear program; decisions as to production levels and/or pricing by OPEC or production levels by U.S. shale producers in future periods; levelsthe impact of COVID-19 on oil demand and economic activity levels; whether inflation impacts future capital expenditures;expenses; success of our risk management techniques; accuracy of our cost estimates; access to and terms of credit in the commercial banking or other debt markets; fluctuations in the prices of goods and services; the uncertainty of drilling results and reserve estimates; operating hazards and remediation costs; disruption of operations and damages from cybersecurity breaches, or from well incidents, climate events such as hurricanes, tropical storms, floods, forest fires, or other natural occurrences; acquisition risks; requirements for capital or its availability; conditions in the worldwide financial, trade and credit markets; general economic conditions; competition; government regulations, including changes in tax or environmental laws or regulations;regulations and consequent unexpected delays, as well as the risks and uncertainties inherent in oil and gas drilling and production activities or that are otherwise discussed in this annual 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.


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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The information required by Item 7A is set forth under Market Risk Management in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Item 8. Financial Statements and Supplementary Information
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7063

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Denbury Inc.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheetsheets of Denbury Inc. and its subsidiaries (Successor) (the “Company”) as of December 31, 2021 and 2020, and the related consolidated statements of operations, of changes in stockholders’ equity and of cash flows for the year ended December 31, 2021 and for the period from September 19, 2020 throughto December 31, 2020 including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2020,2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for the year ended December 31, 2021 and for the period from September 19, 2020 to December 31, 2020 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020,2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis of Accounting

As discussed in Note 1 to the consolidated financial statements, the United States Bankruptcy Court for the Southern District of Texas confirmed the Company’s prepackaged joint plan of reorganization (“the plan”) on September 2, 2020. Confirmation of the plan resulted in the discharge of all claims against the Company that arose before July 30, 2020 and terminates all rights and interests of equity security holders as provided for in the plan. The plan was substantially consummated on September 18, 2020 and the Company emerged from bankruptcy. In connection with its emergence from bankruptcy, the Company adopted fresh start accounting as of September 18, 2020.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audit.audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our auditaudits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the auditaudits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audit of the consolidated financial statementsaudits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our auditaudits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our auditaudits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit providesaudits provide a reasonable basis for our opinions.


7164

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

The Impact of Proved Oil and Natural Gas Reserves on Net Proved Oil and Natural Gas Properties

The Company’s net property and equipment balance, which includes net proved oil and natural gas properties, was $1,303.8$1,541.5 million as of December 31, 2020,2021, depletion, depreciation and amortization (DD&A) expense for the period from September 19, 2020 to December 31, 2020 was $45.8$150.6 million, and write-down of oil and natural gas properties from September 19, 2020 to December 31, 2020 was $1.0$14.4 million. As described in Note 1, the Company follows the full cost method of accounting for oil and gas properties. Under this method, all costs related to the acquisition, exploration and development of oil and natural gas reserves are capitalized and accumulated into a single cost center. The costs capitalized, including production equipment and future development costs, are depleted or depreciated using the unit-of-production method based on proved oil and natural gas reserves. As disclosed by management, under full cost accounting rules, management is required each quarter to perform a ceiling test calculation. 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. The process of estimating oil and natural gas reserves is very complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continued reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Estimating quantities of proved oil and natural gas reserves requires interpretations of available technical data and various assumptions, including future production rates, production costs, severance and excise taxes, capital expenditures and workover and remedial costs, and the assumed effect of governmental rules and regulations. Net proved oil and natural gas reserve estimates are determined by the Company’s internal reservoir engineering team and independent petroleum engineers (collectively “specialists”).

The principal considerations for our determination that performing procedures relating to the impact of proved oil and natural gas reserves on net proved oil and natural gas properties is a critical audit matter are (i) the significant judgment by management, including the use of specialists, when developing the estimates of proved oil and natural gas reserves, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit

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evidence obtained related to the data, methods, and assumptions used by management and its specialists in developing the

65

estimates of proved oil and natural gas reserves and the assumptions applied to the cost center ceiling test and the depletion, depreciation and amortization calculation related to future production rates.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved oil and natural gas reserves, and ceiling test calculation and the depletion, depreciation and amortization calculation. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved oil and natural gas reserves and the reasonableness of the future production rates applied in the cost center ceiling test.test and the depletion, depreciation and amortization calculation. As a basis for using this work, the specialists’ qualifications were understood and the company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists, and an evaluation of the specialists’ findings.

/s/ PricewaterhouseCoopers LLP

Dallas, Texas
March 5, 2021February 24, 2022

We have served as the Company’s auditor since 2004.


7366

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Denbury Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheetstatements of operations, of changes in stockholders’ equity and of cash flows of Denbury Resources Inc. and its subsidiaries (Predecessor) (the “Company”) as of December 31, 2019, and the related consolidated statements of operations, of changes in stockholders' equity and of cash flows for the period from January 1, 2020 throughto September 18, 2020 and for each of the two years in the periodyear ended December 31, 2019 including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial positionresults of operations and cash flows of the Company as of December 31, 2019, and the results of its operations and its cash flows for the period from January 1, 2020 to September 18, 2020 and for each of the two years in the periodyear ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America.

Basis of Accounting

As discussed in Note 1 to the consolidated financial statements, the Company filed petitions on July 30, 2020 with the United States Bankruptcy Court for the Southern District of Texas for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. The Company’s prepackaged joint plan of reorganization was substantially consummated on September 18, 2020 and the Company emerged from bankruptcy. In connection with its emergence from bankruptcy, the Company adopted fresh start accounting. This matter is also described in the “Critical Audit Matters” section of our report.

Change in Accounting Principle

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.


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The Impact of Proved Oil and Natural Gas Reserves on Net Proved Oil and Natural Gas Properties

As described in Note 2 to the consolidated financial statements, the Company’s net property and equipment balance, which includes net proved oil and natural gas properties, was $1,311.6 million as of September 18, 2020, depletion, depreciation and amortization (DD&A) expense for the period from January 1, 2020 to September 18, 2020 was $188.6 million, and write-down of oil and natural gas properties for the period from January 1, 2020 to September 18, 2020 was $996.7 million. As described in Note 1, the Company follows the full cost method of accounting for oil and gas properties. Under this method, all costs related to the acquisition, exploration and development of oil and natural gas reserves are capitalized and accumulated into a single cost center. The costs capitalized, including production equipment and future development costs, are depleted or depreciated using the unit-of-production method based on proved oil and natural gas reserves. As disclosed by management, under full cost accounting rules, management is required each quarter to perform a ceiling test calculation. 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. The process of estimating oil and natural gas reserves is very complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continued reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Estimating quantities of proved oil and natural gas reserves requires interpretations of available technical data and various assumptions, including future production rates, production costs, severance and excise taxes, capital expenditures and workover and remedial costs, and the assumed effect of governmental rules and regulations. Net proved oil and natural gas reserve estimates are determined by the Company’s internal reservoir engineering team and independent petroleum engineers (collectively “specialists”).

The principal considerations for our determination that performing procedures relating to the impact of proved oil and natural gas reserves on net proved oil and natural gas properties is a critical audit matter are (i) the significant judgment by management, including the use of specialists, when developing the estimates of proved oil and natural gas reserves, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence obtained related to the data, methods, and assumptions used by management and its specialists in developing the estimates of proved oil and natural gas reserves and the assumptions applied to the cost center ceiling test related to future production rates.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved oil and natural gas reserves and the reasonableness of the future production rates applied in the cost center ceiling test. As a basis for using this work, the specialists’ qualifications were understood and the company’s relationship with the specialists was assessed. The procedures performed included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists, and an evaluation of the specialists’ findings.

Fresh Start Fair Value Adjustments to Proved Oil and Natural Gas Properties

As described above and in Notes 1 and 2 to the consolidated financial statements, Denbury Inc. (Successor) became the successor reporting company of Denbury Resources Inc. (Predecessor) upon the emergence from bankruptcy on September 18, 2020. During the Predecessor period, the Company applied generally accepted accounting principles for reorganizations, which requires the financial statements for periods subsequent to the commencement of the Chapter 11 Restructuring on July 30, 2020 to distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Upon emergence from bankruptcy, the Company was required to adopt fresh start accounting. Fresh start accounting requires that new fair values be established for the Company’s assets, liabilities and equity as of the date of emergence from bankruptcy, September 18, 2020. The Company’s reorganization items, net was $850.0 million for the period from January 1, 2020 through September 18, 2020, which included fresh start fair value adjustments to proved oil and natural gas properties of $10,941.3 million. The Company determined the fair value of its oil and gas properties based on discounted cash flows. The fair value analysis was based on the Company’s estimated future production rates of proved and probable reserves as prepared by the Company’s independent petroleum engineers. Discounted cash flow models were prepared using the estimated future

75

revenues and operating costs for all developed wells and undeveloped properties comprising the proved and probable reserves. Future revenues were based upon future production rates and forward strip oil and natural gas prices. Operating costs were adjusted for inflation beginning in year 2025. A risk adjustment factor was applied to each reserve category, consistent with the risk of the category. The discounted cash flow models also included adjustments for income tax expenses. Discount factors utilized were derived using a weighted average cost of capital computation, which included an estimated cost of debt and equity for market participants with similar geographies and asset development type and varying corporate income tax rates based on the expected point of sale for each property’s produced assets.

The principal considerations for our determination that performing procedures relating to the fresh start fair value adjustments to proved oil and natural gas properties is a critical audit matter are (i) the significant judgment by management, including the use of specialists, when developing the fresh start fair value adjustments of proved oil and natural gas properties; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to future production rates, forward strip oil and natural gas pricing, operating costs, capital expenditures, and weighted average cost of capital; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included, among others (i) evaluating the appropriateness of the discounted cash flow model; (ii) testing the completeness and accuracy of underlying data used in the discounted cash flow model; and (iii) evaluating the significant assumptions used by management related to future production rates, forward strip oil and natural gas pricing, operating costs, capital expenditures, and weighted average cost of capital. The work of specialists was used in performing the procedures to evaluate the reasonableness of estimates of proved oil and natural gas reserves as stated in the Critical Audit Matter titled “The Impact of Proved Oil and Natural Gas Reserves on Net Proved Oil and Natural Gas Properties” and the reasonableness of the future production rates used in the discounted cash flow models. As a basis for using this work, the specialists’ qualifications were understood and the company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists and an evaluation of the specialists’ findings. Evaluating the reasonableness of management’s assumptions relating to forward strip oil and natural gas pricing, operating costs, and capital expenditures involved evaluating whether the assumptions used by management were reasonable considering the current and past performance of the Company, the consistency with external market and industry data, and whether the assumptions were consistent with evidence obtained in other areas of the audit. Professionals with specialized skill and knowledge were used to assist in assessing the appropriateness of the discounted cash flow models and the reasonableness of the weighted average cost of capital.

/s/ PricewaterhouseCoopers LLP

Dallas, Texas
March 5, 2021

We have served as the Company’s auditor since 2004.

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Table of Contents
Denbury Inc.
Consolidated Balance Sheets
(In thousands, except par value and share data)

 SuccessorPredecessor
 December 31, 2020December 31, 2019
Assets
Current assets  
Cash and cash equivalents$518 $516 
Restricted cash1,000 0 
Accrued production receivable91,421 139,407 
Trade and other receivables, net19,682 18,318 
Derivative assets187 11,936 
Prepaids14,038 10,434 
Total current assets126,846 180,611 
Property and equipment  
Oil and natural gas properties (using full cost accounting)  
Proved properties851,208 11,447,680 
Unevaluated properties85,304 872,910 
CO2 properties
188,288 1,198,846 
Pipelines133,485 2,329,078 
Other property and equipment86,610 212,334 
Less accumulated depletion, depreciation, amortization and impairment(41,095)(11,688,020)
Net property and equipment1,303,800 4,372,828 
Operating lease right-of-use assets20,342 34,099 
Intangible assets, net97,362 22,139 
Other assets86,408 82,190 
Total assets$1,634,758 $4,691,867 

See accompanying Notes to Consolidated Financial Statements.




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Table of Contents
Denbury Inc.
Consolidated Balance Sheets
(In thousands, except par value and share data)
 SuccessorPredecessor
 December 31, 2020December 31, 2019
Liabilities and Stockholders’ Equity
Current liabilities  
Accounts payable and accrued liabilities$112,671 $183,832 
Oil and gas production payable49,165 62,869 
Derivative liabilities53,865 8,346 
Current maturities of long-term debt (including future interest payable of $0 and $86,054, respectively – see Note 8)68,008 102,294 
Operating lease liabilities1,350 6,901 
Total current liabilities285,059 364,242 
Long-term liabilities
Long-term debt, net of current portion (including future interest payable of $0 and $78,860, respectively – see Note 8)70,000 2,232,570 
Asset retirement obligations179,338 177,108 
Derivative liabilities5,087 0 
Deferred tax liabilities, net1,274 410,230 
Operating lease liabilities19,460 41,932 
Other liabilities20,872 53,526 
Total long-term liabilities296,031 2,915,366 
Commitments and contingencies (Note 14)00
Stockholders’ equity
Predecessor preferred stock, $.001 par value, 25,000,000 shares authorized, none issued and outstanding— 0 
Predecessor common stock, $.001 par value, 750,000,000 shares authorized; 508,065,495 shares issued— 508 
Predecessor paid-in capital in excess of par— 2,739,099 
Predecessor treasury stock, at cost, 1,652,771 shares— (6,034)
Successor preferred stock, $.001 par value, 50,000,000 shares authorized, none issued and outstanding0 — 
Successor common stock, $.001 par value, 250,000,000 shares authorized; 49,999,999 shares issued50 — 
Successor paid-in capital in excess of par1,104,276 — 
Accumulated deficit(50,658)(1,321,314)
Total stockholders’ equity1,053,668 1,412,259 
Total liabilities and stockholders’ equity$1,634,758 $4,691,867 

 Successor
 December 31, 2021December 31, 2020
Assets
Current assets  
Cash and cash equivalents$3,671 $518 
Restricted cash— 1,000 
Accrued production receivable143,365 91,421 
Trade and other receivables, net19,270 19,682 
Derivative assets— 187 
Prepaids9,099 14,038 
Total current assets175,405 126,846 
Property and equipment  
Oil and natural gas properties (using full cost accounting)  
Proved properties1,109,011 851,208 
Unevaluated properties112,169 85,304 
CO2 properties
183,369 188,288 
Pipelines224,394 133,485 
Other property and equipment93,950 86,610 
Less accumulated depletion, depreciation, amortization and impairment(181,393)(41,095)
Net property and equipment1,541,500 1,303,800 
Operating lease right-of-use assets19,502 20,342 
Intangible assets, net88,248 97,362 
Other assets78,298 86,408 
Total assets$1,902,953 $1,634,758 
Liabilities and Stockholders’ Equity
Current liabilities  
Accounts payable and accrued liabilities$191,598 $112,671 
Oil and gas production payable75,899 49,165 
Derivative liabilities134,509 53,865 
Current maturities of long-term debt— 68,008 
Operating lease liabilities4,677 1,350 
Total current liabilities406,683 285,059 
Long-term liabilities  
Long-term debt, net of current portion35,000 70,000 
Asset retirement obligations284,238 179,338 
Derivative liabilities— 5,087 
Deferred tax liabilities, net1,638 1,274 
Operating lease liabilities17,094 19,460 
Other liabilities22,910 20,872 
Total long-term liabilities360,880 296,031 
Commitments and contingencies (Note 14)00
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; 50,193,656 and 49,999,999 shares issued, respectively50 50 
Paid-in capital in excess of par1,129,996 1,104,276 
Retained earnings (accumulated deficit)5,344 (50,658)
Total stockholders’ equity1,135,390 1,053,668 
Total liabilities and stockholders’ equity$1,902,953 $1,634,758 
See accompanying Notes to Consolidated Financial Statements.

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Table of Contents
Denbury Inc.
Consolidated Statements of Operations
(In thousands, except per-share data)


SuccessorPredecessorSuccessorPredecessor
Period from
Sept. 19, 2020 through
Dec. 31, 2020		Period from
Jan. 1, 2020 through
Sept. 18, 2020		Year Ended December 31, Year Ended
Dec. 31, 2021		Period from
Sept. 19, 2020 through
Dec. 31, 2020		Period from
Jan. 1, 2020 through
Sept. 18, 2020		Year Ended
Dec. 31, 2019
20192018
Revenues and other incomeRevenues and other income   Revenues and other income   
Oil, natural gas, and related product salesOil, natural gas, and related product sales$201,108 $492,101 $1,212,020 $1,422,589 Oil, natural gas, and related product sales$1,159,955 $201,108 $492,101 $1,212,020 
CO2 sales and transportation fees
CO2 sales and transportation fees
9,419 21,049 34,142 31,145 
CO2 sales and transportation fees
44,175 9,419 21,049 34,142 
Oil marketing revenuesOil marketing revenues5,376 8,543 14,198 1,921 Oil marketing revenues38,742 5,376 8,543 14,198 
Other incomeOther income4,697 8,419 14,523 17,970 Other income15,288 4,697 8,419 14,523 
Total revenues and other incomeTotal revenues and other income220,600 530,112 1,274,883 1,473,625 Total revenues and other income1,258,160 220,600 530,112 1,274,883 
ExpensesExpenses   Expenses   
Lease operating expensesLease operating expenses101,234 250,271 477,220 489,720 Lease operating expenses424,550 101,234 250,271 477,220 
Transportation and marketing expensesTransportation and marketing expenses10,595 27,164 41,810 43,942 Transportation and marketing expenses28,817 10,595 27,164 41,810 
CO2 operating and discovery expenses
CO2 operating and discovery expenses
1,976 2,592 2,922 2,816 
CO2 operating and discovery expenses
6,678 1,976 2,592 2,922 
Taxes other than incomeTaxes other than income16,584 43,531 93,752 104,670 Taxes other than income91,390 16,584 43,531 93,752 
Oil marketing expenses5,318 8,399 14,124 1,676 
Oil marketing purchasesOil marketing purchases37,734 5,318 8,399 14,124 
General and administrative expensesGeneral and administrative expenses19,470 48,522 83,029 71,495 General and administrative expenses79,258 19,470 48,522 83,029 
Interest, net of amounts capitalized of $1,261, $22,885, $36,671 and $37,079, respectively1,815 48,267 81,632 69,688 
Interest, net of amounts capitalized of $4,585, $1,261, $22,885 and $36,671, respectivelyInterest, net of amounts capitalized of $4,585, $1,261, $22,885 and $36,671, respectively4,147 1,815 48,267 81,632 
Depletion, depreciation, and amortizationDepletion, depreciation, and amortization45,812 188,593 233,816 216,449 Depletion, depreciation, and amortization150,640 45,812 188,593 233,816 
Commodity derivatives expense (income)Commodity derivatives expense (income)61,902 (102,032)70,078 (21,087)Commodity derivatives expense (income)352,984 61,902 (102,032)70,078 
Gain on debt extinguishmentGain on debt extinguishment0 (18,994)(155,998)0 Gain on debt extinguishment— — (18,994)(155,998)
Write-down of oil and natural gas propertiesWrite-down of oil and natural gas properties1,006 996,658 0 0 Write-down of oil and natural gas properties14,377 1,006 996,658 — 
Reorganization items, netReorganization items, net0 849,980 0 0 Reorganization items, net— — 849,980 — 
Other expensesOther expenses8,072 35,868 11,187 84,325 Other expenses10,816 8,072 35,868 11,187 
Total expensesTotal expenses273,784 2,378,819 953,572 1,063,694 Total expenses1,201,391 273,784 2,378,819 953,572 
Income (loss) before income taxesIncome (loss) before income taxes(53,184)(1,848,707)321,311 409,931 Income (loss) before income taxes56,769 (53,184)(1,848,707)321,311 
Income tax provision (benefit)Income tax provision (benefit)(2,526)(416,129)104,352 87,233 Income tax provision (benefit)767 (2,526)(416,129)104,352 
Net income (loss)Net income (loss)$(50,658)$(1,432,578)$216,959 $322,698 Net income (loss)$56,002 $(50,658)$(1,432,578)$216,959 
Net income (loss) per common shareNet income (loss) per common shareNet income (loss) per common share
BasicBasic$(1.01)$(2.89)$0.47 $0.75 Basic$1.10 $(1.01)$(2.89)$0.47 
DilutedDiluted$(1.01)$(2.89)$0.45 $0.71 Diluted$1.04 $(1.01)$(2.89)$0.45 
Weighted average common shares outstandingWeighted average common shares outstanding   Weighted average common shares outstanding   
BasicBasic50,000 495,560 459,524 432,483 Basic50,918 50,000 495,560 459,524 
DilutedDiluted50,000 495,560 510,341 456,169 Diluted53,818 50,000 495,560 510,341 

See accompanying Notes to Consolidated Financial Statements.

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Table of Contents
Denbury Inc.
Consolidated Statements of Cash Flows
(In thousands)

SuccessorPredecessorSuccessorPredecessor
Period from
Sept. 19, 2020 through
Dec. 31, 2020		Period from
Jan. 1, 2020 through
Sept. 18, 2020		Year Ended December 31, Year Ended
Dec. 31, 2021		Period from
Sept. 19, 2020 through
Dec. 31, 2020		Period from
Jan. 1, 2020 through
Sept. 18, 2020		Year Ended
Dec. 31, 2019
20192018
Cash flows from operating activitiesCash flows from operating activities   Cash flows from operating activities   
Net income (loss)Net income (loss)$(50,658)$(1,432,578)$216,959 $322,698 Net income (loss)$56,002 $(50,658)$(1,432,578)$216,959 
Adjustments to reconcile net income (loss) to cash flows from operating activitiesAdjustments to reconcile net income (loss) to cash flows from operating activities  Adjustments to reconcile net income (loss) to cash flows from operating activities  
Noncash reorganization items, netNoncash reorganization items, net0 810,909 0 0 Noncash reorganization items, net— — 810,909 — 
Depletion, depreciation, and amortizationDepletion, depreciation, and amortization45,812 188,593 233,816 216,449 Depletion, depreciation, and amortization150,640 45,812 188,593 233,816 
Write-down of oil and natural gas propertiesWrite-down of oil and natural gas properties1,006 996,658 0 0 Write-down of oil and natural gas properties14,377 1,006 996,658 — 
Deferred income taxesDeferred income taxes(2,556)(408,869)100,471 103,234 Deferred income taxes364 (2,556)(408,869)100,471 
Stock-based compensationStock-based compensation8,212 4,111 12,470 11,951 Stock-based compensation25,322 8,212 4,111 12,470 
Commodity derivatives expense (income)Commodity derivatives expense (income)61,902 (102,032)70,078 (21,087)Commodity derivatives expense (income)352,984 61,902 (102,032)70,078 
Receipt (payment) on settlements of commodity derivativesReceipt (payment) on settlements of commodity derivatives21,089 81,396 23,606 (175,248)Receipt (payment) on settlements of commodity derivatives(277,240)21,089 81,396 23,606 
Gain on debt extinguishmentGain on debt extinguishment0 (18,994)(155,998)0 Gain on debt extinguishment— — (18,994)(155,998)
Debt issuance costs and discountsDebt issuance costs and discounts799 11,571 12,303 6,246 Debt issuance costs and discounts2,740 799 11,571 12,303 
Gain from asset sales and otherGain from asset sales and other(10,609)(3,546)(6,723)(8,504)
Other, netOther, net(2,349)439 (8,596)(4,725)Other, net(2,465)1,197 7,162 (92)
Changes in assets and liabilities, net of effects from acquisitionsChanges in assets and liabilities, net of effects from acquisitions   Changes in assets and liabilities, net of effects from acquisitions   
Accrued production receivableAccrued production receivable21,411 26,575 (13,619)20,547 Accrued production receivable(51,944)21,411 26,575 (13,619)
Trade and other receivablesTrade and other receivables15,567 (22,343)9,379 16,094 Trade and other receivables(284)15,567 (22,343)9,379 
Other current and long-term assetsOther current and long-term assets(1,795)743 7,629 (6,827)Other current and long-term assets10,390 (1,795)743 7,629 
Accounts payable and accrued liabilitiesAccounts payable and accrued liabilities(67,167)(16,102)(3,275)13,008 Accounts payable and accrued liabilities28,500 (67,167)(16,102)(3,275)
Oil and natural gas production payableOil and natural gas production payable(6,912)(6,792)2,170 (15,300)Oil and natural gas production payable29,351 (6,912)(6,792)2,170 
Other liabilitiesOther liabilities(4,035)123 (13,250)42,645 Other liabilities(10,970)(4,035)123 (13,250)
Net cash provided by operating activitiesNet cash provided by operating activities40,326 113,408 494,143 529,685 Net cash provided by operating activities317,158 40,326 113,408 494,143 
Cash flows from investing activitiesCash flows from investing activities   Cash flows from investing activities   
Oil and natural gas capital expendituresOil and natural gas capital expenditures(17,964)(99,582)(262,005)(316,647)Oil and natural gas capital expenditures(150,911)(17,964)(99,582)(262,005)
CO2 capital expenditures
(269)(196)(3,154)(5,878)
Pipelines and plants capital expenditures(618)(11,601)(27,319)(23,108)
Acquisitions of oil and natural gas propertiesAcquisitions of oil and natural gas properties(10,979)(82)— (79)
Pipeline capital expendituresPipeline capital expenditures(69,223)(618)(11,601)(27,319)
Net proceeds from sales of oil and natural gas properties and equipmentNet proceeds from sales of oil and natural gas properties and equipment938 41,322 10,196 7,762 Net proceeds from sales of oil and natural gas properties and equipment19,053 938 41,322 10,196 
OtherOther16,029 12,943 12,590 4,595 Other9,128 15,842 12,747 9,515 
Net cash used in investing activitiesNet cash used in investing activities(1,884)(57,114)(269,692)(333,276)Net cash used in investing activities(202,932)(1,884)(57,114)(269,692)
Cash flows from financing activitiesCash flows from financing activities   Cash flows from financing activities   
Bank repaymentsBank repayments(190,000)(551,000)(925,791)(1,982,653)Bank repayments(933,000)(190,000)(551,000)(925,791)
Bank borrowingsBank borrowings120,000 691,000 925,791 1,507,653 Bank borrowings898,000 120,000 691,000 925,791 
Interest payments treated as a reduction of debtInterest payments treated as a reduction of debt0 (46,417)(85,303)(79,606)Interest payments treated as a reduction of debt— — (46,417)(85,303)
Proceeds from issuance of senior secured notes0 0 0 450,000 
Cash paid in conjunction with debt exchangeCash paid in conjunction with debt exchange0 0 (136,427)0 Cash paid in conjunction with debt exchange— — — (136,427)
Cash paid in conjunction with debt repurchasesCash paid in conjunction with debt repurchases0 (14,171)0 0 Cash paid in conjunction with debt repurchases— — (14,171)— 
Costs of debt financingCosts of debt financing(8)(12,482)(11,065)(16,060)Costs of debt financing— (8)(12,482)(11,065)
Pipeline financing and capital lease debt repaymentsPipeline financing and capital lease debt repayments(22,938)(51,792)(13,908)(23,300)Pipeline financing and capital lease debt repayments(68,008)(22,938)(51,792)(13,908)
OtherOther1,638 (9,363)348 (13,486)Other(3,122)1,638 (9,363)348 
Net cash provided by (used in) financing activitiesNet cash provided by (used in) financing activities(91,308)5,775 (246,355)(157,452)Net cash provided by (used in) financing activities(106,130)(91,308)5,775 (246,355)
Net increase (decrease) in cash, cash equivalents, and restricted cashNet increase (decrease) in cash, cash equivalents, and restricted cash(52,866)62,069 (21,904)38,957 Net increase (decrease) in cash, cash equivalents, and restricted cash8,096 (52,866)62,069 (21,904)
Cash, cash equivalents, and restricted cash at beginning of periodCash, cash equivalents, and restricted cash at beginning of period95,114 33,045 54,949 15,992 Cash, cash equivalents, and restricted cash at beginning of period42,248 95,114 33,045 54,949 
Cash, cash equivalents, and restricted cash at end of periodCash, cash equivalents, and restricted cash at end of period$42,248 $95,114 $33,045 $54,949 Cash, cash equivalents, and restricted cash at end of period$50,344 $42,248 $95,114 $33,045 

 See accompanying Notes to Consolidated Financial Statements.

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Table of Contents
Denbury Inc.
Consolidated Statements of Changes in Stockholders’ Equity
(Dollar amounts in thousands)

Common Stock
($.001 Par Value)		Paid-In
Capital in
Excess of
Par		Retained
Earnings (Accumulated Deficit)		Treasury Stock
(at cost)		Total Equity Common Stock
($.001 Par Value)		Paid-In
Capital in
Excess of
Par		Retained
Earnings (Accumulated Deficit)		Treasury Stock
(at cost)		Total Equity
SharesAmountSharesAmountSharesAmountSharesAmount
Balance – December 31, 2017 (Predecessor)402,549,346 $403 $2,507,828 $(1,855,810)457,041 $(4,256)$648,165 
Issued pursuant to stock compensation plans4,556,424 4 (4)— — — — 
Issued pursuant to notes conversion55,249,955 55 161,949 — — — 162,004 
Stock-based compensation— — 15,438 — — — 15,438 
Tax withholding for stock compensation plans— — — — 1,484,708 (6,528)(6,528)
Net income— — — 322,698 — — 322,698 
Balance – December 31, 2018 (Predecessor)Balance – December 31, 2018 (Predecessor)462,355,725 462 2,685,211 (1,533,112)1,941,749 (10,784)1,141,777 Balance – December 31, 2018 (Predecessor)462,355,725 $462 $2,685,211 $(1,533,112)1,941,749 $(10,784)$1,141,777 
Issued pursuant to stock compensation plansIssued pursuant to stock compensation plans9,315,016 9 (9)— — — — Issued pursuant to stock compensation plans9,315,016 9 (9)— — — — 
Issued pursuant to directors’ compensation planIssued pursuant to directors’ compensation plan97,537 — — — — — — Issued pursuant to directors’ compensation plan97,537 — — — — — — 
Issued pursuant to senior subordinated notes exchangesIssued pursuant to senior subordinated notes exchanges36,297,217 37 37,409 (5,161)(1,990,000)7,270 39,555 Issued pursuant to senior subordinated notes exchanges36,297,217 37 37,409 (5,161)(1,990,000)7,270 39,555 
Stock-based compensationStock-based compensation— — 16,488 — — — 16,488 Stock-based compensation— — 16,488 — — — 16,488 
Tax withholding for stock compensation plansTax withholding for stock compensation plans— — — — 1,701,022 (2,520)(2,520)Tax withholding for stock compensation plans— — — — 1,701,022 (2,520)(2,520)
Net incomeNet income— — — 216,959 — — 216,959 Net income— — — 216,959 — — 216,959 
Balance – December 31, 2019 (Predecessor)Balance – December 31, 2019 (Predecessor)508,065,495 508 2,739,099 (1,321,314)1,652,771 (6,034)1,412,259 Balance – December 31, 2019 (Predecessor)508,065,495 508 2,739,099 (1,321,314)1,652,771 (6,034)1,412,259 
Issued pursuant to stock compensation plansIssued pursuant to stock compensation plans312,516 — — — — — — Issued pursuant to stock compensation plans312,516 — — — — — — 
Issued pursuant to directors' compensation planIssued pursuant to directors' compensation plan37,367 — — — — — — Issued pursuant to directors' compensation plan37,367 — — — — — — 
Stock-based compensationStock-based compensation— — 14,317 — — — 14,317 Stock-based compensation— — 14,317 — — — 14,317 
Issued pursuant to notes conversionIssued pursuant to notes conversion7,372,250 8 11,493 — — — 11,501 Issued pursuant to notes conversion7,372,250 8 11,493 — — — 11,501 
Canceled pursuant to stock compensation plansCanceled pursuant to stock compensation plans(6,313,884)(6)6 — — — 0 Canceled pursuant to stock compensation plans(6,313,884)(6)6 — — — — 
Tax withholding for stock compensation plansTax withholding for stock compensation plans— — — — 742,862 (168)(168)Tax withholding for stock compensation plans— — — — 742,862 (168)(168)
Net lossNet loss— — — (1,432,578)— — (1,432,578)Net loss— — — (1,432,578)— — (1,432,578)
Cancellation of Predecessor equityCancellation of Predecessor equity(509,473,744)(510)(2,764,915)2,753,892 (2,395,633)6,202 (5,331)Cancellation of Predecessor equity(509,473,744)(510)(2,764,915)2,753,892 (2,395,633)6,202 (5,331)
Issuance of Successor equityIssuance of Successor equity49,999,999 50 1,095,369 — — — 1,095,419 Issuance of Successor equity49,999,999 50 1,095,369 — — — 1,095,419 
Balance – September 18, 2020 (Predecessor)Balance – September 18, 2020 (Predecessor)49,999,999 $50 $1,095,369 $0 0 $0 $1,095,419 Balance – September 18, 2020 (Predecessor)49,999,999 $50 $1,095,369 $— — $— $1,095,419 
Balance – September 19, 2020 (Successor)Balance – September 19, 2020 (Successor)49,999,999 $50 $1,095,369 $0 0 $0 $1,095,419 Balance – September 19, 2020 (Successor)49,999,999 $50 $1,095,369 $— — $— $1,095,419 
Stock-based compensationStock-based compensation— — 8,907 — — — 8,907 Stock-based compensation— — 8,907 — — — 8,907 
Net lossNet loss— — — (50,658)— — (50,658)Net loss— — — (50,658)— — (50,658)
Balance – December 31, 2020 (Successor)Balance – December 31, 2020 (Successor)49,999,999 $50 $1,104,276 $(50,658)0 $0 $1,053,668 Balance – December 31, 2020 (Successor)49,999,999 50 1,104,276 (50,658)— — 1,053,668 
Stock-based compensationStock-based compensation— — 27,205 — — — 27,205 
Tax withholding for stock compensation plansTax withholding for stock compensation plans— — (2,244)— — — (2,244)
Issued pursuant to exercise of warrantsIssued pursuant to exercise of warrants193,657 — 759 — — — 759 
Net incomeNet income— — — 56,002 — — 56,002 
Balance – December 31, 2021 (Successor)Balance – December 31, 2021 (Successor)50,193,656 $50 $1,129,996 $5,344 — $— $1,135,390 

 See accompanying Notes to Consolidated Financial Statements.

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Note 1. Nature of Operations and Summary of Significant Accounting Policies

Organization and Nature of Operations

Denbury Inc. (“Denbury,” “Company” or the “Successor”), a Delaware corporation, is an independent energy company with operations focused on producing oil from mature oil fields in the Gulf Coast and Rocky Mountain regions.regions of the United States. The Company is differentiated by itsour focus on CO2 EOR and the emerging CCUS industry, supported by the Company’s CO2 EOR technical and operational expertise and its extensive CO2 pipeline infrastructure. The utilization of captured industrial-sourced CO2 in EOR significantly reduces the carbon footprint of the oil that Denbury produces, underpinning the Company’s goal to fully offset its Scope 1, 2, and 3 CO2 emissions within the decade.

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

Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code

On July 28, 2020, Denbury Resources Inc. and its subsidiaries entered into a Restructuring Support Agreement (the “RSA”)restructuring support agreement with lenders holding 100% of the revolving loans under our pre-petition revolving bank credit facility and debtholders holding approximately 67.1% of our senior secured second lien notes and approximately 73.1% of our convertible senior notes, which contemplated a restructuring of the Company pursuant to a prepackaged joint plan of reorganization (the “Plan”). On July 30, 2020 (the “Petition Date”), Denbury Resources Inc. and its subsidiaries filed petitions for reorganization in a “prepackaged” voluntary bankruptcy (the “Chapter 11 Restructuring”) under chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”) under the caption “In re Denbury Resources Inc., et al., Case No. 20-33801”. On September 2, 2020, the Bankruptcy Court entered an order (the “Confirmation Order”) confirming the Plan and approving the Disclosure Statement, and on September 18, 2020 (the “Emergence Date”), the Plan became effective in accordance with its terms and the Company emerged from Chapter 11. On April 23, 2021, the Bankruptcy Court entered a final decree closing the Chapter 11 case captioned “In re Denbury Resources Inc., et al., Case No. 20-33801”; therefore, we have no remaining obligations related to this reorganization.

On the Emergence Date and pursuant to the terms of the Plan and the Confirmation Order, all outstanding obligations under the senior secured second lien notes, convertible senior notes, and senior subordinated notes were fully extinguished, relieving approximately $2.1 billion in aggregate principal of debt by issuing equity and/or warrants in the Successor to the former holders of that debt, and the Company:

•Adopted an amended and restated certificate of incorporation and bylaws which reserved for issuance 250,000,000 shares of common stock, par value $0.001 per share, of Denbury (the “New Common Stock”) and 50,000,000 shares of preferred stock, par value $0.001 per share;
•Cancelled all outstanding senior secured second lien notes, convertible senior notes, and senior subordinated notes issued by the Predecessor. In accordance with the Plan, claims against and interests in the Predecessor were treated as follows:

◦Holders of secured pipeline lease claims received payment in full in cash, the collateral securing such pipeline lease claim, reinstatement, or such other treatment rendering such pipeline lease claim unimpaired (see Note 8, Long-Term Debt – Restructuring of Pipeline Financing Transactions, for discussion of subsequent pipeline transactions);
◦Holders of senior secured second lien notes claims received their pro rata share of 47,499,999 shares representing 95% of the New Common Stock issued on the Emergence Date, subject to dilution on account of warrants and a management incentive plan;
◦Holders of convertible senior notes claims received their pro rata share of (a) 2,500,000 shares representing 5% of the New Common Stock issued on the Emergence Date, subject to dilution on account of warrants and

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a management incentive plan and (b) 100% of the series A warrants (see below), reflecting up to a maximum of 5% ownership stake in the reorganized company’s equity interests;

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◦Holders of subordinated notes claims received their pro rata share of 54.55% of the series B warrants (see below), reflecting up to a maximum of 3% of the reorganized company’s equity interests after giving effect to the exercise of the series A warrants;
◦Holders of existing equity interests received their pro rata share of 45.45% of the series B warrants (see below), reflecting up to a maximum of 2.5% of the reorganized company’s equity interests after giving effect to the exercise of the series A warrants;
◦Issued 2,631,579 series A warrants at an exercise price of $32.59 per share to former holders of the Predecessor’s convertible senior notes and 2,894,740 series B warrants at an exercise price of $35.41 per share to former holders of the Predecessor’s senior subordinated notes and Predecessor’s equity interests; and
◦Holders of general unsecured claims received payment in full in cash, reimbursement, or such other treatment rendering such general unsecured claim unimpaired.
•Entered into a new senior secured revolving credit agreement with a syndicate of banks (the “Successor Bank Credit Agreement”) with total aggregate commitments of $575 million;
•Appointed a new board of directors (the “Board”) consisting of four new independent members: Anthony Abate, Caroline Angoorly, Brett Wiggs and James N. “Jim” Chapman, and three continuing members: Dr. Kevin O. Meyers (Chairman of the Board), Lynn A. Peterson and Chris Kendall, Denbury’s President and Chief Executive Officer; and
•Adopted a framework for a management incentive plan which reserves for officers, other employees, directors and other service providers a pool of shares of New Common Stock, with initial awards issued on December 4, 2020 (see Note 11, Stock Compensation, for further discussion).

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

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

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

Principles of Reporting and Consolidation

The consolidated financial statements herein have been prepared in accordance with GAAP and include the accounts of Denbury and entities in which we hold a controlling financial interest.  Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis.  All intercompany balances and transactions have been eliminated.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amount of certain assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during each reporting period.  Management believes its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and

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uncertainties that may cause actual results to differ materially from such estimates.  Significant estimates underlying these financial statements include (1) the fair value of financial derivative instruments; (2) the estimated quantities of proved oil and

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natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom and the ceiling test; (3) future net cash flow estimates used in the impairment assessment of long-lived assets; (4) the estimated quantities of proved and probable CO2 reserves used to compute depletion of CO2 properties; (5) estimated useful lives used to compute depreciation and amortization of long-lived assets; (6) accruals related to oil and natural gas sales volumes and revenues, capital expenditures and lease operating expenses; (7) the estimated costs and timing of future asset retirement obligations; (8) estimates made in the calculation of income taxes; (9) estimates made in determining the fair values for purchase price allocations; and (9)(10) fair value estimates including estimates of reorganization value, enterprise value, and the fair value of assets and liabilities recorded as a result of the adoption of fresh start accounting.  While management is not aware of any significant revisions to any of its current year-end estimates, there will likely be future revisions to its estimates resulting from matters such as revisions in estimated oil and natural gas volumes, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and natural gas industry, many of which require retroactive application.  These types of adjustments cannot be currently estimated and will be recorded in the period in which the adjustment occurs. 

Business Segment Information

We have evaluated the organization and management of our business and identified only 1 operating segment related to our oil and natural gas operations. Management measures financial performance and makes capital allocation decisions as a single enterprise and not on a geographical or area-by-area basis. All of our operating revenues, income from operations and assets are generated in the United States.

Reclassifications

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

Cash, Cash Equivalents, and Restricted Cash

We consider all highly liquid investments to be cash equivalents if they have maturities of three months or less at the date of purchase. The following table provides a reconciliation of cash, cash equivalents, and restricted cash as reported within the Consolidated Balance Sheets to “Cash, cash equivalents, and restricted cash at end of period” as reported within the Consolidated Statements of Cash Flows:
SuccessorPredecessorSuccessor
In thousandsIn thousandsDecember 31, 2020December 31, 2019In thousandsDecember 31, 2021December 31, 2020
Cash and cash equivalentsCash and cash equivalents$518 $516 Cash and cash equivalents$3,671 $518 
Restricted cash, currentRestricted cash, current1,000 0 Restricted cash, current— 1,000 
Restricted cash included in other assets40,730 32,529 
Restricted cash, long-termRestricted cash, long-term46,673 40,730 
Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash FlowsTotal cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows$42,248 $33,045 Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows$50,344 $42,248 

Restricted cash, currentlong-term in the table above represents restricted escrow funds related to a deposit for our Wyoming working interest acquisition (see Note 17, Subsequent Event) and our December 2020 saleconsists of non-producing surface acreage in the Houston area. 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 Consolidated Balance Sheets.

Oil and Natural Gas Properties

Capitalized Costs.  We follow the full cost method of accounting for oil and natural gas properties.  Under this method, all costs related to the acquisition, exploration and development of oil and natural gas reserves are capitalized and accumulated in a single cost center representing our activities, which are undertaken exclusively in the United States.  Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and nonproductive wells, capitalized interest on qualifying projects, and general and administrative expenses directly related to exploration and development activities, and do not include any costs related to production, general corporate overhead or similar activities.  We assign the purchase price of oil and natural gas properties we acquire to proved and unevaluated properties based on the estimated fair values as defined in the FASC Fair Value Measurement topic.  Proceeds

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received from disposals are credited against accumulated costs except when the sale represents a significant disposal of reserves, in which case a gain or loss would be recognized. A disposal of 25% or more of our proved reserves would be considered significant.


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Depletion and Depreciation.Depletion.  The costs capitalized, including production equipment and future development costs, are depleted or depreciated using the unit-of-production method, based on proved oil and natural gas reserves as determined by independent petroleum engineers.  Oil and natural gas reserves are converted to equivalent units on a basis of 6,000 cubic feet of natural gas to one barrel of crude oil.

Under full cost accounting, we may exclude certain unevaluated costs from the amortization base pending determination of whether proved reserves can be assigned to such properties.  The costs classified as unevaluated are transferred to the full cost amortization base as the 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 project development activities. As a result of this analysis, we recognized impairments of our unevaluated costs totaling $18.2 million during the year ended December 31, 2019, whereby these costs were transferred to the full cost amortization base. 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 coronavirus (“COVID-19”) pandemic combined with the concurrent OPEC+ decision to increase oil supply, we reassessed our development plans and transferred $244.9 million of our unevaluated costs to the full cost pool during the Predecessor period from January 1, 2020 through September 18, 2020. 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 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.

The average first-day-of-the-month NYMEX oil price used in estimating our proved reserves, after adjustments for market differentials and transportation expenses by field, was $55.55$63.86 at December 31, 2019,2021, $35.84 at December 31, 2020, $40.08 at September 18, 2020, and $35.84$55.55 at December 31, 2020.2019. We recognized a full cost pool ceiling test write-down of $14.4 million during the first quarter of 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 3, Acquisition and Divestitures) 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. Primarily as a result of thesethe commodity price declines during 2020, the Predecessor recognized full cost pool ceiling test write-downs of $996.7 million during the period from January 1, 2020 through September 18, 2020, and an additional full cost pool ceiling test write-down of $1.0 million was recognized during the Successor period from September 19, 2020 through December 31, 2020. We did 0tnot record any ceiling test write-downs during the 2019 Predecessor periods of 2018 or 2019.period.

Joint Interest Operations.  Substantially all of our oil and natural gas exploration and production activities are conducted jointly with others.  These financial statements reflect only our proportionate interest in such activities, and any amounts due from other partners are included in trade receivables.
 

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Tertiary Injection Costs.  Our tertiary operations are conducted in reservoirs that have already produced significant amounts of oil over many years; however, in accordance with the Securities and Exchange Commission (“SEC”) rules and regulations for recording proved reserves, we cannot recognize proved reserves associated with enhanced recovery techniques, such as CO2 injection, until we can demonstrate production resulting from the tertiary process or unless the field is analogous to an existing flood.

We capitalize, as a development cost, injection costs in fields that are in their development stage, which means we have not yet seen incremental oil production due to the CO2 injections (i.e., a production response).  These capitalized development costs are included in our unevaluated property costs until we are able to recognize proved reserves associated with the development project.  After we see a production response to the CO2 injections (i.e., the production stage), injection costs are expensed as incurred, and any previously deferred unevaluated development costs become subject to depletion.

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CO2 Properties

We own and produce CO2 reserves, a non-hydrocarbon resource, that are used in our tertiary oil recovery operations on our own behalf and on behalf of other interest owners in enhanced recovery fields, with a portion sold to third-party industrial users.  We record revenue from our sales of CO2 to third parties when it is produced and sold.  Expenses related to the production of CO2 are allocated between volumes sold to third parties and volumes consumed internally that are directly related to our tertiary production.  The expenses related to third-party sales are recorded in “CO2 operating and discovery expenses,” and the expenses related to internal use are recorded in “Lease operating expenses” in the Consolidated Statements of Operations or are capitalized as oil and natural gas properties in our Consolidated Balance Sheets, depending on the stage of the tertiary flood that is receiving the CO2 (see Tertiary Injection Costs above for further discussion).

Costs incurred to search for CO2 are expensed as incurred until proved or probable reserves are established.  Once proved or probable reserves are established, costs incurred to obtain those reserves are capitalized and classified as “CO2 properties” on our Consolidated Balance Sheets.  Capitalized CO2 costs are aggregated by geologic formation and depleted on a unit-of-production basis over proved and probable reserves.

Pipelines

CO2 used in our tertiary floods is transported to our fields through CO2 pipelines.  Costs of CO2 pipelines under construction are not depreciated until the pipelines are placed into service.  Pipelines are depreciated on a straight-line basis over their estimated useful lives, which range from 20 to 4350 years. Capitalized costs include $0.7$22.4 million of CO2 pipelines as of December 31, 2020,2021, that were either under construction or had not been placed into service and therefore, were not subject to depreciation during 2020.2021.

Property and Equipment – Other

Other property and equipment, which includes furniture and fixtures, vehicles, and computer equipment and software, is depreciated principally on a straight-line basis over each asset’s estimated useful life.  Vehicles and furniture and fixtures are generally depreciated over a useful life of one to sixfive years, furniture and fixtures over a life of one to ten years, and computer equipment and software are generally depreciated over a useful life of one to five years.  Leasehold improvements are amortized over the shorter of the estimated useful life or the remaining lease term.

Maintenance and repair costs that do not extend the useful life of the property or equipment are charged to expense as incurred.

Intangible Assets

Our intangible assets subject to amortization for the Predecessor period primarily consisted of amounts assigned in purchase accounting to a CO2 purchase contract with ConocoPhillips to offtake CO2 from the Lost Cabin gas plant in Wyoming, and for the Successor period represent amounts assigned in fresh start accounting to long-term contracts to sell CO2 to industrial customers. We amortize the CO2 contract intangible assets on a straight-line basis over their estimated useful lives, which range from seven to 14 years. Total amortization expense for our intangible assets was $9.1 million during the year ended December 31, 2021, $2.7 million during the Successor period September 19, 2020 through December 31, 2020, $1.7 million for the Predecessor period January 1, 2020 through September 18, 2020, and $2.4 million and $2.4 million during the years ended 2019 and 2018, respectively. The following table summarizes the carrying value of our intangible assets as of December 31, 2020 and 2019:
SuccessorPredecessor
In thousandsDecember 31, 2020December 31, 2019
Long-term contracts to sell CO2 to industrial customers
$97,943 $0 
Other intangibles2,167 37,668 
Accumulated amortization(2,748)(15,529)
Net book value$97,362 $22,139 

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$1.7 million for the Predecessor period January 1, 2020 through September 18, 2020, and $2.4 million during the year ended 2019. The following table summarizes the carrying value of our intangible assets as of December 31, 2021 and 2020:
Successor
In thousandsDecember 31, 2021December 31, 2020
Long-term contracts to sell CO2 to industrial customers
$97,943 $97,943 
Other intangibles2,179 2,167 
Accumulated amortization(11,874)(2,748)
Net book value$88,248 $97,362 

As of December 31, 2020,2021, our estimated amortization expense for our intangible assets subject to amortization over the next five years is as follows:
In thousandsIn thousands In thousands 
2021$9,117 
202220229,117 2022$9,120 
202320239,117 20239,117 
202420249,117 20249,117 
202520259,117 20259,117 
202620269,117 
 
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, and for the Successor period also included long-term contracts to sell CO2 to industrial customers. 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 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 exceededWe did not record an impairment of long-lived assets during the net carrying costs; thus, step two of the impairment test was not required and 0 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 Marchyear ended December 31, 2020; therefore, 0 impairment test was performed for the second quarter of2021, 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). We performed a qualitative assessment as of December 31, 2020 (Successor period) and determined there were no material changes to our key cash flow assumptions and no triggering events since the Company’s assets were revalued in fresh start accounting, September 18, 2020; therefore, 0 impairment test was performed for the fourth quarter of 2020.2019.

Asset Retirement Obligations

In general, our future asset retirement obligations relate to future costs associated with plugging and abandoning our oil, natural gas and CO2 wells, removing equipment and facilities from leased acreage, and returning land to its original condition.  The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using our credit-adjusted-risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset.  The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset.  Revisions to estimated retirement obligations will result in an adjustment to

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the related capitalized asset and corresponding liability.  If the liability for an oil or natural gas well is settled for an amount other than the recorded amount, the difference is recorded to the full cost pool.

Asset retirement obligations are estimated at the present value of expected future net cash flows.  We utilize unobservable inputs in the estimation of asset retirement obligations that include, but are not limited to, costs of labor and materials, profits on costs of labor and materials, the effect of inflation on estimated costs, and the discount rate.  Accordingly, asset retirement obligations are considered a Level 3 measurement under the FASC Fair Value Measurement topic.


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Notes to Consolidated Financial Statements
Commodity Derivative Contracts

We utilize oil and natural gas derivative contracts to mitigate our exposure to commodity price risk associated with our future oil and natural gas production.  These derivative contracts have historically consisted of options, in the form of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps.  Our derivative financial instruments, other than any derivative instruments that are designated under the “normal purchase normal sale” exclusion, are recorded on the balance sheet as either an asset or a liability measured at fair value.  We do not apply hedge accounting to our commodity derivative contracts; accordingly, changes in the fair value of these instruments are recognized in “Commodity derivatives expense (income)” in our Consolidated Statements of Operations in the period of change.

Concentrations of Credit Risk

Our financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents, trade and accrued production receivables, and the derivative instruments discussed above.  Our cash equivalents represent high-quality securities placed with various investment-grade institutions.  This investment practice limits our exposure to concentrations of credit risk.  Our trade and accrued production receivables are dispersed among various customers and purchasers; therefore, concentrations of credit risk are limited.  We evaluate the credit ratings of our purchasers, and if customers are considered a credit risk, letters of credit are the primary security obtained to support lines of credit.  We attempt to minimize our credit risk exposure to the counterparties of our oil and natural gas derivative contracts through formal credit policies, monitoring procedures and diversification.  All of our derivative contracts are with parties that are lenders under our senior secured bank credit facility (or affiliates of such lenders).  There are no margin requirements with the counterparties of our derivative contracts.

Oil and natural gas sales are made on a day-to-day basis or under short-term contracts at the current area market price.  We would not expect the loss of any purchaser to have a material adverse effect upon our operations.  For the year ended December 31, 2021 (Successor), four purchasers each accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP (28%), Hunt Crude Oil Supply Company (12%), Marathon Petroleum (11%) and Sunoco Inc. (11%). For the Successor period September 19, 2020 through December 31, 2020, three purchasers each accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP (30%), Marathon Petroleum (13%) and Hunt Crude Oil Supply Company (12%), and for the Predecessor period January 1, 2020 through September 18, 2020, three purchasers each accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP (30%), Hunt Crude Oil Supply Company (12%) and Marathon Petroleum (12%). For the year ended December 31, 2019 (Predecessor), three purchasers each accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP (32%), Hunt Crude Oil Supply Company (11%) and Sunoco Inc. (11%). For the year ended December 31, 2018 (Predecessor), two purchasers accounted for 10% or more of our oil and natural gas revenues: Plains Marketing LP (24%) and Hunt Crude Oil Supply Company (10%).

Other Receivables

During 2018, we recorded a $16.9 million impairment of a loan related to a proposed plant in the Gulf Coast that would potentially supply CO2 to Denbury, due to uncertainties of the project achieving financial close. The impairment was included within “Other expenses” in our Consolidated Statements of Operations for the year ended December 31, 2018.

Income Taxes

Income taxes are accounted for using the asset and liability method, under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year end.  The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date.  A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.

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Notes to Consolidated Financial Statements

We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the position.  The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement.


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Net Income (Loss) per Common Share

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

The following table sets forth the reconciliations of net income (loss) and weighted average shares used for purposes of calculating basic and diluted net income (loss) per common share for the periods indicated:
SuccessorPredecessorSuccessorPredecessor
Period from
Sept. 19, 2020 through
Dec. 31, 2020		Period from
Jan. 1, 2020 through
Sept. 18, 2020		Year Ended December 31, Year Ended
Dec. 31, 2021		Period from
Sept. 19, 2020 through
Dec. 31, 2020		Period from
Jan. 1, 2020 through
Sept. 18, 2020		Year Ended
Dec. 31, 2019
In thousandsIn thousands20192018In thousands
NumeratorNumeratorNumerator
Net income (loss) – basicNet income (loss) – basic$(50,658)$(1,432,578)$216,959 $322,698 Net income (loss) – basic$56,002 $(50,658)$(1,432,578)$216,959 
Effect of potentially dilutive securitiesEffect of potentially dilutive securitiesEffect of potentially dilutive securities
Interest on convertible senior notes including amortization of discount, net of taxInterest on convertible senior notes including amortization of discount, net of tax0 0 14,134 539 Interest on convertible senior notes including amortization of discount, net of tax— — — 14,134 
Net income (loss) – dilutedNet income (loss) – diluted$(50,658)$(1,432,578)$231,093 $323,237 Net income (loss) – diluted$56,002 $(50,658)$(1,432,578)$231,093 
DenominatorDenominatorDenominator
Weighted average common shares outstanding – basicWeighted average common shares outstanding – basic50,000 495,560 459,524 432,483 Weighted average common shares outstanding – basic50,918 50,000 495,560 459,524 
Effect of potentially dilutive securitiesEffect of potentially dilutive securities  Effect of potentially dilutive securities  
Restricted stock unitsRestricted stock units762 — — — 
WarrantsWarrants2,138 — — — 
Restricted stock and performance-based equity awardsRestricted stock and performance-based equity awards0 0 2,396 6,500 Restricted stock and performance-based equity awards— — — 2,396 
Convertible senior notes(1)
Convertible senior notes(1)
0 0 48,421 17,186 
Convertible senior notes(1)
— — — 48,421 
Weighted average common shares outstanding – dilutedWeighted average common shares outstanding – diluted50,000 495,560 510,341 456,169 Weighted average common shares outstanding – diluted53,818 50,000 495,560 510,341 

(1)For the year ended December 31, 2019, shares shown under “convertible senior notes” represent the prorated portion 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 (see Note 8, Long-Term Debt – 2019 Predecessor Debt Reduction Transactions).

Time-vestingFor each of the periods from September 19, 2020 through December 31, 2020 (Successor) and from January 1, 2020 through September 18, 2020 (Predecessor), the weighted average common shares outstanding used to calculate basic earnings per share and diluted earnings per share were the same, since the Company generated a net loss during those periods. The weighted average diluted shares outstanding would have been 50.0 million for the period September 19, 2020 through December 31, 2020 and 584.4 million for the period January 1, 2020 through September 18, 2020, if the Company had recognized net income during those periods.

Basic weighted average common shares during the year ended December 31, 2021 includes 1,383,144 performance-based and restricted stock units which are fully vested as of December 31, 2021. Although vesting criteria for these awards have been achieved, the shares underlying these awards are not currently outstanding as actual delivery of the shares is included innot scheduled to occur until December 4, 2023. During the Predecessor periods, basic weighted average common shares from the vesting date (although time-vestingincludes restricted stock is issued and outstanding upon grant).  that vested during the periods.

For purposes of calculating diluted weighted average common shares for the years ended December 31, 2021 and 2019, and 2018, the nonvested restricted stock units, nonvested restricted stock and performance-based equity awards, along with unexercised

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warrants 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 earliest date outstanding during the respective periods. In April and May 2018, all of the then outstanding 3½% Convertible Senior Notes due 2024 and 5% Convertible Senior Notes due 2023 converted into shares of Denbury common stock, resulting in the issuance of 55.2 million shares of our common stock upon conversion. These shares have been included in basic weighted average common shares outstanding beginning on the date of conversion.

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Notes to Consolidated Financial Statements

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 year ended December 31, 2021, the period September 19, 2020 through December 31, 2020, and the year ended December 31, 2019, as their effect would have been antidilutive:
SuccessorPredecessor
 Period from
Sept. 19, 2020 through
Dec. 31, 2020		Period from
Jan. 1, 2020 through
Sept. 18, 2020		Year Ended December 31,
In thousands20192018
Stock appreciation rights0 1,007 2,027 2,743 
Restricted stock and performance-based equity awards0 7,280 5,505 1,234 
Convertible senior notes0 87,888 0 0 
Restricted stock units(1)
328 0 0 0 
Warrants(2)
5,526 0 0 0 

(1)    Shares represent the impact over the Successor periodantidilutive, as of the respective dates:
SuccessorPredecessor
In thousandsDecember 31, 2021December 31, 2020December 31, 2019
Restricted stock units— 1,220 — 
Warrants— 5,526 — 
Stock appreciation rights— — 1,981 
Restricted stock and performance-based equity awards— — 4,445 
For the period September 19, 2020 through December 31, 2020, the Company’s restricted stock units and series A and series B warrants were antidilutive based on the Company’s net loss position for the periods. At December 31, 2021, the Company had approximately 1.25.2 million warrants outstanding that can be exercised for shares of the Successor’s common stock, issuable upon full vesting of the restricted stock unit awards issued on December 4, 2020 pursuant to the 2020 Omnibus Stock and Incentive Plan (see Note 11, Stock Compensation).
(2)Shares represent the impact over the Successor period of the approximately 5.5 million shares of the Successor’s common stock issuable upon full exercise of the series A warrants, at an exercise price of $32.59 per share andfor the 2.6 million series BA 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. The warrants were issued pursuant to the Plan to holders of the Predecessor’s convertible senior notes, senior subordinated notes, and equity holders. The dilution from exerciseequity. As of theDecember 31, 2021, 11,694 series A orwarrants and 327,266 series B warrants couldhave been exercised in exchange for a total of 193,657 shares. The warrants may be reduced to the extent warrants are exercised for cash or on a cashless basis.

Environmental and Litigation Contingencies

The Company makes judgments and estimates in recording liabilities for contingencies such as environmental remediation or ongoing litigation.  Liabilities are recorded when it is both probable that a loss has been incurred and such loss is reasonably estimable.  Assessments of liabilities are based on information obtained from independent and in-house experts, loss experience in similar situations, actual costs incurred, and other case-by-case factors.  Any related insurance recoveries are recognized in our financial statements during the period received or at the time receipt is determined to be virtually certain.

Recent Accounting Pronouncements

Recently Adopted

Financial Instruments – Credit Losses. In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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.

Leases. During the Predecessor period, effective January 1, 2019, we adopted FASB ASU 2016-02, Leases, and ASU 2018-01, Leases (Topic 842) – Land Easement Practical Expedient for Transition to Topic 842, using the modified retrospective method with an application date of January 1, 2019. For a discussion of our current accounting for lease contracts, see Note 5, Leases.


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Not Yet Adopted

Reference Rate Reform. In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848) (“ASU 2020-04”). ASU 2020-04 provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions to ease financial reporting burdens related to the expected market transition from the London Interbank Offered Rate (“LIBOR”) or another reference rate to alternative reference rates. The amendments in this ASU were effective upon issuance and generally can be applied to applicable contract modifications through December 31, 2022. Currently, our Successor Bank Credit Agreement is our only contract that makes reference to a LIBOR rate and the agreement outlines the specific procedures that will be undertaken once an appropriate alternative benchmark is identified. We do not expect this guidance to have a significant impact on our consolidated financial statements and related footnote disclosures.

Income Taxes. In December 2019, the FASBFinancial Accounting Standards Board issued ASUAccounting Standards Update (“ASU”) 2019-12, Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes (“ASU 2019-12”). The objective of ASU 2019-12 is to simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740 and to provide more consistent application to improve the comparability of financial statements. Effective January 1, 2021, we adopted ASU 2019-02. The amendments in this ASU are effective for fiscal years beginning after December 15, 2020, and early adoption is permitted. We do not expect the adoptionimplementation of this guidance tostandard did not have a significantmaterial impact on our consolidated financial statements and related footnote disclosures.

Note 2. Fresh Start Accounting

Fresh Start Accounting

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

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Notes to Consolidated Financial Statements

Fresh start accounting requires that new fair values be established for the Company’s assets, liabilities and equity as of the date of emergence from bankruptcy, September 18, 2020, and therefore certain values and operational results of the consolidated financial statements subsequent to September 18, 2020 are not comparable to those in the Company’s consolidated financial statements prior to, and including September 18, 2020. The Emergence Date fair values of the Successor’s assets and liabilities differ materially from their recorded values as reflected on the historical balance sheet of the Predecessor.

Reorganization Value

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


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The following table reconciles the enterprise value to the equity value of the Successor as of the Emergence Date:
In thousandsSept. 18, 2020
Enterprise value$1,280,856 
Plus: Cash and cash equivalents45,585 
Less: Total debt(231,022)
Equity value$1,095,419 

The following table reconciles enterprise value to reorganization value of the Successor (i.e., value of the reconstituted entity) and total reorganization value:
In thousandsSept. 18, 2020
Enterprise value$1,280,856 
Plus: Cash and cash equivalents45,585 
Plus: Current liabilities excluding current maturities of long-term debt239,738 
Plus: Non-interest-bearing noncurrent liabilities185,228 
Reorganization value of the reconstituted Successor$1,751,407 

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

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


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Notes to Consolidated Financial Statements
Reorganization Items, Net

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


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The following table summarizes the losses (gains) on reorganization items, net:
Predecessor
Period from
Jan. 1, 2020 through
Sept. 18, 2020
In thousands
Gain on settlement of liabilities subject to compromise$(1,024,864)
Fresh start accounting adjustments1,834,423 
Professional service provider fees and other expenses11,267 
Success fees for professional service providers9,700 
Loss on rejected contracts and leases10,989 
Valuation adjustments to debt classified as subject to compromise757 
DIPDebtor-in-possession credit agreement fees3,107 
Acceleration of Predecessor stock compensation expense4,601 
Total reorganization items, net$849,980 

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

Valuation Process

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

Oil and Natural Gas Properties

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

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

Discount factors utilized were derived using a weighted average cost of capital computation, which included an estimated cost of debt and equity for market participants with similar geographies and asset development type and varying corporate income tax rates based on the expected point of sale for each property’s produced assets. Reserve values were also adjusted for any asset retirement obligations as well as for CO2 indirect costs not directly allocable to oil fields. Based on this analysis, the

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Company concluded the fair value of its proved and probable reserves was $865.4 million as of the Emergence Date (see footnote 10 to Fresh Start Adjustments discussion below).


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CO2 Properties

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

Pipelines

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

Other Property and Equipment

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

Long-Term Contracts to Sell CO2 to Industrial Customers

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

Favorable and Unfavorable Vendor Contracts

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

Asset Retirement Obligations

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


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Notes to Consolidated Financial Statements
Pipeline Financing Liabilities

The fair value of the pipeline financing liabilities was measured as the present value of the remaining payments under the restructured pipeline agreements (see Note 8, Long-Term Debt – Restructuring of Pipeline Financing Transactions, for further discussion).

Warrants

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

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

Condensed Consolidated Balance Sheet

The following illustrates the effects on the Company’s consolidated balance sheet due to the reorganization and fresh start accounting adjustments. The explanatory notes following the table below provide further details on the adjustments, including the assumptions and methods used to determine fair value for its assets, liabilities, and warrants.
As of September 18, 2020
In thousandsPredecessorReorganization AdjustmentsFresh Start AdjustmentsSuccessor
Assets
Current assets 
Cash and cash equivalents$73,372 $(27,787)(1)$— $45,585 
Restricted cash— 10,662 (2)— 10,662 
Accrued production receivable112,832 — — 112,832 
Trade and other receivables, net36,221 — — 36,221 
Derivative assets32,635 — — 32,635 
Other current assets12,968 (539)(3)— 12,429 
Total current assets268,028 (17,664)— 250,364 
Property and equipment 
Oil and natural gas properties (using full cost accounting)
Proved properties11,723,546 — (10,941,313)782,233 
Unevaluated properties650,553 — (538,570)111,983 
CO2 properties
1,198,515 — (1,011,169)187,346 
Pipelines2,339,864 — (2,207,246)132,618 
Other property and equipment201,565 — (104,152)97,413 
Less accumulated depletion, depreciation, amortization and impairment(12,864,141)— 12,864,141 0 
Net property and equipment3,249,902 — (1,938,309)(10)1,311,593 
Operating lease right-of-use assets1,774 — 69 (10)1,843 
Derivative assets501 — — 501 
Intangible assets, net20,405 — 79,678 (11)100,083 
Other assets81,809 8,241 (4)(3,027)(12)87,023 
Total assets$3,622,419 $(9,423)$(1,861,589)$1,751,407 

As of September 18, 2020
In thousandsPredecessorReorganization AdjustmentsFresh Start AdjustmentsSuccessor
Assets
Current assets 
Cash and cash equivalents$73,372 $(27,787)(1)$— $45,585 
Restricted cash— 10,662 (2)— 10,662 
Accrued production receivable112,832 — — 112,832 
Trade and other receivables, net36,221 — — 36,221 
Derivative assets32,635 — — 32,635 
Other current assets12,968 (539)(3)— 12,429 
Total current assets268,028 (17,664)— 250,364 
Property and equipment 
Oil and natural gas properties (using full cost accounting)
Proved properties11,723,546 — (10,941,313)782,233 
Unevaluated properties650,553 — (538,570)111,983 
CO2 properties
1,198,515 — (1,011,169)187,346 
Pipelines2,339,864 — (2,207,246)132,618 
Other property and equipment201,565 — (104,152)97,413 
Less accumulated depletion, depreciation, amortization and impairment(12,864,141)— 12,864,141 — 
Net property and equipment3,249,902 — (1,938,309)(10)1,311,593 
Operating lease right-of-use assets1,774 — 69 (10)1,843 
Derivative assets501 — — 501 
Intangible assets, net20,405 — 79,678 (11)100,083 
Other assets81,809 8,241 (4)(3,027)(12)87,023 
Total assets$3,622,419 $(9,423)$(1,861,589)$1,751,407 

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As of September 18, 2020
In thousandsPredecessorReorganization AdjustmentsFresh Start AdjustmentsSuccessor
Liabilities and Stockholders’ Equity
Current liabilities 
Accounts payable and accrued liabilities$67,789 $102,793 (5)$3,738 (13)$174,320 
Oil and gas production payable39,372 16,705 (6)— 56,077 
Derivative liabilities8,613 — — 8,613 
Current maturities of long-term debt— 73,199 (6)364 (14)73,563 
Operating lease liabilities— 757 (6)(29)(10)728 
Total current liabilities115,774 193,454 4,073 313,301 
Long-term liabilities 
Long-term debt, net of current portion140,000 42,610 (6)(25,151)(14)157,459 
Asset retirement obligations2,727 180,408 (6)(24,697)(10)158,438 
Derivative liabilities295 — — 295 
Deferred tax liabilities, net— 417,951 (6)(15)(414,120)(15)3,831 
Operating lease liabilities— 515 (6)10 (10)525 
Other liabilities— 3,540 (6)18,599 (16)22,139 
Total long-term liabilities not subject to compromise143,022 645,024 (445,359)342,687 
Liabilities subject to compromise2,823,506 (2,823,506)(6)— — 
Commitments and contingencies (Note 14)
Stockholders’ equity
Predecessor preferred stock— — — — 
Predecessor common stock510 (510)(7)— — 
Predecessor paid-in capital in excess of par2,764,915 (2,764,915)(7)— — 
Predecessor treasury stock, at cost(6,202)6,202 (7)— — 
Successor preferred stock— — — — 
Successor common stock— 50 (8)— 50 
Successor paid-in capital in excess of par— 1,095,369 (8)— 1,095,369 
Accumulated deficit(2,219,106)3,639,409 (9)(1,420,303)(17)— 
Total stockholders’ equity
540,117 1,975,605 (1,420,303)1,095,419 
Total liabilities and stockholders’ equity$3,622,419 $(9,423)$(1,861,589)$1,751,407 

Reorganization Adjustments

(1)Represents the net cash payments that occurred on the Emergence Date as follows:
In thousands
Sources:
Cash proceeds from Successor Bank Credit Agreement$140,000 
Total cash proceeds140,000 
Uses:
Payment in full of DIP Facility and pre-petition revolving bank credit facility(140,000)
Retained professional service provider fees paid to escrow account(10,662)
Non-retained professional service provider fees paid(7,420)
Accrued interest and fees on DIP Facility(1,464)
Debt issuance costs related to Successor Bank Credit Agreement(8,241)
Total cash uses(167,787)
Net uses$(27,787)


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

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

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

(5)Adjustments to accounts payable and accrued liabilities as follows:
In thousands
Accrual of professional service provider fees$2,826 
Payment of accrued interest and fees on DIP Facility(1,464)
Reinstatement of accounts payable and accrued liabilities from liabilities subject to compromise101,431 
Accounts payable and accrued liabilities$102,793 

(6)Liabilities subject to compromise were settled as follows in accordance with the Plan:
In thousands
Liabilities subject to compromise prior to the Emergence Date:
Settled liabilities subject to compromise
Senior secured second lien notes$1,629,457 
Convertible senior notes234,015 
Senior subordinated notes251,480 
Total settled liabilities subject to compromise2,114,952 
Reinstated liabilities subject to compromise
Current maturities of long-term debt73,199 
Accounts payable and accrued liabilities101,431 
Oil and gas production payable16,705 
Operating lease liabilities, current757 
Long-term debt, net of current portion42,610 
Asset retirement obligations180,408 
Deferred tax liabilities289,389 
Operating lease liabilities, long-term515 
Other long-term liabilities3,540 
Total reinstated liabilities subject to compromise708,554 
Total liabilities subject to compromise2,823,506 
Issuance of New Common Stock to second lien note holders(1,014,608)
Issuance of New Common Stock to convertible note holders(53,400)
Issuance of series A warrants to convertible note holders(15,683)
Issuance of series B warrants to senior subordinated note holders(6,398)
Reinstatement of liabilities subject to compromise(708,553)
Gain on settlement of liabilities subject to compromise$1,024,864 

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


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(8)Represents the Successor’s common stock and additional paid-in capital as follows:
In thousands
Capital in excess of par value of 47,499,999 issued and outstanding shares of New Common Stock issued to holders of the senior secured second lien note claims$1,014,608 
Capital in excess of par value of 2,500,000 issued and outstanding shares of New Common Stock issued to holders of the convertible senior note claims53,400 
Fair value of series A warrants issued to convertible senior note holders15,683 
Fair value of series B warrants issued to senior subordinated note holders6,398 
Fair value of series B warrants issued to Predecessor equity holders5,330 
Total change in Successor common stock and additional paid-in capital1,095,419 
Less: Par value of Successor common stock(50)
Change in Successor additional paid-in capital$1,095,369 

(9)Reflects the cumulative net impact of the effects on accumulated deficit as follows:
In thousands
Cancellation of Predecessor common stock, paid-in capital in excess of par, and treasury stock$2,763,824 
Gain on settlement of liabilities subject to compromise1,024,864 
Acceleration of Predecessor stock compensation expense(4,601)
Recognition of tax expenses related to reorganization adjustments(128,556)
Professional service provider fees recognized at emergence(9,700)
Issuance of series B warrants to Predecessor equity holders(5,330)
Other(1,092)
Net impact to Predecessor accumulated deficit$3,639,409 

Fresh Start Adjustments

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

(11)Reflects fair value adjustments to our long-term contracts to sell CO2 to industrial customers.

(12)Reflects fair value adjustments to our other assets as follows:
In thousands
Fair value adjustment for CO2 and oil pipeline line-fill
$(3,698)
Fair value adjustments for escrow accounts671 
Fair value adjustments to other assets$(3,027)

(13)Reflects fair value adjustments to accounts payable and accrued liabilities as follows:
In thousands
Fair value adjustment for the current portion of an unfavorable vendor contract$3,500 
Fair value adjustment for the current portion of Predecessor asset retirement obligation689 
Write-off accrued interest on NEJD pipeline financing(451)
Fair value adjustments to accounts payable and accrued liabilities$3,738 


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(14)Represents adjustments to current and long-term maturities of debt associated with pipeline lease financings. The cumulative effect is as follows:
In thousands
Fair value adjustment for Free State pipeline lease financing$(24,699)
Fair value adjustment for NEJD pipeline lease financing(88)
Fair value adjustments to current and long-term maturities of debt$(24,787)

Our pipeline lease financings were restructured in late October 2020 (see Note 8, Long-Term Debt – Restructuring of Pipeline Financing Transactions).

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

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

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

Note 3. Predecessor DivestitureAcquisition and Divestitures

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 cash (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 on the acquisition date was $5.3 million, and as of December 31, 2021, the fair value of the contingent consideration recorded on our Consolidated Balance Sheets was $7.7 million. The $2.4 million increase at December 31, 2021 from the March 2021 acquisition date fair value was the result of higher NYMEX WTI oil prices and was recorded to “Other expenses” in our Consolidated Statements of Operations.

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

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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 properties60,101 
Other property and equipment1,685 
Asset retirement obligations(39,794)
Contingent consideration(5,320)
Other liabilities(5,766)
Fair value of net assets acquired$10,906 

Divestitures

Hartzog Draw Deep Mineral Rights

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

Houston Area Land Sales

During the second half of 2021, we completed sales of a portion of certain non-producing surface acreage in the Houston area. We received cash proceeds of $15.2 million from the sales and recognized a $10.3 million gain to “Other income” in our Consolidated Statements of Operations.

Gulf Coast Working Interests Sale

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

Note 4. 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. This principle is achieved through applying a five-step process for customer contract revenue recognition:

•Identify the contract or contracts with a customer – We derive the majority of our revenues from oil and natural gas sales contracts and CO2 sales and transportation contracts. The contracts specify each party’s rights regarding the goods or services to be transferred and contain commercial substance as they impact our financial statements. A high percentage of our receivables balance is current, and we have not historically entered into contracts with counterparties that pose a credit risk without requiring adequate economic protection to ensure collection.

•Identify the performance obligations in the contract – Each of our revenue contracts specify a volume per day, or production from a lease designated in the contract (a distinct good), to be delivered at the delivery point over the term of the

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contract (the identified performance obligation). The customer takes delivery and physical possession of the product at the delivery point, which generally is also the point at which title transfers and the customer obtains the risks and rewards of ownershipcontrol (the identified performance obligation is satisfied).

•Determine the transaction price – Typically, our oil and natural gas contracts define the price as a formula price based on the average market price, as specified on set dates each month, for the specific commodity during the month of delivery. Certain of our CO2 contracts define the price as a fixed contractual price adjusted to an inflation index to reflect market pricing. Given the industry practice to invoice customers the month following the month of delivery and our high probability of collection of payment, no significant financing component is included in our contracts.

•Allocate the transaction price to the performance obligations in the contract – The majority of our revenue contracts are short-term, with terms of one year or less, to which we have applied the practical expedient permitted under the standard eliminating the requirement to disclose the transaction price allocated to remaining performance obligations. In limited instances, we have revenue contracts with terms greater than one year; however, the future delivery volumes are wholly

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unsatisfied as they represent separate performance obligations with variable consideration. We utilized the practical expedient which eliminates the requirement to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to wholly unsatisfied performance obligations. As there is only one performance obligation associated with our contracts, no allocation of the transaction price is necessary.

•Recognize revenue when, or as, we satisfy a performance obligation – 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 madereceived within a month following product delivery, and for natural gas and NGL contracts, payment is generally madereceived 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 Consolidated Balance Sheets.

In addition to revenues from oil and natural gas sales contracts and CO2 sales and transportation contracts, in certain situations, the Company enters into marketing arrangements for the purchase and subsequent sale of crude oil forfrom third parties inparties. We recognize the Gulf Coast region. Revenuesrevenue received and the associated expenses fromincurred on these transactions are presentedsales on a gross basis, as “Oil marketing revenues” and “Oil marketing purchases” in our Consolidated Statements of Operations, since we act as a principal in the transaction by assuming control of the commodities purchased and the responsibility to deliver the commodities sold. Revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser.

Disaggregation of Revenue

The following table summarizes our revenues by product type:
SuccessorPredecessorSuccessorPredecessor
Period from
Sept. 19, 2020 through
Dec. 31, 2020		Period from
Jan. 1, 2020 through
Sept. 18, 2020		Year Ended December 31,Year Ended
Dec. 31, 2021		Period from
Sept. 19, 2020 through
Dec. 31, 2020		Period from
Jan. 1, 2020 through
Sept. 18, 2020		Year Ended
Dec. 31, 2019
In thousandsIn thousands20192018In thousands
Oil salesOil sales$199,769 $489,251 $1,205,083 $1,412,358 Oil sales$1,148,022 $199,769 $489,251 $1,205,083 
Natural gas salesNatural gas sales1,339 2,850 6,937 10,231 Natural gas sales11,933 1,339 2,850 6,937 
CO2 sales and transportation fees
CO2 sales and transportation fees
9,419 21,049 34,142 31,145 
CO2 sales and transportation fees
44,175 9,419 21,049 34,142 
Oil marketing revenuesOil marketing revenues5,376 8,543 14,198 1,921 Oil marketing revenues38,742 5,376 8,543 14,198 
Total revenuesTotal revenues$215,903 $521,693 $1,260,360 $1,455,655 Total revenues$1,242,872 $215,903 $521,693 $1,260,360 

Note 5. Leases

We evaluate contracts for leasing arrangements at inception. We lease office space, equipment, and vehicles that have non-cancelable lease terms. Currently, our outstanding leases have remaining terms up to 714 years, with certain land leases having

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remaining terms up to 4948 years.  Leases with a term of 12 months or less are not recorded on our balance sheet. As part of the Chapter 11 Restructuring, the Predecessor elected to terminate some of its operating and finance leases, primarily related to office space. The table below reflects our operating lease right-of-use assets and operating lease liabilities, which primarily consist of our office leases:
SuccessorPredecessorSuccessor
In thousandsIn thousandsDecember 31, 2020December 31, 2019In thousandsDecember 31, 2021December 31, 2020
Operating leasesOperating leasesOperating leases
Operating lease right-of-use assetsOperating lease right-of-use assets$20,342 $34,099 Operating lease right-of-use assets$19,502 $20,342 
Operating lease liabilities – currentOperating lease liabilities – current$1,350 $6,901 Operating lease liabilities – current$4,677 $1,350 
Operating lease liabilities – long-termOperating lease liabilities – long-term19,460 41,932 Operating lease liabilities – long-term17,094 19,460 
Total operating lease liabilitiesTotal operating lease liabilities$20,810 $48,833 Total operating lease liabilities$21,771 $20,810 


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The majority of our leases contain renewal options, typically exercisable at our sole discretion. At emergence, we recorded right-of-use assets and liabilities based on the fair value of lease payments and utilized our incremental borrowing rate based on information available at the Emergence Date. The following weighted average remaining lease terms and discount rates related to our outstanding operating leases:
SuccessorPredecessorSuccessor
December 31, 2020December 31, 2019December 31, 2021December 31, 2020
Weighted average remaining lease termWeighted average remaining lease term6.3 years5.7 yearsWeighted average remaining lease term5.2 years6.3 years
Weighted average discount rateWeighted average discount rate5.6 %6.7 %Weighted average discount rate5.4 %5.6 %

We account for lease and nonlease components in a contract as a single lease component for all asset classes. 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. Variable lease costs represent additional payments in excess of our minimum base rental payments under our office space leases. The Predecessor Company previously subleased part of the office space included in its operating leases for which it received rental payments. Since those office space leases were terminated during the Chapter 11 Restructuring, the underlying sublease agreements were also terminated. The Successor

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Company subsequently entered into an operating lease for a new corporate office space which commenced in October 2020. The following table summarizes the components of lease costs and sublease income:
SuccessorPredecessorSuccessorPredecessor
Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year EndedYear Ended
Dec. 31, 2021		Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended
Dec. 31, 2019
In thousandsIn thousandsIncome StatementDec. 31, 2019In thousandsIncome Statement
Operating lease costOperating lease costGeneral and administrative expenses$872 $5,683 $8,924 Operating lease costGeneral and administrative expenses$4,102 $872 $5,683 $8,924 
Lease operating expenses158 21458Lease operating expenses655 158 214 58 
CO2 operating and discovery expenses
14 375
CO2 operating and discovery expenses
50 14 37 5 
$1,044 $5,934 $8,987 $4,807 $1,044 $5,934 $8,987 
Finance lease costFinance lease costFinance lease cost
Amortization of right-of-use assetsAmortization of right-of-use assetsDepletion, depreciation, and amortization$3 $9 $1,188 Amortization of right-of-use assetsDepletion, depreciation, and amortization$— $3 $9 $1,188 
Interest on lease liabilitiesInterest on lease liabilitiesInterest expense1 3 40 Interest on lease liabilitiesInterest expense— 1 3 40 
Total finance lease costTotal finance lease cost$4 $12 $1,228 Total finance lease cost$— $4 $12 $1,228 
Variable lease costVariable lease cost$670 $258 $3,688 $4,852 
Sublease incomeSublease incomeGeneral and administrative expenses$100 $2,584 $4,127 Sublease incomeGeneral and administrative expenses$— $100 $2,584 $4,127 

Our statement of cash flows included the following activity related to our operating and finance leases:
SuccessorPredecessor
Year Ended
Dec. 31, 2021		Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended
Dec. 31, 2019
In thousands
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases$2,830 $341 $7,341 $10,995 
Operating cash flows from interest on finance leases— 1 3 40 
Financing cash flows from finance leases— 78 10 1,275 
Right-of-use assets obtained in exchange for lease obligations
Operating leases2,683 19,902 1,049 415 
Finance leases— — 162 — 


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Our statement of cash flows included the following activity related to our operating and finance leases:
SuccessorPredecessor
Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended
In thousandsDec. 31, 2019
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases$341 $7,341 $10,995 
Operating cash flows from interest on finance leases1 3 40 
Financing cash flows from finance leases78 10 1,275 
Right-of-use assets obtained in exchange for lease obligations
Operating leases19,902 1,049 415 
Finance leases0 162 0 

The following table summarizes by year the maturities of our lease liabilities as of December 31, 2020:2021:
OperatingOperating
In thousandsIn thousandsLeasesIn thousandsLeases
2021$2,496 
202220224,149 2022$5,705 
202320234,135 20234,712 
202420244,111 20244,138 
202520254,149 20254,177 
202620264,203 
ThereafterThereafter6,263 Thereafter2,326 
Total minimum lease paymentsTotal minimum lease payments25,303 Total minimum lease payments25,261 
Less: Amount representing interestLess: Amount representing interest(4,493)Less: Amount representing interest(3,490)
Present value of minimum lease liabilitiesPresent value of minimum lease liabilities$20,810 Present value of minimum lease liabilities$21,771 


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Note 6. Asset Retirement Obligations

The following table summarizes the changes in our asset retirement obligations:
SuccessorPredecessorSuccessorPredecessor
Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended Year Ended
Dec. 31, 2021		Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020
In thousandsIn thousandsDec. 31, 2019In thousands
Beginning asset retirement obligationsBeginning asset retirement obligations$163,368 $181,760 $176,585 Beginning asset retirement obligations$186,281 $163,368 $181,760 
Liabilities incurred and assumed during periodLiabilities incurred and assumed during period738 736 4,354 Liabilities incurred and assumed during period43,701 738 736 
Revisions in estimated retirement obligationsRevisions in estimated retirement obligations22,660 3,592 9,206 Revisions in estimated retirement obligations69,059 22,660 3,592 
Liabilities settled and sold during periodLiabilities settled and sold during period(3,439)(10,041)(24,342)Liabilities settled and sold during period(10,783)(3,439)(10,041)
Accretion expenseAccretion expense2,954 11,329 15,957 Accretion expense14,353 2,954 11,329 
Fresh start accounting adjustmentFresh start accounting adjustment0 (24,008)0 Fresh start accounting adjustment— — (24,008)
Ending asset retirement obligationsEnding asset retirement obligations186,281 163,368 181,760 Ending asset retirement obligations302,611 186,281 163,368 
Less: current asset retirement obligations(1)
Less: current asset retirement obligations(1)
(6,943)(4,930)(4,652)
Less: current asset retirement obligations(1)
(18,373)(6,943)(4,930)
Long-term asset retirement obligationsLong-term asset retirement obligations$179,338 $158,438 $177,108 Long-term asset retirement obligations$284,238 $179,338 $158,438 

(1)Included in “Accounts payable and accrued liabilities” in our Consolidated Balance Sheets.

Liabilities assumed relate to minor acquisitions,our March 2021 acquisition of Wyoming property interests (see Note 3, Acquisition and Divestitures), with liabilities incurred generally relating to wells and facilities. Revisions during 2021 primarily related to increased well abandonment cost estimates at certain of these fields and an acceleration in the estimated timing of certain future abandonment activities.

We have escrow accounts that are legally restricted for certain of our asset retirement obligations.  The balances of these escrow accounts were $55.2$55.6 million and $53.4$55.2 million as of December 31, 20202021 and 2019,2020, respectively.  These balances are primarily invested in U.S. Treasury bonds, recorded at amortized cost, and money market accounts, which investments are included in “Other assets” in our Consolidated Balance Sheets.  A portion of these investments are included in cash, cash equivalents, and restricted cash balances on our Consolidated Statements of Cash Flows (see Note 1, Nature of Operations and Summary of Significant Accounting Policies – Cash, Cash Equivalents, and Restricted Cash). The carrying values of these investments approximate their estimated fair market value as of December 31, 20202021 and 2019.2020.


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Note 7. Unevaluated Property

A summary of the unevaluated property costs excluded from oil and natural gas properties being amortized at December 31, 2020,2021, and the year in which the costs were incurred follows:
December 31, 2020 December 31, 2021
Costs Incurred During:  Costs Incurred During: 
In thousandsIn thousandsSuccessor 2020
Fresh Start Adjustments (Sept. 18, 2020)(1)
TotalIn thousands2021Successor 2020
Fresh Start Adjustments (Sept. 18, 2020)(1)
Total
Property acquisition costsProperty acquisition costs$0 $84,019 $84,019 Property acquisition costs$— $— $68,103 $68,103 
Exploration and developmentExploration and development46 0 46 Exploration and development39,481 46 — 39,527 
Capitalized interestCapitalized interest1,239 0 1,239 Capitalized interest3,576 963 — 4,539 
TotalTotal$1,285 $84,019 $85,304 Total$43,057 $1,009 $68,103 $112,169 


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(1)Reflects the carrying values of our unevaluated properties as a result of the application of fresh start accounting upon emergence from bankruptcy (see Note 2, Fresh Start Accounting, for additional information) that remain in unevaluated properties as of December 31, 2020.2021.

Our property acquisition costs reflected in the table above relate to fair values assigned during fresh start accounting and are primarily associated with our Cedar Creek Anticline fields and CO2 tertiary potential at Tinsley Oyster Bayou and Salt Creek fields. Exploration and development costs shown as unevaluated properties are primarily associated with our tertiary oil field projects at Cedar Creek Anticline that are under development but did not have associated proved reserves at December 31, 2020.2021.

Costs are transferred into the amortization base on an ongoing basis as projects are evaluated and proved reserves established or impairment determined.  We review the excluded properties for impairment at least annually.  We currently estimate that evaluation of the majority of these properties and the inclusion of their costs in the amortization base is expected to be completed within five to ten years.  Until we are able to determine whether there are any proved reserves attributable to the above costs, we are not able to assess the future impact on the amortization rate of the full cost pool.

Note 8. Long-Term Debt

The table below reflects long-term debt outstanding as of December 31, 20202021 and 2019:2020:

 SuccessorPredecessor
In thousandsDecember 31, 2020December 31, 2019
Successor Senior Secured Bank Credit Agreement$70,000 $0 
Predecessor Senior Secured Bank Credit Agreement0 0 
9% Senior Secured Second Lien Notes due 20210 614,919 
9¼% Senior Secured Second Lien Notes due 20220 455,668 
7¾% Senior Secured Second Lien Notes due 20240 531,821 
7½% Senior Secured Second Lien Notes due 20240 20,641 
6⅜% Convertible Senior Notes due 20240 245,548 
6⅜% Senior Subordinated Notes due 20210 51,304 
5½% Senior Subordinated Notes due 20220 58,426 
4⅝% Senior Subordinated Notes due 20230 135,960 
Pipeline financings68,008 167,439 
Total debt principal balance138,008 2,281,726 
Debt discount0 (101,767)
Future interest payable0 164,914 
Debt issuance costs0 (10,009)
Total debt, net of debt issuance costs and discount138,008 2,334,864 
Less: current maturities of long-term debt(68,008)(102,294)
Long-term debt and capital lease obligations$70,000 $2,232,570 
 Successor
In thousandsDecember 31, 2021December 31, 2020
Senior Secured Bank Credit Agreement$35,000 $70,000 
Pipeline financings— 68,008 
Total debt principal balance35,000 138,008 
Less: current maturities of long-term debt— (68,008)
Long-term debt$35,000 $70,000 

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

Prior to our emergence from bankruptcy, our debt consisted of the Predecessor’s Bank Credit Agreement, senior secured second lien notes, convertible senior notes, senior subordinated notes, pipeline financings, and capital lease obligations. On the Emergence Date, pursuant to the terms of the Plan, all outstanding obligations under the senior secured second lien notes, convertible senior notes, and senior subordinated notes were fully extinguished, relieving approximately $2.1 billion of debt by issuing equity and/or warrants in the Successor to the holders of that debt. See Note 1, Nature of Operations and Summary of

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Significant Accounting Policies – Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code, for additional information.

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Senior Secured Bank Credit Facility

In connection with our emergence from Chapter 11 proceedings on September 18, 2020, we entered into a new credit agreement with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the “Successor Bank Credit Agreement”).thereto. The Successor Bank Credit Agreement is a senior secured revolving credit facility with an initial borrowing base and lender commitments of $575 million. Additionally, under the Successor Bank Credit Agreement, letters of credit are available in an aggregate amount not to exceed $100 million, and short-term swingline loans are available in an aggregate amount not to exceed $25 million, each subject to the available commitments under the Successor Bank Credit Agreement. Availability under the Successor Bank Credit Agreement is subject to a borrowing base, which is redetermined semiannually on or around May 1 and November 1 of each year, with our next scheduled redetermination around May 1, 2021.2022. The borrowing base is adjusted at the lenders’ discretion and is based, in part, upon external factors over which we have no control. The borrowing base is subject to a reduction by twenty-five percent (25%) of the principal amount of any unsecured or subordinated debt issued or incurred. The borrowing base may also be reduced if we sell borrowing base properties and/or cancel commodity derivative positions with an aggregate value in excess of 5% of the then-effective borrowing base between redeterminations. If our outstanding debt under the Successor Bank Credit Agreement exceeds the then-effective borrowing base, we would be required to repay the excess amount over a period not to exceed six months. The Successor Bank Credit Agreement matures on January 30, 2024.

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

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

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

•A Consolidated Total Debt to Consolidated EBITDAX covenant, with such ratio not to exceed 3.5 times; and
•A requirement to maintain a current ratio (i.e., Consolidated Current Assets to Consolidated Current Liabilities) of at least 1.0 times.1.0.

For purposes of computing the current ratio per the Successor Bank Credit Agreement, Consolidated Current Assets exclude the current portion of derivative assets but include available borrowing capacity under the Successor 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.

Loans under the Successor Bank Credit Agreement are subject to varying rates of interest based on either (1) for ABR Loans,alternate base rate loans, a base rate determined under the Successor Bank Credit Agreement (the “ABR”) plus an applicable margin ranging from 2% to 3% per annum, or (b) for LIBOR Loans, the LIBOR rate (subject to a 1% floor) plus an applicable margin ranging from 3% to 4% per annum (capitalized terms as defined in the Successor Bank Credit Agreement). The weighted average interest rate on borrowings outstanding as of December 31, 20202021 under the Successor Bank Credit Agreement was 4.0%. The undrawn portion of the aggregate lender commitments under the Successor Bank Credit Agreement is subject to a commitment fee of 0.5%. As of December 31, 2020,2021, we were in compliance with all debt covenants under the Successor Bank Credit Agreement.

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


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Restructuring of Pipeline Financing Transactions

In May 2008, we closed two transactions with Genesis Energy, L.P. (“Genesis”) involving two of our pipelines. The NEJD pipeline system included a 20-year secured financing lease, and the Free State Pipeline included a long-term transportation service agreement. On August 7, 2020, Genesis, as the beneficiary of the $41.3 million letter of credit issued as financial assurances under the NEJD pipeline lease financing, drew the full amount of such letter of credit in accordance with its terms as a result of the Predecessor’s Chapter 11 Restructuring, which resulted in a corresponding reduction to the principal balance outstanding under such financing. In late October 2020, we restructured our CO2 pipeline financing arrangements with Genesis, whereby (1) Denbury reacquired the NEJD pipeline system from Genesis in exchange for $70 million to bewhich was paid in four equal payments during 2021, representing full settlement of all remaining obligations under the NEJD secured financing lease; and (2) Denbury reacquired the Free State Pipeline from Genesis in exchange for a one-time payment of $22.5 million on October 30, 2020.

Predecessor Senior Secured Bank Credit Facility

From December 2014 through September 18, 2020, the Company maintained a senior secured revolving credit facility with JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the “Predecessor Bank Credit Agreement”). All but a minor portion of the Predecessor Bank Credit Agreement was refinanced through the DIP Facility from August 4, 2020 through September 18, 2020, which was in turn refinanced by the Successor Bank Credit Agreement upon emergence from the Chapter 11 Restructuring.

Extinguishment of Predecessor Senior Secured Second Lien Notes, Convertible Senior Notes, and Senior Subordinated Notes

Upon emergence from the Chapter 11 Restructuring on September 18, 2020, the Predecessor’s 9% Senior Secured Second Lien Notes due 2021 (the “2021 Notes”), 9¼% Senior Secured Second Lien Notes due 2022, 7¾% Senior Secured Second Lien Notes due 2024, (the “7¾% Senior Secured Notes”), 7½% Senior Secured Second Lien Notes due 2024, (the “7½% Senior Secured Notes”), 6⅜% Convertible Senior Notes due 2024 (the “2024 Convertible Notes”), 6⅜% Senior Subordinated Notes due 2021, (the “Subordinated 2021 Notes”), 5½% Senior Subordinated Notes due 2022, (the “Subordinated 2022 Notes”), and 4⅝% Senior Subordinated Notes due 2023 (the “Subordinated 2023 Notes”) were fully extinguished by issuing equity and/or warrants in the Successor to the holders of that debt. The Predecessor debt discussions that follow are included to provide context on the impact of these transactions on the Predecessor’s financial statements.

Second Quarter 2020 Conversion of 2024 Convertible Notes

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

First Quarter 2020 Repurchases of Senior Secured Notes

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


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2019 Predecessor Debt Reduction Transactions

DuringWith a focus on reducing the third quarteramount of 2019,outstanding debt principal, the Predecessor repurchased $11.0 million in aggregate principal amount of its then outstanding Subordinated 2022 Notes in open market transactions for a total purchase price of $5.3 million, excluding accrued interest. Additionally, during the fourth quarter of 2019, the Predecessor repurchased principally through exchanges an additional $25.3 million in aggregate principal amount of its then outstanding Subordinated 2022 Notes and $75.7 million in aggregate principal amount of its then outstanding Subordinated 2023 Notes for $11.2 million in cash and issuance of 38.3 million shares of the Predecessor’s common stock. In connection with these transactions, the Predecessor recognized a $55.5 million gain on debt extinguishment, net of unamortized debt issuance costs written off, during the year ended December 31, 2019, in its Consolidated Statements of Operations.

During June 2019,engaged in a series of debt exchanges the Predecessor extended the maturitiesand repurchase transactions, resulting in total gains on extinguishments of its outstanding long-term debt and reduced the amount of outstanding debt principal. As part of these transactions, holders exchanged a total of $468.4 million aggregate principal amount of the Predecessor’s then outstanding senior subordinated notes for $102.6 million aggregate principal amount of 7¾% Senior Secured Notes, $245.5 million aggregate principal amount of 2024 Convertible Notes and $120.0 million of cash. The exchanged senior subordinated notes consisted of $152.2 million aggregate principal amount of Subordinated 2021 Notes, $219.9 million aggregate principal amount of Subordinated 2022 Notes and $96.3 million aggregate principal amount of Subordinated 2023 Notes. In addition, holders also exchanged $425.4 million of 7½% Senior Secured Notes for $425.4 million aggregate principal amount of 7¾% Senior Secured Notes. In July 2019, holders exchanged an additional $4.0 million aggregate principal amount of 7½% Senior Secured Notes for $3.8 million aggregate principal amount of 7¾% Senior Secured Notes. As a result, the Predecessor recognized a noncash gain on debt extinguishment, net of transaction costs, totaling $100.5$156.0 million for the year ended December 31, 2019, in its Consolidated Statements of Operations.

In accordance with FASC 470-50, Modifications and Extinguishments, the June 2019 exchange of the Predecessor’s existing senior subordinated notes was accounted for as a debt extinguishment. Therefore, the 7¾% Senior Secured Notes and 2024 Convertible Notes were recorded on the balance sheet at fair market value based upon initial trading prices following their issuance, resulting in a discount to their principal amount of $22.6 million and $79.9 million, respectively.

Separately, the June 2019 exchange of the Predecessor’s existing senior secured second lien notes was accounted for as a modification of those notes. Therefore, 0 gain or loss was recognized, and previously deferred debt issuance costs of $6.9 million were treated as a discount to the principal amount of the 7¾% Senior Secured Notes.

Debt Issuance Costs

In connection with the issuance of our outstanding long-term debt, we have incurred debt issuance costs, which are being amortized to interest expense using the straight line or effective interest method over the term of each related facility or borrowing.  Remaining unamortized debt issuance costs were $8.4 million and $14.0 million at December 31, 2020 (Successor) and 2019 (Predecessor), respectively.  Issuance costs associated with our Successor Bank Credit Agreement (Successor period) and Predecessor Bank Credit Agreement (Predecessor period) are included in “Other assets” in the Consolidated Balance Sheets, and issuance costs associated with the Predecessor’s senior secured second lien notes, convertible senior notes, and senior subordinated notes are included as a reduction of “Long-term debt, net of current portion” in the Consolidated Balance Sheets for the Predecessor period.


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borrowing.  Remaining unamortized debt issuance costs were $5.7 million and $8.4 million at December 31, 2021 and 2020, respectively.  Issuance costs associated with our Successor Bank Credit Agreement are included in “Other assets” in the Consolidated Balance Sheets.

Indebtedness Repayment Schedule

At December 31, 2020,2021, our indebtedness is payable over the next five years and thereafter as follows:
In thousandsIn thousands In thousands 
2021$68,008 
202220220 2022$— 
202320230 2023— 
2024202470,000 202435,000 
202520250 2025— 
20262026— 
ThereafterThereafter0 Thereafter— 
Total indebtednessTotal indebtedness$138,008 Total indebtedness$35,000 
 
Note 9. Income Taxes

Our income tax provision (benefit) is as follows:
SuccessorPredecessorSuccessorPredecessor
Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended December 31, Year Ended
Dec. 31, 2021		Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended
Dec. 31, 2019
In thousandsIn thousands20192018In thousands
Current income tax expense (benefit)Current income tax expense (benefit)   Current income tax expense (benefit)   
FederalFederal$0 $(6,407)$2,645 $(17,885)Federal$— $— $(6,407)$2,645 
StateState30 (853)1,236 1,884 State403 30 (853)1,236 
Total current income tax expense (benefit)Total current income tax expense (benefit)30 (7,260)3,881 (16,001)Total current income tax expense (benefit)403 30 (7,260)3,881 
Deferred income tax expense (benefit)Deferred income tax expense (benefit)   Deferred income tax expense (benefit)   
FederalFederal0 (319,011)89,950 93,395 Federal— — (319,011)89,950 
StateState(2,556)(89,858)10,521 9,839 State364 (2,556)(89,858)10,521 
Total deferred income tax expense (benefit)Total deferred income tax expense (benefit)(2,556)(408,869)100,471 103,234 Total deferred income tax expense (benefit)364 (2,556)(408,869)100,471 
Total income tax expense (benefit)Total income tax expense (benefit)$(2,526)$(416,129)$104,352 $87,233 Total income tax expense (benefit)$767 $(2,526)$(416,129)$104,352 

At December 31, 2020,2021, we had 0 federal net operating loss carryforwards (“NOLs”), tax effected and business interest expense carryforward, or tax credits, as the Company’scredit carryforwards (before provision for valuation allowance) totaling $10.3 million and $18.1 million, respectively. Our federal tax attributesNOLs may be carried forward indefinitely and our credit carryforwards begin to expire in 2041. NOL, enhanced oil recovery credit and research and development credit carryforwards generated prior to January 1, 2021 were fully reduced in accordance with the attribute reduction and ordering rules of Section 108 of the Internal Revenue Code of 1986 pertaining to discharge of indebtedness. At December 31, 2020,2021, we had $0.6 million of alternative minimum tax credits, which under the Tax Cut and Jobs Act passed in 2017 will be fully refundable by 2021,2022, and are recorded as a receivable on the balance sheet, and state NOLs and tax credits totaling $56.0$54.9 million (before provision for valuation allowance) related to all our state operations, which continue as carryforwards for the Successor. Our state NOLs expire in various years, starting in 2025.


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Deferred income taxes reflect the available tax carryforwards and the temporary differences based on tax laws and statutory rates in effect at the December 31, 20202021 and 20192020 balance sheet dates.  As of December 31, 2020,2021, we had $75.1$74.1 million of net state deferred tax assets associated with operations in Louisiana, Mississippi, Montana, North Dakota and Alabama, which were

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fully offset with valuation allowances. The valuation allowances will remain until the realization of future deferred tax benefits are more likely than not to become utilized. The changes in our valuation allowance are detailed below:
SuccessorPredecessorSuccessorPredecessor
Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year EndedYear Ended
Dec. 31, 2021		Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended
Dec. 31, 2019
In thousandsIn thousandsDec. 31, 2019Dec. 31, 2018In thousands
Beginning balanceBeginning balance$129,840 $77,215 $51,093 $51,134 Beginning balance$129,408 $129,840 $77,215 $51,093 
ChargesCharges2,269 77,138 26,122 0 Charges29,345 2,269 77,138 26,122 
DeductionsDeductions(2,701)(24,513)0 (41)Deductions(33,291)(2,701)(24,513)— 
Ending balanceEnding balance$129,408 $129,840 $77,215 $51,093 Ending balance$125,462 $129,408 $129,840 $77,215 

As of December 31, 2020,2021, we had 0 unrecognized tax benefits recorded related to an uncertain tax position.

Significant components of our deferred tax assets and liabilities as of December 31, 20202021 and 20192020 are as follows:

SuccessorPredecessor Successor
In thousandsIn thousandsDecember 31, 2020December 31, 2019In thousandsDecember 31, 2021December 31, 2020
Deferred tax assetsDeferred tax assets  Deferred tax assets  
Loss and tax credit carryforwards – stateLoss and tax credit carryforwards – state$54,943 $55,979 
Derivative contractsDerivative contracts30,892 13,090 
Accrued liabilities and other reservesAccrued liabilities and other reserves19,567 15,632 
Business credit carryforwardsBusiness credit carryforwards18,066 — 
Loss carryforwards – federalLoss carryforwards – federal10,310 — 
Lease liabilitiesLease liabilities4,523 6,354 
Property and equipmentProperty and equipment$59,207 $0 Property and equipment2,613 59,207 
Loss and tax credit carryforwards – state55,979 52,917 
Accrued liabilities and other reserves15,632 29,788 
Derivative contracts13,090 0 
Lease liabilities6,354 10,841 
Business interest expense carryforward0 24,513 
Business credit carryforwards0 71,555 
Unrecognized gain and original issue discount on debt exchange0 41,556 
OtherOther4,092 15,664 Other4,206 4,092 
Valuation allowancesValuation allowances(129,408)(77,215)Valuation allowances(125,462)(129,408)
Total deferred tax assetsTotal deferred tax assets24,946 169,619 Total deferred tax assets19,658 24,946 
Deferred tax liabilitiesDeferred tax liabilities  Deferred tax liabilities  
CO2 and other contracts
CO2 and other contracts
(20,030)0 
CO2 and other contracts
(17,208)(20,030)
Operating lease right-of-use assetsOperating lease right-of-use assets(6,190)(7,780)Operating lease right-of-use assets(4,088)(6,190)
Property and equipment0 (569,254)
Derivative contracts0 (1,120)
Other0 (1,695)
Total deferred tax liabilitiesTotal deferred tax liabilities(26,220)(579,849)Total deferred tax liabilities(21,296)(26,220)
Total net deferred tax liabilityTotal net deferred tax liability$(1,274)$(410,230)Total net deferred tax liability$(1,638)$(1,274)


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Our reconciliation of income tax expense computed by applying the U.S. federal statutory rate and the reported effective tax rate on income from continuing operations is as follows:
SuccessorPredecessorSuccessorPredecessor
Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended December 31, Year Ended
Dec. 31, 2021		Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended
Dec. 31, 2019
In thousandsIn thousands20192018In thousands
Income tax provision calculated using the federal statutory income tax rateIncome tax provision calculated using the federal statutory income tax rate$(11,169)$(388,228)$67,475 $86,086 Income tax provision calculated using the federal statutory income tax rate$11,921 $(11,169)$(388,228)$67,475 
State income taxes, net of federal income tax benefitState income taxes, net of federal income tax benefit(2,532)(86,937)7,435 11,968 State income taxes, net of federal income tax benefit450 (2,532)(86,937)7,435 
Tax shortfall (windfall) on stock-based compensation deductionTax shortfall (windfall) on stock-based compensation deduction0 (1,502)1,912 (1,565)Tax shortfall (windfall) on stock-based compensation deduction(267)— (1,502)1,912 
Valuation allowance9,653 19,344 26,122 (42)
Nondeductible compensationNondeductible compensation5,057 — — — 
Change in valuation allowanceChange in valuation allowance(2,928)9,653 19,344 26,122 
Enhanced oil recovery credits generatedEnhanced oil recovery credits generated(14,272)— — — 
Tax attributes reduction – net of CODI exclusionTax attributes reduction – net of CODI exclusion0 31,667 0 0 Tax attributes reduction – net of CODI exclusion— — 31,667 — 
Enhanced oil recovery tax credits generated0 0 0 (10,818)
OtherOther1,522 9,527 1,408 1,604 Other806 1,522 9,527 1,408 
Total income tax expense (benefit)Total income tax expense (benefit)$(2,526)$(416,129)$104,352 $87,233 Total income tax expense (benefit)$767 $(2,526)$(416,129)$104,352 
 
We file consolidated and separate income tax returns in the U.S. federal jurisdiction and in many state jurisdictions.  The statutes of limitation for our income tax returns for tax years ending prior to 20172018 have lapsed and therefore are not subject to examination by respective taxing authorities. We have 0tnot paid any significant interest or penalties associated with our income taxes.

Note 10. Stockholders’ Equity

Registration Rights Agreement

On September 18, 2020, in connection with the Emergence Date,Company’s emergence from Chapter 11 proceedings, the Company entered into a registration rights agreement (the “Registration Rights Agreement”) with certain former beneficial holders of the second lien notes of the Predecessor whothat entered into the RSA dated July 28, 2020,restructuring support agreement leading to the restructuring of the Company pursuant to a prepackaged plan of reorganization and that together with their affiliates received 4% or more of New Common Stock (including sharespursuant to which they are entitled upon exercisethe Company included these holders’ shares of series A warrantscommon stock of the Successor) pursuant toSuccessor in an automatically effective resale registration statement filed with the Plan, orSEC in April 2021 for their affiliates.

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

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

401(k) Plan

We offer a 401(k) plan to which employees may contribute earnings subject to IRS limitations.  We match 100% of an employee’s contribution, up to 6% of compensation, as defined by the plan, which is vested immediately.  Matching contributions to the 401(k) plan totaled $5.1 million during 2021 (Successor), $1.1 million for the period September 19, 2020 through December 31, 2020 (Successor)

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and, $4.4 million for the period January 1, 2020 through September 18, 2020 (Predecessor). During 2019, and 2018, our matching contributions to the 401(k) plan were approximately $6.3 million and $6.2 million, respectively.during 2019 (Predecessor).

Note 11. Stock Compensation

Below is a description of stock compensation relating to both the Predecessor periods (2018, 2019(2019 and January 1, 2020 through September 18, 2020), and the Successor periodperiods (September 19, 2020 through December 31, 2020)2020 and 2021). All stock compensation plans and awards in effect during the Predecessor periods were cancelled upon emergence of the Company from its Chapter 11 Restructuring on September 18, 2020. The plans and awards described below which are designated as Successor

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plans or awards are the only such plans and awards in effect as of December 31, 2020.2021. Each of the plans and awards described below are designated as either Predecessor or Successor, with the exception of the section labeled “Stock-Based Compensation – Predecessor and Successor” which pertains to both Predecessor and Successor periods.

Stock-based Compensation – Predecessor and Successor

Stock-based compensation expense is included in “General and administrative expenses” in the Consolidated Statements of Operations.  Stock-based compensation associated with our employees involved in exploration and drilling activities is capitalized as part of “Oil and natural gas properties” in the Consolidated Balance Sheets. Our accounting policy is to account for forfeitures as they occur.

The following table sets forth stock-based compensation costs for the periods indicated:

SuccessorPredecessorSuccessorPredecessor
Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended December 31, Year Ended
Dec. 31, 2021		Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended
Dec. 31, 2019
In thousandsIn thousands20192018In thousands
Stock-based compensation expense included in G&AStock-based compensation expense included in G&A$8,212 $4,111 $12,470 $11,951 Stock-based compensation expense included in G&A$25,322 $8,212 $4,111 $12,470 
Stock-based compensation capitalizedStock-based compensation capitalized695 1,660 4,018 3,487 Stock-based compensation capitalized1,883 695 1,660 4,018 
Total cost of stock-based compensation arrangementsTotal cost of stock-based compensation arrangements$8,907 $5,771 $16,488 $15,438 Total cost of stock-based compensation arrangements$27,205 $8,907 $5,771 $16,488 
Income tax benefit recognized for stock-based compensation arrangementsIncome tax benefit recognized for stock-based compensation arrangements$2,053 $1,028 $3,118 $2,988 Income tax benefit recognized for stock-based compensation arrangements$6,331 $2,053 $1,028 $3,118 

Management Incentive Plan – Successor

In connection with our emergence from bankruptcy, the Plan provided for the adoption of a management incentive plan, the Denbury Inc. 2020 Omnibus Stock and Incentive Plan (the “LTIP”), effective as of the Emergence Date, through an amendment and restatement of the Denbury Resources Inc. Amended and Restated 2004 Omnibus Stock and Incentive Plan, as amended and restated as of March 26, 2020. The LTIP reserved 6.2 million shares of Denbury’s common stock for awards to officers, other employees, directors and other service providers. The LTIP provides for, among other things, the grant of incentive stock options, nonstatutory stock options, restricted stock, restricted stock units, stock appreciation rights, dividend equivalents, other stock-based awards, cash awards, or any combination of the foregoing. On December 2, 2020, Denbury’s board of directors approved and ratified the LTIP, with initial awards covering 2.2 million shares of common stock granted on December 4, 2020. As of December 31, 2020, 4.02021, 3.9 million shares were available for future grants under the LTIP, all of which could be issued in the form of restricted stock units or performance stock units. Our incentive compensation program is administered by the Compensation Committee of our Board of Directors. The LTIP will expire September 2030.


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Restricted Stock Units – Successor

In December 2020, non-performance-based restricted stock unit (“RSU”) awards were granted to directors and a limited number of employees under the Successor’s LTIP. Holders of non-performance-based RSUs will receive shares of Successor common stock equal to the number of RSUs that have vested upon settlement. Non-performance-based RSUs generally vest ratably over a three-year vestingthree-year period with delivery of the shares occurring at the end of the three-year vesting period. Vested non-performance-based RSU awards provide the holders with dividend equivalent rights payable upon settlement of the underlying RSU awards. Shares to be delivered to participants are expected to be made available from authorized but unissued shares reserved under the LTIP. The grant-date fair value of the RSUs is based on the fair market value of our common stock on the date of grant.

As of December 31, 2020,2021, there was $29.3$19.9 million of unrecognized compensation expense related to the Successor’s nonvested non-performance-based restricted stock unit grants.  This unrecognized compensation cost is expected to be

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recognized over a weighted-average period of 2.91.9 years. The following is a summary of the total vesting date fair value of non-performance-based restricted stock units:
Year Ended
Dec. 31, 2021
In thousands
Fair value of restricted stock units vested$31,073 

A summary of the status of our nonvested non-performance-based RSUs issued and the changes during the Successor period is presented below:
Number
of Awards		Weighted
Average
Grant-Date
Fair Value		Number
of Awards		Weighted
Average
Grant-Date
Fair Value
Nonvested at September 19, 2020 (Successor)0 $0 
Nonvested at December 31, 2020Nonvested at December 31, 20201,219,867 $24.67 
GrantedGranted1,219,867 24.67 Granted56,236 31.87 
VestedVested0 0 Vested(405,311)24.80 
ForfeitedForfeited0 0 Forfeited(20,885)24.67 
Nonvested at December 31, 2020 (Successor)1,219,867 24.67 
Nonvested at December 31, 2021Nonvested at December 31, 2021849,907 25.08 

Performance-Based Stock Units – Successor

In December 2020, the Successor Board of Directors granted performance stock unit (“PSU”) awards to a limited number of employees. The PSU awards vest based on Denbury’s stock price reaching certain levels (based onhad vesting parameters tied to the daily volume-weighted averageCompany’s common stock pricetrading prices and became fully vested on March 3, 2021. Although the New York Stock Exchange (“NYSE”)performance measures for any consecutive 60-day trading period), as shown in the table below, butvesting of these awards have been achieved, delivery of the shares will not occur until the conclusion of the three-year performance period.period, December 4, 2023. Vested performance-based PSU awards provide the holders with dividend equivalent rights payable upon settlement of the underlying PSU awards. Shares to be delivered to participants are expected to be made available from authorized but unissued shares reserved under the LTIP.
TierStock Price Hurdle
Cumulative Percentage of PSUs Granted Hereunder that Become Vested(1)
0Less than $18.750%
1$18.7525%
2$21.0050%
3$23.2575%
4$25.75100%
(1)If the 60-day volume-weighted average price falls between the Stock Price Hurdles in Tier 1, 2, 3 or 4, then the cumulative percentage of PSUs granted that become vested shall be calculated using straight-line interpolation between the corresponding percentages in the table above.

PSU awards are valued using a Monte Carlo simulation. Expected volatilities utilized in the model were estimated using historical volatility of the Predecessor stock over a look-back term generally equivalent to the expected life of the award from the grant date.


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As of December 31, 2020,2021, there was $16.6 million ofno remaining unrecognized compensation expense related to the Successor’s nonvested PSU awards.  This unrecognized compensation cost is expected to be recognized over a weighted-average period of 0.2 years, though the underlying shares will not be delivered until the conclusion of the three-year performance period. The range of assumptions used in the Monte Carlo simulation valuation approach is as follows:
Successor
Period from Sept. 19, 2020 through
Dec. 31, 2020
 
Weighted average fair value of PSU awards granted$24.19 
Risk-free interest rate0.21 %
Expected life0.23 years
Expected volatility110.0 %
Dividend yield0— %


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A summary of the status of the nonvested PSU awards activity during the Successor period is as follows:
Number
of Awards		Weighted
Average
Grant-Date Fair Value		Number
of Awards		Weighted
Average
Grant-Date Fair Value
Nonvested at September 19, 2020 (Successor)0 $0 
Nonvested at December 31, 2020Nonvested at December 31, 20201,021,222 $24.19 
GrantedGranted1,021,222 24.19 Granted— — 
VestedVested0 0 Vested(1,021,222)24.19 
ForfeitedForfeited0 0 Forfeited— — 
Nonvested at December 31, 2020 (Successor)1,021,222 24.19 
Nonvested at December 31, 2021Nonvested at December 31, 2021— — 

The following is a summary of the total vesting date fair value of PSU awards:
Year Ended
Dec. 31, 2021
In thousands
Vesting date fair value of PSU awards$45,077 

June 2020 Compensation Adjustments – Predecessor

In response to the then ongoing significant economic and market uncertainty affecting the oil and gas industry, in June 2020 the Predecessor and its Board of Directors and Compensation Committee implemented a revised compensation structure under which for 21 of the Company’s executives (including our named executive officers) and senior managers, all outstanding equity awards and 2020 targeted variable cash-based compensation were canceled and replaced with a cash retention incentive. In total, $15.2 million in cash retention incentives were prepaid to those employees in June 2020, with an obligation of the executives to repay up to 100% of the compensation (on an after-tax basis) if specified conditions were not satisfied. The Predecessor’s named executive officers’ cash retention incentives were earned 50% based on their continued employment for a period of up to 12 months and 50% based on achieving certain specified incentive metrics.

In accordance with FASC Topic 718, Compensation – Stock Compensation, we accounted for the transaction involving equity compensation as an award modification and reclassified the awards from equity to liability awards. As a result of the modification of the awards, unrecognized compensation at the time of modification was determined to be $18.7 million ($4.1 million of incremental compensation expense), which was higher than the $15.2 million cash payment, and was calculated as the greater of (i) grant date fair value of the previously-outstanding awards plus incremental compensation (defined as cash paid related to the cash retention incentive in excess of the modification date fair value of the previously-existing awards) or (ii) cash paid for the cash retention incentive for each award. The value was recognized as total compensation expense for each award over the service period. The compensation expense was recognized in “General and administrative expenses” in the Consolidated Statements of Operations during the period January 1, 2020 through September 18, 2020 (Predecessor). The accounting for the Predecessor’s remaining share-based compensation awards continued throughout the period covered by the Chapter 11 Restructuring, and upon cancellation of the awards, an additional $4.6 million of compensation expense was recognized during the Predecessor period ended September 18, 2020.


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2004 Omnibus Stock and Incentive Plan – Predecessor

The Amended and Restated 2004 Omnibus Stock and Incentive Plan, amended and restated as of March 26, 2020 (the “2004 Plan”), was an incentive plan that provided for the issuance of incentive and non-qualified stock options, restricted stock awards, restricted stock units, stock appreciation rights (“SARs”) settled in stock, and performance-based awards to officers, employees and directors. Since the 2004 Plan’s inception, awards covering a total of 61.4 million shares of common stock were authorized for issuance pursuant to the 2004 Plan.  In connection with our emergence from bankruptcy, all outstanding equity as of September 18, 2020 was cancelled.

SARs – Predecessor

Prior to January 1, 2016, the Predecessor granted SARs settled in stock to employees. The SARs generally became exercisable over a three-year vesting period, with the specific terms of vesting determined at the time of grant based on guidelines established by the Predecessor’s Compensation Committee of the Board of Directors.  The SARs expired over terms not to exceed 7 years from the date of grant, 90 days after termination of employment, 90 days or one year after permanent disability, depending on the award, or one year after the death of the optionee.  The SARs were granted with a strike price equal to the fair market value at the time of grant, which was equal to the closing price on the NYSE on the date of grant.

The following is a summary of the Predecessor’s SAR activity:
Number
of Awards		Weighted
Average
Exercise Price		Weighted Average Remaining Contractual Life
(in years)		Aggregate Intrinsic Value
(in thousands)
Outstanding at December 31, 2019 (Predecessor)1,981,156 $9.12 
Granted0 0 
Exercised0 0 
Forfeited— — 
Expired(580,087)12.38 
Cancelled(1,401,069)7.77 
Outstanding at September 18, 2020 (Predecessor)0 0 —$0 
Exercisable at end of period0 $0 —$0 

As of December 31, 2018, all SARs vested and there was 0 remaining compensation cost to be recognized in future periods related to nonvested share-based SAR compensation arrangements. The grant-date fair value of SARs vested during the year ended December 31, 2018 was $1.1 million. There were 0 exercises of SARs for the period January 1, 2020 through September 18, 2020 (Predecessor) or the years ended December 31, 2019 and 2018. In connection with our emergence from bankruptcy, all SARs outstanding as of September 18, 2020 were cancelled.

Restricted Stock – Predecessor

During the Predecessor period, we granted non-performance-based restricted stock to employees and directors as part of our long-term compensation program. Holders of non-performance-based restricted stock awards had the rights of owning non-restricted stock (including voting rights) except that the holders were not entitled to delivery of a portion thereof until certain

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requirements were met.  Beginning in 2014, non-performance-based restricted stock awards provided the holders with forfeitable dividend equivalent rights which vested with the underlying shares. Non-performance-based restricted stock vested over a three-year vesting period, with the specific terms of vesting determined at the time of grant.


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The following is a summary of the total vesting date fair value of non-performance-based restricted stock:
Predecessor
Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended December 31,
In thousands20192018
Fair value of restricted stock vested$707 $5,743 $23,060 

A summary of the status of our nonvested non-performance-based restricted stock grants issued and the changes during the Predecessor period is presented below:
Number
of Shares		Weighted
Average
Grant-Date
Fair Value
Nonvested at December 31, 2019 (Predecessor)12,407,436 $1.91 
Granted0 0 
Vested(2,743,473)2.10 
Forfeited— — 
Cancelled(9,663,963)1.85 
Nonvested at September 18, 2020 (Predecessor)0 0 
Predecessor
Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended
Dec. 31, 2019
In thousands
Fair value of restricted stock vested$707 $5,743 

In connection with our emergence from bankruptcy, all restricted stock outstanding as of September 18, 2020 was cancelled and there was 0no remaining compensation cost to be recognized in future periods related to nonvested non-performance-based restricted stock arrangements.

Performance-Based Equity Awards – Predecessor

The Predecessor’s Compensation Committee of the Board of Directors annually granted performance-based equity awards to Denbury’s officers.  Performance-based awards generally vested over 3.25 years for awards granted in 2018, 2019 and 2020. The number of performance-based shares earned (and eligible to vest) during the performance period was dependent upon: (1) the level of success in achieving specifically identified performance targets (“Performance-Based Operational Awards”) and (2) performance of the Predecessor’s stock relative to that of a designated peer group (“Performance-Based TSR Awards”).  As discussed above, in conjunction with our 2020 compensation adjustments, all outstanding Predecessor performance-based equity awards were canceled and replaced with a cash retention incentive in June 2020.

Performance-Based Operational Awards were valued using the fair market value of the Predecessor’s stock, and Performance-Based TSR Awards were valued using a Monte Carlo simulation. Expected volatilities utilized in the model were estimated using historical volatility of the Predecessor stock over a look-back term generally equivalent to the expected life of the award from the grant date. The range of assumptions used in the Monte Carlo simulation valuation approach for Performance-Based TSR Awards (presented at the target level) is as follows:
Predecessor
Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended December 31,
 20192018
Weighted average fair value of Performance-Based TSR Awards granted$0.15 $1.95 $2.29 
Risk-free interest rate0.27 %2.27 %2.37 %
Expected life3.0 years3.0 years3.0 years
Expected volatility89.6 %77.2 %102.9 %
Dividend yield0 %0 %0 %


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A summary of the status of the nonvested performance-based equity awards (presented at the target level) during the Predecessor period is as follows:
Performance-Based
Operational Awards		Performance-Based
TSR Awards
Number
of Awards		Weighted
Average
Grant-Date Fair Value		Number
of Awards		Weighted
Average
Grant-Date Fair Value
Nonvested at December 31, 2019 (Predecessor)1,838,584 $2.27 4,475,998 $2.65 
Granted(1)
0 0 3,041,774 0.15 
Vested(2)
0 0 (742,996)3.42 
Forfeited(102,469)2.28 (385,183)1.26 
Cancelled(1,736,115)2.27 (6,389,593)1.23 
Nonvested at September 18, 2020 (Predecessor)0 0 0 0 
(1)Amounts granted reflect the number of performance units granted. The actual payout of the shares were between 0% and 200%, with any amounts earned above the 100% target levels payable in cash, rather than in shares of stock, in order to conserve available shares.
(2)During 2020, the service period lapsed on these TSR performance unit awards. The lapsed units earned a weighted average of 59% of target for each vested TSR performance-based award, representing 438,363 aggregate shares of Predecessor common stock issued. There were no vestings related to the Predecessor’s Operational performance-based awards during 2020.
Predecessor
Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended
Dec. 31, 2019
 
Weighted average fair value of Performance-Based TSR Awards granted$0.15 $1.95 
Risk-free interest rate0.27 %2.27 %
Expected life3.0 years3.0 years
Expected volatility89.6 %77.2 %
Dividend yield— %— %

The following is a summary of the total vesting date fair value of performance-based equity awards for the Predecessor:
PredecessorPredecessor
Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended December 31,Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended
Dec. 31, 2019
In thousandsIn thousands20192018In thousandsPeriod from Jan. 1, 2020 through
Sept. 18, 2020
Vesting date fair value of Performance-Based Operational AwardsVesting date fair value of Performance-Based Operational Awards$0 $0 $595��Vesting date fair value of Performance-Based Operational Awards$— $— 
Vesting date fair value of Performance-Based TSR AwardsVesting date fair value of Performance-Based TSR Awards79 2,783 542 Vesting date fair value of Performance-Based TSR Awards79 2,783 

In June 2020, all outstanding performance-based equity awards were cancelled and replaced with a cash retention incentive (see June 2020 Compensation Adjustments – Predecessor); there was no remaining compensation cost as of September 18, 2020 to be recognized in future periods related to performance-based equity awards.

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Note 12. 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 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 ofprices, and occasionally requirements under our Successor Bank Credit Agreement, by December 31, 2020, we were required to have hedges in place covering a minimum of 65% of our anticipated crude oil production for the twelve calendar months between August 1, 2020 through July 31, 2021 and 35% of our anticipated crude oil production for the second twelve calendar months between August 1, 2021 through July 31, 2022.bank credit facility. As of December 31, 2020, we were in compliance with the hedging requirements ofunder our Successor Bank Credit Agreement requiring certain minimum commodity hedge levels through July 31, 2022, and we have no further hedging requirements under the Successor Bank Credit Agreement.

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 December 31, 2020,2021, all of our outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those contracts can be offset

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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 December 31, 2020,2021, none of which are classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic:
MonthsMonthsIndex PriceVolume (Barrels per day)Contract Prices ($/Bbl)MonthsIndex PriceVolume (Barrels per day)Contract Prices ($/Bbl)
Range(1)
 Weighted Average Price
Range(1)
 Weighted Average Price
SwapSold PutFloorCeilingSwapFloorCeiling
Oil Contracts:Oil Contracts:Oil Contracts:
2021 Fixed-Price Swaps
Jan – DecNYMEX26,000$38.68 –47.69 $42.54 $— $— $— 
2021 Collars
Jan – DecNYMEX3,000$45.00 –51.30 $— $— $45.00 $50.95 
2022 Fixed-Price Swaps2022 Fixed-Price Swaps2022 Fixed-Price Swaps
Jan – JuneNYMEX8,500$42.65 –45.50 $43.55 $— $— $— 
Jan – JunJan – JunNYMEX15,500$42.65 –58.15 $49.01 $— $— 
July – DecJuly – DecNYMEX9,00050.13 –60.35 56.35 — — 
2022 Collars2022 Collars
Jan – JunJan – JunNYMEX11,000$47.50 –70.75 $— $49.77 $64.31 
July – DecJuly – DecNYMEX10,00047.50 –70.75 — 49.75 64.18 

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

Note 13. 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

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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

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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.

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 December 31, 20202021 and 2019:2020:
Fair Value Measurements Using: Fair Value Measurements Using:
Quoted Prices
in Active
Markets		Significant
Other
Observable
Inputs		Significant
Unobservable
Inputs		Quoted Prices
in Active
Markets		Significant
Other
Observable
Inputs		Significant
Unobservable
Inputs
In thousandsIn thousands(Level 1)(Level 2)(Level 3)TotalIn thousands(Level 1)(Level 2)(Level 3)Total
December 31, 2020 (Successor)    
December 31, 2021December 31, 2021    
LiabilitiesLiabilities
Oil derivative contracts – currentOil derivative contracts – current$— $(134,509)$— $(134,509)
Oil derivative contracts – long-termOil derivative contracts – long-term— — — — 
Total LiabilitiesTotal Liabilities$— $(134,509)$— $(134,509)
December 31, 2020December 31, 2020    
AssetsAssetsAssets
Oil derivative contracts – currentOil derivative contracts – current$0 $187 $0 $187 Oil derivative contracts – current$— $187 $— $187 
Total AssetsTotal Assets$0 $187 $0 $187 Total Assets$— $187 $— $187 
LiabilitiesLiabilitiesLiabilities
Oil derivative contracts – currentOil derivative contracts – current$0 $(53,865)$0 $(53,865)Oil derivative contracts – current$— $(53,865)$— $(53,865)
Oil derivative contracts – long-termOil derivative contracts – long-term0 (5,087)0 (5,087)Oil derivative contracts – long-term— (5,087)— (5,087)
Total LiabilitiesTotal Liabilities$0 $(58,952)$0 $(58,952)Total Liabilities$— $(58,952)$— $(58,952)
December 31, 2019 (Predecessor)    
Assets
Oil derivative contracts – current$0 $8,503 $3,433 $11,936 
Total Assets$0 $8,503 $3,433 $11,936 
Liabilities
Oil derivative contracts – current$0 $(6,522)$(1,824)$(8,346)
Total Liabilities$0 $(6,522)$(1,824)$(8,346)


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


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Level 3 Fair Value Measurements

The following table summarizes the changes in the fair value of our Level 3 assets and liabilities for the periods indicated:
SuccessorPredecessor
Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended
In thousandsDec. 31, 2019
Fair value of Level 3 instruments, beginning of period$0 $1,609 $13,624 
Transfers out of Level 30 (1,609)0 
Fair value adjustments on commodity derivatives0 0 (8,205)
Receipt on settlements of commodity derivatives0 0 (3,810)
Fair value of Level 3 instruments, end of period$0 $0 $1,609 
The amount of total losses for the period included in earnings attributable to the change in unrealized losses relating to assets or liabilities still held at the reporting date$0 $0 $(556)

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

Other Fair Value Measurements

The carrying value of our loans under our Successor Bank Credit Agreement approximate fair value, as they are subject to short-term floating interest rates that approximate the rates available to us for those periods.  We use a market approach to determine the fair value of our fixed-rate long-term debt using observable market data. The fair values of the Predecessor’s senior secured second lien notes, convertible senior notes, and senior subordinated notes were based on quoted market prices, which are considered Level 1 measurements under the fair value hierarchy.  The estimated fair value of the principal amount of our debt as of December 31, 20202021 and 2019,2020, excluding pipeline financing obligations, was $35.0 million and $70.0 million, and $1,833.1 million, respectively, which decrease is primarily the result of the cancellation of $2.1 billion principal amount of debt as part of the Chapter 11 Restructuring.  See Note 1, Nature of Operations and Summary of Significant Accounting Policies – Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code, for additional information.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 14. Commitments and Contingencies

Commitments

We have entered into long-term commitments to purchase CO2 that are either non-cancelable or cancelable only upon the occurrence of specified future events.  The commitments continue for up to 87 years.  The price we will pay for CO2 generally varies depending on the amount of CO2 delivered and the price of oil.  Our annual commitment under these contracts could range from $15 million to $23 million per year, assuming a $60 per Bbl NYMEX oil price. In addition, we have a processing fee contract related to our overriding royalty interest in the CO2 at LaBarge Field. We estimate ourOur annual commitment under this contractthese contracts could range from $8$39 million to $11$46 million in 2022, assuming a $70 per year based on current processing fee rates.Bbl NYMEX oil price and declines in future years as the CO2 purchase contract commitments expire.

We are party to long-term contracts that require us to deliver CO2 to our customers who are industrial end-users of CO2 or EOR customers at various contracted prices. Based upon the maximum amounts deliverabledaily contract quantities as stated in the industrial contracts, we estimate that we maytotal amounts deliverable to these customers could be obligated to deliver up to 673572 Bcf of CO2 to these customers over the next 1413 years. The maximum volume required in any given year is approximately 276 MMcf/d, which we judge to be minor given the size of our Jackson Dome proved CO2 reserves

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at December 31, 2020, our current production capabilities and our projected levels of CO2 usage for our own tertiary flooding program.

Chapter 11 Proceedings

On July 30, 2020, Denbury Resources Inc. and each of its wholly-owned subsidiaries filed for relief under chapter 11 of the Bankruptcy Code. The chapter 11 cases were administered jointly under the caption “In re Denbury Resources Inc., et al., Case No. 20-33801”. On September 2, 2020, the Bankruptcy Court entered the Confirmation Order and on the Emergence Date, all of the conditions of the Plan were satisfied or waived and the Plan became effective and was implemented in accordance with its terms. On September 30, 2020, the Bankruptcy Court closed the chapter 11 cases of each of Denbury Inc.’s wholly-owned subsidiaries. The chapter 11 case captioned “In re Denbury Resources Inc., et al., Case No. 20-33801” will remain pending until the final resolution of all outstanding claims.

Litigation

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

Riley Ridge Helium Supply Contract Claim

As part of our 2010 and 2011 acquisitions of the Riley Ridge Unit and associated gas processing facility that was under construction, the Company assumed a 20-year helium supply contract under which we agreed to supply the helium separated from the full well stream by operation of the gas processing facility to a third-party purchaser, APMTG Helium, LLC (“APMTG”).

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

On March 11, 2019, the trial court entered a final judgment that a force majeure condition did exist, but such condition only excused the Company’s performance for a 35-day period in 2014, and as a result the Company should pay APMTG liquidated damages and interest thereon for all other time periods for performance from contract commencement to the close of evidence (November 29, 2017). On December 4, 2020, the Wyoming Supreme Court entered a judgment affirming the trial court’s ruling on all counts and, as a result, the Company paid total liquidated damages (including interest) of $52.1 million to APMTG on December 23, 2020 in full satisfaction of all claims. The Company had previously recorded an accrual for these costs in “Accounts payable and accrued liabilities” in our Consolidated Balance Sheets.

Other Contingencies

We are 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.  In the past, settlement of these matters has not had a material adverse financial impact on us, and currently we have 0no material assessments for potential taxes.

We are subject to various possible contingencies that arise primarily from interpretation of federal and state laws and regulations affecting the oil and natural gas industry.  Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters.  Although we believe that we have complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued.  In addition, production rates, marketing and environmental matters are subject to regulation by various federal and state agencies.


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Note 15. Additional Balance Sheet Details

Rollforward of Allowance for Doubtful Accounts
SuccessorPredecessorSuccessorPredecessor
Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended Year Ended
Dec. 31, 2021		Period from
Sept. 19, 2020 through
Dec. 31, 2020		Period from
Jan. 1, 2020 through
Sept. 18, 2020		Year Ended
Dec. 31, 2019
In thousandsIn thousandsDec. 31, 2019Dec. 31, 2018In thousands
Beginning balanceBeginning balance$22,146 $17,137 $17,070 $229 Beginning balance$23,206 $22,146 $17,137 $17,070 
Provision for doubtful accountsProvision for doubtful accounts1,060 5,297 68 16,911 Provision for doubtful accounts826 1,060 5,297 68 
Write-offsWrite-offs0 (288)(1)(70)Write-offs(5,085)— (288)(1)
Ending balanceEnding balance$23,206 $22,146 $17,137 $17,070 Ending balance$18,947 $23,206 $22,146 $17,137 

Accounts Payable and Accrued Liabilities

SuccessorPredecessorSuccessor
In thousandsIn thousandsDecember 31, 2020December 31, 2019In thousandsDecember 31, 2021December 31, 2020
Accrued general and administrative expenses$21,825 $21,838 
Accrued lease operating expensesAccrued lease operating expenses21,294 26,686 Accrued lease operating expenses$27,901 $21,294 
Accrued derivative settlementsAccrued derivative settlements27,336 3,908 
Accounts payableAccounts payable18,629 29,077 Accounts payable25,700 18,629 
Taxes payable17,221 21,274 
Accrued compensationAccrued compensation7,512 36,366 Accrued compensation23,735 7,512 
Accrued exploration and development costsAccrued exploration and development costs1,861 7,811 Accrued exploration and development costs18,936 1,861 
Accrued interest1,833 25,253 
Accrued asset retirement obligations – currentAccrued asset retirement obligations – current18,373 6,943 
Taxes payableTaxes payable14,453 17,221 
Accrued general and administrative expensesAccrued general and administrative expenses2,250 21,825 
OtherOther22,496 15,527 Other32,914 13,478 
TotalTotal$112,671 $183,832 Total$191,598 $112,671 



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Note 16. Supplemental Cash Flow Information

Supplemental Cash Flow Information
SuccessorPredecessorSuccessorPredecessor
Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended December 31, Year Ended
Dec. 31, 2021		Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended
Dec. 31, 2019
In thousandsIn thousands20192018In thousands
Supplemental cash flow informationSupplemental cash flow information   Supplemental cash flow information   
Cash paid for interest, expensedCash paid for interest, expensed$813 $29,357 $72,842 $50,076 Cash paid for interest, expensed$4,227 $813 $29,357 $72,842 
Cash paid for interest, capitalizedCash paid for interest, capitalized1,261 22,885 36,671 37,079 Cash paid for interest, capitalized4,585 1,261 22,885 36,671 
Cash paid for interest, treated as a reduction of debtCash paid for interest, treated as a reduction of debt0 46,417 85,303 79,606 Cash paid for interest, treated as a reduction of debt— — 46,417 85,303 
Cash paid for income taxesCash paid for income taxes0 453 2,361 492 Cash paid for income taxes184 — 453 2,361 
Cash received from income tax refundsCash received from income tax refunds10,457 1,932 9,820 8,280 Cash received from income tax refunds3 10,457 1,932 9,820 
Noncash investing and financing activitiesNoncash investing and financing activities  Noncash investing and financing activities  
Increase in asset retirement obligationsIncrease in asset retirement obligations23,398 4,328 13,560 4,499 Increase in asset retirement obligations112,760 23,398 4,328 13,560 
Increase (decrease) in liabilities for capital expendituresIncrease (decrease) in liabilities for capital expenditures1,867 (12,809)(17,740)14,600 Increase (decrease) in liabilities for capital expenditures35,679 1,867 (12,809)(17,740)
Conversion of convertible senior notes into common stockConversion of convertible senior notes into common stock0 11,501 0 162,004 Conversion of convertible senior notes into common stock— — 11,501 — 

Note 17. Subsequent Event

On March 3, 2021, we closed on an agreement to acquire working interest positions in the Big Sand Draw and Beaver Creek oil fields located in Wyoming, including surface facilities and a CO2 transportation pipeline to the acquired fields, for a cash purchase price of $12 million before closing adjustments.

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SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (UNAUDITED)

Costs Incurred

The following table summarizes costs incurred and capitalized in oil and natural gas property acquisition, exploration and development activities.  Property acquisition costs are those costs incurred to purchase, lease or otherwise acquire property, including both undeveloped leasehold and the purchase of reserves in place.  Exploration costs include costs of identifying areas that may warrant examination and examining specific areas that are considered to have prospects containing oil and natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs, and carrying costs on undeveloped properties.  Development costs are incurred to obtain access to proved reserves, including the cost of drilling development wells, and to provide facilities for extracting, treating, gathering and storing the oil and natural gas, and the cost of improved recovery systems.

We capitalize interest on unevaluated oil and natural gas properties that have ongoing development activities.  Included in costs incurred in the table below is capitalized interest of $4.3 million for the year ended December 31, 2021 (Successor), $1.2 million for the period September 19, 2020 through December 31, 2020 (Successor), $22.0 million for the period January 1, 2020 through September 18, 2020 (Predecessor), and $34.1 million and $36.5 million during the yearsyear ended December 31, 2019 and 2018, respectively.(Predecessor).  Costs incurred also include new asset retirement obligations established, as well as changes to asset retirement obligations resulting from revisions in cost estimates or abandonment dates.  Asset retirement obligations included in the table below were $10.1 million for the year ended December 31, 2021 (Successor), $3.4 million for the period September 19, 2020 through December 31, 2020 (Successor), $2.5 million for the period January 1, 2020 through September 18, 2020 (Predecessor), and $15.2 million and $6.8 million duringfor the yearsyear ended December 31, 2019 and 2018, respectively.(Predecessor).  See Note 6, Asset Retirement Obligations, for additional information.

Costs incurred in oil and natural gas activities were as follows:
SuccessorPredecessorSuccessorPredecessor
Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended December 31, Year Ended
Dec. 31, 2021		Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended
Dec. 31, 2019
In thousandsIn thousands20192018In thousands
Property acquisitionsProperty acquisitions   Property acquisitions   
ProvedProved$130 $278 $1,542 $2,030 Proved$11,141 $130 $278 $1,542 
UnevaluatedUnevaluated— — — — Unevaluated— — — — 
ExplorationExploration60 260 2,575 1,030 Exploration79 60 260 2,575 
DevelopmentDevelopment23,741 92,212 259,641 338,203 Development178,411 23,741 92,212 259,641 
Total costs incurred(1)
Total costs incurred(1)
$23,931 $92,750 $263,758 $341,263 
Total costs incurred(1)
$189,631 $23,931 $92,750 $263,758 

(1)Capitalized general and administrative costs that directly relate to exploration and development activities were $24.9 million for the year ended December 31, 2021 (Successor), $5.6 million for the period September 19, 2020 through December 31, 2020 (Successor), $19.5 million for the period January 1, 2020 through September 18, 2020 (Predecessor), and $39.5 million and $37.2 million for the yearsyear ended December 31, 2019 and 2018, respectively.(Predecessor).


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Oil and Natural Gas Operating Results

Results of operations from oil and natural gas producing activities, excluding corporate overhead and interest costs, were as follows:
SuccessorPredecessorSuccessorPredecessor
Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended December 31, Year Ended
Dec. 31, 2021		Period from Sept. 19, 2020 through
Dec. 31, 2020		Period from Jan. 1, 2020 through
Sept. 18, 2020		Year Ended
Dec. 31, 2019
In thousands, except per-BOE dataIn thousands, except per-BOE data20192018In thousands, except per-BOE data
Oil, natural gas, and related product salesOil, natural gas, and related product sales$201,108 $492,101 $1,212,020 $1,422,589 Oil, natural gas, and related product sales$1,159,955 $201,108 $492,101 $1,212,020 
Lease operating expensesLease operating expenses101,234 250,271 477,220 489,720 Lease operating expenses424,550 101,234 250,271 477,220 
Transportation and marketing expensesTransportation and marketing expenses10,595 27,164 41,810 43,942 Transportation and marketing expenses28,817 10,595 27,164 41,810 
Production and ad valorem taxesProduction and ad valorem taxes15,061 38,647 86,820 96,589 Production and ad valorem taxes88,468 15,061 38,647 86,820 
Depletion, depreciation, and amortizationDepletion, depreciation, and amortization37,549 104,504 161,400 144,423 Depletion, depreciation, and amortization119,997 37,549 104,504 161,400 
CO2 properties and pipelines depletion and depreciation(1)
CO2 properties and pipelines depletion and depreciation(1)
1,744 33,839 53,120 48,792 
CO2 properties and pipelines depletion and depreciation(1)
7,180 1,744 33,839 53,120 
Write-down of oil and natural gas propertiesWrite-down of oil and natural gas properties1,006 996,658 — — Write-down of oil and natural gas properties14,377 1,006 996,658 — 
Commodity derivatives expense (income)Commodity derivatives expense (income)61,902 (102,032)70,078 (21,087)Commodity derivatives expense (income)352,984 61,902 (102,032)70,078 
Net operating income (loss)Net operating income (loss)(27,983)(856,950)321,572 620,210 Net operating income (loss)123,582 (27,983)(856,950)321,572 
Income tax provision (benefit)Income tax provision (benefit)— (214,238)80,393 155,053 Income tax provision (benefit)— — (214,238)80,393 
Results of operations from oil and natural gas producing activitiesResults of operations from oil and natural gas producing activities$(27,983)$(642,712)$241,179 $465,157 Results of operations from oil and natural gas producing activities$123,582 $(27,983)$(642,712)$241,179 
Depletion, depreciation, and amortization per BOEDepletion, depreciation, and amortization per BOE$7.72 $10.15 $10.10 $8.77 Depletion, depreciation, and amortization per BOE$7.14 $7.72 $10.15 $10.10 

(1)Represents an allocation of the depletion and depreciation of our CO2 properties and pipelines associated with our tertiary oil producing activities.

Oil and Natural Gas Reserves

Net proved oil and natural gas reserve estimates for all years presented were prepared by DeGolyer and MacNaughton, independent petroleum engineers located in Dallas, Texas.  These oil and natural gas reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage.  The reserve estimates represent our net revenue interest in our properties.  See Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves below for a discussion of the effect of the different prices on reserve quantities and values.  Operating costs, production and ad valorem taxes, and future development costs were based on current costs as of December 31, 2020.2021.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures.  The following reserve data represents estimates only and should not be construed as being exact.  Moreover, the present values should not be construed as the current market value of our oil and natural gas reserves or the costs that would be incurred to obtain equivalent reserves.  Estimates of reserves as of year-end 2021, 2020 2019 and 20182019 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the applicable fiscal 12-month period.  All of our reserves are located in the United States.


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Estimated Quantities of Proved Reserves
Year Ended December 31, Year Ended December 31,
202020192018 202120202019
Oil
(MBbl)		Gas
(MMcf)		Total
(MBOE)		Oil
(MBbl)		Gas
(MMcf)		Total
(MBOE)		Oil
(MBbl)		Gas
(MMcf)		Total
(MBOE)		Oil
(MBbl)		Gas
(MMcf)		Total
(MBOE)		Oil
(MBbl)		Gas
(MMcf)		Total
(MBOE)		Oil
(MBbl)		Gas
(MMcf)		Total
(MBOE)
Balance at beginning of yearBalance at beginning of year226,133 24,334 230,189 255,042 43,008 262,210 252,625 42,721 259,745 Balance at beginning of year140,499 15,604 143,100 226,133 24,334 230,189 255,042 43,008 262,210 
Revisions of previous estimatesRevisions of previous estimates(63,359)(5,822)(64,329)(6,799)(15,299)(9,348)21,658 6,115 22,677 Revisions of previous estimates55,998 (615)55,895 (63,359)(5,822)(64,329)(6,799)(15,299)(9,348)
Improved recovery(1)
Improved recovery(1)
— — — 977 — 977 2,314 (157)2,288 
Improved recovery(1)
— — — — — — 977 — 977 
ProductionProduction(18,237)(2,905)(18,721)(20,685)(3,375)(21,248)(21,364)(3,962)(22,024)Production(17,258)(3,261)(17,801)(18,237)(2,905)(18,721)(20,685)(3,375)(21,248)
Acquisition of minerals in placeAcquisition of minerals in place9,765 5,764 10,725 — — — — — — 
Sales of minerals in placeSales of minerals in place(4,038)(3)(4,039)(2,402)— (2,402)(191)(1,709)(476)Sales of minerals in place(66)(986)(230)(4,038)(3)(4,039)(2,402)— (2,402)
Balance at end of yearBalance at end of year140,499 15,604 143,100 226,133 24,334 230,189 255,042 43,008 262,210 Balance at end of year188,938 16,506 191,689 140,499 15,604 143,100 226,133 24,334 230,189 
Proved Developed Reserves – end of yearProved Developed Reserves – end of year136,402 15,604 139,003 202,816 24,333 206,872 222,736 42,912 229,888 Proved Developed Reserves – end of year179,147 16,506 181,898 136,402 15,604 139,003 202,816 24,333 206,872 
Proved Undeveloped Reserves – end of yearProved Undeveloped Reserves – end of year4,097 — 4,097 23,317 1 23,317 32,306 96 32,322 Proved Undeveloped Reserves – end of year9,791 — 9,791 4,097 — 4,097 23,317 1 23,317 

(1)Improved recovery reflects reserve additions that result from the application of secondary recovery methods such as water flooding or tertiary recovery methods such as CO2 flooding.  In order to recognize proved tertiary oil reserves, we must either have an oil production response to CO2 injections or the field must be analogous to an existing tertiary flood. The magnitude of proved reserves that we can book in any given year will depend on our progress with new floods and the timing of the production response.

Revisions of previous estimates during 2020, 2019, and 2018 primarily reflect changes in commodity prices between December 31, 2017resulting in upward revisions of 50.1 MMBOE during 2021 and 2020.downward revisions of 75.7 MMBOE and 13.7 MMBOE during 2020 and 2019, respectively.

There were no significant additions, excluding acquisitions of minerals in place in 2021, to our oil and natural gas reserves, as the magnitude of proved reserves that we can book in any given year depends on our progress with new floods and the timing of the production response, and we initiated no new floods in 2021, 2020, 2019 or 2018.2019. Acquisition of minerals in place during 2021 were related to our Wind River Basin acquisition.

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves

The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves (“Standardized Measure”) does not purport to present the fair market value of our oil and natural gas properties.  An estimate of such value should consider, among other factors, anticipated future prices of oil and natural gas, the probability of recoveries in excess of existing proved reserves, the value of probable reserves and acreage prospects, and perhaps different discount rates.  It should be noted that estimates of reserve quantities, especially from new discoveries, are inherently imprecise and subject to substantial revision.

Under the Standardized Measure, future cash inflows were estimated by applying a first-day-of-the-month 12-month average price (as shown in the table below) to the estimated future production of year-end proved reserves.  These prices have a significant impact on both the quantities and value of the proved reserves, as reductions in oil and natural gas prices can cause

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wells to reach the end of their economic life much sooner and can make certain proved undeveloped locations uneconomical, both of which reduce the reserves.  The following representative oil and natural gasThese prices were used in the Standardized Measure.  These prices werefurther adjusted by field to arrive at the appropriate corporate net price.
December 31, December 31,
202020192018 202120202019
Oil (NYMEX price per Bbl)Oil (NYMEX price per Bbl)$39.57 $55.69 $65.56 Oil (NYMEX price per Bbl)$66.56 $39.57 $55.69 
Natural Gas (Henry Hub price per MMBtu)Natural Gas (Henry Hub price per MMBtu)1.99 2.58 3.10 Natural Gas (Henry Hub price per MMBtu)3.60 1.99 2.58 


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The changes in the Standardized Measure of discounted future net cash flows in the tables that follow were significantly impacted by the movement in first-day-of-the-month average NYMEX oil prices between 20182019 and 2020.2021. The weighted-averageweighted average oil prices we receive relative to NYMEX oil prices (our NYMEX oil price differential) utilized were $2.70 per Bbl below representative NYMEX oil prices as of December 31, 2021, compared to $3.73 per Bbl below representative NYMEX oil prices as of December 31, 2020, compared toand $0.14 per Bbl below representative NYMEX oil prices as of December 31, 2019, and $0.24 per Bbl below representative NYMEX oil prices as of December 31, 2018.2019.

Future cash inflows were reduced by estimated future production, development and abandonment costs based on current cost, with no escalation to determine pre-tax cash inflows.  Our future net inflows do not include a reduction for cash previously expended on our capitalized CO2 assets that will be consumed in the production of proved tertiary reserves.  Future income taxes were computed by applying the statutory tax rate to the excess of net cash inflows over our tax basis in the associated proved oil and natural gas properties.  Tax credits and net operating loss carryforwards were also considered in the future income tax calculation.  Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure.
December 31, December 31,
In thousandsIn thousands202020192018In thousands202120202019
Future cash inflowsFuture cash inflows$5,010,288 $12,494,358 $16,657,988 Future cash inflows$12,020,943 $5,010,288 $12,494,358 
Future production costsFuture production costs(3,300,890)(6,813,610)(8,000,884)Future production costs(6,652,315)(3,300,890)(6,813,610)
Future development costsFuture development costs(962,224)(1,434,934)(1,524,476)Future development costs(1,116,998)(962,224)(1,434,934)
Future income taxesFuture income taxes(59,600)(586,441)(1,186,769)Future income taxes(776,337)(59,600)(586,441)
Future net cash flowsFuture net cash flows687,574 3,659,373 5,945,859 Future net cash flows3,475,293 687,574 3,659,373 
10% annual discount for estimated timing of cash flows10% annual discount for estimated timing of cash flows(32,840)(1,398,334)(2,594,474)10% annual discount for estimated timing of cash flows(1,288,242)(32,840)(1,398,334)
Standardized measure of discounted future net cash flowsStandardized measure of discounted future net cash flows$654,734 $2,261,039 $3,351,385 Standardized measure of discounted future net cash flows$2,187,051 $654,734 $2,261,039 
 
The following table sets forth an analysis of changes in the Standardized Measure of Discounted Future Net Cash Flows from proved oil and natural gas reserves:
Year Ended December 31, Year Ended December 31,
In thousandsIn thousands202020192018In thousands202120202019
Beginning of yearBeginning of year$2,261,039 $3,351,385 $2,232,429 Beginning of year$654,734 $2,261,039 $3,351,385 
Sales of oil and natural gas produced, net of production costsSales of oil and natural gas produced, net of production costs(250,237)(608,060)(797,132)Sales of oil and natural gas produced, net of production costs(618,119)(250,237)(608,060)
Net changes in prices and production costsNet changes in prices and production costs(1,753,248)(1,244,859)1,963,333 Net changes in prices and production costs2,360,251 (1,753,248)(1,244,859)
Improved recovery(1)
Improved recovery(1)
— 5,785 11,536 
Improved recovery(1)
— — 5,785 
Previously estimated development costs incurredPreviously estimated development costs incurred28,182 81,024 109,214 Previously estimated development costs incurred36,074 28,182 81,024 
Change in future development costsChange in future development costs11,200 (35,624)(42,240)Change in future development costs(15,623)11,200 (35,624)
Revisions due to timing and otherRevisions due to timing and other(127,046)41,841 10,915 Revisions due to timing and other35,887 (127,046)41,841 
Accretion of discountAccretion of discount233,663 367,313 234,434 Accretion of discount68,119 233,663 367,313 
Acquisition of minerals in placeAcquisition of minerals in place105,610 — — 
Sales of minerals in placeSales of minerals in place(55,102)(16,892)1,281 Sales of minerals in place(1,454)(55,102)(16,892)
Net change in income taxesNet change in income taxes306,283 319,126 (372,385)Net change in income taxes(438,428)306,283 319,126 
End of yearEnd of year$654,734 $2,261,039 $3,351,385 End of year$2,187,051 $654,734 $2,261,039 


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(1)Improved recovery additions result from the application of secondary recovery methods such as water flooding or tertiary recovery methods such as CO2 flooding.

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SUPPLEMENTAL CO2 DISCLOSURES (UNAUDITED)

Based on engineering reports prepared by DeGolyer and MacNaughton, proved CO2 reserves were estimated as follows:
Year Ended December 31, Year Ended December 31,
In MMcfIn MMcf202020192018In MMcf202120202019
CO2 reserves
CO2 reserves
   
CO2 reserves
   
Gulf Coast region(1)
Gulf Coast region(1)
4,641,812 4,786,881 4,982,440 
Gulf Coast region(1)
4,474,313 4,641,812 4,786,881 
Rocky Mountain region(2)
Rocky Mountain region(2)
1,089,101 1,120,060 1,155,538 
Rocky Mountain region(2)
1,046,139 1,089,101 1,120,060 

(1)Proved CO2 reserves in the Gulf Coast region consist of reserves from our reservoirs at Jackson Dome and are presented on a gross (8/8ths) basis, of which our net revenue interest was approximately 3.6 Tcf, 3.7 Tcf 3.8 Tcf and 4.03.8 Tcf at December 31, 2021, 2020 and 2019, and 2018, respectively, and include reserves dedicated to volumetric production payments of 3.1 Bcf at December 31, 2018.respectively.

(2)Proved CO2 reserves in the Rocky Mountain region consist of our overriding royalty interest in LaBarge Field, of which our net revenue interest was approximately 1.11.0 Tcf, 1.1 Tcf and 1.21.1 Tcf at December 31, 2021, 2020 2019 and 2018,2019, respectively.


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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.
 
Item 9A. 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 our 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 December 31, 2020,2021, to ensure that information that is required to be disclosed in the reports the Company files and submits under the Securities Exchange Act of 1934 is recorded; that it is processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and that information that is required to be disclosed under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

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 fourth quarter of fiscal 2020,2021, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended.  Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of the end of the period covered by this report based on the framework in “Internal Control – Integrated Framework” (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on that assessment, our Chief Executive Officer and our Chief Financial Officer concluded that our internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles.

The effectiveness of our internal control over financial reporting as of December 31, 2020,2021, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in the report that appears herein.

Important Considerations

The effectiveness of our disclosure controls and procedures and our internal control over financial reporting is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of our systems, the possibility of human error, and the risk of fraud.  Moreover, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions and the risk that the degree of compliance with policies or procedures may deteriorate over time.  Because of these limitations, there can be no assurance that any system of disclosure controls and procedures or internal control over financial reporting will be successful in preventing all errors or fraud or in making all material information known in a timely manner to the appropriate levels of management.

Item 9B. Other Information

None.


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Denbury Inc.
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

None.

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Denbury Inc.
PART III

Item 10. Directors, Executive Officers and Corporate Governance

Except as disclosed below, information as to Item 10 will be set forth in the Proxy Statement (“Proxy Statement”) for the 20212022 Annual Meeting of Shareholders to be held May 26, 20212022 (“Annual Meeting”) and is incorporated herein by reference.

Code of Ethics

We have adopted a Code of Ethics for Senior Financial Officers.  This Code of Ethics, including any amendments or waivers, is posted on our website at www.denbury.com.

Item 11. Executive Compensation

Information as to Item 11 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information as to Item 12 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Information as to Item 13 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.

Item 14. Principal Accountant Fees and Services

Our independent registered public accounting firm is PricewaterhouseCoopers LLP, Dallas, TX, Auditor ID: 238.

Information as to Item 14 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.


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Denbury Inc.
PART IV

Item 15. Exhibits and Financial Statement Schedules
Financial Statements and Schedules.  Financial statements and schedules filed as a part of this report are presented on page 7063.  All financial statement schedules have been omitted because they are not applicable, or the required information is presented in the financial statements or the notes to consolidated financial statements.

Exhibits.  The following exhibits are included as part of this report.
Exhibit No.Exhibit
2(a)
Joint Chapter 11 Plan of Reorganization of Denbury Resources Inc. and its Debtor Affiliates (Technical Modifications) (incorporated by reference to Exhibit A of the Order Approving the Debtors’ Disclosure Statement For, and Confirming, the Debtors’ Joint Chapter 11 Plan of Reorganization of Denbury Resources Inc. and its Debtor Affiliates, filed as Exhibit 2.1 to Form 8-K filed by the Company on September 4, 2020, File No. 001-12935).

3(a)
Third Restated Certificate of Incorporation of Denbury Resources Inc. (incorporated by reference to Exhibit 3.1 of Form 8-K filed by the Company on September 18, 2020, File No. 001-12935).

3(b)
Fourth Amended and Restated Bylaws of Denbury Resources Inc., as of September 18, 2020 (incorporated by reference to Exhibit 3.2 of Form 8-K filed by the Company on September 18, 2020, File No. 001-12935).

4(a)
Series A Warrant Agreement, dated as of September 18, 2020, by and between Denbury Inc., and Broadridge Corporate Issuer Solutions, Inc. (incorporated by reference to Exhibit 10.2 of Form 8-K filed by the Company on September 18, 2020, File No. 001-12935).

4(b)
Series B Warrant Agreement, dated as of September 18, 2020, by and between Denbury Inc., and Broadridge Corporate Issuer Solutions, Inc. (incorporated by reference to Exhibit 10.3 of Form 8-K filed by the Company on September 18, 2020, File No. 001-12935).

4(c)
Registration Rights Agreement, dated as of September 18, 2020, among Denbury Inc. and certain holders identified therein (incorporated by reference to Exhibit 10.4 of Form 8-K filed by the Company on September 18, 2020, File No. 001-12935).

10(a)
Credit Agreement, dated as of September 18, 2020, by and among Denbury Inc., as borrower, the lenders party thereto, and JPMorgan Chase Bank, N.A., as administrative agent, swingline lender, and letter of credit issuer (incorporated by reference to Exhibit 10.1 of Form 8-K filed by the Company on September 18, 2020, File No. 001-12935).

10(b)
First Amendment to Credit Agreement, dated as of November 3, 2021, by and among Denbury Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10(a) of Form 10-Q filed by the Company on November 4, 2021, File No. 001-12935).

10(c) **
Form of Indemnification Agreement, by and between Denbury Inc. and its officers and directors (incorporated by reference to Exhibit 10.5 of Form 8-K filed by the Company on September 18, 2020, File No. 001-12935).

10(c)10(d)

10(d)10(e) **

10(e)10(f) **

10(f) * **

10(g) * **


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Denbury Inc.
Exhibit No.Exhibit
10(g) **

10(h) ***

10(i) **

21*
List of subsidiaries of Denbury Inc.

23(a)*
Consent of PricewaterhouseCoopers LLP.LLP.

23(b)*
Consent of PricewaterhouseCoopers LLP.LLP.

23(c)*
Consent of DeGolyer and MacNaughton.

31(a)*
Certification of Chief Executive Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002.

31(b)*
Certification of Chief Financial Officer Pursuant to Section 302 of 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.

99*
The summary of DeGolyer and MacNaughton’s Report as of December 31, 2020,2021, on oil and gas reserves (SEC Case) dated February 5, 2021.3, 2022.

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 Document Label Linkbase Document
101.PRE*Inline XBRL Taxonomy Extension Presentation Linkbase Document
104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
*   Included herewith.
** Compensation arrangements.

Item 16. Form 10-K Summary

None.

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Denbury Inc.
SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Denbury Inc. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
DENBURY INC.
March 5, 2021February 24, 2022 /s/ Mark C. Allen
  Mark C. Allen
Executive Vice President and Chief Financial Officer
March 5, 2021February 24, 2022 /s/ Nicole Jennings
Nicole Jennings
Vice President and Chief Accounting Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Denbury Inc. and in the capacities and on the dates indicated.

March 5, 2021February 24, 2022 /s/ Christian S. Kendall
  Christian S. Kendall
Director, President and Chief Executive Officer
(Principal Executive Officer)
March 5, 2021February 24, 2022 /s/ Mark C. Allen
  Mark C. Allen
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
March 5, 2021February 24, 2022 /s/ Nicole Jennings
  Nicole Jennings
Vice President and Chief Accounting Officer
(Principal Accounting Officer)
March 5, 2021February 24, 2022 /s/ Kevin O. Meyers
Kevin O. Meyers
Director
March 5, 2021February 24, 2022/s/ Anthony Abate
Anthony Abate
Director
March 5, 2021February 24, 2022/s/ Caroline Angoorly
Caroline Angoorly
Director
March 5, 2021February 24, 2022/s/ James Chapman
James Chapman
Director

March 5, 2021February 24, 2022/s/ Lynn A. Peterson
Lynn A. Peterson
Director
March 5, 2021February 24, 2022/s/ Brett Wiggs
Brett Wiggs
Director
February 24, 2022/s/ Cindy A. Yeilding
Cindy A. Yeilding
Director


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