CAPTURING OUR FUTURE
2 0 2 1 A N N U A L R E P O R T
FORWARD-LOOKING STATEMENTS
This Annual Report contains forward-looking statements regarding the Company’s current expectations and estimates, in addition to the
forward-looking statements discussed under “Forward-Looking Information” at the end of the Management’s Discussion and Analysis
section of the Form 10-K for the year 2021 contained in this Annual Report. These statements are subject to a variety of risks and
uncertainties that could cause the Company’s actual results to differ materially from these expectations and estimates. Since the filing of
our 2021 Form 10-K, the Russian invasion of Ukraine, various government reactions to that conflict, rising inflation and the accompanying
current and anticipated increases in U.S. interest rates, have all added to the volatility of oil prices, the most important determinant of our
operational and financial success.
CAPTURING OUR FUTURE
DEAR FELLOW
SHAREHOLDERS,
2021 marked a year of important progress
recordable safety incident. In every respect,
for Denbury, as we further strengthened the
this is an incredible accomplishment.
foundation upon which we will execute our vision
of Powering the Energy Transition with World-
leading Carbon Solutions. I am incredibly proud
of our team, whose sustained dedication and
resilience enabled us to achieve strong results
in 2021, and whose relentless focus on safety
drove record performance. We are encouraged
by the strong progress underway at Denbury,
and we expect this momentum to continue
as we grow the business and capitalize on the
rapidly increasing demand for carbon capture,
utilization, and storage (CCUS) solutions.
2021 HIGHLIGHTS
Safety is core to our operational performance
and our team continues to put safety at the
center of everything we do. In 2021, we
achieved a Total Recordable Incident Rate of
0.40, our fifth consecutive annual record-low.
This achievement was even more impressive
considering that we not only managed through
the impact of a global pandemic, but that we
did so while executing a significant CO2
pipeline construction project, expending
over 600,000 man-hours without a single
0.40 TOTAL RECORDABLE
INCIDENT RATE, 5TH
CONSECUTIVE ANNUAL RECORD
In 2021, we commenced development of the
Cedar Creek Anticline (CCA) enhanced oil
recovery (EOR) project, the largest potential
CO2 EOR resource that we have ever developed,
which we expect to be one of the largest
CO2 floods in the world. Our achievements
in 2021 included the completion of the 105-
mile CO2 pipeline to CCA on time and under
budget. Development of this project will greatly
enhance the strength and sustainability of our
EOR business while also increasing Denbury’s
production of carbon-negative oil, which we
believe will become a highly desired commodity.
25% of DENBURY’S
PRODUCTION IS CARBON-
NEGATIVE OR “BLUE OIL”
Through our long-term focus on CO2 EOR, we have
built the most expansive CO2 pipeline infrastructure
in the United States, including through the high-
emissions corridor along the U.S. Gulf Coast. In
addition, we have developed a deep talent base
of experts with passion and knowledge around all
aspects of CO2 management. Today, this world-
class team is helping Denbury advance its CCUS
objectives by leveraging our infrastructure and the
broad technical, project, and operational expertise
that uniquely positions Denbury to be the definitive
leader in this emerging industry.
CAPTURING OUR FUTURE
1300+ MILES OF CO
2
PIPELINES IN THE U.S.
development capital expenditures, while
also reducing the Company’s total debt by
more than $100 million. We exited 2021 with
substantial financial liquidity and minimal
We made significant progress toward our CCUS
debt which positions us very well to execute
objectives in 2021 with the entry into our first
on our plans in 2022 and beyond.
CCUS agreements, including with Mitsubishi
for the transport and storage of CO2 captured
from Mitsubishi’s proposed U.S. Gulf Coast
ammonia plant. We also announced an initial CO2
sequestration site agreement in Texas last year,
the first of multiple sites which we expect will
provide significant non-EOR dedicated storage
STORED 3.7 MILLION METRIC
TONS OF INDUSTRIAL-
IN 2021
SOURCED CO
2
LOOKING AHEAD
capacity across our network. Momentum on
I am incredibly excited about what lies ahead
the CCUS front has continued with additional
for Denbury. Our low-decline, EOR operations
emitter and sequestration agreements already
are strong, providing the cash flow to fund our
announced early in 2022.
Denbury’s 2021 financial results reflect our
strong momentum and significant future
potential. For the full year, we generated
operating cash flow in excess of our
future investments in both our EOR and CCUS
operations. Our CCA development will be a
cornerstone of continued strength in both the
near and long-term. Additionally, with the world
searching for the best solutions to mitigate
CARBON CAPTURE,
UTILIZATION,
AND STORAGE
SOURCES
CO
2
Denbury sources CO2 from naturally-occurring
underground reservoirs and from industrial sources
that capture, process and compress the CO2 for
delivery into our pipeline network. The CO2 captured
from industrial sources would otherwise be released
into the atmosphere. Over the next several years,
Denbury plans to significantly increase its supply of
industrial CO2 while reducing naturally-occurring CO2
used in its EOR operations.
CO
2
TRANSPORTATION
We own and operate the most expansive CO2 pipeline
infrastructure in the U.S., including over 1,300 miles of
CO2 pipelines in the Gulf Coast and Rocky Mountains.
Our pipeline network currently transports 14 million
metric tons of CO2 per year in supercritical phase across
our infrastructure for operations and to our industrial
customers. We are continually expanding our pipeline
network to transport CO2 for use in our operations,
and we are assessing expansion projects to connect
sequestration sites to our main pipelines.
climate risk by reducing emissions, CCUS is
increasingly understood as a major part of the
CO2, this is an important time to lead in a
critical high-growth industry. We expect 2022
solution. It is my goal for Denbury to be broadly
to be transformational for our business and
viewed as the leader in this emerging industry.
we are energized by what the future holds.
Moving forward, we are focused on:
• Continuing to improve our record safety
performance;
• Developing our people and attracting new
talent to position Denbury for further success;
We look forward to keeping you updated
on our progress through the coming year
as we capture a new and exciting future for
our shareholders.
On behalf of the Board of Directors and our
employees, thank you for your investment
• Progressing and executing Phase 1 of our
in Denbury.
CCA EOR development project, where initial
production is expected in the second half of 2023;
Sincerely,
• Advancing our significant CCUS growth
opportunities, finalizing new emitter agreements
with both existing and greenfield projects for CO2
transport and storage services; and
• Securing and commencing development of an
industry-leading CO2 sequestration portfolio.
For Denbury, with our significant CO2
infrastructure and extensive expertise in handling
CHRIS KENDALL
PRESIDENT AND
CHIEF EXECUTIVE OFFICER
CO
2
STORAGE
Captured CO2 is safely contained underground
through enhanced oil recovery (EOR) whereby
the injected CO2 moves through the reservoir,
displacing crude oil which is produced. In addition
to EOR, Denbury is building a portfolio of multiple
CO2 EOR PROCESS
direct sequestration sites along the U.S. Gulf Coast
and Rocky Mountains with plans to inject CO2
securely underground for long-term containment in
reservoirs not associated with EOR.
CCUS STRATEGIC BENEFITS
CCUS, through both CO2 EOR or direct
underground sequestration, utilizes proven
technology with the potential for safe, long-term,
deep underground containment of billions of tons
of industrial-sourced CO2. CCUS has the potential
to drive a substantial reduction in atmospheric
CO2 emissions, and when utilizing industrial-
sourced CO2, we estimate the oil produced in EOR
is Scope 1, 2, & 3 negative, making it the most
environmentally-beneficial oil on the planet.
CAPTURING OUR FUTURE
ROCKY MOUNTAIN REGION
FAST FACTS
Cedar Creek Anticline (CCA)
ND
MT
Bell Creek
Gas Draw
Lost
Cabin
CCA CO2 Pipeline
105 Miles
Greencore Pipeline
232 Miles
Hartzog Draw
Salt Creek
Grieve
WY
Beaver Creek
Big Sand Draw
Beaver Creek Pipeline
46 Miles
Shute
Creek
GULF COAST REGION
YE21 OIL & GAS RESERVES
192 MMBOE
2021 SALES VOLUMES
48.8 MBOE/D (24% Carbon-negative)
2021 DEVELOPMENT CAPITAL
$252 MM
2021 TOTAL CO2 SOURCED
~13 MMTPA, ~30% INDUSTRIAL
MS
Tinsley
Jackson
Dome
Delhi
Heidelberg
Martinville
Brookhaven
W. Yellow Creek
Soso Eucutta
TX
LA
Cranfield
Green Pipeline
325 Miles
Mallalieu
Little Creek
McComb
NEJD Pipleline
183 Miles
Nutrien
Conroe
Webster
Thompson
˜90 Miles
Air Products
Oyster Bayou
Manvel
Hastings
Gulf of
Mexico
Denbury Owned and Operated CO2 Pipelines
Denbury Planned CO2 Pipelines
CO2 Pipelines Owned by Others
Denbury Owned Fields – Current CO2 Floods
Denbury Owned Fields – Potential CO2 Floods
Naturally-Occurring CO2 Source
Industrial CO2 Sources Owned or Contracted
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
2021 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, 2021
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
DENBURY INC.
(Exact name of Registrant as specified in its charter)
Delaware
(State or other jurisdiction of incorporation or organization)
20-0467835
(I.R.S. Employer Identification No.)
5851 Legacy Circle,
Plano, TX
(Address of principal executive offices)
Registrant’s telephone number, including area code:
75024
(Zip Code)
(972) 673-2000
Title of Each Class:
Common Stock $.001 Par Value
Trading Symbol:
Name of Each Exchange on Which Registered:
DEN
New York Stock Exchange
Securities registered pursuant to Section 12(b) of the Act:
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 $3,839,619,307.
The number of shares outstanding of the registrant’s Common Stock as of January 31, 2022, was 50,199,676.
DOCUMENTS INCORPORATED BY REFERENCE
Document:
1. Notice and Proxy Statement for the Annual Meeting of Stockholders to be held May 26, 2022.
Incorporated as to:
1. Part III, Items 10, 11, 12, 13, 14
Denbury Inc.
2021 Annual Report on Form 10-K
Table of Contents
Glossary and Selected Abbreviations
PART I
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
Business and Properties
Risk Factors
Unresolved Staff Comments
Properties
Legal Proceedings
Mine Safety Disclosures
PART II
Item 5.
Item 6.
Item 7.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases
of Equity Securities
[Reserved]
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 9C
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Item 15.
Item 16.
Financial Statements and Supplementary Information
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
PART III
Directors, Executive Officers and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters
Certain Relationships and Related Transactions, and Director Independence
Principal Accountant Fees and Services
PART IV
Exhibits and Financial Statement Schedules
Form 10-K Summary
Signatures
2
Page
3
5
25
31
32
32
32
33
35
36
63
63
115
115
115
116
117
117
117
117
117
118
119
120
Bbl
Bbls/d
Bcf
BOE
BOE/d
Btu
CCUS
CO2
EOR
Denbury Inc.
Glossary and Selected Abbreviations
One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil or other
liquid hydrocarbons.
Barrels of oil or other liquid hydrocarbons produced per day.
One billion cubic feet of natural gas or CO2.
One barrel of oil equivalent, using the ratio of one barrel of crude oil, condensate or natural gas liquids to
6 Mcf of natural gas.
BOEs produced per day.
British 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).
Carbon Capture, Use, and Storage.
Carbon dioxide.
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 costs
The 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.
GAAP
MBbls
MBOE
Mcf
Accounting principles generally accepted in the United States of America.
One thousand barrels of crude oil or other liquid hydrocarbons.
One thousand BOEs.
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.
MMBOE
One million BOEs.
MMBtu
MMcf
MMcf/d
One million Btus.
One million cubic feet of natural gas or CO2.
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.
NYMEX
The 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.
3
Denbury Inc.
Proved
Undeveloped
Reserves*
PV-10 Value
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.
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 Recovery A 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.
4
Denbury Inc.
PART I
Item 1. Business and Properties
GENERAL
Denbury Inc., a Delaware corporation, is an independent energy company with operations focused in the Gulf Coast
and Rocky Mountain regions of the United States. The Company is differentiated by its focus on CO2 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, making the Company’s Scope 1 and 2 CO2 emissions negative today, with a
goal to also fully offset Scope 3 CO2 emissions within this decade, primarily through increasing the 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:
•
•
•
•
•
•
leverage our extensive CO2 pipeline assets and CO2 EOR expertise to expand our operations and leadership
position in the 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;
increase the value of our assets by applying our technical expertise in CO2 tertiary recovery and target specific
regions where we either have, or believe we can 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. As part of the plan of reorganization, upon
emergence from 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 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.
5
Denbury Inc.
Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code
On July 30, 2020, Denbury Resources Inc. and its subsidiaries filed petitions for reorganization in a “prepackaged”
voluntary bankruptcy under chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern
District of Texas (the “Bankruptcy Court”) under the caption “In re Denbury Resources Inc., et al., Case No. 20-33801”.
On September 2, 2020, the Bankruptcy Court entered an order confirming the prepackaged joint plan of reorganization (the
“Plan”) and approving the Disclosure Statement, and on September 18, 2020 (the “Emergence Date”), the Plan became
effective in accordance with its terms and the Company emerged from Chapter 11 as the successor reporting company of
Denbury Resources Inc. On April 23, 2021, the Bankruptcy Court entered a final decree closing the Chapter 11 case
captioned “In re Denbury Resources Inc., et al., Case No. 20-33801”; therefore, we have no remaining obligations related
to this reorganization.
Upon emergence from bankruptcy, we met the criteria and were required to adopt fresh start accounting in accordance
with Financial Accounting Standards Board Codification (“FASC”) Topic 852, Reorganizations. Fresh start accounting
requires that new fair values be established for the Company’s assets, liabilities and equity as of the Emergence Date, and
therefore certain values and operational results of the condensed consolidated financial statements subsequent to September
18, 2020 are not comparable to those in the Company’s condensed consolidated financial statements prior to, and including
September 18, 2020. The Emergence Date fair values of the Successor’s assets and liabilities differ materially from their
recorded values as reflected on the historical balance sheets of the Predecessor contained in periodic reports previously
filed with the Securities and Exchange Commission. References to “Successor” relate to the financial position and results
of operations of the Company subsequent to September 18, 2020, and references to “Predecessor” relate to the financial
position and results of operations of the Company prior to, and including, September 18, 2020.
BUSINESS 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
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.
inventories around the world. As we approached the end of 2021,
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 transport and storage of CO2
captured from Mitsubishi’s proposed ammonia project along the U.S. Gulf Coast.
6
Denbury Inc.
•
•
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 utilizing industrial-sourced CO2.
Announced joint development of a Texas Gulf Coast sequestration site with Gulf Coast Midstream Partners, with
potential to store up to 400 million metric tons of CO2.
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 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 our existing CO2 EOR operations,
which have been a significant focus for us for over 22 years.
Supportive U.S. government policy and public pressure on industrial CO2 emitters provide strong incentives for them
to capture their CO2 emissions; for example, in January 2021, 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 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, 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
In addition to the Section 45Q tax credits, some entities may be eligible for other financial
commencement deadline.
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 fee 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 transport
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 a capital efficient expansion of our 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
continue to work 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 experience and expertise in working with CO2 positions us well to be a leader in this rapidly developing industry.
OIL AND NATURAL GAS OPERATIONS
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 Dakota.
Approximately 97% of our production is oil, and over two-thirds of our production is from CO2 EOR. Over time, we have
7
Denbury Inc.
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 operations. Our current portfolio of CO2 EOR projects provides us significant oil
production and reserve growth potential, assuming crude oil prices are at levels that support the development of those
projects.
We have been conducting and expanding EOR operations on our properties 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
In 2012, as part of a significant sale and exchange transaction with Exxon Mobil Corporation
Company (“Encore”).
(“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
In the Gulf Coast region, we own what is, to our
LaBarge Field in Wyoming (the “Bakken Exchange Transaction”).
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
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 CO2 emissions through the associated underground storage of CO2 which 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
8
Field Summary Table below within this section and Supplemental Oil and Natural Gas Disclosures (Unaudited) to the
consolidated financial statements for further discussion of reserve inputs and changes between periods.
Denbury Inc.
Estimated proved reserves
Oil (MBbls)
Natural gas (MMcf)
Oil equivalent (MBOE)
Reserve volumes categories
Proved developed producing
Oil (MBbls)
Natural gas (MMcf)
Oil equivalent (MBOE)
Proved developed non-producing
Oil (MBbls)
Natural gas (MMcf)
Oil equivalent (MBOE)
Proved undeveloped
Oil (MBbls)
Natural gas (MMcf)
Oil equivalent (MBOE)
Percentage of total MBOE
Proved developed producing
Proved developed non-producing
Proved undeveloped
Representative oil and natural gas prices(1)
Oil (NYMEX price per Bbl)
Natural gas (Henry Hub price per MMBtu)
Present values (in thousands)(2)
Discounted estimated future net cash flows before income taxes
(PV-10 Value)(3)
Standardized measure of discounted estimated future net cash flows
after income taxes (“Standardized Measure”)
December 31,
2021
2020
2019
188,938
16,506
191,689
164,744
14,844
167,218
14,403
1,662
14,680
9,791
—
9,791
140,499
15,604
143,100
123,802
14,132
126,158
12,600
1,472
12,845
4,097
—
4,097
226,133
24,334
230,189
178,538
21,627
182,143
24,278
2,706
24,729
23,317
1
23,317
87 %
8 %
5 %
88 %
9 %
3 %
79 %
11 %
10 %
$
66.56
3.60
$ 2,673,822
$ 2,187,051
$
$
$
$
39.57
1.99
55.69
2.58
703,080
$ 2,615,668
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,
9
Denbury Inc.
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.
(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
10
Denbury Inc.
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.
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, 2021, and average daily sales
volumes for 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 Oil and Natural Gas
Reserve Estimates above and Supplemental Oil and Natural Gas Disclosures (Unaudited) in the consolidated financial
statements.
Proved Reserves as of December 31, 2021(1)
% of
Company
Total
MBOEs
Natural
Gas
(MMcf)
MBOEs
Oil
(MBbls)
2021 Average Daily
Sales Volumes
Oil
(Bbls/d)
Natural
Gas
(Mcf/d)
Average
2021 NRI
Tertiary oil and gas properties
Gulf Coast region
Delhi
Hastings
Heidelberg
Oyster Bayou
Tinsley
Other(2)
Total Gulf Coast region
Rocky Mountain region
Bell Creek
Other(3)
Total Rocky Mountain region
Total tertiary properties
Non-tertiary oil and gas properties
Gulf Coast region
11,007
19,832
15,071
15,780
14,879
12,795
89,364
11,265
14,328
25,593
114,957
—
—
—
—
—
—
—
—
—
—
—
11,007
19,832
15,071
15,780
14,879
12,795
89,364
11,265
14,328
25,593
114,957
5.7 %
10.3 %
7.9 %
8.2 %
7.8 %
6.7 %
2,861
4,317
3,921
3,833
3,405
5,969
46.6 %
24,306
5.9 %
7.5 %
13.4 %
60.0 %
4,416
4,059
8,475
32,781
—
—
—
—
—
—
—
—
—
—
—
58.5 %
80.0 %
81.2 %
87.4 %
81.9 %
74.4 %
76.8 %
84.1 %
33.9 %
49.2 %
67.0 %
Total Gulf Coast region
16,985
15,888
19,633
10.2 %
3,068
3,690
34.0 %
Rocky Mountain region
Cedar Creek Anticline(4)
Other(5)
Total Rocky Mountain region
Total non-tertiary properties
Company Total
55,047
1,949
56,996
73,981
188,938
6
612
618
16,506
16,506
55,048
2,051
57,099
76,732
28.7 %
1.1 %
29.8 %
40.0 %
191,689
100.0 %
10,745
687
11,432
14,500
47,281
1,578
3,665
5,243
8,933
8,933
81.2 %
66.4 %
79.9 %
61.4 %
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 2021, which were
$66.56 per Bbl for crude oil and $3.60 per MMBtu for natural gas.
11
Denbury Inc.
(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.
(4) The Cedar Creek Anticline consists of a series of 13 different operating areas.
(5) Includes non-tertiary operations from Wind River Basin, as well as Hartzog Draw and Bell Creek fields.
Enhanced Oil Recovery Overview. EOR using CO2 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.
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:
•
•
•
•
•
•
a lower exploration risk, as we are operating oil fields that have significant historical production and reservoir and
geological data;
lower production decline rates than unconventional development;
reasonable return metrics at currently anticipated long-term 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;
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; and
allowing us to concurrently store CO2 captured from industrial sources in the same underground formations that
previously trapped and stored oil and natural gas.
Our 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.
12
Denbury Inc.
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. 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.
Since 2001, we have 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 to approximately 4.5 Tcf as of
December 31, 2021. The proved CO2 reserve estimates are based on a gross (8/8ths) basis, of which our net revenue
interest is approximately 3.6 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 our customers
who are industrial end-users of 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 naturally occurring CO2 source at Jackson Dome, in our tertiary operations we utilize CO2 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 reduce CO2 emissions through the
associated underground storage of CO2 which occurs as part of our oil-producing EOR operations (see Carbon Capture,
In the Gulf Coast, we are currently party to two long-term contracts to purchase CO2: an
Use and Storage below).
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 to our EOR operations during 2021. During the year ended December 31,
2021, approximately 15% of the CO2 utilized in our Gulf Coast oil and gas operations was industrial-sourced CO2.
In the Gulf Coast region, approximately 77% of our average daily CO2 produced from Jackson Dome or captured from
industrial sources in 2021 was used in our tertiary recovery operations, compared to 78% in 2020 and 84% in 2019, with
the balance delivered to third-party industrial end-users or EOR customers. During 2021, we used an average of 407
MMcf/d of CO2 (including CO2 captured from industrial sources) for our tertiary activities.
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, 2021, we own nearly 925 miles
of CO2 pipelines, which gives us the ability to deliver CO2 throughout the Gulf Coast region.
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
13
Denbury Inc.
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 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 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
Green Pipeline
NEJD Pipeline
Delta Pipeline
Completion
Date
Pipeline
Diameter
(in inches)
Pipeline
Mileage
2010
1986
2009
24”
20”
24”
20”
18”
320
183
111
91
51
Service Area
Gulf Coast corridor from near Donaldsonville,
Louisiana to Hastings Field in Texas; including
connections to 2 industrial-source CO2 providers
Jackson Dome CO2 source to Green Pipeline
connection
Jackson Dome CO2 source to Delhi Field in
Louisiana
Jackson Dome CO2 source to West Yellow Creek in
Mississippi
NEJD Pipeline to Cranfield Field
Free State Pipeline
West Gwinville
2005
1959/2008(1)
(1) Repurposed from a natural gas pipeline to a CO2 pipeline in 2008.
Oil 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, 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,
improves the efficiency of the CO2 flood, and utilizes extracted methane to power the plant and reduce field operating
expenses. Our 2022 development plans include the purchase and installation of an inlet heat exchanger to 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.
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. Our 2022 development plans include
developing the remaining CO2 flood in the 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. Our
2022 development plans include additional A-2 zone 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
14
Denbury Inc.
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. Although production from Tinsley Field peaked in 2015 and is generally on decline, we continue
to evaluate future potential investment opportunities in this field.
Future Gulf Coast Tertiary Opportunities. Future development projects beyond 2022 may include additional
opportunities at Tinsley Field’s Perry sandstone reservoir and expansion of our existing CO2 floods.
In addition to our
existing CO2 floods, we continue to evaluate tertiary potential in our non-tertiary properties such as Webster, Conroe and
Thompson fields, the development of which is primarily dependent upon capital availability and priorities, future oil prices
and in some cases pipeline construction.
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, 2021, our interest in LaBarge Field held
approximately 1.0 Tcf of proved CO2 reserves.
During 2021, we received an average of approximately 110 MMcf/d of CO2 from the Shute Creek gas processing plant
at LaBarge Field that we used in our Rocky Mountain region CO2 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 Rocky Mountain region CO2
floods.
Other Rocky Mountain CO2 Sources. We have a contract in place to receive all of the CO2 from the 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. We did not receive any CO2 volumes 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 Rocky Mountain region EOR development plans.
Rocky Mountain CO2 Pipelines. The 20-inch Greencore Pipeline in Wyoming is the first CO2 pipeline we
constructed in the Rocky Mountain region. The 232-mile pipeline begins at the 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 Lost Cabin gas plant during 2013. During 2014, we completed construction of an interconnect between
our Greencore Pipeline and an existing third-party CO2 pipeline in Wyoming, which enables us to transport CO2 from
LaBarge Field to our Bell Creek Field. In 2021, we completed construction of the CCA CO2 pipeline, which delivers CO2
to our new tertiary development project at CCA. The following table summarizes our most significant CO2 pipelines
owned and operated in the Rocky Mountain region as of December 31, 2021:
CO2 pipelines
Completion
Date
Pipeline
Diameter
(in inches)
Pipeline
Mileage
Greencore Pipeline
CCA Pipeline
Beaver Creek Pipeline
2012
2021
2008
20”
16”
8”
232
105
46
Service Area
Lost Cabin gas plant in Wyoming to Bell Creek Field
in Montana
Bell Creek Field in Montana to CCA
Wyoming Wind River Basin properties
Oil Fields
Cedar Creek Anticline. CCA is the largest property that we own and currently our largest producing property,
contributing approximately 23% of our 2021 total 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
15
Denbury Inc.
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.
During November 2021, we completed a 105-mile CO2 pipeline from Bell Creek Field to CCA. Our 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 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.
Wind River Basin. During March 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, 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. Wind River Basin sales averaged approximately 2,879 BOE/d during the fourth quarter
of 2021 utilizing 100% industrial-sourced CO2. During 2022, we plan to further develop the 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.
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, 2021:
Gulf Coast region
Rocky Mountain region
Total
Developed
Undeveloped
Total
Gross
188,978
385,858
574,836
Net
147,860
343,711
491,571
Gross
286,700
110,390
397,090
Net
17,980
22,862
40,842
Gross
475,678
496,248
971,926
Net
165,840
366,573
532,413
The percentage of our net undeveloped acreage that is subject to expiration over the next three years, if not renewed, is
less than 1% in 2022, approximately 5% in 2023 and none in 2024.
16
Productive Wells
Denbury Inc.
The following table sets forth our gross and net productive oil and natural gas wells as of December 31, 2021:
Producing Oil Wells
Producing Natural Gas Wells
Total
Gross
Net
Gross
Net
Gross
Net
Operated wells
Gulf Coast region
Rocky Mountain region
Total
Non-operated wells
Gulf Coast region
Rocky Mountain region
Total
Total wells
Gulf Coast region
Rocky Mountain region
Total
Drilling Activity
1,032
948
1,980
46
583
629
1,078
1,531
2,609
907
914
1,821
19
131
150
926
1,045
1,971
125
267
392
—
77
77
125
344
469
116
236
352
—
28
28
116
264
380
1,157
1,215
2,372
46
660
706
1,203
1,875
3,078
1,023
1,150
2,173
19
159
178
1,042
1,309
2,351
The following table sets forth the results of our drilling activities over the last three years. As of December 31, 2021,
we did not have any wells in progress.
2021
2020
2019
Gross
Net
Gross
Net
Gross
Net
Year Ended December 31,
Exploratory wells(1)
Productive(2)
Non-productive(3)
Development wells(1)(4)
Productive(2)
Non-productive(3)(5)
Total
—
—
12
1
13
—
—
4
—
4
—
—
5
—
5
—
—
3
—
3
1
—
19
—
20
1
—
18
—
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, an additional 7 wells were drilled for water or CO2 injection purposes. There were no wells drilled
during 2021 or 2020 for water or CO2 injection purposes.
17
Sales Volumes and Unit Prices
Denbury Inc.
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 and 2019:
Year Ended December 31,
2021
2020
2019
Net sales volumes
Gulf Coast region
Oil (MBbls)
Natural gas (MMcf)
Total Gulf Coast region (MBOE)
Rocky Mountain region
Oil (MBbls)
Natural gas (MMcf)
Total Rocky Mountain region (MBOE)
Total Company (MBOE)(1)
Average sales prices – excluding impact of derivative settlements
Gulf Coast region
Oil (per Bbl)
Natural gas (per Mcf)
Rocky Mountain region
Oil (per Bbl)
Natural gas (per Mcf)
Total Company
Oil (per Bbl)
Natural gas (per Mcf)
Average production cost (per BOE sold)(2)
Gulf Coast region(3)
Rocky Mountain region
Total Company(3)
9,991
1,347
10,216
7,266
1,914
7,585
17,801
10,958
1,612
11,227
7,278
1,293
7,494
18,721
$
$
$
$
66.48
$
38.44
$
3.97
1.98
66.58
$
36.79
$
3.44
0.77
66.52
$
37.78
$
3.66
1.44
$
22.50
25.67
23.85
$
18.20
19.63
18.78
12,638
1,779
12,935
8,047
1,595
8,313
21,248
60.32
2.49
55.02
1.57
58.26
2.06
22.49
22.40
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.
(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,
In addition, production costs during 2020 include insurance
respectively, for the year ended December 31, 2021.
If these amounts were excluded,
reimbursements of $15.4 million related to recovery of prior years’ expenses.
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.
18
Denbury Inc.
Further information regarding average 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
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 year ended December 31, 2021, 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%).
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, there 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. 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 (“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.
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
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
19
Denbury Inc.
sources 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
20
Denbury Inc.
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. We have set new record
lows for TRIR 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
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
“Sustainability” link.
21
FEDERAL AND STATE REGULATIONS
Denbury Inc.
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 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 laws 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 PHMSA to prescribe new minimum safety standards for CO2 pipelines. In late 2021, PHMSA adopted new
regulations related to incident and annual reporting and safety requirements for onshore, rural natural gas gathering lines.
The new regulations extend PHMSA’s jurisdiction to 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.
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
22
Denbury Inc.
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 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, 2021, approximately 30% of our net developed acreage and 22% of our December 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. On January 27, 2021, the Biden Administration, through executive action, suspended new leasing and other oil
and natural gas approvals on federal lands. The 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 issued 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 expired, the
actions have caused and continue to cause considerable delay related to the ability to 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.
23
Environmental Regulations
Denbury Inc.
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.
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 related habitats), including certain species that
could be present on our leases, as threatened or endangered; (8) the Migratory Bird Treaty Act and 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
In 2020, the Trump Administration enacted new regulations designed to streamline the federal
development plans.
environmental review process.
In June 2021, the Biden Administration, acting 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 largely return
the National Environmental Policy Act regulations to those that existed prior to 2020 and to ensure federal agencies are
adequately analyzing the potential climate change impacts 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.
24
Item 1A. Risk Factors
Denbury Inc.
The risks described below fall into five broad categories related to (1) oil price volatility and demand, (2) future
executive, legislative or regulatory actions, (3) financial risks, (4) cybersecurity risks, and (5) those related to our
operations and industry. These are not the only risks 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
Oil prices have been very volatile in recent years, which is expected to continue or increase, which may lead to
significant periods of reduced cash flows and negatively affect 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, 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 reduction in worldwide economic activity and oil demand amid the COVID-19 pandemic, plus OPEC
supply pressures. More recently, oil prices plunged in late November 2021 upon identification of the new Omicron variant
of COVID-19, with NYMEX oil prices ranging between $65.57 and $95.46 per barrel between December 1, 2021 and
February 23, 2022.
Oil price volatility will remain. 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, making 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 2021 average daily sales volumes and approximately
99% of our proved reserves at December 31, 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;
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,
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.
25
Denbury Inc.
The continued COVID-19 pandemic is likely to significantly affect worldwide economic activity, which in turn could
negatively affect 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. The ultimate impact on our operational and financial performance will depend on future developments, including
(1) the effectiveness of administration of available vaccines and other therapeutics related to the treatment of COVID-19
and its variants domestically and around the world, (2) the continued efforts to contain the virus or 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.
Geopolitical tensions from the February 2022 Russian troop movements surrounding Ukraine may rise, and create
heightened oil market volatility that could negatively affect both our ability to execute our 2020 business plan and our
financial condition.
Movement of Russian military units into provinces in Eastern Ukraine, and trade and monetary sanctions in response
to future developments, could significantly affect worldwide oil prices and demand and cause turmoil in the global
financial system. This could materially affect our business and financial condition, along with our operating and
development costs, making it difficult to execute our 2022 business plan in a very volatile market. These Eastern European
tensions could also increase China/Taiwan political tensions and U.S./China trade and other relations, with a further effect
on world oil markets and the prices we receive for our 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.
In 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 adopt stricter standards for, and increase oversight and regulation over,
the exploration and production industry at the federal level, these 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, 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, may be impacted by the risks outlined above (See Federal and State Regulations – Federal Leases).
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.
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
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.
liability for contamination resulting from spills, discharges, and releases of substances,
26
Financial Risks
Commodity derivative contracts may expose us to potential financial loss.
Denbury Inc.
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 23,
2022, we have oil derivative contracts in place covering approximately 26,500 Bbls/d for the first half of 2022, 21,000
Bbls/d for the second half of 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 of future participation in significant CCUS activities.
Denbury’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
In addition to price increases by third-party service companies, it may
price increases in certain expense categories).
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.
27
Denbury Inc.
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 acquired upon exercise by holders of our
outstanding warrants, could cause the market price of our common stock to drop significantly, even if our business is
doing well.
In 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 at prices of either $32.59 or $35.41 per
share, respectively, of which outstanding warrants may convert into approximately 5.2 million shares (approximately 9%)
of our common stock outstanding as of 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 negatively affect our common stock price. We cannot
predict the likelihood of exercise of the warrants or sales of shares of our common stock acquired upon exercise, or the
effect of any such sales on the prevailing market price of our 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
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. 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.
28
Risks Relating to Our Operations and Industry
Denbury Inc.
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, especially our development of fields in the 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.
Our production will decline if our access to sufficient amounts of carbon dioxide is limited.
Our CO2 tertiary recovery 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, market conditions and government and/or public pressure may limit 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 or 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, 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
29
Denbury Inc.
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.
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 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. Future extensions of our Green Pipeline,
construction to connect third-party CO2 emitters 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 may be listed as threatened or endangered under the Endangered Species Act, which listing
may 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
30
Denbury Inc.
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 EOR or
CCUS operations.
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 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 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.
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.
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, 2021, four purchasers individually accounted for 10% or more of our oil and natural
gas revenues and, in the aggregate, for 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.
31
Item 2. Properties
Denbury Inc.
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 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.
The information under Note 14, Commitments and Contingencies,
to the consolidated financial statements is
incorporated herein by reference.
Item 4. Mine Safety Disclosures
Not applicable.
32
Denbury Inc.
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
cancelled and 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, 2022, based on information from the Company’s transfer agent, Broadridge
Stock Transfer Agent, there were two holders of record of Denbury’s common stock.
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 2021.
33
Stock Performance Graphs
Denbury Inc.
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, 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, 2021.
SEPTEMBER 21, 2020 to DECEMBER 31, 2021
COMPARISON OF CUMULATIVE TOTAL RETURN – POST BANKRUPTCY EMERGENCE
9/21/20
9/30/20
12/31/20
3/31/21
6/30/21
9/30/21
12/31/21
Denbury Inc.
$
S&P 500
Dow Jones U.S. Exploration
& Production
$
100
100
100
$
97
96
84
$
142
108
114
$
265
115
152
$
424
124
176
$
388
125
180
423
139
194
34
Item 6. [Reserved]
Denbury Inc.
35
Denbury Inc.
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, 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, 2020, as filed with the Securities and Exchange Commission (“SEC”)
on 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 in the Gulf Coast and Rocky Mountain regions.
The Company is differentiated by our focus on CO2 EOR and the emerging CCUS industry, supported by the Company’s
CO2 EOR technical and operational expertise and extensive CO2 pipeline infrastructure. The utilization of captured
industrial-sourced CO2 in EOR significantly reduces the carbon footprint of the oil that Denbury produces, making the
Company’s Scope 1 and 2 CO2 emissions negative today, with a goal to also fully offset our Scope 1, 2, and 3 CO2
emissions within this decade, primarily through increasing the amount of captured industrial-sourced CO2 used in our
operations.
Oil Price Impact on Our Business. Our financial results are significantly impacted by changes in oil prices, as 97%
of our sales volumes are oil. Changes in oil prices impact all aspects of our business, most notably our cash flows from
operations, revenues, capital 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 last three years:
In thousands, except per-unit data
Oil, natural gas, and related product sales
Receipt (payment) on settlements of commodity derivatives
Oil, natural gas, and related product sales and commodity
settlements, combined
Year Ended December 31,
2021
2020
2019
$
1,159,955
$
693,209
$
1,212,020
(277,240)
102,485
23,606
$
882,715
$
795,694
$
1,235,626
Average daily sales (BOE/d)
48,770
51,151
58,213
Average net realized prices
Oil price per Bbl - excluding impact of derivative settlements
$
66.52
$
37.78
$
Oil price per Bbl - including impact of derivative settlements
50.46
43.40
58.26
59.40
Over 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 reduction in worldwide economic activity and oil demand amid the COVID-19 coronavirus (“COVID-19”) pandemic,
36
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
plus OPEC supply pressures. NYMEX WTI oil prices strengthened from an average of approximately $39 per Bbl in 2020
to $68 per Bbl during 2021, reaching highs over $84 per Bbl in late-October 2021, followed by oil prices plunging in late
November 2021 upon identification of the new 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 sales increased by $466.7 million, or 67%, over 2020
levels due to rising oil prices; however, after considering the significant payments made upon settlements under our
commodity derivative contracts, our oil and natural gas sales 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 post-emergence bank credit facility, which significantly limited our ability to fully benefit
from the significant oil price recovery in 2021. Although we were required to hedge a certain percentage of our production
in the first 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 greater mix of collars, providing us more upside price exposure. We currently have no further
hedging requirements under our 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 principal
determinants of our comparative annual results between 2020 and 2021 were (a) an $850.0 million charge for
reorganization items, net, during the prior-year Predecessor period, primarily consisting fresh start accounting adjustments
and (b) a $996.7 million full cost pool ceiling test write-down during the prior-year Predecessor period. Additional drivers
of the comparative 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 cash 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, and 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
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 revenue interest) in the 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 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. 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
fourth quarter of 2021 and the CO2 flood utilizes 100% industrial-sourced CO2.
Cedar Creek Anticline CO2 Pipeline Completion. During 2021, we spent $123.4 million, approximately 49% of our
development capital expenditures, on Cedar 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 2023.
37
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Divestiture of 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 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 the 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.
Advancing 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 industrial emissions. We believe that the assets
and technical expertise required for CCUS are highly aligned with our existing CO2 EOR operations, providing us with a
significant advantage and opportunity to participate in the emerging CCUS industry, as the building of a permanent carbon
sequestration business requires both time and capital to build assets such as those we own and have been operating for
years. During the year ended December 31, 2021, approximately 33% of the CO2 utilized in our oil and gas operations was
industrial-sourced CO2, and we anticipate this percentage could increase in the future as supportive U.S. government policy
and public pressure on industrial CO2 emitters will provide strong incentives for these entities to capture their CO2
emissions.
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 current 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 our EOR operations. As the enhanced Section 45Q regulations are relatively new, it will likely take several
years to construct new capture facilities and for dedicated storage sites to be developed. We believe our existing CO2
pipeline infrastructure, EOR operations, and experience and expertise in working with CO2 all position us to be a leader in
this rapidly developing industry.
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 senior secured bank credit facility. Our most significant cash outlays relate to our
development capital expenditures, and in 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 and capital 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.
2021 Cash Sources and Uses. During 2021, we generated cash flows from operations of $317.2 million, while
incurring development capital expenditures of $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,
38
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
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 rights at Hartzog Draw Field in June 2021 and $15.2 million of proceeds during
the second half of 2021 from sales of non-producing surface acreage primarily around the Houston area. Average
outstanding borrowings under our bank credit facility during 2021 were $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 and 2019:
In thousands
Capital expenditure summary(1)
CCA EOR field expenditures
CCA CO2 pipelines
CCA tertiary development
Non-CCA tertiary and non-tertiary fields
CO2 sources and other CO2 pipelines
Development excluding CCA tertiary
Capitalized internal costs(2)
Development capital expenditures
Acquisitions of oil and natural gas properties(3)
Capital expenditures, before capitalized interest
Capitalized interest
Capital expenditures, total
Year Ended December 31,
2021
2020
2019
$
35,754
$
810
$
87,688
123,442
97,085
1,657
98,742
29,987
252,171
10,979
263,150
4,585
10,942
11,752
49,800
660
50,460
32,956
95,168
176
95,344
24,146
2,424
23,843
26,267
161,921
2,702
164,623
46,031
236,921
284
237,205
36,671
$
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. We estimate that our total oil and natural gas development capital expenditures in
2022, excluding acquisitions and capitalized interest, will be in a range of $290 million to $320 million, which at the
midpoint includes approximately $115 million for CCA’s new EOR development (inclusive of an estimated $25 million of
pre-production CO2 costs) and $190 million for other tertiary and non-tertiary oil-focused development projects, capitalized
internal costs and CO2 sources and pipelines. 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
39
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
million and $370 million. Based on oil prices as of the middle of February 2022, the Company’s hedge positions and other
projections, we estimate that our 2022 cash flows from operations should exceed our budgeted level of capital
expenditures. 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 2022 average daily production will be between 46,000
BOE/d and 49,000 BOE/d. Our anticipated 2022 production level compares to 2021 average production of 48,770 BOE/d.
Senior Secured Bank Credit Agreement.
In September 2020, we entered into a bank credit agreement with
JPMorgan Chase Bank, N.A., as administrative agent, and other lenders party thereto (the “Bank Credit Agreement”). The
Bank Credit Agreement is a senior secured revolving credit facility with an initial borrowing base and lender commitments
of $575 million, under which we had $35.0 million borrowed as of December 31, 2021, leaving us with $528.1 million of
availability after consideration of $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, 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 limits our ability to pay dividends on our common stock or make other restricted
payments in an amount not to exceed “Distributable Free Cash Flow”, but only if (1) no event of default or borrowing base
deficiency exists; (2) our total leverage ratio is 2 to 1 or lower; and (3) availability under the Bank Credit Agreement is at
least 20%. The Bank Credit Agreement also limits our ability to, among other things, incur and repay other indebtedness;
grant liens; engage in certain mergers, consolidations, liquidations and dissolutions; engage in sales of assets; make
acquisitions and investments; make other restricted payments (including redeeming, repurchasing or retiring our common
stock); and enter into commodity derivative agreements, in each case subject to customary exceptions.
The Bank Credit Agreement 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 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, 2021, our
ratio of consolidated total debt to consolidated EBITDAX was 0.10 to 1.0 (with a maximum permitted ratio of 3.5 to 1.0)
and our current ratio was 2.58 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 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, 2021, we had a total of
$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. Certain of these capital
spending plans are further described in 2022 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
40
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
reports. For a further discussion of our future development costs, see Supplemental Oil and Natural Gas Disclosures
(Unaudited) to the consolidated financial statements.
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 commitments under contracts in place as of December 31, 2021. The most material of these commitments within the
next 12 months include:
•
•
Approximately $46 million under contracts for the purchase of CO2 captured from industrial sources 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
Approximately $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 $35.0 million was outstanding as of December 31, 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 by similar directional variances in certain expenses, including a portion of our lease operating
expenses and production taxes, as these expenses correlate to some degree with changes in oil prices.
FINANCIAL OVERVIEW OF TERTIARY OPERATIONS
Our tertiary operations represent a significant portion of our overall 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
22 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
41
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
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.
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. 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.
42
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
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.
In thousands, except per-share data
Financial results
Successor
Predecessor
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
Net income (loss)(1)
Net income (loss) per common share – basic(1)
Net income (loss) per common share – diluted(1)
Net cash provided by operating activities
$
56,002
$
(50,658)
$
(1,432,578) $
216,959
1.10
1.04
317,158
(1.01)
(1.01)
40,326
(2.89)
(2.89)
0.47
0.45
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.
43
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Certain of our financial and operating results and statistics for each of the last three years are included in the following
table.
In thousands, except per-unit data
Average daily sales volumes
Bbls/d
Mcf/d
BOE/d
Oil and natural gas sales
Oil sales
Natural gas sales
Total oil and natural gas sales
Commodity derivative contracts(1)
Receipt (payment) on settlements of commodity derivatives
Noncash fair value losses on commodity derivatives
Commodity derivatives income (expense)
Unit prices – excluding impact of derivative settlements
Oil price per Bbl
Natural gas price per Mcf
Unit prices – including impact of derivative settlements(1)
Oil price per Bbl
Natural gas price per Mcf
Oil and natural gas operating expenses
Lease operating expenses
Transportation and marketing expenses
Production and ad valorem taxes
Oil and natural gas operating revenues and expenses per BOE
Oil and natural gas revenues
Lease operating expenses
Transportation and marketing expenses
Production and ad valorem taxes
CO2 sources – revenues and expenses
CO2 sales and transportation fees
CO2 operating and discovery expenses
CO2 revenue and expenses, net
Year Ended December 31,
2021
2020
2019
47,281
8,933
48,770
1,148,022
11,933
1,159,955
$
$
(277,240) $
(75,744)
(352,984) $
49,828
7,938
51,151
689,020
4,189
693,209
102,485
(62,355)
40,130
66.52
$
3.66
37.78
1.44
$
$
$
$
$
50.46
$
43.40
$
3.66
1.44
56,672
9,246
58,213
1,205,083
6,937
1,212,020
23,606
(93,684)
(70,078)
58.26
2.06
59.40
2.06
424,550
$
351,505
$
477,220
28,817
88,468
37,759
53,708
65.16
$
37.03
$
23.85
1.62
4.97
18.78
2.02
2.87
44,175
(6,678)
37,497
$
$
30,468
(4,568)
25,900
$
$
41,810
86,820
57.04
22.46
1.97
4.09
34,142
(2,922)
31,220
$
$
$
$
$
$
$
$
$
$
(1) See also Commodity Derivative Contracts below and Market Risk Management for information concerning our
commodity derivative transactions.
44
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Sales Volumes
Average daily sales volumes by area for 2021, 2020 and 2019, and for each of the quarters of 2021, is shown below:
Average Daily Sales Volumes (BOE/d)
2021 Quarters
Year Ended December 31,
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
2021
2020
2019
2,925
4,226
4,054
3,554
3,424
6,098
2,931
4,487
3,942
3,791
3,455
6,074
2,859
4,343
3,895
3,942
3,390
5,907
2,731
4,212
3,797
4,039
3,353
5,801
2,861
4,317
3,921
3,833
3,405
5,969
3,419
4,755
4,297
3,818
3,959
6,427
4,324
5,403
4,195
4,345
4,608
7,062
24,281
24,680
24,336
23,933
24,306
26,675
29,937
Operating Area
Tertiary oil sales volumes
Gulf Coast region
Delhi
Hastings
Heidelberg
Oyster Bayou
Tinsley
Other(1)
Total Gulf Coast region
Rocky Mountain region
Bell Creek
Other(2)
Total Rocky Mountain region
4,614
2,573
7,187
4,394
4,378
8,772
4,330
4,703
9,033
4,331
4,551
8,882
4,416
4,059
8,475
5,518
1,942
7,460
5,228
2,196
7,424
Total tertiary oil sales volumes
31,468
33,452
33,369
32,815
32,781
34,135
37,361
Non-tertiary oil and gas sales
volumes
Gulf Coast region
Total Gulf Coast region
3,621
3,415
3,763
3,929
3,683
3,807
4,201
Rocky Mountain region
Cedar Creek Anticline
Other(3)
Total Rocky Mountain region
Total non-tertiary sales volumes
Total continuing sales volumes
Property sales
Gulf Coast Working Interests
Sale(4)
11,150
1,118
12,268
15,889
47,357
10,918
1,348
12,266
15,681
49,133
11,182
1,368
12,550
16,313
49,682
10,784
1,354
12,138
16,067
48,882
11,008
1,298
12,306
15,989
48,770
11,985
1,030
13,015
16,822
50,957
—
—
—
—
—
194
Total sales volumes
47,357
49,133
49,682
48,882
48,770
51,151
14,090
1,262
15,352
19,553
56,914
1,299
58,213
(1) Includes Brookhaven, Cranfield, Eucutta, Little Creek, Mallalieu, Martinville, McComb, Soso and West Yellow Creek
fields.
(2) Includes tertiary sales volumes related to our working interest positions in the Wind River Basin properties acquired on
March 3, 2021, as well as Salt Creek and Grieve fields.
(3) Includes non-tertiary sales volumes from Wind River Basin, as well as Hartzog Draw and Bell Creek fields.
(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 (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 March 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 development 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 party,
45
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
whereby increased oil prices have resulted in increased profitability and thus, reducing sales volumes net to Denbury by
approximately 360 BOE/d when compared to 2020, partially offset by sales increases from our Wind River Basin enhanced
oil recovery fields acquired on March 3, 2021. Our production during 2021 was 97% oil, consistent with 2020 and 2019.
Oil and Natural Gas Revenues
Oil and natural gas revenues increased 67% between 2020 and 2021 and decreased 43% between 2019 and 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:
In thousands
Change in oil and natural gas revenues due to:
Decrease in production
Increase (decrease) in commodity prices
Total increase (decrease) in oil and natural gas
revenues
Year Ended December 31,
2021 vs. 2020
Year Ended December 31,
2020 vs. 2019
Increase
(Decrease) in
Revenues
Percentage
Increase
(Decrease) in
Revenues
Decrease in
Revenues
Percentage
Decrease in
Revenues
$
$
(34,069)
500,815
(5)% $
72 %
(144,118)
(374,693)
466,746
67 % $
(518,811)
(12)%
(31)%
(43)%
Excluding any impact of our commodity derivative contracts, our average net realized commodity prices and NYMEX
differentials were as follows during 2021, 2020 and 2019:
Average net realized prices
Oil price per Bbl
Natural gas price per Mcf
Price per BOE
Average NYMEX differentials
Gulf Coast region
Oil per Bbl
Natural gas per Mcf
Rocky Mountain region
Oil per Bbl
Natural gas per Mcf
Total Company
Oil per Bbl
Natural gas per Mcf
Year Ended December 31,
2021
2020
2019
$
66.52
$
37.78
$
3.66
65.16
1.44
37.03
$
$
$
(1.42) $
0.26
(1.32) $
(0.27)
(1.38) $
(0.05)
(1.14) $
(0.14)
(2.80) $
(1.36)
(1.81) $
(0.69)
58.26
2.06
57.04
3.30
(0.04)
(2.01)
(0.96)
1.23
(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.
46
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
•
Rocky Mountain Region. NYMEX oil differentials in the Rocky Mountain region averaged $1.32 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 month-to-month basis due to weather, refinery or transportation issues, and Canadian
and U.S. crude oil price index volatility.
CO2 Revenues and Expenses
We sell a portion of the CO2 we 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 Purchases
In certain situations, we purchase and subsequently sell oil from third parties. We recognize the revenue received and
the associated expenses incurred on these sales on a gross basis as “Oil marketing revenues” and “Oil marketing purchases”
in our Consolidated Statements of Operations.
Commodity Derivative Contracts
We have routinely entered 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 tables summarize the impact our commodity derivative contracts had on our operating results for the
periods indicated:
In thousands
2021
Successor
Three Months Ended
March 31
June 30
September 30 December 31
Full Year
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)
In thousands
2020
Receipt on settlements of commodity
derivatives
Noncash fair value gains (losses) on
commodity derivatives(1)
Commodity derivatives income
(expense)
Predecessor
Successor
Three Months Ended
March 31
June 30
Period from
July 1
through
September 18
Period from
September 19
through
September 30
Three
Months
Ended
December 31
Full Year
$
24,638
$
45,629
$
11,129
$
6,660
$
14,429
$
102,485
122,133
(85,759)
(15,738)
(2,625)
(80,366)
(62,355)
$
146,771
$
(40,130) $
(4,609)
$
4,035
$
(65,937) $
40,130
47
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
In thousands
2019
Predecessor
Three Months Ended
March 31
June 30
September 30 December 31
Full Year
Receipt (payment) on settlements of commodity derivatives
$
8,206
$
(1,549) $
Noncash fair value gains (losses) on commodity derivatives
(91,583)
26,309
Commodity derivatives income (expense)
$
(83,377) $
24,760
$
8,057
35,098
43,155
$
$
8,892
$
23,606
(63,508)
(93,684)
(54,616) $
(70,078)
Changes in our commodity derivatives expense during 2021 were primarily related to the expiration of commodity
derivative contracts, new commodity derivative contracts entered into for future periods, and to the changes in oil futures
prices between December 31, 2020 and December 31, 2021. The benefit of the significant 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 March 2020 ($30.45 per barrel), when worldwide financial markets were beginning to
absorb the potential impact of a global pandemic, and December 2021 ($71.69 per barrel) as prospects for increased
economic activity and oil demand improved.
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. 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, 2021, and Market Risk
Management below for additional discussion. In addition, the following table summarizes our oil derivative contracts as of
February 23, 2022:
WTI NYMEX
Volumes Hedged (Bbls/d)
Fixed-Price Swaps Weighted Average Swap Price
WTI NYMEX
Volumes Hedged (Bbls/d)
Collars
Weighted Average Floor / Ceiling
Price
1H 2022
2H 2022
1H 2023
2H 2023
15,500
$49.01
11,000
9,500
$57.52
11,500
4,500
$74.88
5,500
2,000
$76.80
2,000
$49.77 / $64.31
$52.39 / $67.29
$63.64 / $84.77
$65.00 / $86.47
Total Volumes Hedged (Bbls/d)
26,500
21,000
10,000
4,000
Based on current contracts in place and NYMEX oil futures prices as of February 23, 2022, which averaged
approximately $87 per Bbl for the remainder of 2022, we currently expect that we would make cash payments of
approximately $250 million during 2022 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 2022 fixed-price swaps which have a weighted
average NYMEX oil price of $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.
48
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Production Expenses
Lease Operating Expenses
In thousands, except per-BOE data
Total lease operating expenses
Total lease operating expenses per BOE
Successor
Predecessor
Period from
Sept. 19, 2020
through
Dec. 31, 2020
101,234
$
Period from
Jan. 1, 2020
through
Sept. 18, 2020
250,271
$
23.85
$
19.90
$
18.36
Year Ended
Dec. 31, 2021
424,550
$
$
Year Ended
Dec. 31, 2019
$
$
477,220
22.46
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. The $73.0 million increase on an absolute-dollar basis was primarily due to $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 but reflective of the different oil price environments in 2020 and 2021. During 2020,
we curtailed production for a short period of time and significantly reduced workover costs due to the extremely 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
February 2021 which created widespread power outages in Texas and disrupted the Company’s operations.
We currently expect lease operating expenses during 2022 to increase on an absolute-dollar and per-BOE basis as a
result of CO2 and power expenses correlated with higher oil and natural 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 agreements.
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. The decrease between periods was primarily due to changes 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 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. The increase between periods was primarily due to an increase in production taxes resulting from higher oil and
natural gas revenues.
49
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
General and Administrative Expenses (“G&A”)
Successor
Predecessor
In thousands, except per-BOE data and employees
Year Ended
Dec. 31, 2021
Cash G&A costs
Stock-based compensation
Severance-related costs
G&A expense
G&A per BOE
Cash G&A costs
Stock-based compensation
Severance-related costs
G&A expenses
Employees as of period end
$
$
$
$
Period from
Sept. 19, 2020
through
Dec. 31, 2020
11,258
$
Period from
Jan. 1, 2020
through
Sept. 18, 2020
41,096
$
8,212
—
4,111
3,315
53,936
25,322
—
79,258
$
19,470
$
48,522
$
$
$
3.03
1.42
—
4.45
716
$
$
2.21
1.62
—
3.83
657
$
$
3.02
0.30
0.24
3.56
662
Year Ended
Dec. 31, 2019
$
51,932
12,470
18,627
83,029
2.44
0.59
0.88
3.91
806
Our 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. The increase in our
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 due to a full year of expense for
restricted stock unit awards also granted in late 2020. Although the performance criteria for these performance-based
equity awards were met in 2021, the shares are not currently outstanding as actual delivery of the shares is not scheduled to
occur until after the end of the performance period, December 4, 2023. We expect stock compensation expense will be
lower in 2022 as future performance awards will be more traditional in nature and will be expensed over a longer time
period.
Interest and Financing Expenses
In thousands, except per-BOE data and interest
rates
Cash interest(1)
Less: interest not reflected as expense for financial
reporting purposes(1)
Noncash interest expense
Amortization of debt discount(2)
Less: capitalized interest
Interest expense, net
Interest expense, net per BOE
Average debt principal outstanding(3)
Average cash interest rate(4)
Successor
Predecessor
Year Ended
Dec. 31, 2021
$
5,992
Period from
Sept. 19, 2020
through
Dec. 31, 2020
$
2,277
Period from
Jan. 1, 2020
through
Sept. 18, 2020
108,824
$
Year Ended
Dec. 31, 2019
191,454
$
—
2,740
—
(4,585)
4,147
0.23
84,970
—
799
—
(1,261)
1,815
0.36
(49,243)
(85,454)
2,439
9,132
(22,885)
48,267
3.54
4,554
7,749
(36,671)
81,632
3.84
$
$
$
$
123,120
$ 1,767,605
$ 2,433,245
$
$
$
$
$
$
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 Financial Accounting Standards
Board Codification (“FASC”) 470-60, Troubled Debt Restructuring by Debtors. The portion of interest treated as a
50
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
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 year ended December 31, 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 July 30, 2020 (the “Petition Date”).
(2) Represents amortization of debt discounts related to the 7¾% Senior Secured Second Lien Notes due 2024 (the “7¾%
Senior Secured Notes”) and 6⅜% Convertible Senior Notes due 2024 (the “2024 Convertible 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 the 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. The decrease between periods was primarily due to a decrease
in the average debt principal outstanding, with the Successor periods 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 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.
Depletion, Depreciation, and Amortization (“DD&A”)
In thousands, except per-BOE data
Oil and natural gas properties
CO2 properties, pipelines, plants and other property
and equipment
Accelerated depreciation charge(1)
Total DD&A
DD&A per BOE
Oil and natural gas properties
CO2 properties, pipelines, plants and other
property and equipment
Accelerated depreciation charge(1)
Total DD&A cost per BOE
Write-down of oil and natural gas properties
Successor
Predecessor
Year Ended
Dec. 31, 2021
$
119,997
Period from
Sept. 19, 2020
through
Dec. 31, 2020
37,188
$
Period from
Jan. 1, 2020
through
Sept. 18, 2020
104,495
$
Year Ended
Dec. 31, 2019
$
159,478
30,643
—
8,624
—
44,939
39,159
74,338
—
150,640
$
45,812
$
188,593
$
233,816
6.74
$
7.31
$
7.66
$
7.51
1.72
—
8.46
14,377
$
$
1.69
—
9.00
1,006
$
$
3.30
2.87
13.83
996,658
$
$
3.49
—
11.00
—
$
$
$
$
(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. The decrease during 2021 compared to the
comparable 2020 period was 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 the
Predecessor period from January 1, 2020 through September 18, 2020. Our oil and natural gas properties depletion rate
was $6.71 per BOE during the fourth quarter of 2021.
51
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
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 prices 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 price used in estimating our proved reserves, after
adjustments for market differentials and transportation expenses by field, was $63.86 at December 31, 2021, $35.84 at
December 31, 2020, $40.08 at September 18, 2020 and $55.55 at December 31, 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 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.
Reorganization Items, Net
“Reorganization items, net” in our Consolidated Statements of Operations includes (i) expenses incurred during the
Company’s “prepackaged” voluntary bankruptcy 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. Professional service provider charges associated
with our restructuring that were incurred outside of this period (before the Petition Date and after the Emergence Date) are
recorded in “Other expenses” in our Consolidated Statements of Operations.
The following table summarizes the losses (gains) on reorganization items, net:
In thousands
Gain on settlement of liabilities subject to compromise
Fresh start accounting adjustments
Professional service provider fees and other expenses
Success fees for professional service providers
Loss on rejected contracts and leases
Valuation adjustments to debt classified as subject to compromise
Debtor-in-possession credit agreement fees
Acceleration of Predecessor stock compensation expense
Total reorganization items, net
Other Expenses
Predecessor
Period from
Jan. 1, 2020
through
Sept. 18, 2020
(1,024,864)
$
1,834,423
11,267
9,700
10,989
757
3,107
4,601
$
849,980
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.
52
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Income Taxes
Successor
Predecessor
In thousands, except per-BOE amounts and tax
rates
Year Ended
Dec. 31, 2021
Period from
Sept. 19, 2020
through
Dec. 31, 2020
Period from
Jan. 1, 2020
through
Sept. 18, 2020
Current income tax expense (benefit)
Deferred income tax expense (benefit)
Total income tax expense (benefit)
Average income tax expense (benefit) per BOE
Effective tax rate
Total net deferred tax liability
$
$
$
$
403
364
767
0.04
1.4 %
1,638
$
$
$
$
30
$
(7,260)
(2,556)
(2,526)
(408,869)
$ (416,129)
(0.49)
$
(30.52)
4.7 %
1,274
22.5 %
Year Ended
Dec. 31, 2019
$
$
$
$
3,881
100,471
104,352
4.91
32.5 %
410,230
Our income tax provisions were based on an estimated combined federal and state statutory tax rate of approximately
25% for 2021, 2020 and 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.
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
was near zero, as any tax expense or benefit associated with pre-tax book income or loss was 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 $0.6 million of alternative minimum tax credits, which under the Tax Cut and Jobs Act will be refunded in
2022 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 2018 have lapsed
and therefore are not subject to examination by respective taxing authorities.
53
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Per-BOE Data
The following table summarizes our cash flow and results of operations on a per-BOE basis for the comparative
periods. Each of the significant individual components is discussed above.
Per-BOE data
Oil and natural gas revenues
Receipt (payment) on settlements of commodity derivatives
Lease operating expenses
Production and ad valorem taxes
Transportation and marketing expenses
Production netback
CO2 sales, net of operating and discovery expenses
General and administrative expenses(1)
Interest expense, net
Reorganization items settled in cash
Stock compensation and other
Changes in assets and liabilities relating to operations
Cash flows from operations
DD&A – excluding accelerated depreciation charge
DD&A – accelerated depreciation charge(2)
Write-down of oil and natural gas properties
Deferred income taxes
Gain on extinguishment of debt
Noncash fair value losses on commodity derivatives
Noncash reorganization items, net
Other noncash items
Net income (loss)
Year Ended December 31,
2020
2019
2021
$
65.16
$
37.03
$
(15.57)
(23.85)
(4.97)
(1.62)
19.15
2.10
(4.45)
(0.23)
—
0.97
0.28
17.82
(8.46)
—
(0.81)
(0.02)
—
(4.26)
—
(1.12)
5.47
(18.78)
(2.87)
(2.02)
18.83
1.39
(3.63)
(2.68)
(2.08)
(0.38)
(3.24)
8.21
(10.43)
(2.09)
(53.29)
21.98
1.01
(3.33)
(43.32)
2.03
$
3.15
$
(79.23) $
57.04
1.11
(22.46)
(4.09)
(1.97)
29.63
1.47
(3.91)
(3.84)
—
0.43
(0.52)
23.26
(11.00)
—
—
(4.73)
7.34
(4.41)
—
(0.25)
10.21
(1) General and administrative expenses include (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.
54
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
MARKET RISK MANAGEMENT
Debt and Interest Rate Sensitivity
At December 31, 2021, we had $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, 2021:
In thousands
Variable rate debt
2022
2023
2024
2025
Total
Fair
Value
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
instruments for trading purposes. Generally,
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
these contracts have consisted of various
combinations of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and
basis swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength,
expectation of future commodity prices, and occasionally requirements under our bank credit facility. As of 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 2022 and 2023 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.
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, 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 net liability recorded at December 31, 2020. This change is
primarily related to the expiration of commodity derivative contracts during 2021, new commodity derivative contracts
entered into during 2021 for future periods, and to the changes in oil futures prices between December 31, 2020 and 2021.
55
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Commodity Derivative Sensitivity Analysis
Based on NYMEX oil futures prices and derivative contracts in place as of December 31, 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 thousands
Based on:
Futures prices as of December 31, 2021
$
10% increase in prices
10% decrease in prices
Receipt / (Payment)
(124,394)
(184,362)
(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 ESTIMATES
The preparation of financial statements in accordance with generally accepted accounting principles requires that we
make certain estimates and 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
to significant
value adjustments, financial projections, enterprise value and equity value, are inherently subject
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.
56
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
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 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 estimated 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
estimated 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
57
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
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.
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 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
2021 oil and natural gas property DD&A rate from $6.71 per BOE to approximately $6.43 per BOE, and a 5% decrease in
our proved reserve quantities would have increased our DD&A rate to approximately $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 $63.86 at December 31, 2021, $35.84 at December 31, 2020,
$40.08 at September 18, 2020, and $55.55 at December 31, 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 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.
58
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
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. 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 $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.
Income Taxes
financial
income tax expense for
We make certain estimates and judgments in determining our
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 our federal and state deferred tax assets. As of December 31, 2021
and 2020, our underlying deferred tax assets were comprised of federal deferred tax assets of $51.4 million and $54.3
million and state deferred tax assets of $74.1 million and $75.1 million, 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
59
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
corresponding change in our valuation allowance, and ($18.5 million) during the Predecessor period from January 1, 2020
through September 18, 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 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);
allocation of the purchase price to assets acquired and 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. We performed a qualitative assessment as of December 31, 2021 and determined there were no material changes to
our key cash flow assumptions and no triggering events since September 18, 2020 when the Company’s assets were
revalued in fresh start accounting; therefore, no impairment test was performed for the fourth quarter of 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
60
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
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, 2021 would increase our estimated
payments on our crude oil derivative contracts by $60 million, and a 10% decrease in NYMEX oil futures prices would
reduce our 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:
In thousands
Standardized Measure (GAAP measure)
Discounted estimated future income tax
PV-10 Value (non-GAAP measure)
FORWARD-LOOKING INFORMATION
Year Ended December 31,
2021
2,187,051
486,771
2,673,822
$
$
$
$
2020
654,734
48,346
703,080
$
$
2019
2,261,039
354,629
2,615,668
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 and 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,
the level and sustainability of the recent increases in worldwide oil prices from their COVID-19 coronavirus caused
downturn, financial forecasts, the extent of future oil price volatility, current or future liquidity sources or their adequacy to
61
Denbury Inc.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
support our anticipated future activities, statements or predictions related to the ultimate nature, timing and economic
impacts of proposed carbon capture, use and 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, price and availability of advantageous commodity derivative
contracts or their predicted downside cash flow protection or cash settlement payments required, forecasted drilling activity
or methods, including the timing and location thereof, estimated timing of commencement of CO2 injections in particular
fields or areas, or initial production responses in tertiary flooding projects, other development activities, finding costs,
interpretation or prediction of formation details, hydrocarbon reserve quantities and values, CO2 reserves and supply and
their availability, potential reserves, barrels or percentages of recoverable original oil in place, the impact of changes or
proposed changes in Federal or state laws or outcomes of any pending litigation, prospective legislation, orders or
regulations affecting the oil and gas industry or environmental regulations, competition, rates of return, and overall
worldwide or U.S. economic conditions, and other variables surrounding operations and future plans. Such forward-
looking statements generally are accompanied by words such as “plan,” “estimate,” “expect,” “predict,” “forecast,” “to our
knowledge,” “anticipate,” “projected,” “preliminary,” “should,” “assume,” “believe,” “may” or other words that convey, or
are intended to convey, the uncertainty of future events or outcomes. Such forward-looking information is based upon
management’s current plans, expectations, estimates, and assumptions that could significantly and adversely affect current
plans, anticipated 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 price differentials and consequently in the prices received
or demand for our oil produced; geopolitical actions and 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 U.S. producers in future periods; the impact of COVID-19 on
oil demand and economic activity levels; whether inflation impacts future expenses; success of our risk management
techniques; 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; conditions in the worldwide financial, trade
and credit markets; general economic conditions; competition; government regulations, including changes in tax or
environmental laws or regulations and 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.
62
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Denbury Inc.
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
Page
Reports of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Cash Flows
Consolidated Statements of Changes in Stockholders’ Equity
Notes to Consolidated Financial Statements
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
Supplemental Oil and Natural Gas Disclosures (Unaudited)
Supplemental CO2 Disclosures (Unaudited)
Nature of Operations and Summary of Significant Accounting Policies
Fresh Start Accounting
Acquisition and Divestitures
Revenue Recognition
Leases
Asset Retirement Obligations
Unevaluated Property
Long-Term Debt
Income Taxes
Stockholders’ Equity
Stock Compensation
Commodity Derivative Contracts
Fair Value Measurements
Commitments and Contingencies
Additional Balance Sheet Details
Supplemental Cash Flow Information
64
68
69
70
71
72
81
89
90
91
94
95
95
98
100
100
105
105
107
108
109
110
114
63
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 sheets 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
to 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, 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, 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 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 audits 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 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. 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 audits also included performing such other procedures as we considered necessary in the circumstances. We
believe that our audits provide a reasonable basis for our opinions.
64
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
$1,541.5 million as of December 31, 2021, depletion, depreciation and amortization (DD&A) expense was $150.6 million,
and write-down of oil and natural gas properties was $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
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, 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 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
February 24, 2022
We have served as the Company’s auditor since 2004.
66
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 statements of operations, of changes in stockholders’ equity and of cash
flows of Denbury Resources Inc. and its subsidiaries (Predecessor) (the “Company”) for the period from January 1, 2020 to
September 18, 2020 and the year 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 results of operations and cash flows of the Company for the period from January 1, 2020 to September 18,
2020 and the year 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.
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.
/s/ PricewaterhouseCoopers LLP
Dallas, Texas
March 5, 2021
We have served as the Company’s auditor since 2004.
67
Denbury Inc.
Consolidated Balance Sheets
(In thousands, except par value and share data)
Assets
Successor
December 31, 2021 December 31, 2020
Liabilities and Stockholders’ Equity
$
$
1,902,953
$
1,634,758
191,598
$
112,671
Current assets
Cash and cash equivalents
Restricted cash
Accrued production receivable
Trade and other receivables, net
Derivative assets
Prepaids
Total current assets
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved properties
Unevaluated properties
CO2 properties
Pipelines
Other property and equipment
Less accumulated depletion, depreciation, amortization and impairment
Net property and equipment
Operating lease right-of-use assets
Intangible assets, net
Other assets
Total assets
Current liabilities
Accounts payable and accrued liabilities
Oil and gas production payable
Derivative liabilities
Current maturities of long-term debt
Operating lease liabilities
Total current liabilities
Long-term liabilities
Long-term debt, net of current portion
Asset retirement obligations
Derivative liabilities
Deferred tax liabilities, net
Operating lease liabilities
Other liabilities
Total long-term liabilities
Commitments and contingencies (Note 14)
Stockholders’ equity
$
3,671
$
—
143,365
19,270
—
9,099
175,405
1,109,011
112,169
183,369
224,394
93,950
(181,393)
1,541,500
19,502
88,248
78,298
518
1,000
91,421
19,682
187
14,038
126,846
851,208
85,304
188,288
133,485
86,610
(41,095)
1,303,800
20,342
97,362
86,408
75,899
134,509
—
4,677
406,683
35,000
284,238
—
1,638
17,094
22,910
360,880
—
50
1,129,996
5,344
1,135,390
49,165
53,865
68,008
1,350
285,059
70,000
179,338
5,087
1,274
19,460
20,872
296,031
—
50
1,104,276
(50,658)
1,053,668
1,634,758
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, respectively
Paid-in capital in excess of par
Retained earnings (accumulated deficit)
Total stockholders’ equity
Total liabilities and stockholders’ equity
$
1,902,953
$
See accompanying Notes to Consolidated Financial Statements.
68
Denbury Inc.
Consolidated Statements of Operations
(In thousands, except per-share data)
Successor
Predecessor
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
Revenues and other income
Oil, natural gas, and related product sales
$
1,159,955
$
201,108
$
492,101
$
1,212,020
CO2 sales and transportation fees
Oil marketing revenues
Other income
44,175
38,742
15,288
9,419
5,376
4,697
Total revenues and other income
1,258,160
220,600
21,049
8,543
8,419
530,112
34,142
14,198
14,523
1,274,883
Expenses
Lease operating expenses
Transportation and marketing expenses
CO2 operating and discovery expenses
Taxes other than income
Oil marketing purchases
General and administrative expenses
Interest, net of amounts capitalized of $4,585, $1,261, $22,885
and $36,671, respectively
Depletion, depreciation, and amortization
Commodity derivatives expense (income)
Gain on debt extinguishment
Write-down of oil and natural gas properties
Reorganization items, net
Other expenses
Total expenses
Income (loss) before income taxes
Income tax provision (benefit)
Net income (loss)
Net income (loss) per common share
Basic
Diluted
424,550
101,234
250,271
477,220
28,817
6,678
91,390
37,734
79,258
4,147
150,640
352,984
—
14,377
—
10,816
1,201,391
56,769
767
10,595
1,976
16,584
5,318
19,470
1,815
45,812
61,902
—
1,006
—
8,072
273,784
(53,184)
(2,526)
27,164
2,592
43,531
8,399
48,522
48,267
188,593
(102,032)
(18,994)
996,658
849,980
35,868
2,378,819
(1,848,707)
(416,129)
56,002
$
(50,658)
$
(1,432,578) $
41,810
2,922
93,752
14,124
83,029
81,632
233,816
70,078
(155,998)
—
—
11,187
953,572
321,311
104,352
216,959
1.10
1.04
$
$
(1.01)
(1.01)
$
$
(2.89) $
(2.89) $
0.47
0.45
$
$
$
Weighted average common shares outstanding
Basic
Diluted
50,918
53,818
50,000
50,000
495,560
495,560
459,524
510,341
See accompanying Notes to Consolidated Financial Statements.
69
Denbury Inc.
Consolidated Statements of Cash Flows
(In thousands)
Successor
Predecessor
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
$
56,002
$
(50,658)
$
(1,432,578) $
216,959
Cash flows from operating activities
Net income (loss)
Adjustments to reconcile net income (loss) to cash flows from
operating activities
Noncash reorganization items, net
Depletion, depreciation, and amortization
Write-down of oil and natural gas properties
Deferred income taxes
Stock-based compensation
Commodity derivatives expense (income)
Receipt (payment) on settlements of commodity derivatives
Gain on debt extinguishment
Debt issuance costs and discounts
Gain from asset sales and other
Other, net
Changes in assets and liabilities, net of effects from acquisitions
Accrued production receivable
Trade and other receivables
Other current and long-term assets
Accounts payable and accrued liabilities
Oil and natural gas production payable
Other liabilities
Net cash provided by operating activities
Cash flows from investing activities
Oil and natural gas capital expenditures
Acquisitions of oil and natural gas properties
Pipeline capital expenditures
Net proceeds from sales of oil and natural gas properties and
equipment
Other
Net cash used in investing activities
Cash flows from financing activities
Bank repayments
Bank borrowings
Interest payments treated as a reduction of debt
Cash paid in conjunction with debt exchange
Cash paid in conjunction with debt repurchases
Costs of debt financing
Pipeline financing and capital lease debt repayments
Other
Net cash provided by (used in) financing activities
Net increase (decrease) in cash, cash equivalents, and restricted cash
Cash, cash equivalents, and restricted cash at beginning of period
—
150,640
14,377
364
25,322
352,984
(277,240)
—
2,740
(10,609)
(2,465)
(51,944)
(284)
10,390
28,500
29,351
(10,970)
317,158
(150,911)
(10,979)
(69,223)
19,053
9,128
(202,932)
—
45,812
1,006
(2,556)
8,212
61,902
21,089
—
799
(3,546)
1,197
21,411
15,567
(1,795)
(67,167)
(6,912)
(4,035)
40,326
(17,964)
(82)
(618)
938
15,842
(1,884)
(933,000)
898,000
(190,000)
120,000
—
—
—
—
(68,008)
(3,122)
(106,130)
8,096
42,248
—
—
—
(8)
(22,938)
1,638
(91,308)
(52,866)
95,114
810,909
188,593
996,658
(408,869)
4,111
(102,032)
81,396
(18,994)
11,571
(6,723)
7,162
26,575
(22,343)
743
(16,102)
(6,792)
123
113,408
(99,582)
—
(11,601)
41,322
12,747
(57,114)
(551,000)
691,000
(46,417)
—
(14,171)
(12,482)
(51,792)
(9,363)
5,775
62,069
33,045
—
233,816
—
100,471
12,470
70,078
23,606
(155,998)
12,303
(8,504)
(92)
(13,619)
9,379
7,629
(3,275)
2,170
(13,250)
494,143
(262,005)
(79)
(27,319)
10,196
9,515
(269,692)
(925,791)
925,791
(85,303)
(136,427)
—
(11,065)
(13,908)
348
(246,355)
(21,904)
54,949
33,045
Cash, cash equivalents, and restricted cash at end of period
$
50,344
$
42,248
$
95,114
$
See accompanying Notes to Consolidated Financial Statements.
70
Denbury Inc.
Consolidated Statements of Changes in Stockholders’ Equity
(Dollar amounts in thousands)
Balance – December 31, 2018 (Predecessor)
462,355,725
$
462
$
2,685,211
$
(1,533,112)
1,941,749
$
(10,784)
$
1,141,777
Common Stock
($.001 Par Value)
Shares
Amount
Paid-In
Capital in
Excess of
Par
Retained
Earnings
(Accumulated
Deficit)
Treasury Stock
(at cost)
Shares
Amount
Total Equity
Issued pursuant to stock compensation plans
9,315,016
Issued pursuant to directors’ compensation
plan
Issued pursuant to senior subordinated notes
exchanges
Stock-based compensation
Tax withholding for stock compensation
plans
Net income
97,537
36,297,217
—
—
—
Balance – December 31, 2019 (Predecessor)
508,065,495
Issued pursuant to stock compensation plans
312,516
Issued pursuant to directors' compensation
plan
Stock-based compensation
Issued pursuant to notes conversion
Canceled pursuant to stock compensation
plans
Tax withholding for stock compensation
plans
Net loss
Cancellation of Predecessor equity
Issuance of Successor equity
37,367
—
7,372,250
(6,313,884)
—
—
(509,473,744)
49,999,999
Balance – September 18, 2020 (Predecessor)
49,999,999
$
Balance – September 19, 2020 (Successor)
49,999,999
$
Stock-based compensation
Net loss
—
—
Balance – December 31, 2020 (Successor)
49,999,999
Stock-based compensation
Tax withholding for stock compensation
plans
Issued pursuant to exercise of warrants
Net income
—
—
193,657
—
Balance – December 31, 2021 (Successor)
50,193,656
$
9
—
37
—
—
—
508
—
—
—
8
(6)
—
—
(9)
—
37,409
16,488
—
—
—
—
—
—
(5,161)
(1,990,000)
—
—
216,959
—
1,701,022
—
—
—
7,270
—
(2,520)
—
—
—
39,555
16,488
(2,520)
216,959
2,739,099
(1,321,314)
1,652,771
(6,034)
1,412,259
—
—
14,317
11,493
6
—
—
—
—
—
—
—
—
(1,432,578)
—
—
—
—
—
742,862
—
(510)
(2,764,915)
2,753,892
(2,395,633)
—
— $
—
—
—
—
—
(168)
—
6,202
—
—
—
14,317
11,501
—
(168)
(1,432,578)
(5,331)
1,095,419
— $
1,095,419
50
50
50
—
—
50
—
—
—
—
50
1,095,369
$
1,095,369
$
$
1,095,369
$
8,907
—
1,104,276
27,205
(2,244)
759
—
$
1,129,996
$
—
—
—
—
(50,658)
(50,658)
—
—
—
56,002
5,344
— $
— $
1,095,419
—
—
—
—
—
—
—
—
—
—
—
—
—
—
8,907
(50,658)
1,053,668
27,205
(2,244)
759
56,002
— $
— $
1,135,390
See accompanying Notes to Consolidated Financial Statements.
71
Denbury Inc.
Notes to Consolidated Financial Statements
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 in the Gulf Coast and Rocky Mountain regions of the United States. The Company is
differentiated by our focus on CO2 EOR and the emerging CCUS industry, supported by the Company’s CO2 EOR
technical and operational expertise and extensive CO2 pipeline infrastructure.
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 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
72
Denbury Inc.
Notes to Consolidated Financial Statements
account of warrants and 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;
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 items, net” 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.
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
73
Denbury Inc.
Notes to Consolidated Financial Statements
to a number of
risks and uncertainties that may cause actual
results to differ materially from such
subject
estimates. Significant estimates underlying these financial statements include (1) the fair value of financial derivative
instruments; (2) the estimated quantities of proved oil and 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 (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 one 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:
In thousands
Cash and cash equivalents
Restricted cash, current
Restricted cash, long-term
Total cash, cash equivalents, and restricted cash shown in the Consolidated
Statements of Cash Flows
Successor
December 31, 2021 December 31, 2020
$
$
3,671
$
—
46,673
50,344
$
518
1,000
40,730
42,248
Restricted cash, long-term in the table above consists of escrow accounts that are legally restricted for certain of our
asset retirement obligations, and are included in “Other assets” in the accompanying 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
74
Denbury Inc.
Notes to Consolidated Financial Statements
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 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.
Depletion. The costs capitalized, including production equipment and future development costs, are depleted 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 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 $63.86 at December 31, 2021, $35.84 at December 31, 2020,
$40.08 at September 18, 2020, and $55.55 at December 31, 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 the 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 2019 Predecessor period.
75
Denbury Inc.
Notes to Consolidated Financial Statements
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.
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.
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 50 years. Capitalized costs include $22.4 million of CO2
pipelines as of December 31, 2021, that were either under construction or had not been placed into service and therefore,
were not subject to depreciation during 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 are generally depreciated
over a useful life of one to five 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.
76
Denbury Inc.
Notes to Consolidated Financial Statements
Intangible Assets
Our intangible assets subject to amortization 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 during the year ended 2019. The following table summarizes the carrying value of our intangible assets as of
December 31, 2021 and 2020:
In thousands
Long-term contracts to sell CO2 to industrial customers
Other intangibles
Accumulated amortization
Net book value
Successor
December 31, 2021 December 31, 2020
$
$
97,943
$
2,179
(11,874)
88,248
$
97,943
2,167
(2,748)
97,362
As of December 31, 2021, our estimated amortization expense for our intangible assets subject to amortization over the
next five years is as follows:
In thousands
2022
2023
2024
2025
2026
$
9,120
9,117
9,117
9,117
9,117
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.
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. 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. We
did not record an impairment of long-lived assets during the year ended December 31, 2021, 2020 or 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
77
Denbury Inc.
Notes to Consolidated Financial Statements
adjustment to 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.
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%).
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.
78
Denbury Inc.
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.
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 periods consist of nonvested restricted stock units, nonvested
performance stock units, and outstanding series A and series B warrants, and during the Predecessor periods consisted of
nonvested restricted stock, nonvested performance-based equity awards, and convertible senior 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:
In thousands
Numerator
Successor
Predecessor
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
Net income (loss) – basic
Effect of potentially dilutive securities
Interest on convertible senior notes including
amortization of discount, net of tax
Net income (loss) – diluted
$
$
56,002
$
(50,658)
$
(1,432,578) $
216,959
—
—
—
14,134
56,002
$
(50,658)
$
(1,432,578) $
231,093
Denominator
Weighted average common shares outstanding –
basic
Effect of potentially dilutive securities
Restricted stock units
Warrants
Restricted stock and performance-based equity
awards
Convertible senior notes(1)
Weighted average common shares outstanding –
diluted
50,918
50,000
495,560
459,524
762
2,138
—
—
—
—
—
—
—
—
—
—
—
—
2,396
48,421
53,818
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).
For 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.
79
Denbury Inc.
Notes to Consolidated Financial Statements
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 not
scheduled to occur until December 4, 2023. During the Predecessor periods, basic weighted average common shares
includes restricted stock that vested during the periods.
For purposes of calculating diluted weighted average common shares for the years ended December 31, 2021 and
2019, the nonvested restricted stock units, nonvested restricted stock and performance-based equity awards, along with
unexercised warrants are included in the computation using the treasury stock method, 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.
The following outstanding securities 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, as of the respective dates:
In thousands
Restricted stock units
Warrants
Stock appreciation rights
Restricted stock and performance-based equity awards
Successor
Predecessor
December 31, 2021 December 31, 2020 December 31, 2019
—
—
—
—
1,220
5,526
—
—
—
—
1,981
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 5.2 million warrants outstanding that can be exercised for shares of the Successor’s common
stock, at an exercise price of $32.59 per share for the 2.6 million series A warrants 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. As of December 31, 2021, 11,694 series A warrants and 327,266 series B warrants have been exercised
in exchange for a total of 193,657 shares. The warrants may be 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
Income Taxes. In December 2019, the Financial Accounting Standards Board issued Accounting 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 implementation of this standard did not have a material impact
on our consolidated financial statements and related footnote disclosures.
80
Denbury Inc.
Notes to Consolidated Financial Statements
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.
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.
The following table reconciles the enterprise value to the equity value of the Successor as of the Emergence Date:
In thousands
Enterprise value
Plus: Cash and cash equivalents
Less: Total debt
Equity value
Sept. 18, 2020
$
1,280,856
45,585
(231,022)
$
1,095,419
The following table reconciles enterprise value to reorganization value of the Successor (i.e., value of the reconstituted
entity) and total reorganization value:
In thousands
Enterprise value
Plus: Cash and cash equivalents
Plus: Current liabilities excluding current maturities of long-term debt
Plus: Non-interest-bearing noncurrent liabilities
Reorganization value of the reconstituted Successor
Sept. 18, 2020
$
1,280,856
45,585
239,738
185,228
$
1,751,407
81
Denbury Inc.
Notes to Consolidated Financial Statements
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.
Reorganization Items, Net
“Reorganization items, net” 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. Professional service provider charges associated with our restructuring
that were incurred outside of this period (before the Petition Date and after the Emergence Date) 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.
The following table summarizes the losses (gains) on reorganization items, net:
In thousands
Gain on settlement of liabilities subject to compromise
Fresh start accounting adjustments
Professional service provider fees and other expenses
Success fees for professional service providers
Loss on rejected contracts and leases
Valuation adjustments to debt classified as subject to compromise
Debtor-in-possession credit agreement fees
Acceleration of Predecessor stock compensation expense
Total reorganization items, net
Valuation Process
Predecessor
Period from
Jan. 1, 2020
through
Sept. 18, 2020
(1,024,864)
$
1,834,423
11,267
9,700
10,989
757
3,107
4,601
$
849,980
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
82
Denbury Inc.
Notes to Consolidated Financial Statements
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 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).
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 estimated 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 estimated 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.
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.
83
Denbury Inc.
Notes to Consolidated Financial Statements
Favorable and Unfavorable Vendor Contracts
We recognized both favorable and unfavorable contracts using the incremental value method under the income
approach. The incremental value method calculates value on the basis of the pricing differential between historical
contracted rates and estimated pricing that the Company would most likely receive if it entered into similar contract
conditions (other than the price) as of the Emergence Date. The differential is applied to expected contract volumes, tax-
affected and discounted at a discount rate consistent with the risk of the associated cash flows.
Asset Retirement Obligations
The fair value of the asset retirement obligations was revalued based upon estimated current reclamation costs for our
assets with reclamation obligations, an appropriate long-term inflation adjustment, and our revised credit adjusted risk-free
rate (“CARFR”). The new CARFR was based on an evaluation of similar industry peers with similar factors such as
emergence, new capital structure and current rates for oil and gas companies.
Pipeline Financing Liabilities
The fair value of the pipeline financing liabilities was measured as the present value of the remaining payments under
the restructured pipeline agreements (see Note 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 model.
The Black-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.
84
Denbury Inc.
Notes to Consolidated Financial Statements
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.
In thousands
Current assets
Assets
Cash and cash equivalents
Restricted cash
Accrued production receivable
Trade and other receivables, net
Derivative assets
Other current assets
Total current assets
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved properties
Unevaluated properties
CO2 properties
Pipelines
Other property and equipment
Less accumulated depletion, depreciation, amortization
and impairment
Net property and equipment
Operating lease right-of-use assets
Derivative assets
Intangible assets, net
Other assets
Total assets
As of September 18, 2020
Predecessor
Reorganization
Adjustments
Fresh Start
Adjustments
Successor
$
73,372
$
—
112,832
36,221
32,635
12,968
268,028
11,723,546
650,553
1,198,515
2,339,864
201,565
(12,864,141)
3,249,902
1,774
501
20,405
81,809
(27,787) (1)
10,662 (2)
$
—
—
—
(539) (3)
(17,664)
$
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
8,241 (4)
(10,941,313)
(538,570)
(1,011,169)
(2,207,246)
(104,152)
12,864,141
(1,938,309) (10)
69 (10)
—
79,678 (11)
(3,027) (12)
45,585
10,662
112,832
36,221
32,635
12,429
250,364
782,233
111,983
187,346
132,618
97,413
—
1,311,593
1,843
501
100,083
87,023
$
3,622,419
$
(9,423)
$
(1,861,589)
$
1,751,407
85
Denbury Inc.
Notes to Consolidated Financial Statements
As of September 18, 2020
Predecessor
Reorganization
Adjustments
Fresh Start
Adjustments
Successor
In thousands
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable and accrued liabilities
$
67,789
$
Oil and gas production payable
Derivative liabilities
Current maturities of long-term debt
Operating lease liabilities
Total current liabilities
Long-term liabilities
Long-term debt, net of current portion
Asset retirement obligations
Derivative liabilities
Deferred tax liabilities, net
Operating lease liabilities
Other liabilities
39,372
8,613
—
—
115,774
140,000
2,727
295
—
—
—
102,793 (5)
16,705 (6)
—
73,199 (6)
757 (6)
193,454
42,610 (6)
180,408 (6)
—
417,951 (6)(15)
515 (6)
3,540 (6)
Total long-term liabilities not subject to compromise
Liabilities subject to compromise
Commitments and contingencies (Note 14)
143,022
2,823,506
645,024
(2,823,506) (6)
Stockholders’ equity
Predecessor preferred stock
Predecessor common stock
Predecessor paid-in capital in excess of par
Predecessor treasury stock, at cost
Successor preferred stock
Successor common stock
Successor paid-in capital in excess of par
Accumulated deficit
Total stockholders’ equity
—
510
2,764,915
(6,202)
—
—
—
(2,219,106)
540,117
—
(510) (7)
(2,764,915) (7)
6,202 (7)
—
50 (8)
1,095,369 (8)
3,639,409 (9)
1,975,605
$
3,738 (13) $
—
—
364 (14)
(29) (10)
4,073
(25,151) (14)
(24,697) (10)
—
(414,120) (15)
10 (10)
18,599 (16)
(445,359)
—
—
—
—
—
—
—
—
(1,420,303) (17)
(1,420,303)
Total liabilities and stockholders’ equity
$
3,622,419
$
(9,423)
$
(1,861,589)
$
174,320
56,077
8,613
73,563
728
313,301
157,459
158,438
295
3,831
525
22,139
342,687
—
—
—
—
—
—
50
1,095,369
—
1,095,419
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
Total cash proceeds
Uses:
Payment in full of DIP Facility and pre-petition revolving bank credit facility
Retained professional service provider fees paid to escrow account
Non-retained professional service provider fees paid
Accrued interest and fees on DIP Facility
Debt issuance costs related to Successor Bank Credit Agreement
Total cash uses
Net uses
86
$
140,000
140,000
(140,000)
(10,662)
(7,420)
(1,464)
(8,241)
(167,787)
$
(27,787)
Denbury Inc.
Notes to Consolidated Financial Statements
(2) Represents the transfer of funds to a restricted cash account utilized for the payment of fees to retained professional
service providers assisting in the bankruptcy process.
(3) Represents the write-off of costs related to the DIP Facility and a run-off policy for directors’ and officers’ insurance
coverage, partially offset by the recording of prepaid amounts for non-retained professional service provider fees.
(4) Represents debt issuance costs related to the Successor Bank Credit Agreement.
(5) Adjustments to accounts payable and accrued liabilities as follows:
In thousands
Accrual of professional service provider fees
Payment of accrued interest and fees on DIP Facility
Reinstatement of accounts payable and accrued liabilities from liabilities subject to compromise
Accounts payable and accrued liabilities
(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
Convertible senior notes
Senior subordinated notes
Total settled liabilities subject to compromise
Reinstated liabilities subject to compromise
Current maturities of long-term debt
Accounts payable and accrued liabilities
Oil and gas production payable
Operating lease liabilities, current
Long-term debt, net of current portion
Asset retirement obligations
Deferred tax liabilities
Operating lease liabilities, long-term
Other long-term liabilities
Total reinstated liabilities subject to compromise
Total liabilities subject to compromise
Issuance of New Common Stock to second lien note holders
Issuance of New Common Stock to convertible note holders
Issuance of series A warrants to convertible note holders
Issuance of series B warrants to senior subordinated note holders
Reinstatement of liabilities subject to compromise
Gain on settlement of liabilities subject to compromise
$
$
2,826
(1,464)
101,431
102,793
$
1,629,457
234,015
251,480
2,114,952
73,199
101,431
16,705
757
42,610
180,408
289,389
515
3,540
708,554
2,823,506
(1,014,608)
(53,400)
(15,683)
(6,398)
(708,553)
$
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.
87
Denbury Inc.
Notes to Consolidated Financial Statements
(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
Capital in excess of par value of 2,500,000 issued and outstanding shares of New Common Stock
issued to holders of the convertible senior note claims
Fair value of series A warrants issued to convertible senior note holders
Fair value of series B warrants issued to senior subordinated note holders
Fair value of series B warrants issued to Predecessor equity holders
Total change in Successor common stock and additional paid-in capital
Less: Par value of Successor common stock
Change in Successor additional paid-in capital
$
1,014,608
53,400
15,683
6,398
5,330
1,095,419
(50)
$
1,095,369
(9) Reflects the cumulative net impact of the effects on accumulated deficit as follows:
In thousands
Cancellation of Predecessor common stock, paid-in capital in excess of par, and treasury stock
$
2,763,824
Gain on settlement of liabilities subject to compromise
Acceleration of Predecessor stock compensation expense
Recognition of tax expenses related to reorganization adjustments
Professional service provider fees recognized at emergence
Issuance of series B warrants to Predecessor equity holders
Other
Net impact to Predecessor accumulated deficit
Fresh Start Adjustments
1,024,864
(4,601)
(128,556)
(9,700)
(5,330)
(1,092)
$
3,639,409
(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
Fair value adjustments for escrow accounts
Fair value adjustments to other assets
(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
Fair value adjustment for the current portion of Predecessor asset retirement obligation
Write-off accrued interest on NEJD pipeline financing
Fair value adjustments to accounts payable and accrued liabilities
$
$
$
$
(3,698)
671
(3,027)
3,500
689
(451)
3,738
88
Denbury Inc.
Notes to Consolidated Financial Statements
(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
Fair value adjustment for NEJD pipeline lease financing
Fair value adjustments to current and long-term maturities of debt
$
$
(24,699)
(88)
(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. Acquisition 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
89
Denbury Inc.
Notes to Consolidated Financial Statements
reserves and liabilities assumed. The following table presents a summary of the fair value of assets acquired and liabilities
assumed in the acquisition:
In thousands
Consideration:
Cash consideration
Less: Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties
Other property and equipment
Asset retirement obligations
Contingent consideration
Other liabilities
Fair value of net assets acquired
Divestitures
Hartzog Draw Deep Mineral Rights
$
10,906
60,101
1,685
(39,794)
(5,320)
(5,766)
10,906
$
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 contract (the identified performance obligation). The customer takes delivery and physical possession of the product at
90
Denbury Inc.
Notes to Consolidated Financial Statements
the delivery point, which generally is also the point at which title transfers and the customer obtains control (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 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 received within a month
following product delivery, and for natural gas and NGL contracts, payment is generally received within two months
following delivery. Timing of revenue recognition may differ from the timing of invoicing to customers; however, as the
right to consideration after delivery is unconditional based on only the passage of time before payment of the consideration
is due, upon delivery we record a receivable in “Accrued production receivable” in our 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 from third
parties. We recognize the revenue received and the associated expenses incurred on these sales on a gross basis, as “Oil
marketing revenues” and “Oil marketing purchases” in our 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:
In thousands
Oil sales
Natural gas sales
CO2 sales and transportation fees
Oil marketing revenues
Total revenues
Note 5. Leases
Successor
Predecessor
Year Ended
Dec. 31, 2021
$
1,148,022
11,933
44,175
38,742
Period from
Sept. 19, 2020
through
Dec. 31, 2020
199,769
$
Period from
Jan. 1, 2020
through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
$
489,251
$
1,205,083
1,339
9,419
5,376
2,850
21,049
8,543
6,937
34,142
14,198
$
1,242,872
$
215,903
$
521,693
$
1,260,360
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 14 years, with certain land leases
having remaining terms up to 48 years. Leases with a term of 12 months or less are not recorded on our balance sheet. The
91
Denbury Inc.
Notes to Consolidated Financial Statements
table below reflects our operating lease right-of-use assets and operating lease liabilities, which primarily consist of our
office leases:
In thousands
Operating leases
Operating lease right-of-use assets
Operating lease liabilities – current
Operating lease liabilities – long-term
Total operating lease liabilities
Successor
December 31, 2021 December 31, 2020
$
$
$
19,502
4,677
17,094
21,771
$
$
$
20,342
1,350
19,460
20,810
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:
Weighted average remaining lease term
Weighted average discount rate
Successor
December 31, 2021 December 31, 2020
5.2 years
5.4 %
6.3 years
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
92
Denbury Inc.
Notes to Consolidated Financial Statements
also terminated. The Successor 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:
Income Statement
General and
administrative expenses
Lease operating
expenses
CO2 operating and
discovery expenses
Depletion, depreciation,
and amortization
Interest expense
In thousands
Operating lease cost
Finance lease cost
Amortization of right-
of-use assets
Interest on lease
liabilities
Total finance lease
cost
Variable lease cost
Sublease income
General and
administrative expenses
Successor
Predecessor
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
$
$
$
$
$
$
4,102
$
872
$
5,683
$
8,924
655
50
158
14
214
37
58
5
4,807
$
1,044
$
5,934
$
8,987
— $
—
— $
3
1
4
670
$
258
$
$
$
9
3
$
1,188
40
12
$
1,228
3,688
$
4,852
— $
100
$
2,584
$
4,127
Our statement of cash flows included the following activity related to our operating and finance leases:
Successor
Predecessor
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
$
2,830
$
341
$
7,341
$
10,995
—
—
1
78
3
10
40
1,275
In thousands
Cash paid for amounts included in the measurement
of lease liabilities
Operating cash flows from operating leases
Operating cash flows from interest on finance
leases
Financing cash flows from finance leases
Right-of-use assets obtained in exchange for lease
obligations
Operating leases
Finance leases
2,683
—
19,902
—
1,049
162
415
—
93
Denbury Inc.
Notes to Consolidated Financial Statements
The following table summarizes by year the maturities of our lease liabilities as of December 31, 2021:
In thousands
2022
2023
2024
2025
2026
Thereafter
Total minimum lease payments
Less: Amount representing interest
Present value of minimum lease liabilities
Note 6. Asset Retirement Obligations
The following table summarizes the changes in our asset retirement obligations:
Operating
Leases
5,705
4,712
4,138
4,177
4,203
2,326
25,261
(3,490)
21,771
$
$
In thousands
Beginning asset retirement obligations
Liabilities incurred and assumed during period
Revisions in estimated retirement obligations
Liabilities settled and sold during period
Accretion expense
Fresh start accounting adjustment
Ending asset retirement obligations
Less: current asset retirement obligations(1)
Long-term asset retirement obligations
Successor
Year Ended
Dec. 31, 2021
$
186,281
Period from
Sept. 19, 2020
through
Dec. 31, 2020
163,368
$
Predecessor
Period from
Jan. 1, 2020
through
Sept. 18, 2020
181,760
$
43,701
69,059
(10,783)
14,353
—
302,611
(18,373)
738
22,660
(3,439)
2,954
—
186,281
(6,943)
736
3,592
(10,041)
11,329
(24,008)
163,368
(4,930)
$
284,238
$
179,338
$
158,438
(1) Included in “Accounts payable and accrued liabilities” in our Consolidated Balance Sheets.
Liabilities assumed relate to 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 $55.6 million and $55.2 million as of December 31, 2021 and 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, 2021 and 2020.
94
Denbury Inc.
Notes to Consolidated Financial Statements
Note 7. Unevaluated Property
A summary of the unevaluated property costs excluded from oil and natural gas properties being amortized at
December 31, 2021, and the year in which the costs were incurred follows:
December 31, 2021
Costs Incurred During:
In thousands
Property acquisition costs
Exploration and development
Capitalized interest
Total
$
$
2021
Successor 2020
— $
39,481
3,576
Fresh Start
Adjustments
(Sept. 18, 2020)(1)
68,103
— $
46
963
—
—
$
Total
68,103
39,527
4,539
43,057
$
1,009
$
68,103
$
112,169
(1) Reflects the carrying values of our unevaluated properties as a result of the application of fresh start accounting upon
information) that remain in
emergence from bankruptcy (see Note 2, Fresh Start Accounting, for additional
unevaluated properties as of December 31, 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 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, 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, 2021 and 2020:
In thousands
Senior Secured Bank Credit Agreement
Pipeline financings
Total debt principal balance
Less: current maturities of long-term debt
Long-term debt
Successor
December 31, 2021 December 31, 2020
$
$
35,000
$
—
35,000
—
35,000
$
70,000
68,008
138,008
(68,008)
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
95
Denbury Inc.
Notes to Consolidated Financial Statements
Operations and Summary of Significant Accounting Policies – Emergence from Voluntary Reorganization Under Chapter
11 of the Bankruptcy Code, for additional information.
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 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, 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 limits our ability 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
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
alternate base rate loans, a base rate determined under the Successor Bank Credit Agreement 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, 2021 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, 2021, we were in compliance with all debt
covenants under the Successor Bank Credit Agreement.
96
Denbury Inc.
Notes to Consolidated Financial Statements
The above description of our Successor Bank Credit Agreement and defined terms are contained in the Successor Bank
Credit Agreement.
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.
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 which 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, 7½% Senior Secured Second Lien Notes due 2024, 6⅜% Convertible Senior Notes due 2024
(the “2024 Convertible Notes”), 6⅜% Senior Subordinated Notes due 2021, 5½% Senior Subordinated Notes due 2022,
and 4⅝% Senior Subordinated Notes due 2023 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.
2019 Predecessor Debt Reduction Transactions
With a focus on reducing the amount of outstanding debt principal, the Predecessor engaged in a series of debt
exchanges and repurchase transactions, resulting in total gains on extinguishments of $156.0 million for the year ended
December 31, 2019, in its Consolidated Statements of Operations.
97
Denbury Inc.
Notes to Consolidated Financial Statements
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 $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, 2021, our indebtedness is payable over the next five years and thereafter as follows:
In thousands
2022
2023
2024
2025
2026
Thereafter
Total indebtedness
Note 9. Income Taxes
Our income tax provision (benefit) is as follows:
In thousands
Current income tax expense (benefit)
Federal
State
Total current income tax expense (benefit)
Deferred income tax expense (benefit)
Federal
State
Total deferred income tax expense (benefit)
Total income tax expense (benefit)
$
$
—
—
35,000
—
—
—
$
35,000
Successor
Predecessor
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
$
— $
— $
(6,407) $
403
403
—
364
364
767
30
30
(853)
(7,260)
—
(2,556)
(2,556)
(319,011)
(89,858)
(408,869)
$
(2,526)
$
(416,129) $
2,645
1,236
3,881
89,950
10,521
100,471
104,352
At December 31, 2021, we had federal net operating loss carryforwards (“NOLs”) and business credit carryforwards
(before provision for valuation allowance) totaling $10.3 million and $18.1 million, respectively. Our federal NOLs 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, 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 2022, and are recorded as a receivable on the balance sheet, and
state NOLs and tax credits totaling $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.
98
Denbury Inc.
Notes to Consolidated Financial Statements
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, 2021 and 2020 balance sheet dates. As of December 31, 2021, we had $74.1
million of net state deferred tax assets associated with operations in Louisiana, Mississippi, Montana, North Dakota and
Alabama, which were 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:
In thousands
Beginning balance
Charges
Deductions
Ending balance
Successor
Predecessor
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
$
$
129,408
$
129,840
$
77,215
$
29,345
(33,291)
2,269
(2,701)
77,138
(24,513)
51,093
26,122
—
125,462
$
129,408
$
129,840
$
77,215
As of December 31, 2021, we had no unrecognized tax benefits recorded related to an uncertain tax position.
Significant components of our deferred tax assets and liabilities as of December 31, 2021 and 2020 are as follows:
In thousands
Deferred tax assets
Loss and tax credit carryforwards – state
Derivative contracts
Accrued liabilities and other reserves
Business credit carryforwards
Loss carryforwards – federal
Lease liabilities
Property and equipment
Other
Valuation allowances
Total deferred tax assets
Deferred tax liabilities
CO2 and other contracts
Operating lease right-of-use assets
Total deferred tax liabilities
Total net deferred tax liability
Successor
December 31, 2021 December 31, 2020
$
54,943
$
30,892
19,567
18,066
10,310
4,523
2,613
4,206
55,979
13,090
15,632
—
—
6,354
59,207
4,092
(125,462)
19,658
(129,408)
24,946
(17,208)
(4,088)
(21,296)
$
(1,638) $
(20,030)
(6,190)
(26,220)
(1,274)
99
Denbury Inc.
Notes to Consolidated Financial Statements
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:
In thousands
Income tax provision calculated using the federal
statutory income tax rate
State income taxes, net of federal income tax benefit
Tax shortfall (windfall) on stock-based
compensation deduction
Nondeductible compensation
Change in valuation allowance
Enhanced oil recovery credits generated
Tax attributes reduction – net of CODI exclusion
Other
Total income tax expense (benefit)
$
Successor
Predecessor
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
$
11,921
$
(11,169)
$
(388,228) $
450
(2,532)
(86,937)
(267)
5,057
(2,928)
(14,272)
—
806
767
—
—
9,653
—
—
1,522
(1,502)
—
19,344
—
31,667
9,527
$
(2,526)
$
(416,129) $
104,352
67,475
7,435
1,912
—
26,122
—
—
1,408
We file consolidated and separate income tax returns in the U.S.
jurisdiction and in many state
jurisdictions. The statutes of limitation for our income tax returns for tax years ending prior to 2018 have lapsed and
therefore are not subject to examination by respective taxing authorities. We have not paid any significant interest or
penalties associated with our income taxes.
federal
Note 10. Stockholders’ Equity
Registration Rights Agreement
On September 18, 2020, in connection with the 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
second lien notes of the Predecessor that entered into the restructuring support agreement leading to the restructuring of the
Company pursuant to a prepackaged plan of reorganization and pursuant to which the Company included these holders’
shares of common stock of the Successor in an automatically effective resale registration statement filed with the SEC in
April 2021 for their 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. 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.
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), $4.4 million for the period January 1, 2020 through September 18, 2020
(Predecessor), and $6.3 million during 2019 (Predecessor).
Note 11. Stock Compensation
Below is a description of stock compensation relating to both the Predecessor periods (2019 and January 1, 2020
through September 18, 2020), and the Successor periods (September 19, 2020 through December 31, 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
100
Denbury Inc.
Notes to Consolidated Financial Statements
designated as Successor plans or awards are the only such plans and awards in effect as of December 31, 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:
In thousands
Stock-based compensation expense included in
G&A
Stock-based compensation capitalized
Total cost of stock-based compensation
arrangements
Income tax benefit recognized for stock-based
compensation arrangements
Management Incentive Plan – Successor
Successor
Predecessor
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
$
$
$
25,322
$
8,212
$
4,111
$
1,883
695
1,660
12,470
4,018
27,205
$
8,907
$
5,771
$
16,488
6,331
$
2,053
$
1,028
$
3,118
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, 2021, 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.
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 period with delivery of the shares occurring at the end of the three-year 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.
101
Denbury Inc.
Notes to Consolidated Financial Statements
As of December 31, 2021, there was $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
recognized over a weighted-average period of 1.9 years. The following is a summary of the total vesting date fair value of
non-performance-based restricted stock units:
In thousands
Fair value of restricted stock units vested
Year Ended
Dec. 31, 2021
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:
Nonvested at December 31, 2020
Granted
Vested
Forfeited
Nonvested at December 31, 2021
Performance-Based Stock Units – Successor
Number
of Awards
1,219,867
$
56,236
(405,311)
(20,885)
849,907
Weighted
Average
Grant-Date
Fair Value
24.67
31.87
24.80
24.67
25.08
In December 2020, the Successor Board of Directors granted performance stock unit (“PSU”) awards to a limited
number of employees. The PSU awards had vesting parameters tied to the Company’s common stock trading prices and
became fully vested on March 3, 2021. Although the performance measures for vesting of these awards have been
achieved, delivery of the shares will not occur until the conclusion of the three-year performance 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.
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.
As of December 31, 2021, there was no remaining unrecognized compensation expense related to the Successor’s PSU
awards. 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
$
24.19
0.21 %
0.23 years
110.0 %
— %
Weighted average fair value of PSU awards granted
Risk-free interest rate
Expected life
Expected volatility
Dividend yield
102
Denbury Inc.
Notes to Consolidated Financial Statements
A summary of the PSU awards activity during the Successor period is as follows:
Nonvested at December 31, 2020
Granted
Vested
Forfeited
Nonvested at December 31, 2021
The following is a summary of the total vesting date fair value of PSU awards:
In thousands
Vesting date fair value of PSU awards
June 2020 Compensation Adjustments – Predecessor
Number
of Awards
Weighted
Average
Grant-Date Fair
Value
1,021,222
$
—
(1,021,222)
—
—
24.19
—
24.19
—
—
Year Ended
Dec. 31, 2021
45,077
$
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.
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 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.
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
103
Denbury Inc.
Notes to Consolidated Financial Statements
thereof until certain 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.
The following is a summary of the total vesting date fair value of non-performance-based restricted stock:
In thousands
Fair value of restricted stock vested
Predecessor
Period from
Jan. 1, 2020
through
Sept. 18, 2020
707
$
Year Ended
Dec. 31, 2019
$
5,743
In connection with our emergence from bankruptcy, all restricted stock outstanding as of September 18, 2020 was
cancelled and there was no 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 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”).
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
Dec. 31, 2019
Weighted average fair value of Performance-Based TSR Awards granted
$
0.15
$
Risk-free interest rate
Expected life
Expected volatility
Dividend yield
0.27 %
3.0 years
89.6 %
— %
1.95
2.27 %
3.0 years
77.2 %
— %
The following is a summary of the total vesting date fair value of performance-based equity awards for the
Predecessor:
In thousands
Vesting date fair value of Performance-Based Operational Awards
Vesting date fair value of Performance-Based TSR Awards
104
Predecessor
Period from
Jan. 1, 2020
through
Sept. 18, 2020
$
Year Ended
Dec. 31, 2019
— $
79
—
2,783
Denbury Inc.
Notes to Consolidated Financial Statements
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.
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.
future cash flows. We do not hold or
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
trading
purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars,
fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps. The production that we hedge has varied
from year to year depending on our levels of debt, financial strength, expectation of future commodity prices, and
occasionally requirements under our bank credit facility. As of December 31, 2020, we were in compliance with the
hedging requirements under 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.
issue derivative financial
instruments for
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, 2021, all of our
outstanding derivative contracts were subject to enforceable master netting arrangements whereby payables on those
contracts can be offset against receivables from separate derivative contracts with the same counterparty. It is our policy to
classify derivative assets and liabilities on a gross basis on our balance sheets, even if the contracts are subject to
enforceable master netting arrangements.
The following table summarizes our commodity derivative contracts as of December 31, 2021, none of which are
classified as hedging instruments in accordance with the FASC Derivatives and Hedging topic:
Volume
(Barrels per
day)
Contract Prices ($/Bbl)
Weighted Average Price
Range(1)
Swap
Floor
Ceiling
Months
Index Price
Oil Contracts:
2022 Fixed-Price Swaps
Jan – Jun
July – Dec
2022 Collars
Jan – Jun
July – Dec
NYMEX
NYMEX
NYMEX
NYMEX
15,500
9,000
11,000
10,000
$
42.65 –
58.15
$
49.01
$
50.13 –
60.35
56.35
— $
—
—
—
$
47.50 –
70.75
$
— $
49.77
$
47.50 –
70.75
—
49.75
64.31
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,
105
Denbury Inc.
Notes to Consolidated Financial Statements
including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily
observable, market corroborated or generally unobservable. We primarily apply the income approach for recurring fair
value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques
that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value
balances based on the observability of those inputs. The FASC establishes a fair value hierarchy that prioritizes the inputs
used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for
identical assets or
liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3
measurement). The three levels of the fair value hierarchy are as follows:
•
•
Level 1 – Quoted prices in active markets for identical assets or liabilities as of the reporting date.
Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either
directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are
valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded
oil derivatives that are based on NYMEX and regional pricing other than NYMEX (e.g., Light Louisiana
Sweet). Our costless collars and the sold put features of our three-way collars are valued using the Black-Scholes
model, an industry standard option valuation model that takes into account inputs such as contractual prices for the
underlying instruments, maturity, quoted forward prices for commodities, interest rates, volatility factors and
credit worthiness, as well as other relevant economic measures. Substantially all of these assumptions are
observable in the marketplace throughout the full term of the instrument, can be derived from observable data or
are supported by observable levels at which transactions are executed in the marketplace.
•
Level 3 – Pricing inputs include significant inputs that are generally less observable. These inputs may be used
with internally developed methodologies that result in management’s best estimate of fair value.
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.
106
Denbury Inc.
Notes to Consolidated Financial Statements
The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that were
accounted for at fair value on a recurring basis as of December 31, 2021 and 2020:
In thousands
December 31, 2021
Liabilities
Oil derivative contracts – current
Oil derivative contracts – long-term
Total Liabilities
December 31, 2020
Assets
Oil derivative contracts – current
Total Assets
Liabilities
Oil derivative contracts – current
Oil derivative contracts – long-term
Total Liabilities
Fair Value Measurements Using:
Quoted Prices
in Active
Markets
(Level 1)
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Total
$
$
$
$
$
$
— $
(134,509) $
— $
(134,509)
—
—
—
—
— $
(134,509) $
— $
(134,509)
— $
— $
187
187
$
$
— $
(53,865) $
—
(5,087)
— $
(58,952) $
— $
— $
— $
—
— $
187
187
(53,865)
(5,087)
(58,952)
Since we do not apply hedge accounting for our commodity derivative contracts, any gains and losses on our assets
and liabilities are included in “Commodity derivatives expense (income)” in the accompanying Consolidated Statements of
Operations.
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. The estimated fair
value of the principal amount of our debt as of December 31, 2021 and 2020, excluding pipeline financing obligations, was
$35.0 million and $70.0 million, respectively. We have other financial instruments consisting primarily of cash, cash
equivalents, U.S. Treasury notes, short-term receivables and payables that approximate fair value due to the nature of the
instrument and the relatively short maturities.
Note 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 7 years. The price we will pay for CO2
generally varies depending on the amount of CO2 delivered and the price of oil.
In addition, we have a processing fee
contract related to our overriding royalty interest in the CO2 at LaBarge Field. Our annual commitment under these
contracts could range from $39 million to $46 million in 2022, assuming a $70 per 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 daily contract quantities as stated in the industrial
contracts, total amounts deliverable to these customers could be up to 572 Bcf of CO2 over the next 13 years.
107
Denbury Inc.
Notes to Consolidated Financial Statements
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
to inherent
adverse effect on our
uncertainties. We accrue for losses from litigation and claims if we determine that a loss is probable and the amount can be
reasonably estimated.
results of operations or cash flows,
litigation is subject
financial position,
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 no 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
In addition, production rates, marketing and environmental matters are subject to regulation by
regulations are issued.
various federal and state agencies.
Note 15. Additional Balance Sheet Details
Rollforward of Allowance for Doubtful Accounts
Successor
Predecessor
In thousands
Beginning balance
Provision for doubtful accounts
Write-offs
Ending balance
Accounts Payable and Accrued Liabilities
In thousands
Accrued lease operating expenses
Accrued derivative settlements
Accounts payable
Accrued compensation
Accrued exploration and development costs
Accrued asset retirement obligations – current
Taxes payable
Accrued general and administrative expenses
Other
Total
Period from
Sept. 19, 2020
through
Dec. 31, 2020
22,146
$
1,060
—
Period from
Jan. 1, 2020
through
Sept. 18, 2020
Year Ended
Dec. 31, 2019
$
17,137
$
17,070
5,297
(288)
68
(1)
Year Ended
Dec. 31, 2021
23,206
826
(5,085)
$
$
18,947
$
23,206
$
22,146
$
17,137
Successor
December 31, 2021 December 31, 2020
$
27,901
$
27,336
25,700
23,735
18,936
18,373
14,453
2,250
32,914
21,294
3,908
18,629
7,512
1,861
6,943
17,221
21,825
13,478
$
191,598
$
112,671
108
Denbury Inc.
Notes to Consolidated Financial Statements
Note 16. Supplemental Cash Flow Information
Supplemental Cash Flow Information
In thousands
Supplemental cash flow information
Successor
Predecessor
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
Cash paid for interest, expensed
$
4,227
$
813
$
29,357
$
Cash paid for interest, capitalized
Cash paid for interest, treated as a reduction of
debt
Cash paid for income taxes
Cash received from income tax refunds
Noncash investing and financing activities
Increase in asset retirement obligations
Increase (decrease) in liabilities for capital
expenditures
Conversion of convertible senior notes into
common stock
4,585
1,261
—
184
3
—
—
10,457
22,885
46,417
453
1,932
72,842
36,671
85,303
2,361
9,820
112,760
23,398
4,328
13,560
35,679
1,867
(12,809)
(17,740)
—
—
11,501
—
109
Denbury Inc.
Unaudited Supplementary Information
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 during the year ended
December 31, 2019 (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 for the year ended December 31, 2019 (Predecessor). See
Note 6, Asset Retirement Obligations, for additional information.
Costs incurred in oil and natural gas activities were as follows:
In thousands
Property acquisitions
Proved
Unevaluated
Exploration
Development
Successor
Predecessor
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
$
11,141
$
130
$
278
$
—
79
178,411
—
60
23,741
23,931
—
260
92,212
$
92,750
$
1,542
—
2,575
259,641
263,758
Total costs incurred(1)
$
189,631
$
(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 for the year ended December 31, 2019 (Predecessor).
110
Denbury Inc.
Unaudited Supplementary Information
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:
In thousands, except per-BOE data
Oil, natural gas, and related product sales
Lease operating expenses
Transportation and marketing expenses
Production and ad valorem taxes
Depletion, depreciation, and amortization
CO2 properties and pipelines depletion and
depreciation(1)
Write-down of oil and natural gas properties
Commodity derivatives expense (income)
Net operating income (loss)
Income tax provision (benefit)
Results of operations from oil and natural gas
producing activities
Depletion, depreciation, and amortization per BOE
Successor
Predecessor
Year Ended
Dec. 31, 2021
$
1,159,955
Period from
Sept. 19, 2020
through
Dec. 31, 2020
201,108
$
Period from
Jan. 1, 2020
through
Sept. 18, 2020
492,101
$
Year Ended
Dec. 31, 2019
$
1,212,020
424,550
28,817
88,468
119,997
7,180
14,377
352,984
123,582
—
123,582
7.14
$
$
101,234
10,595
15,061
37,549
1,744
1,006
61,902
(27,983)
—
(27,983)
7.72
$
$
250,271
27,164
38,647
104,504
33,839
996,658
(102,032)
(856,950)
(214,238)
477,220
41,810
86,820
161,400
53,120
—
70,078
321,572
80,393
$
$
(642,712) $
241,179
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, 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 and 2019 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.
111
Denbury Inc.
Unaudited Supplementary Information
Estimated Quantities of Proved Reserves
Year Ended December 31,
2021
2020
2019
Oil
(MBbl)
Gas
(MMcf)
Total
(MBOE)
Oil
(MBbl)
Gas
(MMcf)
Total
(MBOE)
Oil
(MBbl)
Gas
(MMcf)
Total
(MBOE)
140,499
15,604
143,100
226,133
24,334
230,189
255,042
43,008
262,210
55,998
(615)
55,895
(63,359)
(5,822)
(64,329)
(6,799)
(15,299)
(9,348)
—
—
—
—
—
—
977
—
977
(17,258)
(3,261)
(17,801)
(18,237)
(2,905)
(18,721)
(20,685)
(3,375)
(21,248)
Balance at beginning of
year
Revisions of previous
estimates
Improved recovery(1)
Production
Acquisition of minerals in
place
Sales of minerals in place
(66)
(986)
(230)
(4,038)
9,765
5,764
10,725
—
—
(3)
—
—
(4,039)
(2,402)
—
—
—
(2,402)
Balance at end of year
188,938
16,506
191,689
140,499
15,604
143,100
226,133
24,334
230,189
Proved Developed
Reserves – end of year
Proved Undeveloped
Reserves – end of year
179,147
16,506
181,898
136,402
15,604
139,003
202,816
24,333
206,872
9,791
—
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 reflect changes in commodity prices resulting in upward revisions of 50.1 MMBOE
during 2021 and 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, or 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 wells to reach the end of their economic life much sooner and can make certain proved undeveloped locations
112
Denbury Inc.
Unaudited Supplementary Information
uneconomical, both of which reduce the reserves. These prices were further adjusted by field to arrive at the appropriate
corporate net price.
Oil (NYMEX price per Bbl)
Natural Gas (Henry Hub price per MMBtu)
2021
December 31,
2020
$
66.56
$
39.57
$
3.60
1.99
2019
55.69
2.58
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 2019 and 2021.
The weighted 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, and $0.14 per Bbl below representative NYMEX oil prices as
of December 31, 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.
In thousands
Future cash inflows
Future production costs
Future development costs
Future income taxes
Future net cash flows
10% annual discount for estimated timing of cash flows
2021
December 31,
2020
2019
$ 12,020,943
$
5,010,288
$ 12,494,358
(6,652,315)
(3,300,890)
(6,813,610)
(1,116,998)
(962,224)
(1,434,934)
(776,337)
3,475,293
(1,288,242)
(59,600)
687,574
(586,441)
3,659,373
(32,840)
(1,398,334)
Standardized measure of discounted future net cash flows
$
2,187,051
$
654,734
$
2,261,039
113
Denbury Inc.
Unaudited Supplementary Information
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:
In thousands
Beginning of year
Year Ended December 31,
2020
2019
2021
$
654,734
$
2,261,039
$
3,351,385
Sales of oil and natural gas produced, net of production costs
(618,119)
(250,237)
(608,060)
Net changes in prices and production costs
Improved recovery(1)
Previously estimated development costs incurred
Change in future development costs
Revisions due to timing and other
Accretion of discount
Acquisition of minerals in place
Sales of minerals in place
Net change in income taxes
End of year
2,360,251
(1,753,248)
(1,244,859)
—
36,074
(15,623)
35,887
68,119
105,610
(1,454)
(438,428)
—
28,182
11,200
(127,046)
233,663
—
(55,102)
306,283
5,785
81,024
(35,624)
41,841
367,313
—
(16,892)
319,126
$
2,187,051
$
654,734
$
2,261,039
(1) Improved recovery additions result from the application of secondary recovery methods such as water flooding or
tertiary recovery methods such as CO2 flooding.
SUPPLEMENTAL CO2 DISCLOSURES (UNAUDITED)
Based on engineering reports prepared by DeGolyer and MacNaughton, proved CO2 reserves were estimated as
follows:
In MMcf
CO2 reserves
Gulf Coast region(1)
Rocky Mountain region(2)
Year Ended December 31,
2020
2019
2021
4,474,313
1,046,139
4,641,812
1,089,101
4,786,881
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 and 3.8 Tcf at
December 31, 2021, 2020 and 2019, 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 1.0 Tcf, 1.1 Tcf and 1.1 Tcf at December 31, 2021, 2020 and 2019,
respectively.
114
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Denbury Inc.
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, 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 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, 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.
115
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Denbury Inc.
None.
116
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 2022 Annual Meeting of Shareholders to be held May 26, 2022 (“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.
117
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 63. 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.
2(a)
Exhibit
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)
3(b)
4(a)
4(b)
4(c)
10(a)
10(b)
10(c) **
10(d)
10(e) **
10(f) **
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).
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).
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).
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).
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).
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).
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).
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).
Restructuring Support Agreement, dated July 28, 2020 (incorporated by reference to Exhibit 10.1 of
Form 8-K filed by the Company on July 29, 2020, File No. 001-12935).
2020 Form of Incentive Bonus Agreement for Denbury Resources Inc. (incorporated by reference to
Exhibit 10(g) of Form 10-Q filed by the Company on August 11, 2020, File No. 001-12935).
Denbury Inc. 2020 Omnibus Stock and Incentive Plan (incorporated by reference to Exhibit 10.1 of Form
8-K filed by the Company on December 4, 2020, File No. 001-12935).
118
Denbury Inc.
Exhibit No.
10(g) **
Exhibit
2020 Form of Restricted Stock Unit Award under the 2020 Omnibus Stock and Incentive Plan for
Denbury Inc. (incorporated by reference to Exhibit 10(f) of Form 10-K filed by the Company on March
5, 2021, File No. 001-12935).
10(h) **
10(i) **
21*
23(a)*
23(b)*
23(c)*
31(a)*
2020 Form of Director Deferred Stock Unit Award under the 2020 Omnibus Stock and Incentive Plan for
Denbury Inc. (incorporated by reference to Exhibit 10(g) of Form 10-K filed by the Company on March
5, 2021, File No. 001-12935).
2020 Form of Performance Stock Unit Award under the 2020 Omnibus Stock and Incentive Plan for
Denbury Inc. (incorporated by reference to Exhibit 10(h) of Form 10-K filed by the Company on March
5, 2021, File No. 001-12935).
List of subsidiaries of Denbury Inc.
Consent of PricewaterhouseCoopers LLP.
Consent of PricewaterhouseCoopers LLP.
Consent of DeGolyer and MacNaughton.
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*
99*
Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
The summary of DeGolyer and MacNaughton’s Report as of December 31, 2021, on oil and gas reserves
dated February 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
104
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
* Included herewith.
** Compensation arrangements.
Item 16. Form 10-K Summary
None.
119
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.
February 24, 2022
DENBURY INC.
/s/ Mark C. Allen
Mark C. Allen
Executive Vice President and Chief Financial Officer
February 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.
February 24, 2022
/s/ Christian S. Kendall
Christian S. Kendall
Director, President and Chief Executive Officer
(Principal Executive Officer)
February 24, 2022
/s/ Mark C. Allen
Mark C. Allen
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
February 24, 2022
/s/ Nicole Jennings
Nicole Jennings
Vice President and Chief Accounting Officer
(Principal Accounting Officer)
February 24, 2022
February 24, 2022
February 24, 2022
February 24, 2022
/s/ Kevin O. Meyers
Kevin O. Meyers
Director
/s/ Anthony Abate
Anthony Abate
Director
/s/ Caroline Angoorly
Caroline Angoorly
Director
/s/ James Chapman
James Chapman
Director
120
February 24, 2022
February 24, 2022
February 24, 2022
Denbury Inc.
/s/ Lynn A. Peterson
Lynn A. Peterson
Director
/s/ Brett Wiggs
Brett Wiggs
Director
/s/ Cindy A. Yeilding
Cindy A. Yeilding
Director
121
LIST OF SUBSIDIARIES
Name of Subsidiary
Jurisdiction of Organization
Exhibit 21
Denbury Operating Company
Denbury Onshore, LLC
Denbury Pipeline Holdings, LLC
Denbury Holdings, Inc.
Denbury Green Pipeline – Texas, LLC
Greencore Pipeline Company, LLC
Denbury Gulf Coast Pipelines, LLC
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (No. 333-251121) and
Form S-3 (No. 333-255218) of Denbury Inc. of our report dated February 24, 2022 relating to the financial statements and
the effectiveness of internal control over financial reporting, which appears in this Form 10-K.
Exhibit 23(a)
/s/ PricewaterhouseCoopers LLP
Dallas, Texas
February 24, 2022
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Form S-8 (No. 333-251121) and
Form S-3 (No. 333-255218) of Denbury Resources Inc. of our report dated March 5, 2021 relating to the financial
statements, which appears in this Form 10-K.
Exhibit 23(b)
/s/ PricewaterhouseCoopers LLP
Dallas, Texas
February 24, 2022
Exhibit 23(c)
DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
February 24, 2022
Denbury Inc.
5851 Legacy Circle
Plano, Texas 75024
Ladies and Gentlemen:
We hereby consent to the use of the name DeGolyer and MacNaughton, to references to DeGolyer and MacNaughton,
to the inclusion of our report of third party dated February 3, 2022, regarding the proved reserves of Denbury Inc., and to
the inclusion of information taken from our reports entitled “Report as of December 31, 2021 on Reserves and Revenue of
Certain Properties with interests attributable to Denbury Inc.,” “Report as of December 31, 2020 on Reserves and Revenue
of Certain Properties with interests attributable to Denbury Inc.,” and “Report as of December 31, 2019 on Reserves and
Revenue of Certain Properties with interests attributable to Denbury Resources Inc.” in the Annual Report on Form 10-K
of Denbury Inc. for the year ended December 31, 2021.
Very truly yours,
/s/ DeGolyer and MacNaughton
DeGolyer and MacNaughton
Texas Registered Engineering Firm F-716
CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
Exhibit 31(a)
I, Christian S. Kendall, certify that:
1.
I have reviewed this report on Form 10-K of Denbury Inc. (the registrant);
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present
in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the
periods presented in this report;
4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting
(as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in
which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to
be designed under our supervision, 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;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered
by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during
the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that
has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial
reporting; and
5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control
over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or
persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and
report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in
the registrant’s internal control over financial reporting.
February 24, 2022
/s/ Christian S. Kendall
Christian S. Kendall
Director, President and Chief Executive Officer
CERTIFICATION UNDER SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
Exhibit 31(b)
I, Mark C. Allen, certify that:
1.
I have reviewed this report on Form 10-K of Denbury Inc. (the registrant);
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present
in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the
periods presented in this report;
4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting
(as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in
which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to
be designed under our supervision, 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;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered
by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during
the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that
has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial
reporting; and
5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control
over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or
persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and
report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in
the registrant’s internal control over financial reporting.
February 24, 2022
/s/ Mark C. Allen
Mark C. Allen
Executive Vice President, Chief Financial Officer,
Treasurer, and Assistant Secretary
Certification of Chief Executive Officer and Chief Financial Officer
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
Exhibit 32
In connection with the accompanying Annual Report on Form 10-K for the year ended December 31, 2021 (the Report) of
Denbury Inc. (Denbury) as filed with the Securities and Exchange Commission, each of the undersigned, in his capacity as
an officer of Denbury, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002, that to his knowledge:
1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as
amended; and
2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of
operations of Denbury.
Dated: February 24, 2022
/s/ Christian S. Kendall
Christian S. Kendall
Director, President and Chief Executive Officer
Dated: February 24, 2022
/s/ Mark C. Allen
Mark C. Allen
Executive Vice President, Chief Financial Officer,
Treasurer, and Assistant Secretary
CORPORATE INFORMATION
BOARD OF DIRECTORS
KEVIN O. MEYERS
Chairman of the Board
Independent Consultant
ANTHONY M. ABATE
Independent Consultant
CAROLINE G. ANGOORLY
Managing Partner
GreenTao LLC
JAMES N. CHAPMAN
Independent Consultant
CHRISTIAN S. KENDALL
President and Chief Executive Officer
Denbury Inc.
LYNN A. PETERSON
Chief Executive Officer and President
Whiting Petroleum Corporation
BRETT R. WIGGS
Chief Executive Officer
Oryx Midstream Services
CINDY A. YEILDING
Independent Consultant
CONTACTING BOARD MEMBERS
You may contact our board members by addressing a letter
to Denbury Inc., Attn: Corporate Secretary, or by email to
secretary@denbury.com
EXECUTIVE OFFICERS
CHRIS KENDALL
President and Chief Executive Officer
MARK ALLEN
STOCK EXCHANGE LISTING
New York Stock Exchange (“NYSE”) Ticker Symbol: DEN
CORPORATE HEADQUARTERS
Denbury Inc.
5851 Legacy Circle, Suite 1200
Plano, Texas 75024
972. 673. 2000
www.denbury.com
STOCK TRANSFER AGENT & REGISTRAR
For questions concerning dividends, stock certificates, transfer
procedures or address changes, please contact:
Broadridge Corporate Issuer Solutions
P.O. Box 1342
Brentwood, NY 11717
866.804.4482
Email: shareholder@broadridge.com
www.shareholder.broadridge.com/bcis
INVESTOR INQUIRIES
Investor Relations
972. 673. 2000
Email: ir@denbury.com
ANNUAL CERTIFICATIONS
During 2021, our Chief Executive Officer certified to the NYSE
that he is not aware of any violation by the Company of the NYSE’s
corporate governance listing standards.
FINANCIAL INFORMATION REQUESTS
For additional information and to receive additional copies of
the Annual Report on Form 10-K as filed with the Securities and
Exchange Commission (“SEC”) or to obtain other Denbury public
documents, please contact: Denbury Inc. Investor Relations 5851
Legacy Circle, Suite 1200 Plano, Texas 75024 972.673.2000
Email: ir@denbury.com Our Form 10-K filed with the SEC is
included herein, excluding all exhibits other than our Section 302,
404 and 906 certifications by the CEO and CFO. We will send
shareholders our Form 10-K exhibits and any of our corporate
governance documents, without charge, upon request. These
documents are also available on our website at www.denbury.com.
Executive Vice President, Chief Financial Officer, Treasurer and
Assistant Secretary
ANNUAL MEETING
JIM MATTHEWS
Executive Vice President, Chief Administrative Officer, General
Counsel and Secretary
The Annual Meeting of Stockholders will be held virtually at
www.virtualshareholdermeeting.com/DEN2022 (1-800-586-1548
for questions) at 8:00 A.M. CDT on Wednesday, June 1, 2022.
JENNY COCHRAN
Senior Vice President, Business Services
MATT DAHAN
Senior Vice President, Business Development and Technology
LEGAL COUNSEL
Baker & Hostetler LLP
BANKERS
J.P. Morgan (Agent)
DAVID SHEPPARD
Senior Vice President, Operations
NIK WOOD
Senior Vice President, CCUS
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
PricewaterhouseCoopers LLP
RESERVES ENGINEERS
DeGolyer and MacNaughton
D E N B U R Y I N C .
5 8 5 1 L E G A C Y C I R C L E
S U I T E 1 2 0 0
P L A N O , T E X A S 7 5 0 2 4
9 7 2 . 6 7 3 . 2 0 0 0
W W W . D E N B U R Y . C O M