DENBURY INC. 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 endedDecember 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 endedDecember 31, 2020 , as filed with theSecurities and Exchange Commission ("SEC") onMarch 5, 2021 . As a result of the Company's emergence from bankruptcy and adoption of fresh start accounting onSeptember 18, 2020 (the "Emergence Date"), certain values and operational results of the consolidated financial statements subsequent toSeptember 18, 2020 are not comparable to those in the Company's consolidated financial statements prior to, and includingSeptember 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 theSecurities and Exchange Commission . References to "Successor" relate to the financial position and results of operations of the Company subsequent toSeptember 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 theGulf Coast andRocky 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 thatDenbury 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: Year Ended December 31, In thousands, except per-unit data 2021 2020 2019 Oil, natural gas, and related product sales$ 1,159,955 $ 693,209 $ 1,212,020 Receipt (payment) on settlements of commodity derivatives (277,240) 102,485 23,606 Oil, natural gas, and related product sales and commodity settlements, combined$ 882,715
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 $ 58.26 Oil price per Bbl - including impact of derivative settlements 50.46 43.40 59.40 Over the last several years, NYMEX oil prices have been extremely volatile, reaching a three-year peak over$84 per Bbl inOctober 2021 compared to lows averaging$17 per Bbl inApril 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, plusOPEC 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 inlate-October 2021 , followed by oil prices plunging in lateNovember 2021 upon 36 --------------------------------------------------------------------------------
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identification of the new Omicron variant of COVID-19, with NYMEX oil prices
recovering in early 2022 to new seven year highs of
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 inSeptember 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 ofDenbury filing for bankruptcy and emerging from bankruptcy duringSeptember 2020 , our 2020 financial results are broken out between the Predecessor period (January 1, 2020 throughSeptember 18, 2020 ) and the Successor period (September 19, 2020 throughDecember 31, 2020 ). For the Predecessor period fromJanuary 1, 2020 throughSeptember 18, 2020 , we recognized a net loss of$1.4 billion , and for the Successor period fromSeptember 19, 2020 throughDecember 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 ofSeptember 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 theMarch 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 ofWyoming CO2 EOR Fields. OnMarch 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 inWyoming , 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 inJanuary 2022 and if the price condition is met, the second$4 million payment will be due inJanuary 2023 . As ofDecember 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 theMarch 2021 acquisition date fair value. This$2.4 million increase atDecember 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 fromBell Creek to CCA, along with an additional pipeline lateral that will service the initial EOR development and additional future phases. First CO2 injections inCCA's Red River formation commenced in earlyFebruary 2022 , and tertiary oil production response is anticipated in the second half of 2023. 37 --------------------------------------------------------------------------------
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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. AtDecember 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 ofDecember 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 ofFebruary 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, we paid$70.0 million to Genesis Energy, L.P. in accordance with theOctober 2020 restructuring of the financing arrangements of our NEJD CO2 pipeline system and acquired ourWind River Basin properties inWyoming 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 38 --------------------------------------------------------------------------------
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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:
Year Ended December 31,
In thousands 2021 2020 2019
Capital expenditure summary(1)
CCA EOR field expenditures $ 35,754 $ 810 $ 2,424
CCA CO2 pipelines 87,688 10,942 23,843
CCA tertiary development 123,442 11,752 26,267
Non-CCA tertiary and non-tertiary fields 97,085 49,800 161,921
CO2 sources and other CO2 pipelines 1,657 660 2,702
Development excluding CCA tertiary 98,742 50,460 164,623
Capitalized internal costs(2) 29,987 32,956 46,031
Development capital expenditures 252,171 95,168 236,921
Acquisitions of oil and natural gas properties(3) 10,979 176 284
Capital expenditures, before capitalized interest 263,150 95,344 237,205
Capitalized interest 4,585 24,146 36,671
Capital expenditures, total $ 267,735 $ 119,490 $ 273,876
(1)Capital expenditures in this summary are presented on an as-incurred basis
(including accruals), and are $36.6 million higher than the capital expenditures
in the Consolidated Statements of Cash Flows which are presented on a cash paid
basis.
(2)Includes capitalized internal acquisition, exploration and development costs
and pre-production tertiary startup costs.
(3)Primarily consists of working interest positions in the Wind River Basin
enhanced oil recovery fields acquired on March 3, 2021 .
Supply Chain Issues and Potential Cost Inflation. Recent U.S. supply chain
constraints, together with tight labor markets, could increase our costs in 2022
and future periods. Most of the cost inflation pressures we experienced during
late 2021 were tied to rising fuel and power costs in our operations but were
not material to our 2021 financial results. We have increased our 2022
operational budget for anticipated inflation and have taken steps to build our
on-hand supply stock for items frequently used in our operations to address
possible supply chain disruptions.
2022 Plans and Capital Budget. 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 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.
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Also, at December 31, 2021 , we had $528.1 million of availability under our bank
credit facility, which we believe is more than adequate to cover any near-term
liquidity needs.
Based on our capital spending plans, we currently anticipate 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 ofDecember 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 ofFebruary 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 theSEC onSeptember 18, 2020 . Commitments, Obligations and Off-Balance Sheet Arrangements. As ofDecember 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 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 40 --------------------------------------------------------------------------------
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commitments under contracts in place as of
•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 onJanuary 30, 2024 , and of which$35.0 million was outstanding as ofDecember 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 longer for a tertiary production response to occur. Further,
we may spend significant amounts of capital before we can recognize any proved
reserves from fields we flood and, even after a field has proved reserves,
significant amounts of additional capital will usually be required to fully
develop the field.
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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.
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RESULTS OF OPERATIONS
Financial and Operating Results Tables
Certain of our financial results for our Successor and Predecessor periods are included in the following table.
Successor Predecessor
Period from Period from
Sept. 19, 2020 Jan. 1, 2020
Year Ended through through Year Ended
In thousands, except per-share data Dec. 31, 2021 Dec. 31, 2020 Sept. 18, 2020 Dec. 31, 2019
Financial results
Net income (loss)(1) $ 56,002 $ (50,658) $ (1,432,578) $ 216,959
Net income (loss) per common share -
basic(1) 1.10 (1.01) (2.89) 0.47
Net income (loss) per common share -
diluted(1) 1.04 (1.01) (2.89) 0.45
Net cash provided by operating activities 317,158 40,326 113,408 494,143
(1)Includes a pre-tax full cost pool ceiling test write-down of our oil and
natural gas properties of $14.4 million for the year ended December 31, 2021 ,
$1.0 million for the Successor period September 19, 2020 through December 31,
2020 , and $996.7 million for the Predecessor period January 1, 2020 through
September 18, 2020 . In addition, the Predecessor period January 1, 2020 through
September 18, 2020 includes reorganization adjustments, net totaling $850.0
million .
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OperationsCertain of our financial and operating results and statistics for each of the last three years are included in the following table.
Year Ended December 31,
In thousands, except per-unit data 2021 2020 2019
Average daily sales volumes
Bbls/d 47,281 49,828 56,672
Mcf/d 8,933 7,938 9,246
BOE/d 48,770 51,151 58,213
Oil and natural gas sales
Oil sales $ 1,148,022 $ 689,020 $ 1,205,083
Natural gas sales 11,933 4,189 6,937
Total oil and natural gas sales $ 1,159,955 $ 693,209 $ 1,212,020
Commodity derivative contracts(1)
Receipt (payment) on settlements of commodity derivatives $ (277,240) $ 102,485 $ 23,606
Noncash fair value losses on commodity derivatives (75,744) (62,355) (93,684)
Commodity derivatives income (expense) $
(352,984)
$ 66.52 $ 37.78 $ 58.26 Natural gas price per Mcf 3.66 1.44 2.06 Unit prices - including impact of derivative settlements(1) Oil price per Bbl$ 50.46 $ 43.40 $ 59.40 Natural gas price per Mcf 3.66 1.44 2.06 Oil and natural gas operating expenses Lease operating expenses$ 424,550 $ 351,505 $ 477,220 Transportation and marketing expenses 28,817 37,759 41,810 Production and ad valorem taxes 88,468 53,708 86,820
Oil and natural gas operating revenues and expenses per BOE Oil and natural gas revenues
$ 65.16 $ 37.03 $ 57.04 Lease operating expenses 23.85 18.78 22.46 Transportation and marketing expenses 1.62 2.02 1.97 Production and ad valorem taxes 4.97 2.87 4.09 CO2 sources - revenues and expenses CO2 sales and transportation fees$ 44,175 $ 30,468 $ 34,142 CO2 operating and discovery expenses (6,678) (4,568) (2,922) CO2 revenue and expenses, net$ 37,497 $ 25,900 $ 31,220
(1)See also Commodity Derivative Contracts below and Market Risk Management for information concerning our commodity derivative transactions.
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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 Second Third Fourth
Operating Area Quarter Quarter Quarter Quarter 2021 2020 2019
Tertiary oil sales volumes
Gulf Coast region
Delhi 2,925 2,931 2,859 2,731 2,861 3,419 4,324
Hastings 4,226 4,487 4,343 4,212 4,317 4,755 5,403
Heidelberg 4,054 3,942 3,895 3,797 3,921 4,297 4,195
Oyster Bayou 3,554 3,791 3,942 4,039 3,833 3,818 4,345
Tinsley 3,424 3,455 3,390 3,353 3,405 3,959 4,608
Other(1) 6,098 6,074 5,907 5,801 5,969 6,427 7,062
Total Gulf Coast region 24,281 24,680 24,336 23,933 24,306 26,675 29,937
Rocky Mountain region
Bell Creek 4,614 4,394 4,330 4,331 4,416 5,518 5,228
Other(2) 2,573 4,378 4,703 4,551 4,059 1,942 2,196
Total Rocky Mountain region 7,187 8,772 9,033 8,882 8,475 7,460 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 volumesGulf Coast regionTotal Gulf Coast region 3,621 3,415 3,763 3,929 3,683 3,807 4,201Rocky Mountain region Cedar Creek Anticline 11,150 10,918 11,182 10,784 11,008 11,985 14,090 Other(3) 1,118 1,348 1,368 1,354 1,298 1,030 1,262Total Rocky Mountain region 12,268 12,266 12,550 12,138 12,306 13,015 15,352 Total non-tertiary sales volumes 15,889 15,681 16,313 16,067 15,989 16,822
19,553
Total continuing sales volumes 47,357 49,133 49,682 48,882 48,770 50,957 56,914 Property sales Gulf Coast Working Interests Sale(4) - - - - - 194 1,299 Total sales volumes 47,357 49,133 49,682 48,882 48,770 51,151 58,213 (1)Includes Brookhaven, Cranfield, Eucutta,Little Creek , Mallalieu, Martinville, McComb, Soso andWest Yellow Creek fields. (2)Includes tertiary sales volumes related to our working interest positions in theWind River Basin properties acquired onMarch 3, 2021 , as well asSalt Creek and Grieve fields.
(3)Includes non-tertiary sales volumes from
(4)Includes non-tertiary sales related to the
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 ourGulf Coast Working Interests Sale inMarch 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, whereby increased oil prices have resulted in increased profitability and thus, reducing sales volumes net toDenbury by approximately 360 BOE/d when 45 --------------------------------------------------------------------------------
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
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:
Year Ended December 31, Year Ended December 31,
2021 vs. 2020 2020 vs. 2019
Increase Percentage Increase
(Decrease) in (Decrease) in Decrease in Percentage Decrease
In thousands Revenues Revenues Revenues in Revenues
Change in oil and natural gas revenues
due to:
Decrease in production $ (34,069) (5) % $ (144,118) (12) %
Increase (decrease) in commodity prices 500,815 72 % (374,693) (31) %
Total increase (decrease) in oil and
natural gas revenues $ 466,746 67 % $ (518,811) (43) %
Excluding any impact of our commodity derivative contracts, our average net
realized commodity prices and NYMEX differentials were as follows during 2021,
2020 and 2019:
Year Ended December 31,
2021 2020 2019
Average net realized prices
Oil price per Bbl $ 66.52 $ 37.78 $ 58.26
Natural gas price per Mcf 3.66 1.44 2.06
Price per BOE 65.16 37.03 57.04
Average NYMEX differentials
Gulf Coast region
Oil per Bbl $ (1.42) $ (1.14) $ 3.30
Natural gas per Mcf 0.26 (0.14) (0.04)
Rocky Mountain region
Oil per Bbl $ (1.32) $ (2.80) $ (2.01)
Natural gas per Mcf (0.27) (1.36) (0.96)
Total Company
Oil per Bbl $ (1.38) $ (1.81) $ 1.23
Natural gas per Mcf (0.05) (0.69) (0.47)
Prices received in a regional market fluctuate frequently and can differ from NYMEX pricing due to a variety of reasons, including supply and/or demand factors, crude oil quality, and location differentials.
•Gulf Coast Region. Our average NYMEX oil differential in theGulf 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 ourGulf Coast grades weakened relative to NYMEX WTI index prices. For our crude oil sold under Light Louisiana Sweet ("LLS") index prices, the LLS-to-NYMEX differential averaged a positive$1.49 per Bbl on a trade-month basis during 2021, compared to a positive$2.12 per Bbl differential during 2020. •Rocky Mountain Region. NYMEX oil differentials in theRocky 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 theRocky Mountain region can fluctuate with regional supply and demand trends and can fluctuate significantly on a 46 --------------------------------------------------------------------------------
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Management's Discussion and Analysis of Financial Condition and Results of
Operations
month-to-month basis due to weather, refinery or transportation issues, and
Canadian and
CO2 Revenues and Expenses
We sell a portion of the CO2 we produce fromJackson 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 endedDecember 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:
Successor
Three Months Ended
In thousands March 31 June 30 September 30 December 31 Full Year
2021
Payment on settlements of commodity
derivatives $ (38,453) $
(63,343)
(77,290) (109,321) 35,925 74,942 (75,744)
Commodity derivatives expense $ (115,743) $ (172,664) $ (41,745) $ (22,832) $ (352,984)
Predecessor Successor
Period from Period from Three Months
Three Months Ended July 1 September 19 Ended
through through
In thousands March 31 June 30 September 18 September 30 December 31 Full Year
2020
Receipt on settlements of
commodity derivatives $ 24,638 $ 45,629 $ 11,129 $ 6,660 $ 14,429 $ 102,485
Noncash fair value gains
(losses) on commodity
derivatives(1) 122,133 (85,759) (15,738) (2,625) (80,366) (62,355)
Commodity derivatives income
(expense) $ 146,771 $ (40,130) $ (4,609) $ 4,035 $ (65,937) $ 40,130
Predecessor
Three Months Ended
In thousands March 31 June 30 September 30 December 31 Full Year
2019
Receipt (payment) on settlements of
commodity derivatives $ 8,206 $ (1,549)
(91,583) 26,309 35,098 (63,508) (93,684)
Commodity derivatives income (expense)
$ 43,155 $ (54,616) $ (70,078) 47
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
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 :
1H 2022 2H 2022 1H 2023 2H 2023
WTI NYMEX Volumes Hedged (Bbls/d) 15,500 9,500 4,500 2,000
Fixed-Price Swaps Weighted Average Swap Price $49.01 $57.52 $74.88 $76.80
WTI NYMEX Volumes Hedged (Bbls/d) 11,000 11,500 5,500 2,000
Weighted Average Floor /
Collars Ceiling Price $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.
Production Expenses
Lease Operating Expenses
Successor Predecessor
Period from Period from
Sept. 19, 2020 Jan. 1, 2020
Year Ended through through Year Ended
In thousands, except per-BOE data Dec. 31, 2021 Dec. 31, 2020 Sept. 18, 2020 Dec. 31, 2019
Total lease operating expenses $ 424,550 $ 101,234 $ 250,271 $ 477,220 Total lease operating expenses per BOE
19.90$ 18.36 $ 22.46 48
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
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 endedDecember 31, 2020 . The decrease between periods was primarily due to changes to a portion of our transportation agreements in theRocky Mountain region during the third quarter of 2021 to begin selling our production atGuernsey, Wyoming versusCushing, 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 endedDecember 31, 2020 . The increase between periods was primarily due to an increase in production taxes resulting from higher oil and natural gas revenues.
General and Administrative Expenses ("G&A")
Successor Predecessor
Period from Period from
Sept. 19, 2020 Jan. 1, 2020
Year Ended through through Year Ended
In thousands, except per-BOE data and employees Dec. 31, 2021 Dec. 31, 2020 Sept. 18, 2020 Dec. 31, 2019
Cash G&A costs $ 53,936 $ 11,258 $ 41,096 $ 51,932
Stock-based compensation 25,322 8,212 4,111 12,470
Severance-related costs - - 3,315 18,627
G&A expense $ 79,258 $ 19,470 $ 48,522 $ 83,029
G&A per BOE
Cash G&A costs $ 3.03 $ 2.21 $ 3.02 $ 2.44
Stock-based compensation 1.42 1.62 0.30 0.59
Severance-related costs - - 0.24 0.88
G&A expenses $ 4.45 $ 3.83 $ 3.56 $ 3.91
Employees as of period end 716 657 662 806
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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 $13.0 million increase in
stock-based compensation expense resulting from the vesting of performance-based
equity awards granted in late 2020, as well as being due to a full year of
expense for restricted stock unit awards also granted in late 2020. Although the
performance criteria for these performance-based equity awards were met in 2021,
the shares are not currently outstanding as actual delivery of the shares is not
scheduled to occur until after the end of the performance period, December 4,
2023 . We expect stock compensation expense will be lower in 2022 as future
performance awards will be more traditional in nature and will be expensed over
a longer time period.
Interest and Financing Expenses
Successor Predecessor
Period from Sept. Period from Jan.In thousands, except per-BOE data and interest Year Ended
19, 2020 through 1, 2020 through Year Ended rates Dec. 31, 2021 Dec. 31, 2020 Sept. 18, 2020 Dec. 31, 2019 Cash interest(1)$ 5,992 $ 2,277 $ 108,824 $ 191,454 Less: interest not reflected as expense for financial reporting purposes(1) - - (49,243) (85,454) Noncash interest expense 2,740 799 2,439 4,554 Amortization of debt discount(2) - - 9,132 7,749 Less: capitalized interest (4,585) (1,261) (22,885) (36,671) Interest expense, net$ 4,147 $ 1,815 $ 48,267 $ 81,632 Interest expense, net per BOE$ 0.23 $ 0.36 $ 3.54 $ 3.84 Average debt principal outstanding(3)$ 84,970 $ 123,120 $ 1,767,605 $ 2,433,245 Average cash interest rate(4) 7.1 % 6.5 % 8.6 % 7.9 % (1)Cash interest during the Predecessor periods includes the portion of interest on certain debt instruments accounted for as a reduction of debt for GAAP financial reporting purposes in accordance with Financial Accounting Standards Board Codification ("FASC") 470-60, Troubled Debt Restructuring by Debtors. The portion of interest treated as a reduction of debt was related to the Predecessor's 9% Senior Secured Second Lien Notes due 2021 (the "2021 Notes") and 9¼% Senior Secured Second Lien Notes due 2022 (the "2022 Notes") during the Predecessor period fromJanuary 1, 2020 throughSeptember 18, 2020 and year endedDecember 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 onJuly 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 6?% Convertible Senior Notes due 2024 (the "2024 Convertible Notes") during the Predecessor periodJanuary 1, 2020 throughSeptember 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 endedDecember 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. 50
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
OperationsDepletion, Depreciation, and Amortization ("DD&A")
Successor Predecessor
Period from Period from
Sept. 19, 2020 Jan. 1, 2020
Year Ended through through Year Ended
In thousands, except per-BOE data Dec. 31, 2021 Dec. 31, 2020 Sept. 18, 2020 Dec. 31, 2019
Oil and natural gas properties $ 119,997 $ 37,188 $ 104,495 $ 159,478
CO2 properties, pipelines, plants and other
property and equipment 30,643 8,624 44,939 74,338
Accelerated depreciation charge(1) - - 39,159 -
Total DD&A $ 150,640 $ 45,812 $ 188,593 $ 233,816
DD&A per BOE
Oil and natural gas properties $ 6.74 $ 7.31 $ 7.66 $ 7.51
CO2 properties, pipelines, plants and other
property and equipment 1.72 1.69 3.30 3.49
Accelerated depreciation charge(1) - - 2.87 -
Total DD&A cost per BOE $ 8.46 $ 9.00 $ 13.83 $ 11.00 Write-down of oil and natural gas properties
$ 996,658 $ - (1)Represents an accelerated depreciation charge related to capitalized amounts associated with unevaluated properties that were transferred to the full cost pool. DD&A expense was$150.6 million during 2021, compared to$234.4 million for the combined Predecessor and Successor periods included within the year endedDecember 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 ofSeptember 18, 2020 and an accelerated depreciation charge of$39.2 million during the Predecessor period fromJanuary 1, 2020 throughSeptember 18, 2020 . Our oil and natural gas properties depletion rate was$6.71 per BOE during the fourth quarter of 2021.
Full Cost Pool Ceiling Test
Under full cost accounting rules, we are required each quarter (as well as at the end of the Predecessor period) to perform a ceiling test calculation. Under these rules, the full cost ceiling value is calculated using the average first-day-of-the-month oil and natural gas 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 atDecember 31, 2021 ,$35.84 atDecember 31, 2020 ,$40.08 atSeptember 18, 2020 and$55.55 atDecember 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 theMarch 2021 acquisition ofWyoming 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 fromJanuary 1, 2020 throughSeptember 18, 2020 , and an additional full cost pool ceiling test write-down of$1.0 million was recognized during the Successor period fromSeptember 19, 2020 throughDecember 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
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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:
Predecessor
Period from
Jan. 1, 2020
through
In thousands Sept. 18, 2020
Gain on settlement of liabilities subject to compromise $ (1,024,864)
Fresh start accounting adjustments 1,834,423
Professional service provider fees and other expenses 11,267
Success fees for professional service providers 9,700
Loss on rejected contracts and leases 10,989
Valuation adjustments to debt classified as subject to compromise
757
Debtor-in-possession credit agreement fees 3,107
Acceleration of Predecessor stock compensation expense 4,601
Total reorganization items, net $ 849,980
Other Expenses
Other expenses totaled $10.8 million during 2021 and primarily includes plant
operating expenses, litigation accruals and noncash fair value adjustments for
contingent consideration payments related to our March 2021 Wind River Basin CO2
EOR field acquisition, slightly offset by insurance reimbursements for
previously-incurred costs associated with the February 2020 Delta-Tinsley CO2
pipeline repair. Other expenses totaled $43.9 million for the combined
Predecessor and Successor periods included within the year ended December 31,
2020 . Other expenses during 2020 primarily are comprised of $28.2 million of
professional fees associated with restructuring activities, $5.1 million for the
write-off of certain trade receivables, $4.3 million of costs associated with
the Delta-Tinsley CO2 pipeline repair, and $0.9 million of costs associated with
the APMTG Helium, LLC helium supply contract ruling.
Income Taxes
Successor Predecessor
Period from Sept. Period from Jan.
In thousands, except per-BOE amounts and Year Ended 19, 2020 through 1, 2020 through Year Ended
tax rates Dec. 31, 2021 Dec. 31, 2020 Sept. 18, 2020 Dec. 31, 2019
Current income tax expense (benefit) $ 403 $ 30 $ (7,260) $ 3,881
Deferred income tax expense (benefit) 364 (2,556) (408,869) 100,471
Total income tax expense (benefit) $ 767 $ (2,526) $ (416,129) $ 104,352
Average income tax expense (benefit) per
BOE $ 0.04 $ (0.49) $ (30.52) $ 4.91
Effective tax rate 1.4 % 4.7 % 22.5 % 32.5 %
Total net deferred tax liability $ 1,638 $ 1,274 $ 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.
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Management's Discussion and Analysis of Financial Condition and Results of
Operations
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
As provided for under FASC 740-270-35-2, we determined the actual effective tax rate for the Predecessor period fromJanuary 1, 2020 throughSeptember 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 ourTexas 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 --------------------------------------------------------------------------------
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Management's Discussion and Analysis of Financial Condition and Results of
Operations
Per-BOE Data
The following table summarizes our cash flow and results of operations on a per-BOE basis for the comparative periods. Each of the significant individual components is discussed above.
Year Ended December 31,
Per-BOE data 2021 2020 2019
Oil and natural gas revenues $ 65.16 $ 37.03 $ 57.04
Receipt (payment) on settlements of commodity derivatives (15.57) 5.47 1.11
Lease operating expenses (23.85) (18.78) (22.46)
Production and ad valorem taxes (4.97) (2.87) (4.09)
Transportation and marketing expenses (1.62) (2.02) (1.97)
Production netback 19.15 18.83 29.63
CO2 sales, net of operating and discovery expenses 2.10 1.39 1.47
General and administrative expenses(1) (4.45) (3.63) (3.91)
Interest expense, net (0.23) (2.68) (3.84)
Reorganization items settled in cash - (2.08) -
Stock compensation and other 0.97 (0.38) 0.43
Changes in assets and liabilities relating to operations 0.28 (3.24) (0.52)
Cash flows from operations 17.82 8.21 23.26
DD&A - excluding accelerated depreciation charge (8.46) (10.43) (11.00)
DD&A - accelerated depreciation charge(2) - (2.09) -
Write-down of oil and natural gas properties (0.81) (53.29) -
Deferred income taxes (0.02) 21.98 (4.73)
Gain on extinguishment of debt - 1.01 7.34
Noncash fair value losses on commodity derivatives (4.26) (3.33) (4.41)
Noncash reorganization items, net - (43.32) -
Other noncash items (1.12) 2.03 (0.25)
Net income (loss) $ 3.15 $ (79.23) $ 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.
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MARKET RISK MANAGEMENT
Debt and Interest Rate Sensitivity
AtDecember 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 ofDecember 31, 2021 : Fair In thousands 2022 2023 2024 2025 Total Value Variable rate debt Senior SecuredBank Credit Facility (weighted average interest rate of 4.0% at December 31, 2021) $ - $ -$ 35,000 $ -$ 35,000 $ 35,000
Commodity Derivative Contracts
We enter into oil derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future oil production and to provide more certainty to our future cash flows. We do not hold or issue derivative financial instruments for trading purposes. Generally, these contracts have consisted of various combinations of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps. The production that we hedge has varied from year to year depending on our levels of debt, financial strength, expectation of future commodity prices, and occasionally requirements under our bank credit facility. As ofDecember 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 throughJuly 31, 2022 , and we have no further hedging requirements under ourBank 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. AtDecember 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 atDecember 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 betweenDecember 31, 2020 and 2021. 55
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Management's Discussion and Analysis of Financial Condition and Results of
OperationsCommodity Derivative Sensitivity Analysis
Based on NYMEX oil futures prices and derivative contracts in place as ofDecember 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 Receipt / (Payment) Based on: Futures prices as of December 31, 2021 $ (124,394) 10% increase in prices (184,362) 10% decrease in prices (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 value adjustments, financial projections, enterprise value and equity value, are inherently subject to significant uncertainties and the resolution of contingencies beyond our control. Accordingly, there is no assurance that the estimates, assumptions, valuations or financial projections will be realized, and actual results could vary materially. Among the most material of these judgments and estimates that were made were the following: •Reorganization Value - The reorganization value derived from the range of enterprise values associated with the Plan was allocated to the Company's identifiable tangible and intangible assets and liabilities based on their fair values. The value of the reconstituted entity (i.e., Successor) was based on management projections and the valuation models as determined by the Company's financial advisors in setting an estimated range of enterprise values. With the assistance of third-party valuation advisors, we determined the enterprise and corresponding equity value of the Successor using various valuation approaches and methods, including: (i) income approach using a calculation of the present value of future cash flows based on our financial projections, (ii) the market approach using selling prices of similar assets and (iii) the cost approach. •Oil and Natural Gas Properties - The fair value of our oil and natural gas properties was determined based on the discounted cash flows expected to be generated from these assets. The computations were based on market conditions and reserves in place as of the Emergence Date. The fair value analysis was based on the Company's estimated future production rates of proved and probable reserves as prepared by the Company's independent petroleum engineers. Discounted cash flow models were prepared using the 56 --------------------------------------------------------------------------------
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estimated future revenues and operating costs for all developed wells and
undeveloped properties comprising the proved and probable reserves. Future
revenue estimates were based upon estimated future production rates and forward
strip oil and natural gas prices as of the Emergence Date through 2024 and
escalated for inflation thereafter, adjusted for differentials. Operating costs
were adjusted for estimated inflation beginning in year 2025. A risk adjustment
factor was applied to each reserve category, consistent with the risk of the
category. The discounted cash flow models also included adjustments for income
tax expenses.
Discount factors utilized were derived using a weighted average cost of capital
computation, which included an estimated cost of debt and equity for market
participants with similar geographies and asset development type and varying
corporate income tax rates based on the expected point of sale for each
property's produced assets. Reserve values were also adjusted for any asset
retirement obligations as well as for CO2 indirect costs not directly allocable
to oil fields.
•CO2 Properties - The fair value of CO2 properties includes the value of CO2
mineral rights and associated infrastructure and was determined using the
discounted cash flow method under the income approach. After-tax cash flows were
forecast based on expected costs to produce and transport CO2 as 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
Businesses involved in the production of oil and natural gas are required to
follow accounting rules that are unique to the oil and gas industry. We apply
the full cost method of accounting for our oil and natural gas
properties. Another acceptable method of accounting for oil and natural gas
production activities is the successful efforts method of accounting. In
general, the primary differences between the two methods are related to the
capitalization of costs and the evaluation for asset impairment. Under the full
cost method, all geological and geophysical costs, exploratory dry holes and
delay rentals are capitalized to the full cost pool, whereas under the
successful efforts method such costs are expensed as incurred. In the assessment
of impairment of oil and natural gas properties, the successful efforts method
follows the Accounting for the Impairment or Disposal of Long-Lived Assets topic
of the FASC, under which the net book value of assets is measured for impairment
against the undiscounted future cash flows using commodity prices consistent
with management expectations. Under the full cost method, the full cost pool
(net book value of oil and natural gas properties) is measured against future
cash flows discounted at 10% using the average first-day-of-the-month oil and
natural gas price for each month during a 12-month rolling period through the
end of each quarterly reporting period. The financial results for a given period
could be substantially different depending on the method of accounting that an
oil and gas entity applies. Further, we do not designate our oil and natural gas
derivative contracts as hedging instruments for accounting purposes under the
Derivatives and Hedging topic of the FASC (see below), and as a result, these
contracts are not considered in the full cost ceiling test.
We make significant estimates at the end of each period related to accruals for
oil and natural gas revenues, production, capitalized costs and operating
expenses. We calculate these estimates with our best available data, which
includes, among other things, production reports, price posting, information
compiled from daily drilling reports and other internal tracking devices, and
analysis of historical results and trends. While management is not aware of any
required revisions to its estimates, there will likely be future adjustments
resulting from such things as revisions in estimated oil and natural gas
volumes, changes in ownership interests, payouts, joint venture audits,
re-allocations by the purchasers or pipelines, or other corrections and
adjustments common in the oil and gas industry, many of which will require
retroactive application. These types of adjustments cannot be currently
estimated or determined and will be recorded in the period during which the
adjustment occurs.
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Under full cost accounting, the estimated quantities of proved oil and natural
gas reserves used to compute depletion and the related present value of
estimated future net cash flows therefrom used to perform the full cost ceiling
test have a significant impact on the underlying financial statements. The
process of estimating oil and natural gas reserves is very complex, requiring
significant decisions in the evaluation of all available geological,
geophysical, engineering and economic data. The data for a given field may also
change substantially over time as a result of numerous factors, including
additional development activity, evolving production history and continued
reassessment of the viability of production under varying economic
conditions. As a result, material revisions to existing reserve estimates may
occur from time to time. Although every reasonable effort is made to ensure the
reported reserve estimates represent the most accurate assessments possible,
including the hiring of independent engineers to prepare reported estimates, the
subjective decisions and variances in available data for various fields make
these estimates generally less precise than other estimates included in our
financial statement disclosures. Over the last three years, annual revisions to
our reserve estimates, excluding any revisions related to changes in commodity
prices, have averaged approximately 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 .
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
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million of our unevaluated costs to the full cost pool during the Predecessor
period from January 1, 2020 through September 18, 2020 . Upon emergence from
bankruptcy, the Company adopted fresh start accounting which resulted in our oil
and natural gas properties, including unevaluated properties, being recorded at
their fair values at the Emergence Date (see Note 2, Fresh Start Accounting, for
additional information).
Tertiary Injection Costs
Our tertiary operations are conducted in reservoirs that have already produced
significant amounts of oil over many years; however, in accordance with the
rules for recording proved reserves, we cannot recognize proved reserves
associated with enhanced recovery techniques, such as CO2 injection, until we
can demonstrate production resulting from the tertiary process or unless the
field is analogous to an existing flood. Our costs associated with the CO2 we
produce (or acquire) and inject are principally our cash out-of-pocket costs of
production, transportation and acquisition, and to pay royalties.
We capitalize, as a development cost, injection costs in fields that are in
their development stage, which means we have not yet seen incremental oil
production due to the CO2 injections (i.e., a production response). These
capitalized development costs will be included in our unevaluated property costs
until we are able to recognize proved oil reserves associated with the
development project. After we see a production response to the CO2 injections
(i.e., the production stage), injection costs will be expensed as incurred, and
any previously deferred unevaluated development costs will become subject to
depletion. We capitalized $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
We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Our federal and state income tax returns are generally not prepared or filed before the consolidated financial statements are prepared; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits and net operating loss carryforwards. Adjustments related to these estimates are recorded in our tax provision in the period in which we finalize our income tax returns. Further, we must assess the likelihood that we will be able to recover or utilize our deferred tax assets. If recovery is not likely, we must record a valuation allowance against such deferred tax assets for the amount we would not expect to recover, which would result in an increase to our income tax expense. As ofDecember 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 ofDecember 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 endedDecember 31, 2021 , ($0.5 million ) during the Successor period fromSeptember 19, 2020 throughDecember 31, 2020 , although any change would be offset by a corresponding change in our valuation allowance, and ($18.5 million ) during the Predecessor period fromJanuary 1, 2020 throughSeptember 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
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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 ofDecember 31, 2021 and determined there were no material changes to our key cash flow assumptions and no triggering events sinceSeptember 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 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 ofDecember 31, 2021 would 60 --------------------------------------------------------------------------------
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increase our estimated payments on our crude oil derivative contracts by
Recent Accounting Pronouncements
See Note 1, Nature of Operations and Summary of Significant Accounting Policies, to the consolidated financial statements for a discussion of recent accounting pronouncements.
NON-GAAP FINANCIAL MEASURE AND RECONCILIATION
Reconciliation of Standardized Measure to PV-10 Value
PV-10 Value is a non-GAAP measure and is different from the Standardized Measure in that PV-10 Value is a pre-tax number and the Standardized Measure is an after-tax number. The information used to calculate PV-10 Value is derived directly from data determined in accordance with FASC Topic 932. We believe that PV-10 Value is a useful supplemental disclosure to the Standardized Measure because the Standardized Measure can be impacted by a company's unique tax situation, and it is not practical to calculate the Standardized Measure on a property-by-property basis. Because of this, PV-10 Value is a widely used measure within the industry and is commonly used by securities analysts, banks and credit rating agencies to evaluate the estimated future net cash flows from proved reserves on a comparative basis across companies or specific properties. PV-10 Value is commonly used by us and others in our industry to evaluate properties that are bought and sold, to assess the potential return on investment in our oil and natural gas properties, and to perform our impairment testing of oil and natural gas properties. PV-10 Value is not a measure of financial or operating performance under GAAP, nor should it be considered in isolation or as a substitute for the Standardized Measure. Our PV-10 Value and the Standardized Measure do not purport to represent the fair value of our oil and natural gas reserves. See also Glossary and Selected Abbreviations for the definition of "PV-10 Value" and Supplemental Oil and Natural Gas Disclosures (Unaudited) to the consolidated financial statements for additional disclosures about the Standardized Measure.
The following table provides a reconciliation of the Standardized Measure to PV-10 Value for the periods indicated:
Year Ended December 31,
In thousands 2021 2020 2019
Standardized Measure (GAAP measure)
354,629
PV-10 Value (non-GAAP measure)$ 2,673,822 $ 703,080 $ 2,615,668 FORWARD-LOOKING INFORMATION The data and/or statements contained in this Annual Report on Form 10-K that are not historical facts, including, but not limited to, statements found in the sections entitled "Business 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 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 61 --------------------------------------------------------------------------------
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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.
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Denbury Inc.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The information required by Item 7A is set forth under Market Risk Management in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.
Item 8. Financial Statements and Supplementary Information
Page
Reports of Independent Registered Public Accounting Firm 64
Consolidated Balance Sheets 68
Consolidated Statements of Operations 69
Consolidated Statements of Cash Flows 70
Consolidated Statements of Changes in Stockholders' Equity 71
Notes to Consolidated Financial Statements
1. Nature of Operations and Summary of Significant Accounting Policies 72
2. Fresh Start Accounting 80
3. Acquisition and Divestitures 88
4. Revenue Recognition 89
5. Leases 90
6. Asset Retirement Obligations 93
7. Unevaluated Property 94
8. Long-Term Debt 94
9. Income Taxes 97
10. Stockholders' Equity 99
11. Stock Compensation 99
12. Commodity Derivative Contracts 104
13. Fair Value Measurements 104
14. Commitments and Contingencies 106
15. Additional Balance Sheet Details 107
16. Supplemental Cash Flow Information 107
Supplemental Oil and Natural Gas Disclosures (Unaudited) 108
Supplemental CO 2 Disclosures (Unaudited) 112
63
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets ofDenbury Inc. and its subsidiaries (Successor) (the "Company") as ofDecember 31, 2021 and 2020, and the related consolidated statements of operations, of changes in stockholders' equity and of cash flows for the year endedDecember 31, 2021 and for the period fromSeptember 19, 2020 toDecember 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 ofDecember 31, 2021 , based on criteria established in Internal Control - Integrated Framework (2013) issued by theCommittee of Sponsoring Organizations of theTreadway 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 ofDecember 31, 2021 and 2020, and the results of its operations and its cash flows for the year endedDecember 31, 2021 and for the period fromSeptember 19, 2020 toDecember 31, 2020 in conformity with accounting principles generally accepted inthe United States of America . Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as ofDecember 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, theUnited States Bankruptcy Court for the Southern District of Texas confirmed the Company's prepackaged joint plan of reorganization ("the plan") onSeptember 2, 2020 . Confirmation of the plan resulted in the discharge of all claims against the Company that arose beforeJuly 30, 2020 and terminates all rights and interests of equity security holders as provided for in the plan. The plan was substantially consummated onSeptember 18, 2020 and the Company emerged from bankruptcy. In connection with its emergence from bankruptcy, the Company adopted fresh start accounting as ofSeptember 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 thePublic Company Accounting Oversight Board (United States ) (PCAOB) and are required to be independent with respect to the Company in accordance with theU.S. federal securities laws and the applicable rules and regulations of theSecurities 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
The Company's net property and equipment balance, which includes net proved oil and natural gas properties, was$1,541.5 million as ofDecember 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/
Dallas, Texas February 24, 2022
We have served as the Company's auditor since 2004.
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of
Opinion on the Financial Statements
We have audited the accompanying consolidated statements of operations, of changes in stockholders' equity and of cash flows ofDenbury Resources Inc. and its subsidiaries (Predecessor) (the "Company") for the period fromJanuary 1, 2020 toSeptember 18, 2020 and the year endedDecember 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 fromJanuary 1, 2020 toSeptember 18, 2020 and the year endedDecember 31, 2019 in conformity with accounting principles generally accepted inthe United States of America .
Basis of Accounting
As discussed in Note 1 to the consolidated financial statements, the Company filed petitions onJuly 30, 2020 with theUnited 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 onSeptember 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 thePublic Company Accounting Oversight Board (United States ) (PCAOB) and are required to be independent with respect to the Company in accordance with theU.S. federal securities laws and the applicable rules and regulations of theSecurities 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/
Dallas, Texas March 5, 2021
We have served as the Company's auditor since 2004.
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Denbury Inc.
Consolidated Balance Sheets
(In thousands, except par value and share data)
Successor
December 31, December 31,
2021 2020
Assets
Current assets
Cash and cash equivalents $ 3,671 $ 518
Restricted cash - 1,000
Accrued production receivable 143,365 91,421
Trade and other receivables, net 19,270 19,682
Derivative assets - 187
Prepaids 9,099 14,038
Total current assets 175,405 126,846
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved properties 1,109,011 851,208
Unevaluated properties 112,169 85,304
CO2 properties 183,369 188,288
Pipelines 224,394 133,485
Other property and equipment 93,950 86,610
Less accumulated depletion, depreciation, amortization and impairment
(181,393) (41,095)
Net property and equipment 1,541,500 1,303,800
Operating lease right-of-use assets 19,502 20,342
Intangible assets, net 88,248 97,362
Other assets 78,298 86,408
Total assets $ 1,902,953 $ 1,634,758
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable and accrued liabilities $ 191,598 $ 112,671
Oil and gas production payable 75,899 49,165
Derivative liabilities 134,509 53,865
Current maturities of long-term debt - 68,008
Operating lease liabilities 4,677 1,350
Total current liabilities 406,683 285,059
Long-term liabilities
Long-term debt, net of current portion 35,000 70,000
Asset retirement obligations 284,238 179,338
Derivative liabilities - 5,087
Deferred tax liabilities, net 1,638 1,274
Operating lease liabilities 17,094 19,460
Other liabilities 22,910 20,872
Total long-term liabilities 360,880 296,031
Commitments and contingencies (Note 14)
Stockholders' equity
Preferred stock, $.001 par value, 50,000,000 shares authorized, none
issued and outstanding - -
Common stock,
50 50
Paid-in capital in excess of par 1,129,996 1,104,276
Retained earnings (accumulated deficit) 5,344 (50,658)
Total stockholders' equity 1,135,390 1,053,668
Total liabilities and stockholders' equity $ 1,902,953 $ 1,634,758
See accompanying Notes to Consolidated Financial Statements.
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Denbury Inc.
Consolidated Statements of Operations
(In thousands, except per-share data)
Successor Predecessor
Period from Period from
Sept. 19, 2020 Jan. 1, 2020
Year Ended through through Year Ended
Dec. 31, 2021 Dec. 31, 2020 Sept. 18, 2020 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 44,175 9,419 21,049 34,142
Oil marketing revenues 38,742 5,376 8,543 14,198
Other income 15,288 4,697 8,419 14,523
Total revenues and other income 1,258,160 220,600 530,112 1,274,883
Expenses
Lease operating expenses 424,550 101,234 250,271 477,220 Transportation and marketing expenses 28,817 10,595 27,164 41,810 CO2 operating and discovery expenses 6,678 1,976 2,592 2,922 Taxes other than income 91,390 16,584 43,531 93,752 Oil marketing purchases 37,734 5,318 8,399 14,124 General and administrative expenses 79,258 19,470 48,522 83,029 Interest, net of amounts capitalized of$4,585 ,$1,261 ,$22,885 and$36,671 , respectively 4,147 1,815 48,267 81,632 Depletion, depreciation, and amortization 150,640 45,812 188,593 233,816 Commodity derivatives expense (income) 352,984 61,902 (102,032) 70,078 Gain on debt extinguishment - - (18,994) (155,998) Write-down of oil and natural gas properties 14,377 1,006 996,658 - Reorganization items, net - - 849,980 - Other expenses 10,816 8,072 35,868 11,187 Total expenses 1,201,391 273,784 2,378,819 953,572 Income (loss) before income taxes 56,769 (53,184) (1,848,707) 321,311 Income tax provision (benefit) 767 (2,526) (416,129) 104,352 Net income (loss)$ 56,002 $ (50,658) $ (1,432,578) $ 216,959 Net income (loss) per common share Basic $ 1.10$ (1.01) $ (2.89) $ 0.47 Diluted $ 1.04$ (1.01) $ (2.89) $ 0.45 Weighted average common shares outstanding Basic 50,918 50,000 495,560 459,524 Diluted 53,818 50,000 495,560 510,341
See accompanying Notes to Consolidated Financial Statements.
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Denbury Inc.
Consolidated Statements of Cash Flows
(In thousands)
Successor Predecessor
Period from Period from
Sept. 19, 2020 Jan. 1, 2020
Year Ended through through Year Ended
Dec. 31, 2021 Dec. 31, 2020 Sept. 18, 2020 Dec. 31, 2019
Cash flows from operating activities
Net income (loss) $ 56,002 $ (50,658) $ (1,432,578) $ 216,959
Adjustments to reconcile net income (loss) to
cash flows from operating activities
Noncash reorganization items, net - - 810,909 -
Depletion, depreciation, and amortization 150,640 45,812 188,593 233,816
Write-down of oil and natural gas properties 14,377 1,006 996,658 -
Deferred income taxes 364 (2,556) (408,869) 100,471
Stock-based compensation 25,322 8,212 4,111 12,470
Commodity derivatives expense (income) 352,984 61,902 (102,032) 70,078
Receipt (payment) on settlements of commodity
derivatives (277,240) 21,089 81,396 23,606
Gain on debt extinguishment - - (18,994) (155,998)
Debt issuance costs and discounts 2,740 799 11,571 12,303
Gain from asset sales and other (10,609) (3,546) (6,723) (8,504)
Other, net (2,465) 1,197 7,162 (92)
Changes in assets and liabilities, net of effects
from acquisitions
Accrued production receivable (51,944) 21,411 26,575 (13,619)
Trade and other receivables (284) 15,567 (22,343) 9,379
Other current and long-term assets 10,390 (1,795) 743 7,629
Accounts payable and accrued liabilities 28,500 (67,167) (16,102) (3,275)
Oil and natural gas production payable 29,351 (6,912) (6,792) 2,170
Other liabilities (10,970) (4,035) 123 (13,250)
Net cash provided by operating activities 317,158 40,326 113,408 494,143
Cash flows from investing activities
Oil and natural gas capital expenditures (150,911) (17,964) (99,582) (262,005)
Acquisitions of oil and natural gas properties (10,979) (82) - (79)
Pipeline capital expenditures (69,223) (618) (11,601) (27,319)
Net proceeds from sales of oil and natural gas
properties and equipment 19,053 938 41,322 10,196
Other 9,128 15,842 12,747 9,515
Net cash used in investing activities (202,932) (1,884) (57,114) (269,692)
Cash flows from financing activities
Bank repayments (933,000) (190,000) (551,000) (925,791)
Bank borrowings 898,000 120,000 691,000 925,791
Interest payments treated as a reduction of debt - - (46,417) (85,303)
Cash paid in conjunction with debt exchange - - - (136,427)
Cash paid in conjunction with debt repurchases - - (14,171) -
Costs of debt financing - (8) (12,482) (11,065)
Pipeline financing and capital lease debt
repayments (68,008) (22,938) (51,792) (13,908)
Other (3,122) 1,638 (9,363) 348
Net cash provided by (used in) financing
activities (106,130) (91,308) 5,775 (246,355)
Net increase (decrease) in cash, cash
equivalents, and restricted cash 8,096 (52,866) 62,069 (21,904)
Cash, cash equivalents, and restricted cash at
beginning of period 42,248 95,114 33,045 54,949
Cash, cash equivalents, and restricted cash at
end of period $ 50,344 $ 42,248 $ 95,114 $ 33,045
See accompanying Notes to Consolidated Financial Statements.
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Denbury Inc.
Consolidated Statements of Changes in Stockholders' Equity
(Dollar amounts in thousands)
Paid-In Retained
Common Stock Capital in Earnings Treasury Stock
($.001 Par Value) Excess of (Accumulated (at cost)
Shares Amount Par Deficit) Shares Amount Total Equity
Balance - December 31, 2018
(Predecessor) 462,355,725 $ 462 $ 2,685,211 $ (1,533,112) 1,941,749 $ (10,784) $ 1,141,777
Issued pursuant to stock
compensation plans 9,315,016 9 (9) - - - -
Issued pursuant to directors'
compensation plan 97,537 - - - - - -
Issued pursuant to senior
subordinated notes exchanges 36,297,217 37 37,409 (5,161) (1,990,000) 7,270 39,555
Stock-based compensation - - 16,488 - - - 16,488
Tax withholding for stock
compensation plans - - - - 1,701,022 (2,520) (2,520)
Net income - - - 216,959 - - 216,959
Balance - December 31, 2019
(Predecessor) 508,065,495 508 2,739,099 (1,321,314) 1,652,771 (6,034) 1,412,259
Issued pursuant to stock
compensation plans 312,516 - - - - - -
Issued pursuant to directors'
compensation plan 37,367 - - - - - -
Stock-based compensation - - 14,317 - - - 14,317
Issued pursuant to notes conversion 7,372,250 8 11,493 - - - 11,501
Canceled pursuant to stock
compensation plans (6,313,884) (6) 6 - - - -
Tax withholding for stock
compensation plans - - - - 742,862 (168) (168)
Net loss - - - (1,432,578) - - (1,432,578)
Cancellation of Predecessor equity (509,473,744) (510) (2,764,915) 2,753,892 (2,395,633) 6,202 (5,331)
Issuance of Successor equity 49,999,999 50 1,095,369 - - - 1,095,419
Balance - September 18, 2020
(Predecessor) 49,999,999 $ 50 $ 1,095,369 $ - -
$ -
Balance -September 19, 2020 (Successor) 49,999,999$ 50 $ 1,095,369 $ - - $ -$ 1,095,419 Stock-based compensation - - 8,907 - - - 8,907 Net loss - - - (50,658) - - (50,658) Balance -December 31, 2020 (Successor) 49,999,999 50 1,104,276 (50,658) - - 1,053,668 Stock-based compensation - - 27,205 - - - 27,205 Tax withholding for stock compensation plans - - (2,244) - - - (2,244) Issued pursuant to exercise of warrants 193,657 - 759 - - - 759 Net income - - - 56,002 - - 56,002 Balance -December 31, 2021 (Successor) 50,193,656$ 50 $ 1,129,996 $ 5,344 - $ -$ 1,135,390 See accompanying Notes to Consolidated Financial Statements. 71
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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"), aDelaware corporation, is an independent energy company with operations focused in theGulf Coast andRocky Mountain regions ofthe 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 ofDenbury Resources Inc. (the "Predecessor") upon the Predecessor's emergence from bankruptcy onSeptember 18, 2020 . References to "Successor" relate to the financial position and results of operations of the Company subsequent toSeptember 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 . OnSeptember 18, 2020 ,Denbury filed the Third Restated Certificate of Incorporation with theDelaware Secretary of State to effect a change of the Company's corporate name fromDenbury Resources Inc. toDenbury Inc. , and onSeptember 21, 2020 , the Successor's new common stock commenced trading on theNew York Stock Exchange under the ticker symbol DEN.
Emergence from Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code
OnJuly 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"). OnJuly 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 theUnited States Bankruptcy Court for the Southern District of Texas (the "Bankruptcy Court ") under the caption "In reDenbury Resources Inc. , et al., Case No. 20-33801". OnSeptember 2, 2020 , theBankruptcy Court entered an order (the "Confirmation Order") confirming the Plan and approving the Disclosure Statement, and onSeptember 18, 2020 (the "Emergence Date"), the Plan became effective in accordance with its terms and the Company emerged from Chapter 11. OnApril 23, 2021 , theBankruptcy Court entered a final decree closing the Chapter 11 case captioned "In reDenbury 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, ofDenbury (the "New Common Stock") and 50,000,000 shares of preferred stock, par value$0.001 per share; •Cancelled all outstanding senior secured second lien notes, convertible senior notes, and senior subordinated notes issued by the Predecessor. In accordance with the Plan, claims against and interests in the Predecessor were treated as follows: •Holders of secured pipeline lease claims received payment in full in cash, the collateral securing such pipeline lease claim, reinstatement, or such other treatment rendering such pipeline lease claim unimpaired (see Note 8, Long-Term Debt - Restructuring of Pipeline Financing Transactions, for discussion of subsequent pipeline transactions); •Holders of senior secured second lien notes claims received their pro rata share of 47,499,999 shares representing 95% of the New Common Stock issued on the Emergence Date, subject to dilution on account of warrants and a management incentive plan; •Holders of convertible senior notes claims received their pro rata share of (a) 2,500,000 shares representing 5% of the New Common Stock issued on the Emergence Date, subject to dilution on account of warrants and 72 --------------------------------------------------------------------------------
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Denbury Inc. Notes to Consolidated Financial Statements 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 andJames N. "Jim" Chapman , and three continuing members: Dr.Kevin O. Meyers (Chairman of the Board),Lynn A. Peterson andChris 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 onDecember 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 ofDenbury and entities in which we hold a controlling financial interest. Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis. All intercompany balances and transactions have been eliminated.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires
management to make estimates and assumptions that affect the reported amount of
certain assets and liabilities, disclosure of contingent assets and liabilities
at the date of the financial statements, and the reported amounts of revenues
and expenses during each reporting period. Management believes its estimates and
assumptions are reasonable; however, such estimates and assumptions are subject
to a number of risks and uncertainties that may cause actual results to differ
materially from such estimates. Significant estimates underlying these financial
statements include (1) the fair value of financial derivative instruments; (2)
the estimated quantities of proved oil and
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Denbury Inc. Notes to Consolidated Financial Statements 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 inthe 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:
Successor
In thousands December 31, 2021 December 31, 2020
Cash and cash equivalents $ 3,671 $ 518
Restricted cash, current - 1,000
Restricted cash, long-term 46,673 40,730
Total cash, cash equivalents, and restricted cash shown in the Consolidated Statements of Cash Flows
$ 50,344 $ 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.
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 inthe United States . Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and nonproductive wells, capitalized interest on qualifying projects, and general and administrative expenses directly related to exploration and development activities, and do not include any costs related to production, general corporate overhead or similar activities. We assign the purchase price of oil and natural gas properties we acquire to proved and unevaluated properties based on the estimated fair values as defined in the FASC Fair Value Measurement topic. Proceeds 74 --------------------------------------------------------------------------------
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Denbury Inc. Notes to Consolidated Financial Statements 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 endedDecember 31, 2019 , whereby these costs were transferred to the full cost amortization base. Given the significant declines in NYMEX oil prices in March andApril 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 fromJanuary 1, 2020 throughSeptember 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 ofOil 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 atDecember 31, 2021 ,$35.84 atDecember 31, 2020 ,$40.08 atSeptember 18, 2020 , and$55.55 atDecember 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 theMarch 2021 acquisition ofWyoming 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 fromJanuary 1, 2020 throughSeptember 18, 2020 , and an additional full cost pool ceiling test write-down of$1.0 million was recognized during the Successor period fromSeptember 19, 2020 throughDecember 31, 2020 . We did not record any ceiling test write-downs during the 2019 Predecessor period. Joint Interest Operations. Substantially all of our oil and natural gas exploration and production activities are conducted jointly with others. These financial statements reflect only our proportionate interest in such activities, and any amounts due from other partners are included in trade receivables. 75 --------------------------------------------------------------------------------
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Denbury Inc. Notes to Consolidated Financial Statements 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 theSecurities 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.
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 ofDecember 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.
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 endedDecember 31, 2021 ,$2.7 million during the Successor periodSeptember 19, 2020 throughDecember 31, 2020 , 76 --------------------------------------------------------------------------------
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Denbury Inc.
Notes to Consolidated Financial Statements
$1.7 million for the Predecessor period January 1, 2020 through September 18,
2020 , and $2.4 million during the year ended 2019. The following table
summarizes the carrying value of our intangible assets as of December 31, 2021
and 2020:
Successor
In thousands December 31, 2021 December 31, 2020Long-term contracts to sell CO2 to industrial customers $
97,943 $ 97,943 Other intangibles 2,179 2,167 Accumulated amortization (11,874) (2,748) Net book value $ 88,248 $ 97,362 As ofDecember 31, 2021 , our estimated amortization expense for our intangible assets subject to amortization over the next five years is as follows: In thousands 2022$ 9,120 2023 9,117 2024 9,117 2025 9,117 2026 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 endedDecember 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
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.
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Denbury Inc. Notes to Consolidated Financial Statements
Commodity Derivative Contracts
We utilize oil and natural gas derivative contracts to mitigate our exposure to commodity price risk associated with our future oil and natural gas production. These derivative contracts have historically consisted of options, in the form of price floors, collars, three-way collars, fixed-price swaps, fixed-price swaps enhanced with a sold put, and basis swaps. Our derivative financial instruments, other than any derivative instruments that are designated under the "normal purchase normal sale" exclusion, are recorded on the balance sheet as either an asset or a liability measured at fair value. We do not apply hedge accounting to our commodity derivative contracts; accordingly, changes in the fair value of these instruments are recognized in "Commodity derivatives expense (income)" in our Consolidated Statements of Operations in the period of change.
Concentrations of Credit Risk
Our financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents, trade and accrued production receivables, and the derivative instruments discussed above. Our cash equivalents represent high-quality securities placed with various investment-grade institutions. This investment practice limits our exposure to concentrations of credit risk. Our trade and accrued production receivables are dispersed among various customers and purchasers; therefore, concentrations of credit risk are limited. We evaluate the credit ratings of our purchasers, and if customers are considered a credit risk, letters of credit are the primary security obtained to support lines of credit. We attempt to minimize our credit risk exposure to the counterparties of our oil and natural gas derivative contracts through formal credit policies, monitoring procedures and diversification. All of our derivative contracts are with parties that are lenders under our senior secured bank credit facility (or affiliates of such lenders). There are no margin requirements with the counterparties of our derivative contracts. Oil and natural gas sales are made on a day-to-day basis or under short-term contracts at the current area market price. We would not expect the loss of any purchaser to have a material adverse effect upon our operations. For the year endedDecember 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%) andSunoco Inc. (11%). For the Successor periodSeptember 19, 2020 throughDecember 31, 2020 , three purchasers each accounted for 10% or more of our oil and natural gas revenues:Plains Marketing LP (30%), Marathon Petroleum (13%) andHunt Crude Oil Supply Company (12%), and for the Predecessor periodJanuary 1, 2020 throughSeptember 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 endedDecember 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%) andSunoco 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. 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. 78 --------------------------------------------------------------------------------
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Denbury Inc. Notes to Consolidated Financial Statements
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:
Successor Predecessor
Period from Period from
Sept. 19, 2020 Jan. 1, 2020
Year Ended through through Year Ended
In thousands Dec. 31, 2021 Dec. 31, 2020 Sept. 18, 2020 Dec. 31, 2019
Numerator
Net income (loss) - basic $ 56,002 $ (50,658) $ (1,432,578) $ 216,959
Effect of potentially dilutive securities
Interest on convertible senior notes including
amortization of discount, net of tax - - - 14,134
Net income (loss) - diluted $ 56,002 $ (50,658) $ (1,432,578) $ 231,093
Denominator
Weighted average common shares outstanding -
basic 50,918 50,000 495,560 459,524
Effect of potentially dilutive securities
Restricted stock units 762 - - -
Warrants 2,138 - - -
Restricted stock and performance-based equity
awards - - - 2,396
Convertible senior notes(1) - - - 48,421
Weighted average common shares outstanding -
diluted 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.
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
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Denbury Inc.
Notes to Consolidated Financial Statements
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:
Successor Predecessor
In thousands December 31, 2021 December 31, 2020 December 31, 2019
Restricted stock units - 1,220 -
Warrants - 5,526 -
Stock appreciation rights - - 1,981
Restricted stock and performance-based equity
awards - - 4,445
For the period September 19, 2020 through December 31, 2020 , the Company's
restricted stock units and series A and series B warrants were antidilutive
based on the Company's net loss position for the periods. At December 31, 2021 ,
the Company had approximately 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. InDecember 2019 , theFinancial 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. EffectiveJanuary 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.
Note 2. Fresh Start Accounting
Fresh Start Accounting
Upon emergence from bankruptcy, we met the criteria and were required to adopt
fresh start accounting in accordance with FASC Topic 852, Reorganizations, which
on the Emergence Date resulted in a new entity, the Successor, for financial
reporting purposes, with no beginning retained earnings or deficit as of the
fresh start reporting date. The criteria requiring fresh start accounting are:
(1) the holders of the then-existing common shares of the Predecessor received
less than 50 percent of the new common shares of the Successor outstanding upon
emergence from bankruptcy and (2) the reorganization value of the Company's
assets immediately prior to confirmation of the Plan was less than the total of
all post-petition liabilities and allowed claims.
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Denbury Inc. Notes to Consolidated Financial Statements Fresh start accounting requires that new fair values be established for the Company's assets, liabilities and equity as of the date of emergence from bankruptcy,September 18, 2020 , and therefore certain values and operational results of the consolidated financial statements subsequent toSeptember 18, 2020 are not comparable to those in the Company's consolidated financial statements prior to, and includingSeptember 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 theBankruptcy Court , the valuation analysis resulted in an enterprise value between$1.1 billion and$1.5 billion , with a midpoint of$1.3 billion . ForU.S. GAAP purposes, we valued the Successor's individual assets, liabilities, and equity instruments and determined the value of the enterprise was approximately$1.3 billion as of the Emergence Date, which fell in line with the midpoint of the forecast enterprise value ranges approved by theBankruptcy Court . Specific valuation approaches and key assumptions used to arrive at reorganization value, and the value of discrete assets and liabilities resulting from the application of fresh start accounting, are described below in greater detail within the valuation process. The following table reconciles the enterprise value to the equity value of the Successor as of the Emergence Date: In thousands Sept. 18, 2020 Enterprise value$ 1,280,856 Plus: Cash and cash equivalents 45,585 Less: Total debt (231,022) Equity value$ 1,095,419 The following table reconciles enterprise value to reorganization value of the Successor (i.e., value of the reconstituted entity) and total reorganization value: In thousands Sept. 18, 2020 Enterprise value$ 1,280,856 Plus: Cash and cash equivalents 45,585
Plus: Current liabilities excluding current maturities of long-term debt
239,738
Plus: Non-interest-bearing noncurrent liabilities 185,228
Reorganization value of the reconstituted Successor $ 1,751,407
With the assistance of third-party valuation advisors, we determined the
enterprise and corresponding equity value of the Successor using various
valuation approaches and methods, including: (i) income approach using a
calculation of the present value of future cash flows based on our financial
projections, (ii) the market approach using selling prices of similar assets and
(iii) the cost approach.
The enterprise value and corresponding equity value are dependent upon achieving
the future financial results set forth in our valuation using an asset-based
methodology of estimated proved reserves, undeveloped properties, and other
financial information, considerations and projections, applying a combination of
the income, cost and market approaches as of the fresh start reporting date of
September 18, 2020 . All estimates, assumptions, valuations and financial
projections, including the fair value adjustments, the financial projections,
the enterprise value and equity value projections, are inherently subject to
significant uncertainties and the resolution of contingencies beyond our
control. Accordingly, there is no assurance that the estimates, assumptions,
valuations or financial projections will be realized, and actual results could
vary materially.
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Denbury Inc. Notes to Consolidated Financial Statements
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$22.0 million from the Petition Date through the Emergence Date associated with our outstanding senior secured second lien notes, convertible senior notes, and senior subordinated notes was not accrued or recorded in the consolidated statement of operations as interest expense. The following table summarizes the losses (gains) on reorganization items, net: Predecessor Period fromJan. 1, 2020 through In thousandsSept. 18, 2020 Gain on settlement of liabilities subject to compromise$ (1,024,864) Fresh start accounting adjustments 1,834,423 Professional service provider fees and other expenses 11,267 Success fees for professional service providers 9,700 Loss on rejected contracts and leases 10,989
Valuation adjustments to debt classified as subject to compromise
757
Debtor-in-possession credit agreement fees 3,107
Acceleration of Predecessor stock compensation expense 4,601
Total reorganization items, net $ 849,980
Valuation Process
The fair values of our principal assets, including oil and natural gas
properties, CO2 properties, pipelines, other property and equipment, long-term
contracts to sell CO2 to industrial customers, favorable and unfavorable vendor
contracts, pipeline financing liabilities and right-of-use assets, asset
retirement obligations and warrants were estimated as of the Emergence Date.
The Company's principal assets are its oil and natural gas properties, which are accounted for under the full cost accounting method as described in Note 1, Nature of Operations and Summary of Significant Accounting Policies -Oil and Natural Gas Properties . The Company determined the fair value of its oil and gas properties based on the discounted cash flows expected to be generated from these assets. The computations were based on market conditions and reserves in place as of the Emergence Date. The fair value analysis was based on the Company's estimated future production rates of proved and probable reserves as prepared by the Company's independent petroleum engineers. Discounted cash flow models were prepared using the estimated future revenues and operating costs for all developed wells and undeveloped properties comprising the proved and probable reserves. Future revenues were based upon future production rates and forward strip oil and natural gas prices as of the Emergence Date through 2024 and escalated for inflation thereafter, adjusted for differentials. Operating costs were adjusted for inflation beginning in year 2025. A risk adjustment factor was applied to each reserve category, consistent with the risk of the category. The discounted cash flow models also included adjustments for income tax expenses. Discount factors utilized were derived using a weighted average cost of capital computation, which included an estimated cost of debt and equity for market participants with similar geographies and asset development type and varying corporate income tax rates based on the expected point of sale for each property's produced assets. Reserve values were also adjusted for any asset retirement obligations as well as for CO2 indirect costs not directly allocable to oil fields. Based on this analysis, the 82 --------------------------------------------------------------------------------
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Denbury Inc. Notes to Consolidated Financial Statements
Company concluded the fair value of its proved and probable reserves was
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, sinceDenbury 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.
Favorable and Unfavorable Vendor Contracts
We recognized both favorable and unfavorable contracts using the incremental
value method under the income approach. The incremental value method calculates
value on the basis of the pricing differential between historical contracted
rates and estimated pricing that the Company would most likely receive if it
entered into similar contract conditions (other than the price) as of the
Emergence Date. The differential is applied to expected contract volumes,
tax-affected and discounted at a discount rate consistent with the risk of the
associated cash flows.
Asset Retirement Obligations
The fair value of the asset retirement obligations was revalued based upon
estimated current reclamation costs for our assets with reclamation obligations,
an appropriate long-term inflation adjustment, and our revised credit adjusted
risk-free rate ("CARFR"). The new CARFR was based on an evaluation of similar
industry peers with similar factors such as emergence, new capital structure and
current rates for oil and gas companies.
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Denbury Inc. Notes to Consolidated Financial Statements
Pipeline Financing Liabilities
The fair value of the pipeline financing liabilities was measured as the present value of the remaining payments under the restructured pipeline agreements (see Note 8, Long-Term Debt - Restructuring of Pipeline Financing Transactions, for further discussion). Warrants The fair values of the warrants issued upon the Emergence Date were estimated by applying a Black-Scholes 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.
Condensed Consolidated Balance Sheet
The following illustrates the effects on the Company's consolidated balance sheet due to the reorganization and fresh start accounting adjustments. The explanatory notes following the table below provide further details on the adjustments, including the assumptions and methods used to determine fair value for its assets, liabilities, and warrants.
As of September 18, 2020
Reorganization Fresh Start
In thousands Predecessor Adjustments Adjustments Successor
Assets
Current assets
Cash and cash equivalents $ 73,372 $ (27,787) (1) $ - $ 45,585
Restricted cash - 10,662 (2) - 10,662
Accrued production receivable 112,832 - - 112,832
Trade and other receivables, net 36,221 - - 36,221
Derivative assets 32,635 - - 32,635
Other current assets 12,968 (539) (3) - 12,429
Total current assets 268,028 (17,664) - 250,364
Property and equipment
Oil and natural gas properties (using
full cost accounting)
Proved properties 11,723,546 - (10,941,313) 782,233
Unevaluated properties 650,553 - (538,570) 111,983
CO2 properties 1,198,515 - (1,011,169) 187,346
Pipelines 2,339,864 - (2,207,246) 132,618
Other property and equipment 201,565 - (104,152) 97,413
Less accumulated depletion,
depreciation, amortization and
impairment (12,864,141) - 12,864,141 -
Net property and equipment 3,249,902 - (1,938,309) (10) 1,311,593
Operating lease right-of-use assets 1,774 - 69 (10) 1,843
Derivative assets 501 - - 501
Intangible assets, net 20,405 - 79,678 (11) 100,083
Other assets 81,809 8,241 (4) (3,027) (12) 87,023
Total assets $ 3,622,419 $ (9,423)$ (1,861,589) $ 1,751,407 84
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Denbury Inc. Notes to Consolidated Financial Statements
As of September 18, 2020
Reorganization Fresh Start
In thousands Predecessor Adjustments Adjustments Successor
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable and accrued
liabilities $ 67,789 $
102,793 (5)
39,372 16,705 (6) - 56,077
Derivative liabilities 8,613 - - 8,613
Current maturities of long-term debt - 73,199 (6) 364 (14) 73,563
Operating lease liabilities - 757 (6) (29) (10) 728
Total current liabilities 115,774 193,454 4,073 313,301
Long-term liabilities
Long-term debt, net of current
portion 140,000 42,610 (6) (25,151) (14) 157,459
Asset retirement obligations 2,727 180,408 (6) (24,697) (10) 158,438
Derivative liabilities 295 - - 295
Deferred tax liabilities, net - 417,951 (6)(15) (414,120) (15) 3,831 Operating lease liabilities
- 515 (6) 10 (10) 525
Other liabilities - 3,540 (6) 18,599 (16) 22,139
Total long-term liabilities not
subject to compromise 143,022 645,024 (445,359) 342,687
Liabilities subject to compromise 2,823,506 (2,823,506) (6) - -
Commitments and contingencies (Note
14)
Stockholders' equity
Predecessor preferred stock - - - -
Predecessor common stock 510 (510) (7) - -
Predecessor paid-in capital in excess
of par 2,764,915 (2,764,915) (7) - -
Predecessor treasury stock, at cost (6,202) 6,202 (7) - -
Successor preferred stock - - - -
Successor common stock - 50 (8) - 50
Successor paid-in capital in excess
of par - 1,095,369 (8) - 1,095,369
Accumulated deficit (2,219,106) 3,639,409 (9) (1,420,303) (17) -
Total stockholders' equity 540,117 1,975,605 (1,420,303) 1,095,419
Total liabilities and stockholders'
equity $ 3,622,419 $ (9,423) $ (1,861,589) $ 1,751,407 Reorganization Adjustments
(1)Represents the net cash payments that occurred on the Emergence Date as follows: In thousands Sources: Cash proceeds from Successor Bank Credit Agreement$ 140,000 Total cash proceeds 140,000 Uses:
Payment in full of DIP Facility and pre-petition revolving bank credit facility
(140,000)
Retained professional service provider fees paid to escrow account
(10,662)
Non-retained professional service provider fees paid
(7,420)
Accrued interest and fees on DIP Facility
(1,464)
Debt issuance costs related to Successor Bank Credit Agreement (8,241) Total cash uses (167,787) Net uses$ (27,787) 85
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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
$ 2,826 Payment of accrued interest and fees on DIP Facility (1,464)
Reinstatement of accounts payable and accrued liabilities from liabilities subject to compromise
101,431
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$ 1,629,457 Convertible senior notes 234,015 Senior subordinated notes 251,480 Total settled liabilities subject to compromise
2,114,952
Reinstated liabilities subject to compromise Current maturities of long-term debt
73,199
Accounts payable and accrued liabilities
101,431
Oil and gas production payable
16,705
Operating lease liabilities, current
757
Long-term debt, net of current portion
42,610
Asset retirement obligations
180,408
Deferred tax liabilities
289,389
Operating lease liabilities, long-term
515
Other long-term liabilities
3,540
Total reinstated liabilities subject to compromise
708,554
Total liabilities subject to compromise
2,823,506
Issuance of New Common Stock to second lien note holders
(1,014,608)
Issuance of New Common Stock to convertible note holders
(53,400)
Issuance of series A warrants to convertible note holders
(15,683)
Issuance of series B warrants to senior subordinated note holders (6,398) Reinstatement of liabilities subject to compromise
(708,553)
Gain on settlement of liabilities subject to compromise $
1,024,864
(7)Represents the cancellation of the Predecessor's common stock, treasury
stock, and related components of the Predecessor's paid-in capital in excess of
par. Paid-in capital in excess of par includes
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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
53,400
Fair value of series A warrants issued to convertible senior note holders
15,683
Fair value of series B warrants issued to senior subordinated note holders
6,398
Fair value of series B warrants issued to Predecessor equity holders
5,330
Total change in Successor common stock and additional paid-in capital
1,095,419
Less: Par value of Successor common stock (50) Change in Successor additional paid-in capital
$ 1,095,369
(9)Reflects the cumulative net impact of the effects on accumulated deficit as follows: In thousands Cancellation of Predecessor common stock, paid-in capital in excess of par, and treasury stock $ 2,763,824 Gain on settlement of liabilities subject to compromise
1,024,864
Acceleration of Predecessor stock compensation expense (4,601)
Recognition of tax expenses related to reorganization adjustments
(128,556)
Professional service provider fees recognized at emergence (9,700) Issuance of series B warrants to Predecessor equity holders (5,330) Other (1,092) Net impact to Predecessor accumulated deficit $ 3,639,409 Fresh Start Adjustments (10)Reflects fair value adjustments to our (i) oil and natural gas properties, CO2 properties, pipelines, and other property and equipment, as well as the elimination of accumulated depletion, depreciation, and amortization, (ii) operating lease right-of-use assets and liabilities, and (iii) asset retirement obligations.
(11)Reflects fair value adjustments to our long-term contracts to sell CO2 to industrial customers.
(12)Reflects fair value adjustments to our other assets as follows: In thousands Fair value adjustment for CO2 and oil pipeline line-fill $ (3,698) Fair value adjustments for escrow accounts
671
Fair value adjustments to other assets $ (3,027)
(13)Reflects fair value adjustments to accounts payable and accrued liabilities
as follows:
In thousands
Fair value adjustment for the current portion of an unfavorable vendor
contract $ 3,500 Fair value adjustment for the current portion of Predecessor asset retirement obligation
689
Write-off accrued interest on NEJD pipeline financing (451)
Fair value adjustments to accounts payable and accrued liabilities
$ 3,738
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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 $
(24,699)
Fair value adjustment for NEJD pipeline lease financing
(88)
Fair value adjustments to current and long-term maturities of debt $ (24,787)
Our pipeline lease financings were restructured in late October 2020 (see Note 8, Long-Term Debt - Restructuring of Pipeline Financing Transactions).
(15)Represents (i) adjustment to deferred taxes, including the recognition of tax expenses related to reorganization adjustments as a result of the cancellation of debt and retaining tax attributes for the Successor and the reinstatement of deferred tax liabilities subject to compromise totaling $128.6 million and (ii) adjustments to deferred tax liabilities related to fresh start accounting of $414.1 million.
(16)Represents a fair value adjustment for the long-term portion of an unfavorable vendor contract.
(17)Represents the cumulative effect of the fresh start accounting adjustments discussed above.
Note 3. Acquisition and Divestitures
Acquisition of
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 inWyoming from a subsidiary of Devon Energy Corporation, including surface facilities and a 46-mile CO2 transportation pipeline to the acquired fields. The acquisition purchase price was $10.9 million cash (after final closing adjustments) plus two contingent $4 million cash payments if NYMEX WTI oil prices average at least $50 per Bbl during each of 2021 and 2022. We made the first contingent payment in January 2022 and if the price condition is met, the second $4 million payment will be due in January 2023. The fair value of the contingent consideration on the acquisition date was $5.3 million, and as of December 31, 2021, the fair value of the contingent consideration recorded on our Consolidated Balance Sheets was $7.7 million. The $2.4 million increase at December 31, 2021 from the March 2021 acquisition date fair value was the result of higher NYMEX WTI oil prices and was recorded to "Other expenses" in our Consolidated Statements of Operations. The fair values allocated to our assets acquired and liabilities assumed for the acquisition were based on significant inputs not observable in the market and considered level 3 inputs. The fair value of the assets acquired and liabilities assumed was finalized during the third quarter of 2021, after consideration of final closing adjustments and evaluation of reserves and 88 --------------------------------------------------------------------------------
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Denbury Inc. Notes to Consolidated Financial Statements
liabilities assumed. The following table presents a summary of the fair value of assets acquired and liabilities assumed in the acquisition:
In thousands Consideration: Cash consideration $ 10,906
Less: Fair value of assets acquired and liabilities assumed: Proved oil and natural gas properties
60,101 Other property and equipment 1,685 Asset retirement obligations (39,794) Contingent consideration (5,320) Other liabilities (5,766) Fair value of net assets acquired $ 10,906 Divestitures
Hartzog Draw Deep Mineral Rights
On June 30, 2021, we closed the sale of undeveloped, unconventional deep mineral rights in Hartzog Draw Field inWyoming . 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
Gulf Coast Working Interests Sale
On March 4, 2020, the Predecessor sold half of its working interest positions in four southeastTexas oil fields for $40 million net cash and a carried interest in ten wells to be drilled by the purchaser. The Predecessor did not record a gain or loss on the sale of the properties in accordance with the full cost method of accounting.
Note 4. Revenue Recognition
We record revenue in accordance with FASC Topic 606, Revenue from Contracts with
Customers. The core principle of FASC Topic 606 is that an entity should
recognize revenue for the transfer of goods or services equal to the amount of
consideration that it expects to be entitled to receive for those goods or
services. This principle is achieved through applying a five-step process for
customer contract revenue recognition:
•Identify the contract or contracts with a customer - We derive the majority of
our revenues from oil and natural gas sales contracts and CO2 sales and
transportation contracts. The contracts specify each party's rights regarding
the goods or services to be transferred and contain commercial substance as they
impact our financial statements. A high percentage of our receivables balance is
current, and we have not historically entered into contracts with counterparties
that pose a credit risk without requiring adequate economic protection to ensure
collection.
•Identify the performance obligations in the contract - Each of our revenue
contracts specify a volume per day, or production from a lease designated in the
contract (a distinct good), to be delivered at the delivery point over the term
of the
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Denbury Inc. Notes to Consolidated Financial Statements contract (the identified performance obligation). The customer takes delivery and physical possession of the product at the delivery point, which generally is also the point at which title transfers and the customer obtains 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:
Successor Predecessor
Period from Period from
Sept. 19, 2020 Jan. 1, 2020
Year Ended through through Year Ended
In thousands Dec. 31, 2021 Dec. 31, 2020 Sept. 18, 2020 Dec. 31, 2019
Oil sales $ 1,148,022 $ 199,769 $ 489,251 $ 1,205,083
Natural gas sales 11,933 1,339 2,850 6,937
CO2 sales and transportation fees 44,175 9,419 21,049 34,142
Oil marketing revenues 38,742 5,376 8,543 14,198
Total revenues $ 1,242,872 $ 215,903 $ 521,693 $ 1,260,360
Note 5. Leases
We evaluate contracts for leasing arrangements at inception. We lease office
space, equipment, and vehicles that have non-cancelable lease terms. Currently,
our outstanding leases have remaining terms up to 14 years, with certain land
leases having
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Denbury Inc.
Notes to Consolidated Financial Statements
remaining terms up to 48 years. Leases with a term of 12 months or less are not
recorded on our balance sheet. The table below reflects our operating lease
right-of-use assets and operating lease liabilities, which primarily consist of
our office leases:
Successor
In thousands December 31, 2021 December 31, 2020
Operating leases
Operating lease right-of-use assets $ 19,502 $ 20,342
Operating lease liabilities - current $ 4,677 $
1,350
Operating lease liabilities - long-term 17,094
19,460
Total operating lease liabilities $ 21,771 $
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:
Successor
December 31, 2021 December 31, 2020
Weighted average remaining lease term 5.2 years 6.3 years
Weighted average discount rate 5.4 % 5.6 %
We account for lease and nonlease components in a contract as a single lease
component for all asset classes. Lease costs for operating leases or leases with
a term of 12 months or less are recognized on a straight-line basis over the
lease term. For finance leases, interest on the lease liability and the
amortization of the right-of-use asset are recognized separately, with the
depreciable life reflective of the expected lease term. Variable lease costs
represent additional payments in excess of our minimum base rental payments
under our office space leases. The Predecessor Company previously subleased part
of the office space included in its operating leases for which it received
rental payments. Since those office space leases were terminated during the
Chapter 11 Restructuring, the underlying sublease agreements were also
terminated. The Successor
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Denbury Inc. Notes to Consolidated Financial Statements
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:
Successor Predecessor
Period from Period from
Sept. 19, 2020 Jan. 1, 2020
Year Ended through through Year Ended
In thousands Income Statement Dec. 31, 2021 Dec. 31, 2020 Sept. 18, 2020 Dec. 31, 2019
General and administrative
Operating lease cost expenses $ 4,102 $ 872 $ 5,683 $ 8,924
Lease operating expenses 655 158 214 58
CO2 operating and discovery
expenses 50 14 37 5
$ 4,807 $ 1,044 $ 5,934 $ 8,987
Finance lease cost
Amortization of Depletion, depreciation,
right-of-use assets and amortization $ - $ 3 $ 9 $ 1,188
Interest on lease
liabilities Interest expense - 1 3 40
Total finance lease
cost $ - $ 4 $ 12 $ 1,228
Variable lease cost $ 670 $ 258 $ 3,688 $ 4,852
General and administrative
Sublease income expenses $ - $ 100 $ 2,584 $ 4,127
Our statement of cash flows included the following activity related to our operating and finance leases:
Successor Predecessor
Period from
Period from Sept. Jan. 1, 2020
Year Ended 19, 2020 through through Year Ended
In thousands Dec. 31, 2021 Dec. 31, 2020 Sept. 18, 2020 Dec. 31, 2019
Cash paid for amounts included in the
measurement of lease liabilities
Operating cash flows from operating
leases $ 2,830 $ 341 $ 7,341 $ 10,995
Operating cash flows from interest on
finance leases - 1 3 40
Financing cash flows from finance
leases - 78 10 1,275
Right-of-use assets obtained in
exchange for lease obligations
Operating leases 2,683 19,902 1,049 415
Finance leases - - 162 -
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Denbury Inc.
Notes to Consolidated Financial Statements
The following table summarizes by year the maturities of our lease liabilities
as of December 31, 2021:
Operating
In thousands Leases
2022 $ 5,705
2023 4,712
2024 4,138
2025 4,177
2026 4,203
Thereafter 2,326
Total minimum lease payments 25,261
Less: Amount representing interest (3,490)
Present value of minimum lease liabilities $ 21,771
Note 6. Asset Retirement Obligations
The following table summarizes the changes in our asset retirement obligations:
Successor Predecessor
Period from
Sept. 19, 2020 Period from Jan. 1,
Year Ended through 2020 through
In thousands Dec. 31, 2021 Dec. 31, 2020 Sept. 18, 2020
Beginning asset retirement obligations $ 186,281 $ 163,368 $ 181,760
Liabilities incurred and assumed during period 43,701 738 736
Revisions in estimated retirement obligations 69,059 22,660 3,592
Liabilities settled and sold during period (10,783) (3,439) (10,041)
Accretion expense 14,353 2,954 11,329
Fresh start accounting adjustment - - (24,008)
Ending asset retirement obligations 302,611 186,281 163,368
Less: current asset retirement obligations(1) (18,373) (6,943) (4,930)
Long-term asset retirement obligations $ 284,238 $ 179,338 $ 158,438
(1)Included in "Accounts payable and accrued liabilities" in our Consolidated Balance Sheets.
Liabilities assumed relate to our March 2021 acquisition ofWyoming 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 inU.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. 93 --------------------------------------------------------------------------------
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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:
Fresh Start
Adjustments (Sept.
In thousands 2021 Successor 2020 18, 2020)(1) Total
Property acquisition costs $ - $ - $ 68,103 $ 68,103
Exploration and development 39,481 46 - 39,527
Capitalized interest 3,576 963 - 4,539
Total $ 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 emergence from bankruptcy (see Note
2, Fresh Start Accounting, for additional information) that remain in
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:
Successor
In thousands December 31, 2021 December 31, 2020
Senior Secured Bank Credit Agreement $ 35,000 $ 70,000
Pipeline financings - 68,008
Total debt principal balance 35,000 138,008
Less: current maturities of long-term debt - (68,008)
Long-term debt $ 35,000 $ 70,000
The ultimate parent company in our corporate structure, Denbury Inc. , is the
sole issuer of all our outstanding obligations under our Successor Bank Credit
Agreement. Denbury Inc. has no independent assets or operations. Each of the
subsidiary guarantors of such obligations is 100% owned, directly or indirectly,
by Denbury Inc , and the guarantees of such obligations are full and
unconditional and joint and several.
Prior to our emergence from bankruptcy, our debt consisted of the Predecessor's
Bank Credit Agreement, senior secured second lien notes, convertible senior
notes, senior subordinated notes, pipeline financings, and capital lease
obligations. On the Emergence Date, pursuant to the terms of the Plan, all
outstanding obligations under the senior secured second lien notes, convertible
senior notes, and senior subordinated notes were fully extinguished, relieving
approximately $2.1 billion of debt by issuing equity and/or warrants in the
Successor to the holders of that debt. See Note 1, Nature of Operations and
Summary of Significant Accounting Policies - Emergence from Voluntary
Reorganization Under Chapter 11 of the Bankruptcy Code, for additional
information.
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Denbury Inc. Notes to Consolidated Financial Statements
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 withJPMorgan Chase Bank, N.A ., as administrative agent, and other lenders party thereto. The SuccessorBank 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 SuccessorBank 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 ofDenbury 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 SuccessorBank Credit Agreement, Consolidated Current Assets exclude the current portion of derivative assets but include available borrowing capacity under the SuccessorBank 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.
The above description of our Successor Bank Credit Agreement and defined terms are contained in the Successor Bank Credit Agreement.
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Denbury Inc. Notes to Consolidated Financial Statements
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 withJPMorgan Chase Bank, N.A ., as administrative agent, and other lenders party thereto (the "Predecessor Bank Credit Agreement"). All but a minor portion of the PredecessorBank Credit Agreement was refinanced through the DIP Facility from August 4, 2020 through September 18, 2020, which was in turn refinanced by the SuccessorBank 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, 6?% Convertible Senior Notes due 2024 (the "2024 Convertible Notes"), 6?% Senior Subordinated Notes due 2021, 5½% Senior Subordinated Notes due 2022, and 4?% 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.
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
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Denbury Inc. Notes to Consolidated Financial Statements 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 35,000 2025 - 2026 - Thereafter - Total indebtedness $ 35,000 Note 9. Income Taxes
Our income tax provision (benefit) is as follows:
Successor Predecessor
Period from
Sept. 19, 2020 Period from Jan.
Year Ended through 1, 2020 through Year Ended
In thousands Dec. 31, 2021 Dec. 31, 2020 Sept. 18, 2020 Dec. 31, 2019
Current income tax expense (benefit)
Federal $ - $ - $ (6,407) $ 2,645
State 403 30 (853) 1,236
Total current income tax expense
(benefit) 403 30 (7,260) 3,881
Deferred income tax expense (benefit)
Federal - - (319,011) 89,950
State 364 (2,556) (89,858) 10,521
Total deferred income tax expense
(benefit) 364 (2,556) (408,869) 100,471
Total income tax expense (benefit) $ 767 $ (2,526) $ (416,129) $ 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.
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
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Denbury Inc.
Notes to Consolidated Financial Statements
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:
Successor Predecessor
Period from Period from
Sept. 19, 2020 Jan. 1, 2020
Year Ended through through Year Ended
In thousands Dec. 31, 2021 Dec. 31, 2020 Sept. 18, 2020 Dec. 31, 2019
Beginning balance $ 129,408 $ 129,840 $ 77,215 $ 51,093
Charges 29,345 2,269 77,138 26,122
Deductions (33,291) (2,701) (24,513) -
Ending balance $ 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:
Successor
In thousands December 31, 2021 December 31, 2020
Deferred tax assets
Loss and tax credit carryforwards - state $ 54,943 $ 55,979
Derivative contracts 30,892
13,090
Accrued liabilities and other reserves 19,567
15,632
Business credit carryforwards 18,066 - Loss carryforwards - federal 10,310 - Lease liabilities 4,523 6,354 Property and equipment 2,613 59,207 Other 4,206 4,092 Valuation allowances (125,462) (129,408) Total deferred tax assets 19,658 24,946 Deferred tax liabilities CO2 and other contracts (17,208) (20,030) Operating lease right-of-use assets (4,088)
(6,190)
Total deferred tax liabilities (21,296)
(26,220)
Total net deferred tax liability $ (1,638) $ (1,274)
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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:
Successor Predecessor
Period from
Sept. 19, 2020 Period from Jan.
Year Ended through 1, 2020 through Year Ended
In thousands Dec. 31, 2021 Dec. 31, 2020 Sept. 18, 2020 Dec. 31, 2019
Income tax provision calculated using the
federal statutory income tax rate $ 11,921 $ (11,169) $ (388,228) $ 67,475
State income taxes, net of federal income tax
benefit 450 (2,532) (86,937) 7,435
Tax shortfall (windfall) on stock-based
compensation deduction (267) - (1,502) 1,912
Nondeductible compensation 5,057 - - -
Change in valuation allowance (2,928) 9,653 19,344 26,122
Enhanced oil recovery credits generated (14,272) - - -
Tax attributes reduction - net of CODI
exclusion - - 31,667 -
Other 806 1,522 9,527 1,408
Total income tax expense (benefit) $ 767 $ (2,526) $ (416,129) $ 104,352
We file consolidated and separate income tax returns in the U.S. federal
jurisdiction and in many state jurisdictions. The statutes of limitation for our
income tax returns for tax years ending prior to 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.
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 theSEC 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 toIRS 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).
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