PLANO, Texas, May 06, 2021 (GLOBE NEWSWIRE) — Denbury Inc. (NYSE: DEN) (“Denbury” or the “Company”) today provided results for the first quarter of 2021, including the following key outcomes:


  • Net cash provided by operating activities was $53 million; Adjusted cash flow from operations(1) (non-GAAP measure) was $81 million.
  • Development capital expenditures totaled $20 million; Free cash flow(1) (non-GAAP measure) was $59 million.
  • Net loss totaled $70 million, or $1.38 per diluted share. Adjusted net income(1) (non-GAAP measure) was $22 million, or $0.44 per diluted share(1) (non-GAAP measure) and Adjusted EBITDAX(1) (non-GAAP measure) totaled $82 million.
  • Total production averaged 47,357 BOE/d, consistent with expectations. Severe winter weather reduced volumes for the quarter by approximately 1,400 BOE/d.
  • Approved the initial phase of the CO2 enhanced oil recovery (EOR) development at Cedar Creek Anticline (CCA), including the Greencore CO2 pipeline extension from Bell Creek to CCA.
  • Successfully closed the acquisition of the Big Sand Draw and Beaver Creek EOR fields in the Wind River Basin in early March 2021.
  • Announced Nikulas Wood as Senior Vice President to lead the Denbury Carbon Solutions team, focused on expanding the Company’s leading Carbon Capture, Use and Storage (CCUS) position to drive future value.
  • Added Cindy Yeilding to the Denbury Board of Directors. Yeilding chaired the coordinating subcommittee of the 2019 National Petroleum Council study on CCUS.


Chris Kendall, the Company’s President and CEO, commented, “I am pleased with our first quarter performance, and we are off to a great start to the year. Although severe winter weather temporarily impacted operations, Denbury’s low-decline and low capital-intensity asset base nonetheless delivered meaningful free cash flow in the first quarter. Looking forward to the rest of the year, we are preparing to kick off construction on our CCA CO2 pipeline in the coming weeks. The CCA EOR development, which will produce low carbon-intensity blue oil through utilization of industrial-sourced CO2, provides the Company with a deep inventory of resource development opportunities and decades of free cash flow.

The Denbury Carbon Solutions team continues to progress multiple agreements that we expect will advance significant growth in Denbury’s transport and storage of captured industrial-sourced CO2. Denbury’s proven track record of partnership with industrial emitters in providing practical, reliable, and secure CO2 transportation and storage solutions is unmatched in the industry. Considering the Company’s ideally positioned infrastructure and extensive CO2 experience, CCUS represents an incredible value creation opportunity for our Company.”


Total revenues and other income in the first quarter of 2021 were $251 million, an increase of 27% from the fourth quarter 2020 and 4% from the prior-year first quarter. The quarterly increases were primarily a result of higher realized pre-hedge oil prices, despite lower production due to severe winter weather in the first quarter 2021, natural field decline, and Denbury’s significant reduction in capital spending in 2020 related to the COVID-19 impact on global oil demand.

Denbury’s oil and natural gas production averaged 47,357 BOE/d during first quarter 2021, consistent with expectations, considering the impact of severe winter weather (lowered first quarter 2021 volumes approximately 1,400 BOE/d), as well as the March 2021 acquisition of assets in the Wind River Basin (added 870 BOE/d for the first quarter 2021). Over 97 percent of the Company’s first quarter 2021 production was oil, with two-thirds of total volumes coming from tertiary CO2 fields. Blue oil production, resulting from captured industrial-sourced CO2 injection, increased to approximately 25% of total oil volumes as of the end of the first quarter.

Denbury’s first quarter 2021 average pre-hedge realized oil price was $56.28 per barrel (“Bbl”), representing a differential of $1.54 per Bbl below NYMEX WTI oil prices. The first quarter 2021 differential was on the favorable end of the Company’s expectation of between $1.50 to $2.00 per Bbl discount to WTI.

Lease operating expenses (“LOE”) in first quarter 2021 totaled $82 million, or $19.23 per BOE. LOE was lower than anticipated in the first quarter primarily due to a favorable adjustment to power costs associated with winter storm Uri, which caused significant power outages and disrupted the Company’s operations. Under certain of Denbury’s power agreements, the Company is provided compensation for reduced power usage, which resulted in a benefit of $15 million for the quarter. The net impact to Denbury from lost production and revenues due to the storm, incremental costs incurred for recovery, and the reduced power usage benefit was estimated to be a positive $6 million for the first quarter 2021.

General and administrative (“G&A”) expenses were $32 million in first quarter 2021, in line with expectations. G&A included $18 million of non-cash expense for stock-based compensation, of which $15 million is non-recurring as the performance measures underlying those awards were achieved in the first quarter.

Commodity derivatives expense was $116 million in the first quarter of 2021, a result of the strengthening of oil prices during the period. Cash payments on hedges that settled in the first quarter totaled $38 million (representing $9.28 per Bbl), with the remaining amount representing the mark-to-market change in the value of the Company’s hedging portfolio.

Adjustments to net loss for the quarter included the $77 million mark-to-market change on hedging and a $14 million full-cost ceiling test impairment. The full-cost ceiling test impairment resulted primarily from the difference in recording the book value of acquired properties at a higher oil price than the 12-month look-back oil price used in the ceiling test.

Depletion, depreciation, and amortization was $39 million during first quarter 2021, or $9.26 per BOE. The Company’s effective tax rate for the first quarter 2021 was negligible, due primarily to a valuation allowance on its federal and state deferred tax assets which offsets the tax benefit generated from the pre-tax loss.


First quarter 2021 development capital expenditures, which excluded acquisitions and capitalized interest, totaled $20 million, less than eight percent of the Company’s annual capital budget. Acquisitions of oil & natural gas properties totaled nearly $11 million for the first quarter 2021, primarily representing the net purchase price of the Big Sand Draw and Beaver Creek fields in the Wind River Basin.


The Company’s total debt balance as of the end of the first quarter 2021 was $126 million, down $12 million from the end of 2020. Denbury had $75 million of outstanding borrowings drawn on its senior secured bank credit facility at the end of the quarter. Including unrestricted cash, total liquidity at the end of the first quarter was $483 million, after consideration of outstanding letters of credit.

The borrowing base for the Company’s $575 million senior secured bank credit facility was reaffirmed with its lending group at the end of April 2021.


The Company has added new oil hedges for 2022, including certain swaps and collars to secure additional cash flows at improved prices. Details of the Company’s current hedging positions are included below:

2Q – 4Q 2021 1H 2022 2H 2022
WTI NYMEX Volumes Hedged (Bbls/d) 29,000 15,500 8,000
Fixed-Price Swaps Swap Price(1) $43.86 $49.01 $55.85
WTI NYMEX Volumes Hedged (Bbls/d) 4,000 8,000 7,000
Collars Floor – Ceiling Price(1) $46.25 – 53.04 $49.69 – 62.16 $49.64 – 61.66
Total Volumes Hedged (Bbls/d) 33,000 23,500 15,000
(1) Averages are volume weighted.


As expected, first quarter 2021 capital spending and production were low relative to annual guidance levels. The Company’s production outlook for the year remains unchanged at a range of 47,500 to 51,500 BOE/d. Considering a full quarter’s production impact from the asset acquisition and recovery from first quarter 2021 winter storms, Denbury anticipates quarterly production volumes will increase in the second quarter 2021.

Development capital expenditures for 2021 are still expected to range from $250 million to $270 million. Second quarter capital expenditures should step up meaningfully with tertiary field work at the Oyster Bayou and Tinsley fields, as well as initial spending for construction of the extension of the Greencore CO2 pipeline and EOR development at CCA. Capital levels are expected to increase throughout the year in line with planned development activities.


Additional guidance details are available in the Company’s supplemental first quarter 2021 earnings presentation, which is available in the Investor Relations section of the Company’s website


Denbury will host a conference call and webcast to review and discuss first quarter 2021 financial and operating results and outlook today, Thursday, May 6, at 11:00 a.m. Central Time. Additionally, Denbury will post presentation materials on its website before market open today. The presentation webcast will be available, both live and for replay, on the Investor Relations page of the Company’s website at Individuals who would like to participate in the conference call should dial the following numbers shortly before the scheduled start time: 877.705.6003 or 201.493.6725 with confirmation number 13696087.

Denbury is an independent energy company with operations and assets focused on Carbon Capture, Use and Storage (CCUS) and Enhanced Oil Recovery (EOR) in the Gulf Coast and Rocky Mountain regions. For over two decades, the Company has maintained a unique strategic focus on utilizing CO2 in its EOR operations and since 2012 has also been active in CCUS through the injection of captured industrial-sourced CO2. The Company currently injects over three million tons of captured industrial-sourced CO2 annually, and its objective is to fully offset its Scope 1, 2, and 3 CO2 emissions within this decade, primarily through increasing the amount of captured industrial-sourced CO2 used in its operations. For more information about Denbury, visit

This press release, other than historical information, contains forward-looking statements that involve risks and uncertainties including estimated 2021 production and capital expenditures, and other risks and uncertainties detailed in the Company’s filings with the Securities and Exchange Commission, including Denbury’s most recent report on Form 10-K. These risks and uncertainties are incorporated by this reference as though fully set forth herein. These statements are based on financial and market, engineering, geological and operating assumptions that management believes are reasonable based on currently available information; however, management’s assumptions and the Company’s future performance are both subject to a wide range of risks, and there is no assurance that these goals and projections can or will be met. Actual results may vary materially. In addition, any forward-looking statements represent the Company’s estimates only as of today and should not be relied upon as representing its estimates as of any future date. Denbury assumes no obligation to update its forward-looking statements.


The following tables include selected unaudited financial and operational information for the comparative three-month periods ended March 31, 2021 and 2020. References to “Successor” refer to the new Denbury reporting entity after the Company’s emergence from bankruptcy on September 18, 2020, and references to “Predecessor” refer to the Denbury entity prior to emergence from bankruptcy. All production volumes and dollars are expressed on a net revenue interest basis with gas volumes converted to equivalent barrels at 6:1.


The following information is based on GAAP reporting earnings (along with additional required disclosures) included or to be included in the Company’s periodic reports:

Successor Predecessor
Quarter Ended Quarter Ended
In thousands, except per-share data March 31, 2021 March 31, 2020
Revenues and other income
Oil sales $ 233,044 $ 228,577
Natural gas sales 2,401 1,047
CO2 sales and transportation fees 9,228 8,028
Oil marketing revenues 6,126 3,721
Other income 360 828
Total revenues and other income 251,159 242,201
Lease operating expenses 81,970 109,270
Transportation and marketing expenses 7,797 9,621
CO2 operating and discovery expenses 993 752
Taxes other than income 18,963 19,686
Oil marketing expenses 6,085 3,661
General and administrative expenses 31,983 9,733
Interest, net of amounts capitalized of $1,083 and $9,452, respectively 1,536 19,946
Depletion, depreciation, and amortization 39,450 96,862
Commodity derivatives expense (income) 115,743 (146,771 )
Gain on debt extinguishment (18,994 )
Write-down of oil and natural gas properties 14,377 72,541
Other expenses 2,146 2,494
Total expenses 321,043 178,801
Income (loss) before income taxes (69,884 ) 63,400
Income tax provision (benefit)
Current income taxes (191 ) (6,407 )
Deferred income taxes (51 ) (4,209 )
Net income (loss) $ (69,642 ) $ 74,016
Net income (loss) per common share
Basic $ (1.38 ) $ 0.15
Diluted $ (1.38 ) $ 0.14
Weighted average common shares outstanding
Basic 50,319 494,259
Diluted 50,319 586,190


Successor Predecessor
Quarter Ended Quarter Ended
In thousands March 31, 2021 March 31, 2020
Cash flows from operating activities
Net income (loss) $ (69,642 ) $ 74,016
Adjustments to reconcile net income (loss) to cash flows from operating activities
Depletion, depreciation, and amortization 39,450 96,862
Write-down of oil and natural gas properties 14,377 72,541
Deferred income taxes (51 ) (4,209 )
Stock-based compensation 17,680 2,453
Commodity derivatives expense (income) 115,743 (146,771 )
Receipt (payment) on settlements of commodity derivatives (38,453 ) 24,638
Gain on debt extinguishment (18,994 )
Debt issuance costs and discounts 685 4,926
Other, net 727 (673 )
Changes in assets and liabilities, net of effects from acquisitions
Accrued production receivable (36,750 ) 66,937
Trade and other receivables 865 (22,914 )
Other current and long-term assets (2,542 ) 2,539
Accounts payable and accrued liabilities (1,402 ) (72,607 )
Oil and natural gas production payable 12,795 (15,948 )
Other liabilities (826 ) (954 )
Net cash provided by operating activities 52,656 61,842
Cash flows from investing activities
Oil and natural gas capital expenditures (19,627 ) (46,016 )
Acquisitions of oil and natural gas properties (10,665 ) (42 )
Pipelines and plants capital expenditures (458 ) (6,294 )
Net proceeds from sales of oil and natural gas properties and equipment 3 40,543
Other (2,916 ) (4,479 )
Net cash used in investing activities (33,663 ) (16,288 )
Cash flows from financing activities
Bank repayments (202,000 ) (161,000 )
Bank borrowings 207,000 161,000
Interest payments treated as a reduction of debt (18,211 )
Cash paid in conjunction with debt repurchases (14,171 )
Pipeline financing debt repayments (16,509 ) (3,690 )
Other (3,013 ) (2,953 )
Net cash used in financing activities (14,522 ) (39,025 )
Net increase in cash, cash equivalents, and restricted cash 4,471 6,529
Cash, cash equivalents, and restricted cash at beginning of period 42,248 33,045
Cash, cash equivalents, and restricted cash at end of period $ 46,719 $ 39,574


In thousands, except par value and share data March 31, 2021 Dec. 31, 2020
Current assets
Cash and cash equivalents $ 5,647 $ 518
Restricted cash 400 1,000
Accrued production receivable 128,171 91,421
Trade and other receivables, net 18,322 19,682
Derivative assets 236 187
Prepaids 9,043 14,038
Total current assets 161,819 126,846
Property and equipment
Oil and natural gas properties (using full cost accounting)
Proved properties 936,742 851,208
Unevaluated properties 86,878 85,304
CO2 properties 188,516 188,288
Pipelines 133,722 133,485
Other property and equipment 92,037 86,610
Less accumulated depletion, depreciation, amortization and impairment (89,538 ) (41,095 )
Net property and equipment 1,348,357 1,303,800
Operating lease right-of-use assets 19,832 20,342
Derivative assets 3,021
Intangible assets, net 95,096 97,362
Other assets 93,035 86,408
Total assets $ 1,721,160 $ 1,634,758
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable and accrued liabilities $ 118,189 $ 112,671
Oil and gas production payable 61,960 49,165
Derivative liabilities 129,124 53,865
Current maturities of long-term debt 51,499 68,008
Operating lease liabilities 2,660 1,350
Total current liabilities 363,432 285,059
Long-term liabilities
Long-term debt, net of current portion 75,000 70,000
Asset retirement obligations 223,465 179,338
Derivative liabilities 10,188 5,087
Deferred tax liabilities, net 1,224 1,274
Operating lease liabilities 18,961 19,460
Other liabilities 26,964 20,872
Total long-term liabilities 355,802 296,031
Commitments and contingencies
Stockholders’ equity
Preferred stock, $.001 par value, 50,000,000 shares authorized, none issued and outstanding
Common stock, $.001 par value, 250,000,000 shares authorized; 50,005,619 and 49,999,999 shares issued, respectively 50 50
Paid-in capital in excess of par 1,122,176 1,104,276
Accumulated deficit (120,300 ) (50,658 )
Total stockholders equity 1,001,926 1,053,668
Total liabilities and stockholders’ equity $ 1,721,160 $ 1,634,758


All production volumes and dollars are expressed on a net revenue interest basis with gas volumes converted to equivalent barrels at 6:1.

Quarter Ended
March 31,
2021 2020
Average daily production (BOE/d)
Gulf Coast region 24,281 28,931
Rocky Mountain region 7,187 7,930
Total tertiary production 31,468 36,861
Gulf Coast region 3,621 4,173
Rocky Mountain region 12,268 14,151
Total non-tertiary production 15,889 18,324
Total Company
Oil (Bbls/d) 46,007 54,649
Natural gas (Mcf/d) 8,102 7,899
BOE (6:1) 47,357 55,965
Unit sales price (excluding derivative settlements)
Gulf Coast region
Oil (per barrel) $ 56.46 $ 47.52
Natural gas (per mcf) 3.39 1.81
Rocky Mountain region
Oil (per barrel) $ 56.03 $ 43.57
Natural gas (per mcf) 3.20 0.96
Total Company
Oil (per barrel)(1) $ 56.28 $ 45.96
Natural gas (per mcf) 3.29 1.46
BOE (6:1) 55.24 45.09
(1) Total company realized oil prices including derivative settlements during the three months ended March 31, 2021 and 2020 were $47.00 per Bbl and $50.92 per Bbl, respectively.


Reconciliation of net income (loss) (GAAP measure) to adjusted net income (non-GAAP measure)

Adjusted net income is a non-GAAP measure provided as a supplement to present an alternative net income (loss) measure which excludes expense and income items (and their related tax effects) not directly related to the Company’s ongoing operations. Management believes that adjusted net income may be helpful to investors by eliminating the impact of noncash and/or special or unusual items not indicative of the Company’s performance from period to period, and is widely used by the investment community, while also being used by management, in evaluating the comparability of the Company’s ongoing operational results and trends. Adjusted net income should not be considered in isolation, as a substitute for, or more meaningful than, net income (loss) or any other measure reported in accordance with GAAP, but rather to provide additional information useful in evaluating the Company’s operational trends and performance.

Successor Predecessor
Quarter Ended Quarter Ended
March 31, 2021 March 31, 2020
In thousands, except per-share data Amount Per Diluted Share Amount Per Diluted Share
Net income (loss) (GAAP measure)(1) $ (69,642 ) $ (1.38 ) $ 74,016 $ 0.14
Adjustments to reconcile to adjusted net income (non-GAAP measure)
Noncash fair value losses (gains) on commodity derivatives(2) 77,290 1.51 (122,133 ) (0.21 )
Write-down of oil and natural gas properties(3) 14,377 0.28 72,541 0.12
Accelerated depreciation charge(4) 37,368 0.06
Gain on debt extinguishment(5) (18,994 ) (0.03 )
Other(6) 325 0.03 1,404 0.00
Estimated income taxes on above adjustments to net income (loss) and other discrete tax items(7) (16,782 ) (0.02 )
Adjusted net income (non-GAAP measure) $ 22,350 $ 0.44 $ 27,420 $ 0.06
(1) Diluted net income (loss) per common share includes the impact of potentially dilutive securities including performance stock units, nonvested restricted stock units, and warrants during the Successor period and includes nonvested restricted stock, nonvested performance-based equity awards, and shares into which the Predecessor’s previous convertible senior notes were convertible.
(2) The net change between periods of the fair market values of open commodity derivative positions, excluding the impact of settlements on commodity derivatives during the period.
(3) Full cost pool ceiling test write-downs related to the Company’s oil and natural gas properties.
(4) Accelerated depreciation related to impaired unevaluated properties that were transferred to the full cost pool.
(5) Gain on debt extinguishment related to the Company’s 2020 open market repurchases.
(6) Other adjustments include (a) a $0.3 million write-off of trade receivables during the three months ended March 31, 2021 and (b) <$1 million of costs associated with the helium supply contract ruling and $1 million of costs associated with the Delta-Tinsley CO2 pipeline incident during the three months ended March 31, 2020.
(7) The estimated income tax impacts on adjustments to net income for the three months ended March 31, 2020 are computed based upon an estimated annual effective tax rate of 16%, with other discrete tax adjustments totaling $39 million primarily comprised of the tax effect of the ceiling test and accelerated depreciation, impacts of the CARES Act, and the periodic tax impacts of a shortfall (benefit) on the stock-based compensation deduction.


Reconciliation of net income (loss) (GAAP measure) to Adjusted EBITDAX (non-GAAP measure)

Adjusted EBITDAX is a non-GAAP measure which management uses and is calculated based upon (but not identical to) a financial covenant related to “Consolidated EBITDAX” in the Company’s senior secured bank credit facility, which excludes certain items that are included in net income (loss), the most directly comparable GAAP financial measure. Items excluded include interest, income taxes, depletion, depreciation, and amortization, and items that the Company believes affect the comparability of operating results such as items whose timing and/or amount cannot be reasonably estimated or are nonrecurring. Management believes Adjusted EBITDAX may be helpful to investors in order to assess the Company’s operating performance as compared to that of other companies in the industry, without regard to financing methods, capital structure or historical costs basis. It is also commonly used by third parties to assess leverage and the Company’s ability to incur and service debt and fund capital expenditures. Adjusted EBITDAX should not be considered in isolation, as a substitute for, or more meaningful than, net income (loss), cash flow from operations, or any other measure reported in accordance with GAAP. The Company’s Adjusted EBITDAX may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDAX, EBITDAX or EBITDA in the same manner.  The following table presents a reconciliation of the Company’s net income (loss) to Adjusted EBITDAX.

Successor Predecessor
In thousands Quarter Ended Quarter Ended
March 31, 2021 March 31, 2020
Net income (loss) (GAAP measure) $ (69,642 ) $ 74,016
Adjustments to reconcile to Adjusted EBITDAX
Interest expense 1,536 19,946
Income tax expense (benefit) (242 ) (10,616 )
Depletion, depreciation, and amortization 39,450 96,862
Noncash fair value losses (gains) on commodity derivatives 77,290 (122,133 )
Stock-based compensation 17,680 2,453
Gain on debt extinguishment (18,994 )
Write-down of oil and natural gas properties 14,377 72,541
Noncash, non-recurring and other 1,467 2,364
Adjusted EBITDAX (non-GAAP measure)(1) $ 81,916 $ 116,439
(1) Excludes pro forma adjustments related to qualified acquisitions or dispositions under the Company’s senior secured bank credit facility.


Reconciliation of cash flows from operations (GAAP measure) to adjusted cash flows from operations (non-GAAP measure) and free cash flow (non-GAAP measure)

Adjusted cash flows from operations is a non-GAAP measure that represents cash flows provided by operations before changes in assets and liabilities, as summarized from the Company’s Unaudited Condensed Consolidated Statements of Cash Flows. Adjusted cash flows from operations measures the cash flows earned or incurred from operating activities without regard to the collection or payment of associated receivables or payables. Free cash flow is a non-GAAP measure that represents adjusted cash flows from operations less interest treated as debt reduction, development capital expenditures and capitalized interest, but before acquisitions. Management believes that it is important to consider these additional measures, along with cash flows from operations, as it believes the non-GAAP measures can often be a better way to discuss changes in operating trends in its business caused by changes in production, prices, operating costs and related factors, without regard to whether the earned or incurred item was collected or paid during that period. Adjusted cash flows from operations and free cash flow are not measures of financial performance under GAAP and should not be considered as alternatives to cash flows from operations, investing, or financing activities, nor as a liquidity measure or indicator of cash flows.

Successor Predecessor
In thousands Quarter Ended Quarter Ended
March 31, 2021 March 31, 2020
Cash flows from operations (GAAP measure) $ 52,656 $ 61,842
Net change in assets and liabilities relating to operations 27,860 42,947
Adjusted cash flows from operations (non-GAAP measure) 80,516 104,789
Interest on notes treated as debt reduction (21,354 )
Development capital expenditures (20,079 ) (38,785 )
Capitalized interest (1,083 ) (9,452 )
Free cash flow (non-GAAP measure) $ 59,354 $ 35,198


Quarter Ended
March 31,
In thousands 2021 2020
Capital expenditure summary
Cedar Creek Anticline tertiary development $ 36 $ 1,354
Other tertiary oil fields 4,080 13,372
Non-tertiary fields 8,342 10,954
Capitalized internal costs(2) 7,600 8,881
Oil and natural gas capital expenditures 20,058 34,561
Cedar Creek Anticline CO2 pipeline 21 4,175
Other CO2 pipelines, sources and other 49
Development capital expenditures 20,079 38,785
Acquisitions of oil and natural gas properties(3) 10,665 42
Capital expenditures, before capitalized interest 30,744 38,827
Capitalized interest 1,083 9,452
Capital expenditures, total $ 31,827 $ 48,279
(1) Capital expenditure amounts include accrued capital.
(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.