DENBURY INC. The following discussion and analysis should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and Notes thereto included herein and our Consolidated Financial Statements and Notes thereto included in our Annual Report on Form 10-K for the year endedDecember 31, 2022 (the "Form 10-K"), along with Management's Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K. Any terms used but not defined herein have the same meaning given to them in the Form 10-K. 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 the 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 than our forward-looking statements. OVERVIEWDenbury is an independent energy company with operations focused in theGulf Coast andRocky Mountain regions. The Company is differentiated by its focus on CO2 enhanced oil recovery ("EOR") and the emerging carbon capture, utilization, and storage ("CCUS") industry, supported by the Company's CO2 EOR technical and operational expertise and its extensive CO2 pipeline infrastructure. The utilization of captured industrial-sourced CO2 in EOR significantly reduces the carbon footprint of the oil thatDenbury produces, making the Company's Scope 1 and 2 CO2e emissions negative today. We have set a target, within the decade, to reach Net Zero for our Scope 1, Scope 2 and those Scope 3 emissions that result from consumers' use of the oil and natural gas we sell (defined as Category 11 emissions by the Greenhouse Gas Protocol). Our CO2 EOR oil recovery operations result in associated underground storage of CO2. This means thatDenbury's activities are currently supporting and advancing the national energy transition through the increasing use of industrially sourced CO2 in EOR operations, and we are building out a dedicated CCUS platform for the transportation and permanent storage of captured industrial CO2 emissions at scale. During the three months endedMarch 31, 2023 , approximately 40% of the CO2 utilized in our operated oil and gas operations was industrial-sourced CO2, compared to 36% of the CO2 utilized during the three months endedMarch 31, 2022 . Our industrial-sourced CO2 usage in the first quarter of 2023 equates to an annualized average CO2 usage rate of over 4.6 million metric tons. 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 allocation and budgeting decisions, and oil and natural gas reserves volumes. Oil prices have historically been volatile and can fluctuate significantly over short periods of time for many different reasons, such as global supply and demand and geopolitical events. Average NYMEX WTI oil prices were approximately$76 per Bbl during the first quarter of 2023 as compared to$95 per Bbl in the first quarter of 2022. 16 --------------------------------------------------------------------------------
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
OperationsThe table below outlines selected financial items and sales volumes, along with changes in our realized oil prices, before and after commodity derivative impacts, for our most recent comparative quarterly periods:
Three Months Ended
In thousands, except per-unit
data March 31, 2023 Dec. 31, 2022 Sept. 30, 2022 June 30, 2022 March 31, 2022
Oil, natural gas, and related
product sales $ 314,489 $ 346,578 $ 395,223 $ 451,970 $ 384,911
Receipt (payment) on
settlements of commodity
derivatives 2,065 (38,956) (55,780) (127,959) (93,057)
Oil, natural gas, and related product sales and commodity derivative settlements, combined$ 316,554 $ 307,622 $ 339,443 $ 324,011 $ 291,854 Average daily sales (BOE/d) 47,655 46,641 47,109 46,561 46,925 Average net realized oil prices Oil price per Bbl - excluding impact of derivative settlements $ 74.87$ 82.54 $ 92.77$ 108.81 $ 93.17 Oil price per Bbl - including impact of derivative settlements 75.36 73.13 79.49 77.63 70.43 Average NYMEX oil differential per Bbl $ (1.28) $ 0.03 $ 0.82 $ 0.09 $ (1.37) As shown in the table above, our oil and natural gas revenues have decreased since 2022 primarily due to the decrease in oil prices. We received$2.1 million during the first quarter of 2023 related to the expiration of commodity derivative contracts. During 2022, the benefit of high oil prices during the first half of the year was offset in part by the impact of higher cash payments on our commodity derivative contracts, which contracts were generally put in place in late 2020 as a requirement under our bank credit facility shortly after we exited bankruptcy. First Quarter 2023 Financial Results and Highlights. We recognized net income of$89.2 million , or$1.66 per diluted common share, during the first quarter of 2023, compared to a net loss of$0.9 million , or$0.02 per diluted common share, during the first quarter of 2022. Drivers of the comparative operating results between the first quarter of 2023 and 2022 include the following: •Oil and natural gas revenues decreased by$70.4 million (18%) during the first quarter of 2023 due to lower oil prices; •Commodity derivatives expense decreased by$215.8 million consisting of a$120.7 million improvement in noncash fair value changes between periods ($21.1 million gain during the first quarter of 2023 compared to a$99.7 million loss during the first quarter of 2022), and a$95.1 million decrease in cash payments upon derivative contract settlements ($2.1 million in cash receipts during the first quarter of 2023 compared to$93.1 million in payments during the first quarter of 2022); •Lease operating expenses increased by$11.3 million (10%), primarily due to higher workover, repair and maintenance, labor, and CO2 purchase costs; and •Income tax expense increased by$34.8 million , from a benefit of$6.5 million during the first quarter of 2022 to$28.3 million in expense during the first quarter of 2023, primarily due to the release in 2022 of a portion of the valuation allowance on our deferred tax assets.Cedar Creek Anticline CO2 EOR Development . We allocated 40% of our first quarter oil & gas development capital to the CCA EOR project, primarily focused on the construction of four planned CO2 recycle facilities, well conversions, and drilling the Interlake Pennel CO2 pilot. Commissioning of the initial CO2 recycle facility within the Cedar Hills South field was completed late in the first quarter of 2023 as planned, and commissioning of the second facility is expected to be completed during the second quarter of 2023, with the remaining two recycle facilities currently expected to be complete during the third 17 --------------------------------------------------------------------------------
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operationsquarter of 2023. We currently expect initial EOR production to commence during the second quarter of 2023, with incremental EOR production reaching 2,000 Bbls/d by the end of 2023 and 7,500 Bbls/d to 12,500 Bbls/d by the end of 2024.
Carbon Capture, Utilization and Storage Activities. We invested$19.7 million of development capital into CCUS assets during the first quarter of 2023, primarily for the development of dedicated CO2 sequestration sites, including the drilling of a stratigraphic test well in ourAlabama sequestration site and incremental seismic and acreage across our sequestration portfolio. We also obtained the rights to develop a new sequestration site inWyoming , located directly below our Greencore CO2 pipeline, with estimated CO2 storage potential of up to 40 million metric tons. InApril 2023 , we acquired the right to develop a 30,000 acre dedicated CO2 sequestration site inMatagorda County, Texas , approximately 60 miles southwest of the terminus of the Company's Green CO2 pipeline, with estimated CO2 storage potential of more than 115 million metric tons. On the transportation and storage side of our CCUS business, we executed two new agreements with eFuels companies,HIF Global and Monarch Energy Development LLC , to source and transport up to 2.4 million metric tons of CO2 per year to planned projects in southeastTexas . To date, we have signed agreements covering the potential future transportation and storage of up to 22 Mmtpa from the planned capture of CO2 emissions from existing and proposed industrial plants. On the sequestration front, we have signed agreements securing the rights to nine future storage sites which we believe have the potential to store more than 2.1 billion metric tons of CO2. In addition to our core CCUS development activities, during the first quarter of 2023, we made two investments in carbon capture technology companies including a$2 million equity investment in Aqualung Carbon Capture AS and a$5 million equity investment inION Clean Energy, Inc. InApril 2023 , based on the achievement of certain milestones, we invested the remaining$10 million of our original$20 million commitment in Clean Hydrogen Works, the project development company of a planned blue hydrogen/ammonia multi-block facility for which we have signed a definitive agreement for the transportation and storage of CO2 for the first two blocks of the proposed plant. These investments are included in "Other assets" in the Unaudited Condensed Consolidated Balance Sheet as ofMarch 31, 2023 .
CAPITAL RESOURCES AND LIQUIDITY
Overview. Our cash flows from operations and availability under our senior secured bank credit facility are our primary sources of capital and liquidity. Our most significant cash capital outlays relate to our oil and gas development capital expenditures and CCUS initiatives. During the three months endedMarch 31, 2023 , we generated$88.5 million in cash flow from operations, or$139.6 million before working capital changes, as the first quarter included$51.1 in cash outflows for working capital items primarily related to annual ad valorem tax payments and bonus payments. We invested cash of$133.1 million in oil and gas and CCUS activities during the first quarter of 2023 and financing activities supplemented our cash flow by$44.6 million , primarily from borrowings under our bank credit facility. As ofMarch 31, 2023 , we had$68.0 million of outstanding borrowings, up from$29.0 million atDecember 31, 2022 , and$10.1 million of outstanding letters of credit under our$750 million senior secured bank credit facility, leaving us with$671.9 million of borrowing base availability. This liquidity is more than adequate to meet our currently planned operating and capital needs. 2023 Capital Expenditure Plans. We estimate that our total oil and natural gas development capital expenditures in 2023, excluding acquisitions and capitalized interest, will be in a range of$350 million to$370 million , and our CCUS capital expenditures will be in a range of$140 million to$160 million , for a total of$510 million at the combined midpoints. In addition to the Company's budgeted capital expenditures, we expect to incur approximately$17 million for CCUS equity investments and approximately$36 million for plugging and abandonment costs. During the first quarter of 2023, we incurred$99.8 million of oil and natural gas development capital expenditures and$19.7 million of CCUS capital expenditures, or approximately 28% and 13% of our total annual budget, respectively. Based on current projections, including estimated production costs, oil price differentials and other assumptions, we currently anticipate that our 2023 cash flows from operations, excluding working capital changes, will approximately meet or exceed our budgeted capital expenditures and planned asset retirement obligation activities for the year, assuming oil prices of approximately$75 per Bbl in 2023. Also, atMarch 31, 2023 , we had$671.9 million of availability under our bank credit facility, which we believe is more than adequate to cover any near-term liquidity needs. 18 --------------------------------------------------------------------------------
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
Capital Expenditure Summary. For purposes of tracking and comparing our capital
budget to capital expenditure activity, we base those comparisons on when the
capital expenditures are incurred, which is generally different than what is
reported in our cash flow statements which reflects when cash is actually paid.
The information included in the following table reflects our incurred capital
expenditures:
Three Months Ended
March 31,
In thousands 2023 2022
Capital expenditure summary(1)
CCA EOR field expenditures(2) $ 40,038 $ 17,722
CCA CO2 pipelines 523 2,191
CCA tertiary development 40,561 19,913
Non-CCA tertiary and non-tertiary fields 49,093 29,363
CO2 sources, other CO2 pipelines and other 1,563
730
Capitalized internal costs(3) 8,574
7,600
Oil and gas development capital expenditures 99,791
57,606
CCUS storage sites and related capital expenditures 19,688
20,949
Oil and gas and CCUS development capital expenditures 119,479
78,555
Capitalized interest 1,693
1,158
Acquisitions of oil and natural gas properties 35 371 Equity investments(4) 7,108 - Total capital expenditures$ 128,315 $ 80,084 (1)Capital expenditures in this summary are presented on an as-incurred basis (including accruals) and are$0.9 million and$10.0 million lower than the capital expenditures in the Unaudited Condensed Consolidated Statements of Cash Flows for the three months endedMarch 31, 2023 and 2022, respectively, which are presented on a cash basis. (2)Includes pre-production CO2 costs associated with the CCA EOR development project totaling$5.2 million during the first quarter of 2023 and$2.8 million during the first quarter of 2022. (3)Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs, excluding CCA. (4)Represents two investments made in carbon capture technology companies during the first quarter of 2023, including a$2 million equity investment in Aqualung Carbon Capture AS and a$5 million equity investment inION Clean Energy, Inc. The investments are included in "Other assets" in the Unaudited Condensed Consolidated Balance Sheet as ofMarch 31, 2023 . SupplyChain Issues and Potential Cost Inflation. Worldwide andU.S. supply chain issues, together with higher commodity prices, power costs, service costs and tight labor markets in theU.S. , increased our costs throughout 2022 and continue to have ongoing impacts in 2023. Although the inflationary cost increases and supply chain issues have begun to level off in certain areas, we still expect additional cost and demand increases in certain categories of goods, services and wages in our operations during 2023, which could negatively impact our results of operations and cash flows in future periods. See Results of Operations - Production Expenses below for further discussion. Senior Secured Bank Credit Agreement. InSeptember 2020 , we entered into a credit agreement withJPMorgan Chase Bank, N.A ., as administrative agent, and other lenders party thereto (as amended, the "Bank Credit Agreement"). The Bank Credit Agreement is a senior secured revolving credit facility with a maturity date ofMay 4, 2027 . Under the 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 Bank Credit Agreement. Availability under the Bank Credit Agreement is subject to a borrowing base, which is redetermined semiannually on or aroundMay 1 andNovember 1 of each year. As part of our Spring 2023 semiannual borrowing base redetermination, the borrowing base and lender commitments for our Bank Credit Agreement were reaffirmed at$750 million , with our next scheduled redetermination aroundNovember 1, 2023 . The borrowing base is adjusted at the lenders' discretion and is based, in 19 --------------------------------------------------------------------------------
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
part, upon external factors over which we have no control. If our outstanding
debt under the 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.
On
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 certain exceptions to such limitations, as specified in the Bank Credit Agreement. OurBank Credit Agreement required certain minimum commodity hedge levels in connection with our emergence from bankruptcy; however, these conditions were met as ofDecember 31, 2020 , and we currently have no ongoing hedging requirements under the Bank Credit Agreement.
The Bank Credit Agreement contains certain financial performance covenants including the following:
•A Consolidated Total Debt to Consolidated EBITDAX covenant (as defined in the Bank Credit 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 ofMarch 31, 2023 , our ratio of consolidated total debt to consolidated EBITDAX was 0.11 to 1.0 (with a maximum permitted ratio of 3.5 to 1.0) and our current ratio was 2.89 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 ofMay 1, 2023 , 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, including certain referenced defined terms, is a summary of certain principal terms and conditions contained in the Bank Credit Agreement and amendments thereto, each of which is filed as an exhibit to our periodic reports filed with theSecurities and Exchange Commission ("SEC"). Commitments, Obligations and Off-Balance Sheet Arrangements. We incur numerous contractual commitments in the ordinary course of business including debt service requirements, operating leases, purchase obligations, and asset retirement obligations. Our operating leases primarily consist of our office leases. Our purchase obligations represent future cash commitments primarily for purchase contracts for CO2 captured from industrial sources, CO2 processing fees, transportation agreements and well-related costs. Our off-balance sheet arrangements include obligations for various development and exploratory expenditures that arise from our normal oil and natural gas or CCUS capital expenditure program or from other transactions common to our industry, none of which are recorded on our balance sheet. During 2022 and 2023, we entered into storage contracts to secure rights to underground pore space in anticipation of future CCUS operations. Noncancelable commitments under those contracts total$2 million as ofMarch 31, 2023 . In addition, in order to recover our undeveloped proved reserves, we must also fund the associated future development costs estimated in our proved reserve reports.
Our commitments, obligations and off-balance sheet arrangements as of
20
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
OperationsRESULTS OF OPERATIONS
Financial and Operating Results Tables
Certain of our operating results and statistics for the comparative three months
ended
Three Months Ended
March 31 , In thousands, except per-share and unit data 2023
2022
Financial results Net income (loss)$ 89,199 $ (872) Net income (loss) per common share - basic 1.73
(0.02)
Net income (loss) per common share - diluted 1.66
(0.02)
Net cash provided by operating activities 88,522 90,143 Average daily sales volumes Bbls/d 46,389 45,466 Mcf/d 7,600 8,753 BOE/d(1) 47,655 46,925 Oil and natural gas sales Oil sales$ 312,572 $ 381,242 Natural gas sales 1,917 3,669 Total oil and natural gas sales$ 314,489 $ 384,911 Commodity derivative contracts(2) Receipt (payment) on settlements of commodity derivatives$ 2,065 $ (93,057) Noncash fair value gains (losses) on commodity derivatives 21,058
(99,662)
Commodity derivatives income (expense)$ 23,123
$ 74.87 $ 93.17 Natural gas price per Mcf 2.80
4.66
Unit prices - including impact of derivative settlements(2) Oil price per Bbl
$ 75.36 $ 70.43 Natural gas price per Mcf 2.80
4.66
Oil and natural gas operating expenses Lease operating expenses$ 129,174 $ 117,828 Transportation and marketing expenses 5,389
4,645
Production and ad valorem taxes 28,263
30,443
Oil and natural gas operating revenues and expenses per BOE Oil and natural gas revenues
$ 73.32 $ 91.14 Lease operating expenses 30.12
27.90
Transportation and marketing expenses 1.26
1.10
Production and ad valorem taxes 6.59
7.21
CO2 - revenues and expenses CO2 sales and transportation fees$ 10,686 $ 13,422 CO2 operating and discovery expenses (1,196) (2,817) CO2 revenue and expenses, net$ 9,490 $ 10,605 (1)Barrel of oil equivalent using the ratio of one barrel of oil to six Mcf of natural gas ("BOE"). (2)See also Commodity Derivative Contracts below and Item 3. Quantitative and Qualitative Disclosures about Market Risk for information concerning our derivative transactions. 21
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
OperationsSales Volumes
Average daily sales volumes by area for each of the four quarters of 2022 and for the first quarter of 2023 is shown below:
Average Daily Sales Volumes (BOE/d)
First Fourth Third Second First
Quarter Quarter Quarter Quarter Quarter
Operating Area 2023 2022 2022 2022 2022
Tertiary oil sales volumes
Gulf Coast region
Delhi 2,514 2,528 2,557 2,478 2,675
Hastings 4,450 4,198 4,211 4,304 4,430
Heidelberg 3,539 3,670 3,571 3,528 3,653
Oyster Bayou 3,832 3,417 3,490 3,423 3,745
Tinsley 3,205 2,248 3,133 3,050 3,015
Other(1) 5,585 5,652 5,541 5,422 5,498
Total Gulf Coast region 23,125 21,713 22,503 22,205 23,016
Rocky Mountain region
Bell Creek 3,808 3,767 3,975 4,122 4,474
Wind River Basin 3,872 3,726 3,121 2,703 2,517
Other(2) 2,744 2,824 2,759 2,361 2,229
Total Rocky Mountain region 10,424 10,317 9,855 9,186 9,220
Total tertiary oil sales volumes 33,549 32,030 32,358 31,391 32,236
Non-tertiary oil and gas sales volumes
Gulf Coast region
Total Gulf Coast region 3,398 3,666 3,727 3,566 3,630
Rocky Mountain region
Cedar Creek Anticline 9,316 9,366 9,593 10,224 9,721
Other(3) 1,392 1,579 1,431 1,380 1,338
Total Rocky Mountain region 10,708 10,945 11,024 11,604 11,059
Total non-tertiary sales volumes 14,106 14,611 14,751 15,170 14,689
Total sales volumes 47,655 46,641 47,109 46,561 46,925
(1)Includes Brookhaven, Cranfield, Eucutta, Little Creek , Mallalieu,
Martinville, McComb, Soso, and West Yellow Creek fields.
(2)Includes tertiary sales volumes related to our working interest positions in
the Salt Creek and Grieve fields.
(3)Includes non-tertiary sales volumes from Wind River Basin , as well as Hartzog
Draw and Bell Creek fields.
Total sales volumes during the first quarter of 2023 averaged 47,655 BOE/d, up
approximately 2% from the fourth quarter of 2022 and the first quarter of 2022.
Compared to fourth quarter of 2022, the increase in sales volumes was primarily
driven by the recovery of production lost due to the late-December 2022 winter
storms, which mostly impacted CCA and Hastings fields, coupled with higher
production at Oyster Bayou and an increase in sales at Tinsley Field, primarily
due to the sale of inventory built in the fourth quarter of 2022 as a result of
the timing of barge loadings. Curtailments stemming from the CO2 development
activities at CCA were just over 500 Bbls/d during the first quarter, up
slightly from the prior year fourth quarter. On a year-over-year basis, the
sales volumes increase compared to sales levels in the first quarter of 2022 was
primarily attributable to enhancements and additional development of the CO2
floods at Soso Rodessa Phase 1 and Wind River Basin .
Our sales volumes during the three months ended
22
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
OperationsOil and Natural Gas Revenues
Our oil and natural gas revenues during the three months endedMarch 31, 2023 decreased 18% compared to these revenues for the same period in 2022. The changes in our oil and natural gas revenues are due to lower realized commodity prices (excluding any impact of our commodity derivative contracts), as reflected in the following table: Three Months Ended March 31, 2023 vs. 2022 Increase Percentage Increase (Decrease) in (Decrease) in In thousands Revenues Revenues Change in oil and natural gas revenues due to: Increase in sales volumes$ 5,989 2 % Decrease in realized commodity prices (76,411) (20) % Total decrease in oil and natural gas revenues$ (70,422) (18) %
Excluding any impact of our commodity derivative contracts, our average net
realized commodity prices and NYMEX differentials were as follows during each of
the three months ended
Three Months Ended
March 31,
2023 2022
Average net realized prices
Oil price per Bbl $ 74.87 $ 93.17
Natural gas price per Mcf 2.80 4.66
Price per BOE 73.32 91.14
Average NYMEX differentials
Gulf Coast region
Oil per Bbl $ (1.29) $ (1.37)
Natural gas per Mcf (0.05) 0.16
Rocky Mountain region
Oil per Bbl $ (1.28) $ (1.38)
Natural gas per Mcf 0.04 0.08
Total Company
Oil per Bbl $ (1.28) $ (1.37)
Natural gas per Mcf 0.01 0.11
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$1.29 per Bbl during the first quarter of 2023, a slight improvement from a negative$1.37 per Bbl during the first quarter of 2022 and a decrease from a negative$0.40 per Bbl during the fourth quarter of 2022. •Rocky Mountain Region. Our average NYMEX oil differentials in theRocky Mountain region was a negative$1.28 per Bbl during the first quarter of 2023, compared to a negative$1.38 per Bbl below NYMEX during the first quarter of 2022 and a positive$0.56 per Bbl during the fourth quarter of 2022. 23 --------------------------------------------------------------------------------
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
OperationsCO2 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 Unaudited Condensed Consolidated Statements of Operations. CO2 sales and transportation fees were$10.7 million during the three months endedMarch 31, 2023 , compared to$13.4 million during the three months endedMarch 31, 2022 . The decrease in CO2 sales and transportation fees from the prior-year period is primarily due to a short-term sales contract in place during the first quarter of 2022 as well as unplanned downtime of third-party purchasers.
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 Unaudited Condensed 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 currently consist of fixed-price swaps and costless collars. The following table summarizes the impact our crude oil derivative contracts had on our operating results for the three months endedMarch 31, 2023 and 2022: Three Months Ended March 31, In thousands 2023 2022
Receipt (payment) on settlements of commodity derivatives
$ (93,057) Noncash fair value gains (losses) on commodity derivatives 21,058 (99,662) Total income (expense)$ 23,123 $ (192,719) Commodity derivatives income (expense) is comprised of (1) payments or receipts on settlements of commodity derivatives and (2) noncash changes in the fair values of commodity derivatives. Changes in the fair values of commodity derivatives are due to changes in oil futures prices since the prior period or subsequent to entering into new derivative agreements. During the first three months of 2023, we received$2.1 million upon expiration of commodity derivative contracts, compared to cash payments upon settlement of$93.1 million during the first three months of 2022. In order to provide a level of price protection to our oil production, we have hedged a portion of our estimated oil production through 2024 using NYMEX fixed-price swaps and costless collars. Upon emergence from bankruptcy inSeptember 2020 , we were required to hedge through mid-2022 at certain levels of estimated production under our post-emergence bank credit facility. Those hedges resulted in significant cash losses to us during 2022 as oil prices subsequently improved beyond our hedged prices. We no longer have any hedging requirements under our bank credit facility; however, we plan to continue to hedge a portion of our production in order to provide a level of certainty in our cash flows. See Note 6, Commodity Derivative Contracts, to the Unaudited Condensed Consolidated Financial Statements for additional details of our outstanding commodity derivative contracts as ofMarch 31, 2023 , and Item 3, Quantitative and Qualitative Disclosures about 24 --------------------------------------------------------------------------------
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Management's Discussion and Analysis of Financial Condition and Results of
Operations
Market Risk below for additional discussion. In addition, the following table
summarizes our commodity derivative contracts as of
2Q 2023 2H 2023 1H 2024 2H 2024
WTI NYMEX Volumes Hedged (Bbls/d) 9,500 18,000 5,000 1,000
Fixed-Price Swaps Weighted Average Swap Price $76.65 $78.51 $75.34 $75.12
WTI NYMEX Volumes Hedged (Bbls/d) 17,500 9,000 - -
Weighted Average Floor /
Collars Ceiling Price $69.71 / $100.42 $68.33 / $100.69 - -
Total Volumes Hedged (Bbls/d) 27,000 27,000 5,000 1,000
Based on current contracts in place and NYMEX oil futures prices as of May 1,
2023 , which averaged approximately $74 per Bbl for the remainder of 2023, we
currently expect that we would receive cash receipts of approximately $15
million during 2023 upon settlement of these contracts, the amount of which is
primarily dependent upon fluctuations in future NYMEX oil prices in relation to
the prices of our 2023 fixed-price swaps (which have a weighted average NYMEX
oil price of $78.12 per Bbl). 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
Three Months Ended
March 31,
In thousands, except per-BOE data 2023 2022
Total lease operating expenses $ 129,174 117,828
Total lease operating expenses per BOE
When comparing the first three months of 2023 and 2022, total lease operating expenses increased by$11.3 million (10%) on an absolute-dollar basis, or$2.22 (8%) on a per-BOE basis. Inflation and higher activity levels resulted in higher labor costs ($2.5 million ), repair and maintenance ($2.4 million ) and workover costs ($2.2 million ) and CO2 costs increased primarily due to an industrial CO2 contract change ($1.3 million ). Compared to the fourth quarter of 2022, lease operating expenses in the most recent quarter increased$3.4 million (3%) on an absolute-dollar basis and$0.81 (3%) on a per-BOE basis, due primarily to higher repair and maintenance and workover costs.
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$5.4 million and$4.6 million for the three months endedMarch 31, 2023 and 2022, respectively. The increase was primarily due to a change in certain of our sales contracts.
Taxes Other Than Income
Taxes other than income includes production, ad valorem and franchise taxes. Taxes other than income decreased$2.3 million (7%) during the three months endedMarch 31, 2023 , compared to the same prior-year period, due primarily to a decrease in production taxes resulting from lower oil and natural gas revenues. 25 --------------------------------------------------------------------------------
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
OperationsGeneral and Administrative Expenses ("G&A")
Three Months Ended
March 31,
In thousands, except per-BOE data and employees 2023 2022
Cash G&A costs $ 18,039 $ 15,721
Stock-based compensation 4,938 2,971
G&A expense $ 22,977 $ 18,692
G&A per BOE
Cash G&A costs $ 4.21 $ 3.72
Stock-based compensation 1.15 0.71
G&A expenses $ 5.36 $ 4.43
Employees as of period end 774 724
Our G&A expense on an absolute-dollar basis was $23.0 million during the three
months ended March 31, 2023 , an increase of $4.3 million from the same
prior-year period, with the increase primarily due to higher employee-related
costs, including salaries and stock compensation expense.
Interest and Financing Expenses
Three Months Ended
March 31,
In thousands, except per-BOE data and interest rates 2023 2022 Cash interest(1)$ 2,089 $ 1,130 Noncash interest expense 531 685 Less: capitalized interest (1,693) (1,158) Interest expense, net$ 927 $ 657 Interest expense, net per BOE$ 0.22 $ 0.16 Average debt principal outstanding$ 62,346 $ 34,278 Average cash interest rate(2) 8.0 % 5.5 % (1)Includes commitment fees paid on the Company's bank credit facility but excludes debt issue costs. (2)Excludes commitment fees paid on the Company's bank credit facility and debt issue costs. 26
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
OperationsDepletion, Depreciation, and Amortization ("DD&A")
Three Months Ended
March 31,
In thousands, except per-BOE data 2023 2022
Oil and natural gas properties $
34,199
6,716 6,677
Accelerated depreciation charge 1,117 -
Total DD&A $ 42,032 $ 35,345
DD&A per BOE
Oil and natural gas properties $
7.97
1.57 1.58
Accelerated depreciation charge 0.26 -
Total DD&A cost per BOE $ 9.80 $ 8.37
DD&A expense during the three months ended March 31, 2023 increased $6.7 million
compared to the three months ended March 31, 2022 , primarily due to higher
depletable costs for our oil and gas properties, accelerated depreciation in the
current period and an increase in accretion expense on our asset retirement
obligations. We expect DD&A expense will be higher subsequent to the initial
booking of proved reserves at our new CCA CO2 flood, which we currently expect
will occur in the second quarter of 2023.
Other Expenses
Other expenses during the three months endedMarch 31, 2023 totaled$1.5 million , compared to$2.1 million during the three months endedMarch 31, 2022 . Other expenses during the three months endedMarch 31, 2023 primarily includes$1.3 million in CCUS-related expenses and$1.0 million of plant operating expense, partially offset by an approximate$1.0 million reversal of the second quarter 2022 accrual for the Delta Pipeline CO2 release incident costs resulting from a negotiated settlement. Other expenses during the three months endedMarch 31, 2022 included$1.0 million in plant operating expenses,$0.3 million in expenses related to the Delta Pipeline incident,$0.3 million in CCUS expenses, and a$0.2 million contingent consideration adjustment related to a previous acquisition. Income Taxes Three Months EndedMarch 31 ,
In thousands, except per-BOE amounts and tax rates 2023 2022 Current income tax expense (benefit)
$ 2,338 $
(561)
Deferred income tax expense (benefit) 25,912
(5,944)
Total income tax expense (benefit)$ 28,250 $
(6,505)
Average income tax expense (benefit) per BOE$ 6.59 $
(1.54)
Effective tax rate 24.1 % 88.2 % Total net deferred tax liability$ 97,031 $
4,306
We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. Our income taxes are based on an estimated combined federal and state statutory rate of approximately 25% in 2023 and 2022. Our effective tax rate for the three months endedMarch 31, 2023 was slightly lower than our estimated statutory rate primarily due to excess stock compensation deductions that were recorded discretely in the quarter. Our effective tax rate for the three months endedMarch 31, 2022 was higher than our estimated statutory rate due to the release of a portion of the 27 --------------------------------------------------------------------------------
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
Operations
valuation allowance on our deferred tax assets combined with the net loss for
the period. Our annualized effective tax rate including any discrete items for
the year ended December 31, 2023 is currently estimated to be approximately 24%.
We make 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. Significant judgment is required in estimating valuation
allowances, and in making this determination we consider all available positive
and negative evidence and make certain assumptions. The realization of a
deferred tax asset ultimately depends on the existence of sufficient taxable
income in the applicable carryback or carryforward periods. In our assessment,
we consider the nature, frequency, and severity of current and cumulative
losses, as well as historical and forecasted financial results, the overall
business environment, our industry's historic cyclicality, the reversal of
existing deferred tax assets and liabilities, and tax planning strategies.
We assess the valuation allowance recorded on our deferred tax assets on a
quarterly basis, which was $59.2 million at December 31, 2022 . This valuation
allowance relates primarily to our Louisiana net deferred tax assets of $55.4
million , as well as our Alabama net deferred tax assets and certain Mississippi
tax credits totaling $3.8 million . We have concluded that the benefits of such
deferred tax assets are not more likely than not to be realized due to lack of
sufficient taxable income to fully realize the benefits of such deferred tax
assets.
During the three months ended March 31, 2023 , we received $0.6 million of
refundable alternative minimum tax credits under the Tax Cut and Jobs Act, which
amount was recorded as a receivable on the balance sheet at December 31, 2022 .
We have state net operating loss carryforwards that expire in various years,
starting in 2025. Our Louisiana net operating loss carryforwards may be carried
forward indefinitely.
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.
Three Months Ended
March 31,
Per-BOE data 2023 2022
Oil and natural gas revenues $ 73.32 $ 91.14
Receipt (payment) on settlements of commodity derivatives 0.49 (22.03)
Lease operating expenses (30.12)
(27.90)
Production and ad valorem taxes (6.59)
(7.21)
Transportation and marketing expenses (1.26)
(1.10)
Production netback 35.84
32.90
CO2 sales, net of operating and discovery expenses 2.21 2.51 General and administrative expenses (5.36) (4.43) Interest expense, net (0.22) (0.16) Stock compensation and other 0.08 0.09 Changes in assets and liabilities relating to operations (11.91) (9.57) Cash flows from operations 20.64 21.34 DD&A (9.54) (8.37) DD&A - accelerated depreciation charge (0.26) - Deferred income taxes (6.04) 1.41 Noncash fair value gains (losses) on commodity derivatives 4.90 (23.60) Other noncash items 11.10 9.01 Net income (loss)$ 20.80 $ (0.21) 28
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Denbury Inc.
Management's Discussion and Analysis of Financial Condition and Results of
OperationsCRITICAL ACCOUNTING POLICIES
For additional discussion of our critical accounting policies, see Management's Discussion and Analysis of Financial Condition and Results of Operations in our Form 10-K. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in the notes to the Company's Unaudited Condensed Consolidated Financial Statements contained in this Quarterly Report on Form 10-Q.
FORWARD-LOOKING INFORMATION
The data and/or statements contained in this Quarterly Report on Form 10-Q,
particularly statements found in "Management's Discussion and Analysis of
Financial Condition and Results of Operations," that are not historical facts,
are forward-looking statements, as that term is defined in Section 21E of the
Securities Exchange Act of 1934, as amended (the "Exchange Act"), that involve a
number of risks and uncertainties, and include, but are not limited to: possible
or assumed future results of operations, cash flows, production and capital
expenditures; goals and predictions as to the Company's future carbon capture,
use and storage ("CCUS") activities; and assumptions as to oil markets or
general economic conditions.
Such forward-looking statements may be or may concern, among other things, the
level and volatility of posted or realized oil prices; the adequacy of our
liquidity sources to support our future activities; statements or predictions
related to the ultimate timing and financial impact of our proposed CCUS
arrangements, including the estimated emissions storage capacity of storage
sites, predictions of long-term cumulative capital investments in CCUS, the
volumes of CO2 emissions we estimate can be transported and stored, along with
the timing of receipt of first revenues from storage of CO2; our projected
production levels, oil and natural gas revenues or oilfield costs, the impact of
supply chain issues and inflation on our results of operations; current or
future expectations or estimations of our cash flows or the impact of changes in
commodity prices on cash flows; availability, terms and financial statement and
cash settlement impact of commodity derivative contracts or their predicted
downside cash flow protection; forecasted drilling activity or methods,
including the timing and location thereof; anticipated timing of initial
production responses in tertiary flooding projects in particular fields or
areas; 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 tax or environmental laws or regulations or in any future
regulation of CO2 pipelines; the outcomes of any pending litigation or
regulatory proceedings; 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
be affected by various factors discussed below, along with currently unknowable
events beyond our control. 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 from current projections
are fluctuations in worldwide or U.S. oil prices, especially in light of
existing economic uncertainties or geopolitical events such as the war in
Ukraine ; widespread inflation in economies across the world; future decisions or
actions as to production levels and/or pricing by OPEC ; as to our CCUS
activities, the successful completion of technical and feasibility evaluations,
the raising of funds sufficient to build and operate add-on or new facilities,
the pace of finalization of CCUS arrangements; and the receipt of required
regulatory approval or classifications; success of our risk management
techniques; 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, or other natural occurrences; conditions in
the worldwide financial, trade currency and credit markets; the risks and
uncertainties inherent in oil and gas drilling and production activities; and
the risks and uncertainties set forth from time to time in this or our other
periodic public reports, other filings and public statements including, without
limitation, the Company's most recent Form 10-K.
29
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Denbury Inc.
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