# W&T OFFSHORE INC (WTI) FY 2024 MD&A

Verbatim Item 7 Management's Discussion and Analysis from W&T OFFSHORE INC's 10-K for fiscal year 2024.

SEC filing source: https://www.sec.gov/Archives/edgar/data/1288403/000155837025002116/wti-20241231x10k.htm
Accession: 0001558370-25-002116
Filing date: 2025-03-04
Report date: 2024-12-31
Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary.
Confidence: high

Company profile: /company/WTI/
All MD&A years: /company/WTI/mda/
Previous year: /company/WTI/mda/fy2023/ (FY 2023)
Next year: /company/WTI/mda/fy2025/ (FY 2025)

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations is based on, and should be read in conjunction with Part I, Item 1. Business, Item 1A. Risk Factors, Item 2. Properties and Item 7A. Quantitative and Qualitative Disclosures About Market Risk and with Part 1I, Item 8. Financial Statements and Supplementary Data and other financial information appearing elsewhere in this 2024 Form 10-K. The following discussion and analysis includes forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those anticipated in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this Form 10-K, particularly in Part I, Item 1A. Risk Factors.

This section primarily discusses 2024 and 2023 items and comparisons between 2024 and 2023. Discussions of 2023 items and comparisons between 2023 and 2022 that are not included in this Form 10-K are incorporated by reference to 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 year ended December 31, 2023.

Business Overview

We are an independent oil and natural gas producer, active in the exploration, development and acquisition of oil and natural gas properties in the Gulf of America. As of December 31, 2024, we held working interests in 52 offshore producing fields in federal and state waters (which include 45 fields in federal waters and seven in state waters). We currently have under lease approximately 646,200 gross acres (502,300 net acres) spanning across the outer continental shelf off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 5,500 gross acres in Alabama state waters, 493,000 gross acres on the conventional shelf and approximately 147,700 gross acres in the deepwater. A majority of our daily production is derived from wells we operate. Our interests in fields, leases, structures and equipment are primarily owned by our wholly-owned subsidiaries and through our proportionately consolidated interest in Monza Energy LLC.

In managing our business, we are focused on optimizing production and making profitable investments, pursuing high rate of return projects and developing oil and natural gas resources in a manner that allows us to grow our production, reserves and cash flow in a capital efficient manner, organically enhancing the value of our assets.

Recent Developments

Business and Operational Updates

On January 16, 2024, we closed on our acquisition of rights, titles and interest in and to certain leases, wells and personal property in the central shelf region of the Gulf of America, among other assets, for $77.3 million (including closing fees and other transaction costs). The acquisition was funded using cash on hand. We also assumed the related

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AROs associated with these assets. This transaction is described in more detail under Financial Statements and Supplementary Data – Note 2 – Acquisitions, under Part II, Item 8 of this Annual Report.

In December 2024, we entered into a purchase and sale agreement to sell a non-core interest in the Garden Banks Blocks 385 and 386. The effective date of the sale was December 1, 2024, and the transaction closed on January 8, 2025 for approximately $11.9 million following customary purchase price adjustments.

Effective December 20, 2024, we entered into a resolution with the third-party pipeline operator at our West Delta 73 field. As a result of this resolution, we expect to restart production from the field in the second quarter of 2025. We originally acquired the West Delta 73 field in our January 2024 acquisition.

In June 2024, we received notice from BSEE that we would be required to cease production at our Main Pass 108 and 98 fields as the result of a shut-in of midstream infrastructure not owned by us. On December 11, 2024, we entered into a purchase agreement and other arrangements with the trustee of the bankruptcy estate of Energy XXI GOM, LLC and Cox Operating L.L.C. (the “Cox Trustee”) to acquire the necessary midstream infrastructure, which is expected to allow us to return the Main Pass 108 and 98 fields to production in the second quarter of 2025. Following developments in connection with the acquisition of the midstream infrastructure, on February 25, 2025, we mutually terminated the purchase agreement with the Cox Trustee and entered into a new purchase agreement with the Cox Trustee including the midstream infrastructure and additional properties. The closing of the acquisitions contemplated by the purchase agreement and subsequent return to production are subject to our obtaining approval from the Bankruptcy Court for the Southern District of Texas, necessary governmental approvals and permits in connection with the acquisitions, in addition to customary closing conditions.

In January 2025, we received $58.5 million related to the settlement of claims related to the Mobile Bay plant turnaround in February 2023. During the turnaround, the MB 78-1 well was shut-in and did not return to production following completion of the planned maintenance. We filed a claim under our Energy Package Policy and in December 2024, we and the underwriters of the Energy Package Policy agreed to a settlement of claims.

Issuance of 10.75% Notes and Related Transactions

On January 28, 2025, we issued $350.0 million of 10.75% Notes. The 10.75% Notes were issued at par and mature on February 1, 2029. The net proceeds from the issuance of the 10.75% Notes along with cash on hand were used to (i) purchase for cash pursuant to a tender offer (the “Tender Offer”), such of our 11.75% Senior Second Lien Notes due 2026 (the “11.75% Notes”) that were validly tendered (and not validly withdrawn) pursuant to the Tender Offer, (ii) on or after August 1, 2025, redeem in full any remaining 11.75% Notes not validly tendered and accepted for purchase in the Tender Offer and, pending such redemptions, satisfy and discharge the indenture governing the 11.75% Notes; (iii) repay outstanding amounts under the credit agreement of certain of our indirect, wholly-owned subsidiaries (the “Term Loan”), and (iv) pay any premiums, fees and expenses relating to these transactions.

Termination of Credit Agreement and Entry into New Credit Agreement

On January 28, 2025, in conjunction with the issuance of the 10.75% Notes, we terminated our Sixth Amended and Restated Credit Agreement (the “Credit Agreement”) and entered into the New Credit Agreement which provides us a revolving credit and letter of credit facility with initial bank lending commitments of $50.0 million with a letter of credit sublimit of $10.0 million. The New Credit Agreement matures on July 28, 2028.

See Financial Statements and Supplementary Data – Note 19 – Subsequent Events under Part II, Item 8 in this Form 10-K for additional information.

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​

Business Outlook

Our financial condition, cash flow and results of operations are significantly affected by the volume of our oil, NGLs and natural gas production and the prices that we receive for such production. Changes in the prices that we receive for our production impact all aspects of our business; most notably our cash flows from operations, revenues, capital allocation and budgeting decisions and our reserves volumes. Prices of oil, NGLs and natural gas have historically been volatile and can fluctuate significantly over short periods of time for many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, domestic production activities and political issues, and international geopolitical and economic events. 

The EIA published its latest Short-Term Energy Outlook in January 2025. The EIA expects downward oil price pressures over much of the next two years as they expect that global oil production will grow more than global oil demand. The EIA forecasts that the spot price for WTI oil will average $70.33 per barrel in 2025, 8% less than 2024, and then continue to fall another 11% to $62.50 per barrel in 2026. The unwinding of OPEC+ production cuts and strong growth in oil production outside of OPEC+ results in global oil production growing in the EIA forecast. Although the EIA is forecasting OPEC+ will increase production, they expect the group will produce less oil than stated in its most recent production target in an effort to avoid significant inventory builds.

The EIA expects the spot prices for Henry Hub natural gas to average $3.14 per MMBtu in 2025 and $3.97 per MMBtu in 2026, up from a historically low average of $2.19 per MMBtu in 2024. The EIA expects wholesale natural gas prices to increase because growth in demand, led by liquified natural gas exports, will outpace production growth and keep inventories in the next two years at or below their previous five-year averages.

Our average realized sales price for oil and natural gas differs from the WTI average price and the NYMEX Henry Hub average price, respectively, primarily due to premiums or discounts, quality adjustments, location adjustments and volume weighting (collectively referred to as differentials). Oil price differentials primarily represent the transportation costs in moving produced oil at the wellhead to a refinery and are based on the availability of pipeline, rail and other transportation. Natural gas price differentials are strongly impacted by local market fundamentals, availability of transportation capacity from producing areas and seasonal impacts. Prices and differentials for NGLs are related to the supply and demand for the products making up these liquids. Some of them more typically correlate to the price of oil while others are affected by natural gas prices as well as the demand for certain chemical products which are used as feedstock.

In addition to the impact of volatile commodity prices on our operations, continuing inflation could also impact our sales margins and profitability. The United States has experienced a rise in inflation since October 2021. Inflation peaked during mid-2022 at 9.1% but the rate of inflation has been gradually declining since the second half of 2022 according to the Consumer Price Index (the “CPI”). The annual inflation rate for December 2024 was 2.9%, a decrease from the 3.4% rate for December 2023. However, the annual inflation rate of January 2025 was 3.0%, an increase from the 2.9% rate for December 2024. Beginning in September 2024, the Federal Reserve made three cuts to the target federal funds rate, bringing the target federal funds range down to 4.25% to 4.50%, easing monetary policy for the first time in four years due to progress in inflation moving sustainably toward 2%. The Summary of Economic Projections published by the Federal Reserve in December 2024 points to another 50 basis points of cuts in 2025. However, if inflation were to continue to rise again, it is possible the Federal Reserve would continue to take action they deem necessary to bring inflation down and to ensure price stability, including targeted federal funds rate increases, which could have the effects of raising the cost of capital and depressing economic growth, either or both of which could negatively impact our business.

Key Challenges and Uncertainties

In addition to general market conditions and competition in the oil and natural gas industry, we believe the following represent the key challenges and uncertainties we will face in the future.

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Commodity Prices

A prolonged period of weak commodity prices may create uncertainties in our financial condition and results of operations. Such uncertainties may include:

[[GREPCENT_TABLE]]
[["","\u25cf","ceiling test write-downs of the carrying value of our oil and natural gas properties;"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u25cf","reductions in our proved reserves and the estimated value thereof;"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u25cf","additional supplemental bonding and potential collateral requirements; and"]]
[[/GREPCENT_TABLE]]

[[GREPCENT_TABLE]]
[["","\u25cf","our ability to fund capital expenditures needed to replace produced reserves, which must be replaced on a long-term basis to provide cash to fund liquidity needs."]]
[[/GREPCENT_TABLE]]

Deferred Production

Since our operations are in the Gulf of America, we are particularly vulnerable to the effects of hurricanes on production and operations. Significant hurricane impacts include reductions and/or deferrals of future oil and natural gas production and revenues, increased lease operating expenses for evacuations and repairs and possible acceleration of plugging and abandonment costs.

Our production was impacted due to precautionary shut-ins of facilities and evacuations associated with Hurricanes Francine, Helene and Rafael. For 2024, we estimate deferred production related to Hurricane Francine was approximately 132.8 MBoe and affected 35 fields, deferred production related to Hurricane Helene was approximately 17.2 MBoe and affected five fields and deferred production related to Hurricane Rafael was approximately 3.4 MBoe and affected three fields.

Production downtime following these hurricanes was extended as a result of damage and power loss at third party downstream facilities, including oil terminals, natural gas processing plants and refineries, causing them to remain offline for several weeks. While our assets and infrastructure did not suffer significant damage during the storm, we incurred $1.1 million of unplanned costs for minor repairs and restoring production, as well as evacuating employees and contractors, as a result of the hurricane. These amounts are reflected in lease operating expense.

In addition, our oil, NGLs and natural gas production can also be significantly affected by both planned and unplanned production downtime caused by events such as planned repairs and upgrades, third-party downtime associated with non-operated properties and the transportation, gathering or processing of production and weather events. For 2024, we estimate deferred production was approximately 2.6 MMBoe, excluding the deferred production from the hurricanes.

BOEM Matters  

The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations or provide acceptable financial assurances to satisfy lease obligations, including decommissioning activities on the OCS. In April 2024, BOEM released a final rule that changes the way BOEM evaluates the financial health of companies and offshore assets in setting financial assurance requirements. Under the new rule, BOEM streamlined the criteria used to evaluate the financial health of an energy company down to two factors: (i) the company’s credit rating, and (ii) the ratio of the value of the company’s proved reserves to decommissioning liability associated with those reserves. The new rule also codifies the usage of BSEE decommissioning estimates to evaluate supplemental financial assurance requirements and allows third party guarantors (upon agreement with BOEM) to provide limited guarantees to specific amounts or specific leases instead of the blanket guarantees that have been used in the past. Finally, the new rule also requires a base financial assurance requirement of $500,000 for federal RUEs to match the requirement for state RUEs. To provide the industry with flexibility to meet the new financial assurance requirements, BOEM will allow current lessees and grant holders to request phased-in payments over a three-year period. BOEM estimates that the industry will be required to provide $6.9 billion in new financial assurances under the new rule, which took effect on June 29, 2024. Following the announcement of the new rule, a series of lawsuits from both states and industry groups have been filed against BOEM to block the implementation of the new rule. We are actively monitoring ongoing litigation with respect to the new rule. However, President Trump may seek to suspend, revise or rescind this final rule pursuant to Interior Secretary Burgum’s Secretarial Order 3418 dated February 2, 2025. The substance and timing of such legal and regulatory actions cannot be predicted at this time. The future cost of compliance with respect to supplemental financial assurances, including the

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obligations imposed on us, whether as current or predecessor lessee or grant holder in respect of BOEM’s final rule or any new, more stringent, rules related to supplemental financial assurances could materially and adversely affect our financial condition, cash flows, liquidity and results of operations. Additionally, regardless of the final rule, BOEM has the right to issue liability orders in the future, including if it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities. For more information on the BOEM and financial assurance obligations to that agency, see Business – Environmental, Health and Safety Matters and Government Regulations – Other Regulation of the Oil and Natural Gas Industry under Part I, Item 1 of this Form 10-K.

Bonding

In prior years, some of the sureties, which provided us surety bonds that we use for supplemental financial assurance purposes, requested and received collateral from us. Pursuant to the terms of our agreement with various sureties under out existing bonding arrangements, we may be required to post collateral. These sureties may request additional collateral from us in the future, which could be significant and could materially impact our liquidity.

To the extent we are unable to provide collateral or provide an adequate alternative, including financing, we may be forced to reduce our capital expenditures in the current year or future years, may be unable to execute our ARO plan or may be unable to comply with our existing debt instruments.

To the extent that the Sureties succeed in forcing us to fulfill the Demanded Collateral, or in the event that other surety entities attempt to do the same, the fulfilment of such demands could be significant and our liquidity position could be negatively impacted, and we may be required to seek alternative financing.

For more information on risks associated with our bonding, please see Risk Factors under Part I, Item 1A of this Form 10-K.

RESULTS OF OPERATIONS

Revenues

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs. Our oil, NGL and natural gas revenues do not include the effects of derivatives, which are reported in Derivative (gain) loss, net in our Consolidated Statements of Operations.

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The following table presents information regarding our revenues, production volumes and average realized sales prices (which exclude the effect of hedging unless otherwise stated) for 2024 and 2023 (in thousands, except average realized sales prices data):

[[GREPCENT_TABLE]]
[["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","Year Ended December 31,","\u200b","\u200b","\u200b"],["\u200b","\u200b","2024","","2023","","\u200b","Change"],["Revenues:","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Oil","\u200b","$","395,620","\u200b","$","381,389","\u200b","$","14,231"],["NGLs","\u200b","","27,978","\u200b","","32,446","\u200b","","(4,468)"],["Natural gas","\u200b","","90,877","\u200b","","110,158","\u200b","","(19,281)"],["Other","\u200b","","10,786","\u200b","","8,663","\u200b","","2,123"],["Total revenues","\u200b","$","525,261","\u200b","$","532,656","\u200b","$","(7,395)"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Production Volumes:","\u200b","","","\u200b","","","\u200b"],["Oil (MBbls)","\u200b","","5,255","\u200b","","5,050","\u200b","","205"],["NGLs (MBbls)","\u200b","","1,212","\u200b","","1,415","\u200b","","(203)"],["Natural gas (MMcf)","\u200b","","34,296","\u200b","","37,591","\u200b","","(3,295)"],["Total oil equivalent (MBoe)","\u200b","","12,183","\u200b","\u200b","12,730","\u200b","\u200b","(547)"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Average daily equivalent sales (Boe/day)","\u200b","\u200b","33,287","\u200b","\u200b","34,877","\u200b","\u200b","(1,590)"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Average realized sales prices:","\u200b","","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Oil ($/Bbl)","\u200b","$","75.28","\u200b","$","75.52","\u200b","$","(0.24)"],["NGLs ($/Bbl)","\u200b","","23.08","\u200b","","22.93","\u200b","","0.15"],["Natural gas ($/Mcf)","\u200b","","2.65","\u200b","","2.93","\u200b","","(0.28)"],["Oil equivalent ($/Boe)","\u200b","\u200b","42.23","\u200b","\u200b","41.16","\u200b","\u200b","1.07"],["Oil equivalent ($/Boe), including realized commodity derivatives","\u200b","","42.47","\u200b","","40.84","\u200b","","1.63"]]
[[/GREPCENT_TABLE]]

​

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Changes in average sales prices and production volumes caused the following changes to our oil, NGL and natural gas revenues between 2024 and 2023 (in thousands):

[[GREPCENT_TABLE]]
[["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","Price","","Volume","\u200b","Total"],["Oil","$","(1,208)","\u200b","$","15,439","\u200b","$","14,231"],["NGLs","","172","\u200b","\u200b","(4,640)","\u200b","","(4,468)"],["Natural gas","","(9,626)","\u200b","\u200b","(9,655)","\u200b","","(19,281)"],["\u200b","$","(10,662)","\u200b","$","1,144","\u200b","$","(9,518)"]]
[[/GREPCENT_TABLE]]

​

Production volumes decreased by 547 MBoe to 12,183 MBoe during 2024 compared to the same period in 2023, primarily due to deferred production of approximately 0.8 MMBoe at our Mobile Bay Properties, approximately 0.3 MMBoe from the shut-on of the MP 98 and 108 fields and approximately 0.2 MMBoe from the effects of Hurricanes Francine, Helene and Rafael. These decreases were partially offset by approximately 1.9 MMBoe of production from wells acquired in both the January 2024 and the September 2023 acquisitions.

Operating Expenses

The following table presents information regarding costs and expenses and selected average costs and expenses per Boe sold for the periods presented and corresponding changes (in thousands):

[[GREPCENT_TABLE]]
[["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","Year Ended December 31,","\u200b","\u200b","\u200b"],["\u200b","","2024","","2023","","\u200b","Change"],["Operating expenses:","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Lease operating expenses","\u200b","$","281,488","\u200b","$","257,676","\u200b","$","23,812"],["Gathering, transportation and production taxes","\u200b","\u200b","28,177","\u200b","\u200b","26,250","\u200b","\u200b","1,927"],["Depreciation, depletion and amortization","","\u200b","143,025","\u200b","\u200b","114,677","","\u200b","28,348"],["Asset retirement obligations accretion expense","","\u200b","32,374","\u200b","\u200b","29,018","","\u200b","3,356"],["General and administrative expenses","\u200b","\u200b","82,391","\u200b","\u200b","75,541","\u200b","\u200b","6,850"],["Total operating expenses","\u200b","$","567,455","\u200b","$","503,162","\u200b","$","64,293"],["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Average per Boe ($/Boe):","\u200b","","","\u200b","","","\u200b"],["Lease operating expenses","\u200b","$","23.10","\u200b","$","20.24","\u200b","$","2.86"],["Gathering, transportation and production taxes","\u200b","","2.31","\u200b","","2.06","\u200b","","0.25"],["Depreciation, depletion and amortization","\u200b","","11.74","\u200b","","9.01","\u200b","","2.73"],["Asset retirement obligations accretion expense","\u200b","\u200b","2.66","\u200b","\u200b","2.28","\u200b","\u200b","0.38"],["General and administrative expenses","\u200b","","6.76","\u200b","","5.93","\u200b","","0.83"],["Total operating expenses","\u200b","$","46.57","\u200b","$","39.52","\u200b","$","7.05"]]
[[/GREPCENT_TABLE]]

​

Lease operating expenses

Lease operating expenses include the expense of operating and maintaining our wells, platforms and other infrastructure primarily in the Gulf of America. These operating costs are comprised of several components including direct or base lease operating expenses, insurance premiums, workover costs and facility maintenance expenses. Our lease operating costs, which depend in part on the type of commodity produced, the level of workover activity and the geographical location of the properties, increased $23.8 million to $281.5 million in 2024 compared to $257.7 million in 2023. On a per Boe basis, lease operating expenses increased to $23.10 per Boe during 2024 compared to $20.24 per Boe during 2023. On a component basis, base lease operating expenses increased $30.2 million, facility maintenance expenses increased $7.9 million and hurricane repairs increased $1.0 million, These increases were partially offset by a decrease of $15.3 million in workover expenses.

Expenses for direct labor, materials, supplies, repair, third-party costs and insurance comprise the most significant portion of our base lease operating expense. Base lease operating expenses increased primarily due to increases of $37.5 million of expenses at the fields acquired in January 2024 and September 2023 partially offset by $6.1 million of reduced expenses from the abandonment work to shutdown certain of our fields.

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Workover and facilities maintenance expenses consist of costs associated with major remedial operations on completed wells to restore, maintain or improve the well’s production. Since these remedial operations are not regularly scheduled, workover and maintenance expense are not necessarily comparable from period to period. The decrease in workover expenses and the increase in facilities maintenance expenses were due to the timing and mix of projects undertaken.

Hurricane expenses consist of costs for minor repairs and restoring production, as well as evacuating employees and contractors incurred as a result of Hurricanes Francine, Helene and Rafael.

Gathering, transportation and production taxes 

Gathering and transportation consist of costs incurred in the post-production shipping of oil, NGLs, and natural gas to the point of sale. Production taxes consist of severance taxes levied by the Alabama Department of Revenue , the Louisiana Department of Revenue and the Texas Department of Revenue on production of oil and natural gas from land or water bottoms within the boundaries of each state. Gathering, transportation and production taxes increased to $28.2 million in 2024 compared to $26.3 million in 2023, primarily due to increase of $1.5 million in gathering and transportation fees and $0.4 million in production taxes. Gathering and transportation fees increased during the first half of 2024 compared with the first half of 2023 primarily related to higher production volumes in the first quarter of 2024 and higher processing fees for our Mobile Bay production that had to be re-routed to a different processing plant due to the shut-in of our primary Mobile Bay processing plant. These fees decreased in the second half of 2024 as our production volumes decreased compared with the same period in 2023. The increase in production taxes is primarily related to the start of payments to the state of Louisiana from our acquisition of oil and natural gas properties in September 2023.

Depreciation, depletion and amortization

 Depreciation, depletion and amortization expense (“DD&A”) is the expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas reserves. We use the full cost method of accounting for oil and natural gas activities. DD&A increased $28.3 million for 2024 compared to 2023 primarily due to increases of $33.3 million from an increase in the depletion rate per Mcfe and $1.3 million for depreciation of other property and the corporate airplane acquired in May 2023, partially offset by $6.3 million from the decrease in production for 2024 compared with 2023. The DD&A rate increased to $11.74 per Boe in 2024 from $9.01 per Boe in 2023. The DD&A rate per Boe increased primarily as a result of a higher depreciable base due to our January 2024 acquisition, increases in capital expenditures, future development costs and capitalized ARO and lower proved reserves.

Asset retirement obligations accretion expense

Accretion expense is the expensing of the changes in value of our ARO as a result of the passage of time over the estimated productive life of the related assets as the discounted liabilities are accreted to their expected settlement values. Accretion expense increased to $32.4 million in 2024 compared to $29.0 million in 2023 primarily due to our acquisition in January 2024 and revisions to the estimates used in calculating the liability. 

General and administrative expenses

General and administrative (“G&A”) expenses generally consist of costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production operations, bad debt expense, share-based compensation costs, audit and other fees for professional services and legal compliance. For 2024, G&A expenses were $82.4 million compared to $75.5 million in 2023. The increase is primarily due to increases of (i) $4.0 million in payroll costs consisting of $1.8 million related to merit and headcount increases and a $2.2 million employee retention credit recorded in 2023, (ii) $2.8 million in non-recurring legal fees and (iii) $1.9 million in medical claims cost, partially offset by a $2.1 million decrease in short-term incentive compensation costs.

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Other Income and Expense

The following table presents the components of other income and expense for the periods presented and corresponding changes (in thousands):

[[GREPCENT_TABLE]]
[["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","Year Ended December 31,","\u200b","\u200b","\u200b"],["\u200b","","2024","","2023","","\u200b","Change"],["Interest expense, net","\u200b","$","40,454","\u200b","$","44,689","\u200b","$","(4,235)"],["Derivative gain, net","","\u200b","(3,589)","\u200b","\u200b","(54,759)","","\u200b","51,170"],["Other expense, net","","\u200b","18,071","\u200b","\u200b","5,621","","\u200b","12,450"],["Income tax (benefit) expense","","\u200b","(9,985)","\u200b","\u200b","18,345","","\u200b","(28,330)"]]
[[/GREPCENT_TABLE]]

​

Interest expense, net

 Interest expense, net of interest income, decreased $4.2 million for 2024 compared with 2023 primarily due to decreases of $7.9 million from the redemption in February 2023 of our 9.75% Senior Second Lien Notes due 2023 and $1.9 million from the lower outstanding principal balance of the Term Loan, partially offset by $2.8 million incurred on the 11.75% Notes issued in late January 2023 and a $2.6 million decrease in interest income.

Derivative gain, net  

Unrealized gains or losses on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on our Consolidated Statements of Operations at the end of each month. During 2024, the $3.6 million derivative gain consisted of $2.9 million of realized gains on settled contracts and $0.7 million of unrealized gain, net, from the increase in the fair value of the open contracts. During 2023, the $54.8 million derivative gain consisted of $4.1 million of realized losses on settled contracts and $58.9 million of unrealized gain, net, from the increase in the fair value of the open contracts.

As a result of the derivative contracts we have on our anticipated natural gas production volumes through April 2028, we expect these activities to continue to impact net income based on fluctuations in market prices for natural gas.

Other expense, net

During 2024, other expense, net, was $18.1 million, compared to $5.6 million for 2023. During 2024 and 2023, other expense primarily consisted of $20.9 million and $6.2 million, respectively, of additional expenses for net abandonment obligations pertaining to a number of legacy Gulf of America properties, partially offset by fees paid by producers to tie into our subsea equipment at one of our wells.

Income tax (benefit) expense

Our effective tax rates for 2024 and 2023 were 10.3% and 54.0%, respectively. These rates differed from the federal statutory rate of 21% primarily due to the impact of state income taxes, non-deductible compensation and adjustments to the valuation allowance on our deferred tax assets.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity Overview

Our primary liquidity needs are to fund capital and operating expenditures and strategic acquisitions to allow us to replace our oil and natural gas reserves, repay and service outstanding borrowings, operate our properties and satisfy our ARO. We have funded such activities in the past with cash on hand, net cash provided by operating activities, sales of property, securities offerings and bank and other borrowings, and expect to continue to do so in the future.

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We expect to support our business requirements primarily with cash on hand and cash generated from operations. As of December 31, 2024, we had $109.0 million of available cash on hand and $50.0 million available under our Credit Agreement, based on a borrowing base of $50.0 million. We also have up to approximately $83.0 million of availability through our “at-the-market” equity offering program, pursuant to which we may offer and sell shares of our common stock from time to time. Based on our current financial condition and current expectations of future market conditions, we believe our cash on hand, cash flows from operating activities and access to the equity markets from our “at-the-market” equity offering program will provide us with additional liquidity to continue our growth to take advantage of the current commodity environment and will allow us to meet our cash requirements for at least the next 12 months and beyond.

We continuously review our liquidity and capital resources. If market conditions were to change, for instance, due to uncertainty created by geopolitical events, a pandemic or a significant prolonged decline in oil and natural gas prices, and our revenue was reduced significantly or operating costs were to increase significantly, our cash flows and liquidity could be negatively impacted.

Cash Flow Information

The following table summarizes cash flows provided by (used in) by type of activity for the following periods (in thousands):

[[GREPCENT_TABLE]]
[["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","Year Ended December 31,","\u200b","\u200b","\u200b"],["\u200b","\u200b","2024","\u200b","2023","\u200b","\u200b","Change"],["Operating activities","\u200b","$","59,539","\u200b","$","115,326","\u200b","$","(55,787)"],["Investing activities","\u200b","","(118,177)","\u200b","","(81,608)","\u200b","","(36,569)"],["Financing activities","\u200b","","(8,562)","\u200b","","(321,737)","\u200b","","313,175"]]
[[/GREPCENT_TABLE]]

​

Operating activities – Net cash provided by operating activities for 2024 was $59.5 million, decreasing $55.8 million from 2023. This was primarily due to decreases of $37.6 million in net (loss) income adjusted for certain non-cash items and $18.2 million from changes in operating assets and liabilities. The decrease in net (loss) income adjusted for certain non-cash items was primarily related to a $7.4 million decrease in revenues and increases in cash operating expenses, partially offset by a $13.5 million increase in derivative cash receipts. The decrease in operating assets and liabilities is primarily related to lower accounts receivable balances due to decreased revenues partially offset by higher accounts payable and accrued liabilities balances in the current period.

Investing activities – Net cash used in investing activities for 2024 increased $36.6 million compared to 2023. This was primarily due to an increase of $53.3 million in acquisition of property interests, partially offset by a decrease of $4.5 million in investment in oil and natural gas properties and the purchase of the corporate aircraft during 2023.

Financing activities – Net cash used in financing activities during 2024 decreased by $313.2 million compared to 2023. This was primarily due to the redemption of the $552.5 million principal amount outstanding of the 9.75% Notes in February 2023 partially offset by the net cash proceeds of $275.0 million received from the issuance of the 11.75% Notes in January 2023.

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Capital Expenditures

The level of our investment in oil and natural gas properties changes from time to time depending on numerous factors including the prices of oil, NGLs and natural gas, acquisition opportunities, liquidity and financing options and the results of our exploration and development activities.

The following table presents our investments in oil and gas properties and equipment for exploration, development, acquisitions and other leasehold costs (in thousands):

[[GREPCENT_TABLE]]
[["\u200b","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["\u200b","\u200b","Year Ended December 31,"],["\u200b","","2024","","2023"],["Exploration and development","\u200b","\u200b","\u200b","\u200b","\u200b","\u200b"],["Conventional shelf (1)","\u200b","$","17,755","\u200b","$","14,464"],["Deepwater","\u200b","\u200b","7,650","\u200b","\u200b","25,551"],["Acquisitions of interests","\u200b","","80,635","\u200b","","27,384"],["Seismic and other","\u200b","","8,150","\u200b","","1,263"],["Investments in oil and gas property/equipment \u2013 accrual basis","\u200b","$","114,190","\u200b","$","68,662"]]
[[/GREPCENT_TABLE]]

​

[[GREPCENT_TABLE]]
[["(1)","Includes exploration and development capital expenditures in Alabama state waters."]]
[[/GREPCENT_TABLE]]

Our preliminary capital expenditure budget for 2025 has been established in the range of $34.0 million to $42.0 million, which excludes acquisitions. In our view of the outlook for 2025, we believe this level of capital expenditure will enhance our liquidity capacity throughout 2025 and beyond while providing liquidity to make strategic acquisitions. At current pricing levels, we expect our cash flows to cover our liquidity requirements, and we expect additional financing sources to be available if needed. If our liquidity becomes stressed from significant or prolonged reductions in realized prices, we have flexibility in our capital expenditure budget to reduce investments. We strive to maintain flexibility in our capital expenditure projects and if commodity prices improve, we may increase our investments.

Acquisitions  

We have grown by making strategic acquisitions of producing properties in the Gulf of America. We seek opportunities where we can exploit additional drilling projects and reduce costs. In January 2024, we closed on the acquisition of rights, titles and interest in and to certain leases, wells and personal property in the central shelf region of the Gulf of America, among other assets, for $77.3 million, subject to customary purchase price adjustments. The transaction was funded with cash on hand. We also received a final settlement statement for our September 2023 acquisition of certain oil and natural gas producing assets in the central and eastern shelf region of the Gulf of America and recorded an additional $3.3 million of oil and natural gas properties.

Any future acquisitions are subject to the completion of satisfactory due diligence, the negotiation and resolution of significant legal issues, the negotiation, documentation and completion of mutually satisfactory definitive agreements among the parties, the consent of our lenders, our ability to finance the acquisition and approval of our board of directors. We cannot guarantee that any such potential transaction would be completed on acceptable terms, if at all.

Asset Retirement Obligations

We have obligations to plug and abandon wells, remove platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations. During 2024, we paid $39.7 million related to these obligations. Our ARO estimates as of December 31, 2024 and 2023 were $548.8 million and $498.8 million, respectively. As our ARO estimates are for work to be performed in the future, and in the case of our non-current ARO, extend from one-to-many years in the future, the timing and amount of actual expenditures could be substantially different than our estimates. See Part I, Item 1A. Risk Factors and Financial Statements and Supplementary Data – Note 4 – Asset Retirement Obligations under Part II, Item 8 in this Form 10-K for additional information regarding our ARO.

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Debt

As of December 31, 2024, we have $399.1 million in aggregate principal amount of long-term debt outstanding, with $28.7 million in aggregate principal coming due over the next twelve months.

On January 28, 2025, we issued $350.0 million of 10.75% Notes. The 10.75% Notes were issued at par and mature on February 1, 2029. We also terminated the Credit Agreement and used the net proceeds from the issuance of the 10.75% Notes and cash on hand to repay in full all outstanding amounts owed under the Term Loan and the 11.75% Notes outstanding.

On January 28, 2025, in conjunction with the issuance of the 10.75% Notes, we entered into the New Credit Agreement which provides us a revolving credit and letter of credit facility with initial bank lending commitments of $50.0 million with a letter of credit sublimit of $10.0 million. The New Credit Agreement matures on July 28, 2028.

For additional information about our long-term debt, see Part II, Item 8. Financial Statements and Supplementary Data – Note 5 – Debt and Note 19 – Subsequent Events of this Annual Report.

Dividends

In November 2023, we announced that our board of directors approved the implementation of a quarterly cash dividend payable to holders of common stock. During 2024, we have paid cash dividends totaling approximately $6.0 million to holders of our common stock. The amount and frequency of future dividends is subject to the discretion of our board of directors and primarily depends on earnings, capital expenditures, debt covenants and various other factors. For additional information about our dividends, see Part II, Item 8. Financial Statements and Supplementary Data – Note 7 – Stockholders’ Equity and Note 19 – Subsequent Events of this Annual Report.

Contractual Obligations and Commitments

Our material cash commitments from known contractual and other obligations consist primarily of obligations for debt and related interest, operating leases, ARO and other obligations as part of normal operations. Certain amounts included in our contractual obligations as of December 31, 2024 are based on our estimates and assumptions about these obligations, including their duration, anticipated actions by third parties and other factors.

See Financial Statements and Supplementary Data – Note 5 – Debt under Part II, Item 8 in this 10-K for information regarding scheduled maturities of our debt. See Financial Statements and Supplementary Data – Note 10 – Leases under Part II, Item 8 in this 10-K for information regarding scheduled maturities of our operating leases.

As of December 31, 2024, we had expected cash payments for estimated interest on our long-term debt of $10.1 million payable within the next twelve months and $10.2 million payable through the maturity dates of our long-term debt.

We entered into a drilling contract during 2023. As of December 31, 2024, we anticipate that rig preparation work will begin in the fourth quarter of 2025 and drilling will begin in March 2026. We expect the total obligation under the contract to be approximately $9.9 million.

As of December 31, 2024, we had obligations for estimated fees for surety bonds related to obligations under certain purchase and sale agreements and for supplemental bonding for plugging and abandonment of $6.7 million payable in the next twelve months and $80.3 million through the estimated timing of the plugging and abandonment obligation occurs. The amounts are based on current market rates and conditions for these types of bonds and are subject to change. Excluded are potential increases in surety bond requirements which cannot be determined.

Additionally, we have obligations related to estimates of minimum quantities obligations for certain pipeline contracts which were assumed in conjunction with the purchase of an interest in the Heidelberg field of $0.6 million in the next twelve months and $1.0 million through the term of the contracts.

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We have obligations under joint interest arrangements related to commitments that have not yet been incurred. In these instances, we are obligated to pay, according to our interest ownership, a portion of exploration and development costs, and operating costs, which potentially could be offset by our interest in future revenue from these non-operated properties. We also have obligations to plug and abandon well bores, remove platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations. These obligations for future commitments cannot be determined due to the variability of factors involved.

CRITICAL ACCOUNTING ESTIMATES

An accounting policy is deemed to be critical if the nature of the estimate or assumption it incorporates is subject to a material level of judgment related to matters that are highly uncertain and changes in those estimates and assumptions are reasonably likely to materially impact our consolidated financial statements. These estimates reflect our best judgment about current, and for some estimates, future, economic and market conditions and their potential effects based on information available as of the date of these financial statements. Our most significant accounting policies are discussed in Financial Statements and Supplementary Data – Note 1 – Significant Accounting Policies under Part II, Item 8 in this Form 10-K.

We believe that the following are the critical accounting estimates used in the preparation of our consolidated financial statements for the year ended December 31, 2024. There are other items within our consolidated financial statements that require estimation and judgment, but they are not deemed critical as defined above.

Accounting for Oil and Natural Gas Properties

We account for our oil and natural gas operations using the full cost method of accounting. Under this method, substantially all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the internal costs directly related to acquisition, development and exploration activities, asset retirement costs, and capitalized interest. Under the full cost method, dry hole costs, geological and geophysical costs, and overhead costs directly related to these activities are capitalized into the full cost pool, which is subject to amortization and assessed for impairment on a quarterly basis through a ceiling test calculation as discussed below.

Our rate of recording depletion expense is primarily dependent upon our estimate of proved reserves, which is utilized in our unit-of-production method calculation. If the estimates of proved reserves were to be reduced, the rate at which we record depletion expense would increase, reducing net income. Such a reduction in reserves may result from calculated lower market prices for oil, NGLs and natural gas, which may make it non-economic to drill for and produce higher cost reserves. At December 31, 2024, a five percent positive revision to proved reserves would decrease the depletion rate by approximately $0.09 per Mcfe and a five percent negative revision to proved reserves would increase the depletion rate by approximately $0.10 per Mcfe.

Under the full cost method, we are subject to quarterly calculations of a ceiling or limitation on the amount of our oil and natural gas properties that can be capitalized on our Consolidated Balance Sheet. If the net capitalized costs of our oil and natural gas properties exceed the cost center ceiling, we are subject to a ceiling test write-down to the extent of such excess. If required, it would reduce earnings in the period of occurrence and could result in lower amortization expense in future periods.

The PV-10 of our estimated proved reserves is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. However, the associated prices of oil, NGL and natural gas reserves that are included in the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that we use the unweighted arithmetic average price of oil and natural gas as of the first day of each month for the 12-month period ending at the balance sheet date. If average oil and natural gas prices decline, it is possible that write-downs of our oil and natural gas properties could occur in the future. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

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Using the first-day-of-the-month average for the 12-months ended December 31, 2024 of the WTI oil spot price of $76.32 per barrel, adjusted by lease or field for quality, transportation fees, and regional price differentials, and the first-day-of-the-month average for the 12-months ended December 31, 2024 of the Henry Hub natural gas price of $2.13 per MMBtu, adjusted by lease or field for energy content, transportation fees, and regional price differentials, our ceiling test calculation did not generate an impairment at December 31, 2024. Additionally, a 10% reduction in PV-10 at December 31, 2024, while all other factors remained constant, would also not have generated an impairment.

The policies discussed above impact the carrying value of our properties and involve significant judgments about the impact of future events on our estimated cash flows. Future events and circumstances currently unknown to us could require future impairments to our properties and materially change the carrying value of our properties.

Oil and Natural Gas Reserve Quantities

Proved oil, NGL and natural gas reserves are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board. The rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalation in future years except by contractual arrangements. Our reserve estimates are prepared by our reserve engineers and our independent petroleum consultant, NSAI.

Our reserve estimates are updated at least annually using geological and reserve data, as well as production performance data. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates, while decreases in recoverable economic volumes generally increase per unit depletion rates. A decline in proved reserves may result from lower market prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimate may impact the outcome of our assessment of oil and natural gas producing properties for impairment. We cannot predict what reserve revisions may be required in future periods.

We periodically reevaluate proved reserves along with estimates of future production rates, production costs and the timing of development expenditures. Future results of operations for any period could be materially affected by changes in our assumptions. Significant changes in these estimates could result in a change to our estimated reserves, which could lead to a material change to our production depletion expense.

Asset Retirement Obligations

We have significant obligations associated with the retirement of our oil and natural gas wells and related infrastructure. We have obligations to plug and abandon all wells, remove our platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and natural gas production operations. Estimating the future restoration and removal cost requires us to make estimates and judgments because the removal obligations may be many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

We accrue a liability with respect to these obligations based on our estimates of the timing and the fair value of an obligation to replace, remove or retire the associated assets. After initial recording, the liability is accreted to its future estimated value using an assumed cost of funds.

In estimating the liability associated with our AROs, we utilize several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate. To the extent future revisions to these estimates impact the value of our abandonment liability, a corresponding adjustment is made to our oil and natural gas property balance.

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Income Taxes

Our income tax expense and deferred tax assets and liabilities reflect management’s best assessment of estimated current and future taxes to be paid. Significant judgments and estimates are required in determining consolidated income tax expense.

Deferred income taxes arise from temporary differences between the book carrying amounts and the tax basis of assets and liabilities, which will result in taxable or deductible amounts in the future. In evaluating our ability to recover our deferred tax assets, we consider all available positive and negative evidence including scheduled reversals of deferred tax liabilities, projected future taxable income, tax–planning strategies and results of recent operations. In projecting future taxable income, we begin with historical results adjusted for changes in accounting policies and incorporate assumptions, including the amount of future U.S. federal and state pretax operating income, the reversal of temporary differences and the implementation of feasible and prudent tax–planning strategies. These assumptions require significant judgment about the forecasts of future taxable income and are consistent with the plans and estimates we use to manage the underlying business.

As of December 31, 2024, we have federal net operating loss (“NOL”) carryforwards of $51.5 million that do not expire, state NOL carryforwards of $104.1 million that expire on various dates from 2026 through 2043 and interest expense limitation carryforwards that do not expire. We believe that it is more likely than not that the benefit from certain of these carryforwards will not be realized. In recognition of this risk, we have provided a valuation allowance of $29.2 million on the deferred tax assets related to these carryforwards. If our assumptions change and we determine that we will be able to realize these carryforwards, the tax benefits related to any reversal of the valuation allowance on deferred tax assets as of December 31, 2024 would be recognized as a reduction of income tax expense.