W&T OFFSHORE INC (WTI)

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:

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):

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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):

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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):

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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):

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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):

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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):

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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.

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 2. Properties, Item 1A. Risk Factors 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 2023 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 2023 and 2022 items and comparisons between 2023 and 2022. Discussions of 2021 items and comparisons between 2022 and 2021 that are not included in the 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, 2022.

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 Mexico. As of December 31, 2023, we held working interests in 53 offshore producing fields in federal and state waters (which include 44 fields in federal waters and nine in state waters). We currently have under lease approximately 597,100 gross acres (440,000 net acres) spanning across the outer continental shelf off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 8,000 gross acres in Alabama state waters, 435,600 gross acres on the conventional shelf and approximately 153,500 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.

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.

Business Outlook

Our cash flows are materially impacted by the prices of commodities we produce (oil, NGLs and natural gas). During 2023, commodity prices experienced significant declines from those experienced during 2022. The average WTI oil price for 2023 was approximately 18% lower than the average for 2022 and the average Henry Hub natural gas price for 2023 was approximately 61% lower than the average for 2022. While the current outlook for commodity prices is favorable, other global factors could adversely impact our operations, and commodity prices could significantly decline from current levels.

In addition, the prices of goods and services used in our business can vary and impact our cash flows and margins. Our margins in 2023 decreased from 2022 primarily due to lower average realized commodity prices, coupled with higher operating expenses. We measure margins using an Adjusted EBITDA margin which we define as net income (loss) before income tax expense, net interest expense, depreciation, depletion, amortization and accretion, unrealized commodity derivative gain or loss and the effects of derivative premium payments, allowance for credit losses, non-cash incentive compensation, non-recurring costs related to IT services transition, non-ARO P&A costs, and other miscellaneous costs as a percent of revenue, which is not a financial measurement under GAAP.

Although we have historically increased our reserves and production through acquisitions, our drilling program, and other projects that optimize production on existing wells, our production decreased 13% in 2023 from the prior year. Our proved reserves also decreased by 42.3 MMBoe in 2023, primarily due to the significant decrease in commodity prices in 2023 as compared to 2022.

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We continually monitor current and forecasted commodity prices to assess what changes, if any, should be made to our 2024 plans. See Liquidity and Capital Resources under this Item 7 in this Form 10-K for additional information.

Recent Developments

On December 13, 2023, we entered into a purchase and sale agreement to acquire rights, titles and interest in and to certain leases, wells and personal property in the central shelf region of the Gulf of Mexico, among other assets, for a gross purchase price of $72.0 million, subject to customary purchase price adjustments. The transaction closed on January 16, 2024 and was funded using cash on hand. The Company also assumed the related AROs associated with these assets.

On February 28, 2024, we amended the Credit Agreement to extend the maturity date to March 28, 2024.

On March 5, 2024, we declared a first quarter dividend of $0.01 per share. We expect to pay the dividend on March 25, 2024, to stockholders of record as of the close of business on March 18, 2024.

Factors Affecting the Comparability of our Financial Condition and Results of Operations

In January 2023, we issued $275.0 million of 11.75% Notes. The 11.75% Notes were issued at par and have a maturity date of February 1, 2026. In February 2023, we redeemed all of the 9.75% Notes outstanding at a redemption price of 100.000%, plus accrued and unpaid interest to the redemption date. We used the net proceeds from the issuance of the 11.75% Notes and $296.1 million of cash on hand to fund the redemption. See Financial Statements and Supplementary Data –Note 2 – Debt under Part II, Item 8 in this Form 10-K for additional information.

In September 2023, we acquired working interests in certain oil and natural gas producing assets in the central and eastern shelf region of the Gulf of Mexico for $27.4 million. This transaction is described in more detail under Financial Statements and Supplementary Data – Note 7 – Acquisitions, under Part II, Item 8 of this Annual Report.

Known Trends and Uncertainties

Volatility in Oil, NGL and Natural Gas Prices – Historically, the markets for oil and natural gas have been volatile. Our cash flows are materially impacted by the prices of commodities we produce (oil and natural gas, and the NGLs extracted from the natural gas). Our realized sales prices received for our oil, NGLs and natural gas production are affected by 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. For 2023, our realized prices for oil decreased 19%, NGLs decreased 38% and natural gas decreased 59% from 2022, having an adverse impact on our margins in addition to increased operating expenses. As a result, we cannot accurately predict future commodity prices, therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our drilling program, production volumes or revenues.

The U.S. Energy Information Administration (“EIA”) published its latest Short-Term Energy Outlook in February 2024. Spot prices for WTI oil averaged $77.58 per barrel in 2023, and the EIA is forecasting WTI spot prices to average $77.68 for 2024. The WTI oil spot price increased in January 2024 compared with the December 2023 average price of $71.89 per barrel, averaging $73.82 per barrel because of heightened uncertainty about global oil shipments as attacks to vessels in the Red Sea intensified. The EIA is forecasting WTI spot prices will rise into the mid-$80 per barrel range in the coming months, but downward pressures may emerge in 2024 as global oil inventories increase. Ongoing risks of supply disruptions in the Middle East could create the potential for oil prices to be higher than the EIA has forecasted.

Spot prices for Henry Hub natural gas averaged $2.53 per MMBtu in 2023, and the EIA is forecasting that Henry Hub prices will average $2.65 in 2024. The Henry Hub spot price averaged $3.23 per MMBtu in January 2024; however, spot prices were volatile, rising sharply to $13.20 per MMBtu on January 12 in anticipation of severely cold weather throughout the U.S. for the following weekend. After the weekend, prices quickly fell and continued to decrease until January 23, when the price hit the monthly low of $2.15 per MMBtu. Mild weather for the remainder of the first quarter of 2024 could keep the average Henry Hub spot price near $2.40 per MMBtu during February and March, but volatility could return if severely cold weather emerges, even for a short period.

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We hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Financial Statements and Supplementary Data – Note 4 – Derivative Financial Instruments, under Part II, Item 8 of this Annual Report for additional information regarding our commodity derivative positions as of December 31, 2023.

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

Rising Interest Rates and Inflation of Cost of Goods, Services and Personnel – Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increase, while during periods of commodity price declines, decreases in oilfield costs typically lag behind commodity price decreases. Continued inflationary pressures and increased commodity prices may also result in increases in the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise.

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 2023 was 3.4%. These inflationary pressures have caused the Federal Reserve to tighten monetary policy by approving a series of increases to the Federal Funds Rate. As of December 31, 2023, the Federal Reserve benchmark rate ranged from 5.25% to 5.50%. Although the Federal Reserve has stated that they will begin reducing the benchmark rate in 2024, if inflation were to continue to rise, it is possible the Federal Reserve would continue to take action they deem necessary to bring inflation down and to ensure price stability, including further 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.

Inflation Reduction Act of 2022 – In August 2022, President Biden signed the IRA into law. Several provisions in the IRA are expected to apply to our business. For instance, the IRA specifically directs the DOI to accept the highest bids received for Lease Sale 257, which was vacated by U.S. District Court for the District of Columbia in January 2022, and move forward with Lease Sales 259 and 261 in the Gulf of Mexico, notwithstanding the June 30, 2022 expiration of the 2017-2022 Outer Continental Shelf Oil and Gas Leasing Program. Lease Sale 259 was held in March 2023, and Lease Sale 261 was held in December 2023.

In September 2023, consistent with the requirements of the IRA concerning offshore conventional and renewable energy leasing, the DOI announced its proposed 2024 – 2029 OCS Program. The proposed OCS Program includes a maximum of three potential oil and natural gas lease sales in the Gulf of Mexico scheduled in 2025, 2027 and 2029. In compliance with the IRA, these three lease sales are the minimum number that will enable the DOI to continue to expand its offshore wind leasing program through 2030. The reduction of the proposed OCS Program to a maximum of three potential lease sales will bring the federal oil and natural gas program in line with the Biden administration’s goal of net zero emissions by 2050 and meet the IRA’s requirement for future offshore renewable energy leasing.

The IRA also increases the minimum oil and gas royalty rate for new offshore leases from the current 12.50% to 16.67% and caps the royalty rate at 18.75% for 10 years. The 18.75% cap is commensurate with existing offshore royalty rate for leases in water depth exceeding 200 meters. This provision does not affect existing offshore leases.

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Furthermore, the IRA amends the federal Clean Air Act to impose a fee on emissions of methane from sources required to report their greenhouse gas emissions to the EPA, including sources in the offshore and onshore oil and gas production, and onshore processing, transmission and compression, gathering, and boosting station source categories. For such qualifying facilities, the charge starts at $900 per metric ton of methane reported for calendar year 2024. In 2025, the charge increases to $1,200 per metric ton of methane. For calendar year 2026 and thereafter, the fee will be $1,500 per metric ton of methane. Calculation of the charge is based on certain thresholds established in the IRA. The charge will be based on the prior year’s emissions, and the first fee payment will be in 2025 based on 2024 data. The methane emissions charge may increase our operating costs and adversely affect our business.

Impairment of Oil and Natural Gas Properties – Under the full cost method of accounting that we use for our oil and gas operations, our capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. Any costs in excess of the ceiling are recognized as a non-cash “Write-down of oil and natural gas properties” on the Consolidated Statements of Operations and an increase to “Accumulated depreciation, depletion and amortization” on our Consolidated Balance Sheets. The expense may not be reversed in future periods, even though higher oil, NGL and natural gas prices may subsequently increase the ceiling. We perform this ceiling test calculation each quarter. In accordance with SEC rules and regulations, we utilize SEC pricing when performing the ceiling test. At December 31, 2023, our ceiling test computation was based on SEC pricing of $78.21 per Bbl of oil and $2.64 per Mcf of natural gas.

As part of our period end reserves estimation process for future periods, we expect changes in the key assumptions used, which could be significant, including updates to future pricing estimates and differentials, future production estimates to align with our anticipated five-year drilling plan and changes in our capital costs and operating expense assumptions. There is a significant degree of uncertainty with the assumptions used to estimate future undiscounted cash flows due to, but not limited to, the risk factors referred to in Part I, Item 1A. Risk Factors. Any decrease in pricing, negative change in price differentials, or increase in capital or operating costs could negatively impact the estimated undiscounted cash flows related to our proved oil and natural gas properties.

Deferred Production – Our oil, NGLs and natural gas production is 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, the transportation, gathering or processing of production and weather events. For 2023, we estimate deferred production was approximately 2,541 MBoe.

Regulations – We are subject to a number of regulations from federal and state governmental entities, which are described under Part I, Item 1. Business ‒ Environmental, Health and Safety Matters and Government Regulations in this Form 10-K. We and others like us, are exposed to a number of risks by operating in the oil and natural gas industry in the Gulf of Mexico, which are described in Item 1A. Risk Factors, in this Form 10-K.

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. As of December 31, 2023, we are in compliance with our financial assurance obligations to the BOEM and have no outstanding BOEM orders related to financial assurance obligations. We and other offshore Gulf of Mexico producers may, in the ordinary course of business, receive demands in the future for financial assurances from the BOEM as the BOEM continues to reevaluate its requirements for financial assurance. 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.

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Surety Bond Collateral – In prior years, some of the sureties that provide us surety bonds used for supplemental financial assurance purposes have requested and received collateral from us and may request additional collateral from us in the future, which could be significant and could impact our liquidity. In addition, pursuant to the terms of our agreements with various sureties under our existing bonds or under any additional bonds we may obtain, we are required to post collateral at any time, on demand, at the surety’s discretion. In both 2023 and 2022, we have not had to post collateral for sureties, and we currently do not have any collateral posted for surety bonds. The issuance of any additional surety bonds or other security to satisfy future BOEM orders, collateral requests from surety bond providers and collateral requests from other third-parties may require the posting of cash collateral, which may be significant, and may require the creation of escrow accounts.

RESULTS OF OPERATIONS

Year Ended December 31, 2023 Compared to Year Ended December 31, 2022

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. The following table presents our sources of revenue as a percentage of total revenue:

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The information below provides a discussion of, and an analysis of significant variance in, our oil, NGL and natural gas revenues, production volumes and average sales prices for 2023 and 2022 (in thousands):

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Changes in average sales prices and sales volumes caused the following changes to our oil, NGL and natural gas revenues between 2023 and 2022 (in thousands):

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Realized Prices on the Sale of Oil, NGLs and Natural Gas – Our average realized sales price for oil differs from the WTI average spot price primarily due to premiums or discounts, quality adjustments, location adjustments and volume weighting (collectively referred to as differentials). Oil quality adjustments can vary significantly by field as a result of quality and location. All of our oil is produced offshore in the Gulf of Mexico and is primarily characterized as Poseidon, Light Louisiana Sweet and Heavy Louisiana Sweet. Similar to oil prices, the differentials for these types of oil can vary based on the aforementioned factors and have experienced volatility in the past.

Two major components of our NGLs, ethane and propane, typically make up over 70% of an average NGL barrel. The changes in realized sales prices for NGLs are mostly a function of the change in oil prices combined with changes in supply and demand for propane and ethane.

The prices we realize for sales of natural gas differ from quoted Henry Hub spot prices as a result of quality and location differentials. During 2023, we experienced a positive natural gas differential due to approximately 70% of our natural gas being sold in a Florida market area, which had a premium to Henry Hub.

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Oil, NGLs, and Natural Gas Volumes – Production volumes decreased by 1,894 MBoe to 12,730 MBoe during 2023 primarily due to downtime related to field and well maintenance events, primarily at Mobile Bay and other OCS fields, and natural production declines, partially offset by production from the acquisition completed in September 2023.

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):

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Lease operating expenses – Lease operating expenses include the expense of operating and maintaining our wells, platforms and other infrastructure primarily in the Gulf of Mexico. 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 $33.3 million to $257.7 million in 2023 compared to $224.4 million in 2022. On a per Boe basis, lease operating expenses increased to $20.24 per Boe during 2023 compared to $15.35 per Boe during 2022. On a component basis, base lease operating expenses increased $15.2 million, workover expenses increased $9.7 million and facility maintenance expenses increased $8.7 million. These increases were partially offset by a decrease of $0.3 million in hurricane repairs.

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 a full year of expenses at the fields acquired in February 2022 and three months of expenses at the fields acquired in September 2023, as well as higher repair, maintenance and labor costs at other fields. In addition, expenses related to our insurance coverage also increased due to higher premiums on our policies that were renewed in June 2023.

Workover and facility 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. During 2023, we incurred $12.0 million in workover expenses primarily at our Mobile Bay Properties due to numerous workover projects including well cleanout, recovering of fishing tools and stimulating to return the wells back to production.

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 and the Texas Department of Revenue on production of oil and natural gas from land or water bottoms within the boundaries of each state, respectively. Gathering, transportation and production taxes decreased to $26.3 million in 2023 compared to $35.1 million in 2022, primarily due to lower production volumes and realized prices partially offset by the transportation contract related to the properties acquired in 2022.

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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. See Part II, Item 8. Financial Statements and Supplementary Data — Note 1 — Summary of Significant Accounting Policies for further discussion. DD&A increased to $114.7 million in 2023 from $107.1 million in 2022. The DD&A rate increased to $9.01 per Boe in 2023 from $7.33 per Boe in 2022. The DD&A rate per Boe increased primarily as a result of a higher depreciable base due to 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 $29.0 million in 2023 compared to $26.5 million in 2022 primarily due to the increase in our ARO liability (see Part II, Item 8. Financial Statements and Supplementary Data — Note 8 — Asset Retirement Obligations).

General and administrative expenses (“G&A”) – G&A expense generally consists 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 2023, G&A expenses were $75.5 million compared to $73.7 million in 2022. The increase is primarily due to increased payroll costs, share-based compensation costs and professional fees, partially offset by a decrease in legal expenses and a $2.2 million employee retention credit recorded in 2023. Share-based compensation costs were higher due to the higher grant date fair values of share-based compensation awards outstanding during 2023 as compared to the value of awards outstanding during 2022. Legal expenses decreased primarily due to non-recurring legal fees incurred during 2022 related to a review of processes and controls within our information technology department.

Other Income and Expense

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

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Derivative (gain) loss – 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. During 2022, the $85.5 million derivative loss recorded for oil and natural gas derivative contracts consisted of $125.1 million of premium payments and realized losses on settled contracts and $39.6 million of unrealized gain, net from the increase in fair value of open contracts. During the second quarter of 2022, the Company monetized a portion of existing hedge positions through restructuring of strike prices on certain outstanding purchased calls covering the second half of 2022 through the first quarter of 2025. This transaction resulted in net cash proceeds of $105.3 million, which are included as an offset to realized losses for 2022.

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. 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. As of December 31, 2023, we do not have any open oil contracts. See Financial Statements and Supplementary Data – Note 4 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K for additional information.

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Interest expense, net – Interest expense, net of interest income, was $44.7 million during 2023, decreasing $24.8 million from $69.4 million during 2022. The decrease is primarily due to the redemption of the 9.75% Notes in February 2023, decreased interest expense on the lower outstanding principal balance of the Term Loan and an increase in interest income, partially offset by interest expense incurred on the 11.75% Notes issued in late January 2023. See Financial Statements and Supplementary Data – Note 2 – Debt under Part II, Item 8 in this Form 10-K for additional information on our debt.

Other expense, net – During 2023, other expense, net, was $5.6 million, compared to $14.3 million for 2022. During both 2023 and 2022, other expense primarily consisted of additional expenses for net abandonment obligations pertaining to a number of legacy Gulf of Mexico properties.

Income tax expense – Our effective tax rates for 2023 and 2022 were 54.0% and 18.8%, respectively. In 2023, the rate differed from the federal statutory rate of 21% primarily due to adjustments in the valuation allowance, compensation adjustments and the impact of state income taxes. In 2022, the rate differed from the federal statutory rate primarily due to adjustments in the valuation allowance and the impact of state income taxes.

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.

We expect to support our business requirements primarily with cash on hand and cash generated from operations. As of December 31, 2023, we had $173.3 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.

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):

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Operating activities – Net cash provided by operating activities for 2023 was $115.3 million, decreasing $224.2 million from 2022. The change between periods is primarily due to (i) a $388.3 million decrease in revenues and (ii) a $36.2 million increase in operating expenses, partially offset by (iii) a $79.1 million decrease in derivative cash settlements, including premium payments, and (iv) a $29.0 million decrease in interest paid. These decreases in operating cash flow were partially offset by the changes in operating assets and liabilities which increased operating cash flows by $25.1 million primarily related to (i) lower accounts receivable balance due to decreased realized prices, (ii) and lower accounts payable and accrued liabilities balances in the current period and (iii) a $42.3 million decrease in ARO settlements.

Investing activities – Net cash used in investing activities for 2023 decreased $13.5 million compared to 2022. This was primarily due to decreases of $24.1 million in acquisition of property interests and $1.7 million in investment in oil and natural gas properties, partially offset by the purchase of the corporate aircraft and furniture, fixtures and other.

Financing activities – Net cash used in financing activities during 2023 increased by $292.8 million compared to 2022. This was primarily due to long-term debt repayments of $544.0 million, primarily due to the redemption of the $552.5 million principal amount outstanding 9.75% Notes and the $16.5 million of net proceeds received from the sales of equity securities under our at-the-market equity offering program in 2022, partially offset by the $275.0 million in proceeds from the issuance of the 11.75% Notes.

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):

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The following table presents our exploration and development capital expenditures geographically (in thousands):

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Our preliminary capital expenditure budget for 2024 has been established in the range of $35.0 million to $45.0 million, which excludes acquisitions. In our view of the outlook for 2024, we believe this level of capital expenditure will enhance our liquidity capacity throughout 2024 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.

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Acquisitions

We have grown by making strategic acquisitions of producing properties in the Gulf of Mexico. We seek opportunities where we can exploit additional drilling projects and reduce costs. In September 2023, we acquired eight shallow water oil and natural gas producing assets in the central and eastern shelf region of the Gulf of Mexico for $27.4 million, after normal and customary post-effective date adjustments (including net operating cash flow attributable to the properties from the effective date to the respective closing date). The transaction was funded with cash on hand.

On December 13, 2023, we entered into a purchase and sale agreement to acquire rights, titles and interest in and to certain leases, wells and personal property in the central shelf region of the Gulf of Mexico, among other assets, for a gross purchase price of $72.0 million, subject to customary purchase price adjustments. The transaction closed on January 16, 2024 and was funded using cash on hand.

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

Annually, we review and revise our ARO estimates. Our ARO at December 31, 2023 and 2022 were $498.8 million and $466.4 million, respectively. The increase is primarily due to revisions in expected timing and amount of costs to be incurred. These increases were partially offset by $34.0 million related to liabilities settled during 2023. Our estimate of ARO spending in 2024 is approximately $35.0 to $45.0 million. During 2023 and 2022, we revised our estimates of costs anticipated to be charged by service providers for plugging and abandonment projects and revised our estimates to actual spending as invoices were processed and projects were completed. As these estimates are for work to be performed in the future, and in many cases, several years in the future, actual expenditures could be substantially different than our estimates. Additionally, we revise our estimates to account for the cost to comply with any new or revised regulations, including increases in work scope and cost changes from interpretation of work scope. See Part I, Item 1A. Risk Factors and Financial Statements and Supplementary Data – Note 8 – Asset Retirement Obligations under Part II, Item 8 in this Form 10-K for additional information regarding our ARO.

Debt

The primary terms of our long-term debt, the conditions related to incurring additional debt, and the conditions and limitations concerning early repayment of certain debt are disclosed in Financial Statements and Supplementary Data –Note 2 – Debt under Part II, Item 8 in this Form 10-K.

Term Loan – As of December 31, 2023, we had $114.2 million of Term Loan principal outstanding. The Term Loan requires quarterly amortization payments, bears interest at a fixed rate of 7.0% per annum and will mature on May 19, 2028. The Term Loan is non-recourse to us and our subsidiaries other than the Subsidiary Borrowers (and the subsidiary that owns the equity of the Subsidiary Borrowers) and is not secured by any assets other than first lien security interests in the equity in the Borrowers and a first lien mortgage security interest and mortgages on certain assets of the Subsidiary Borrowers.

11.75% Senior Second Lien Notes due 2026 – As of December 31, 2023, we had $275.0 million in aggregate principal amount of our 11.75% Notes issued and outstanding. The 11.75% Notes were issued at par with an interest rate of 11.75% per annum that matures on February 1, 2026. The 11.75% Senior Second Lien Notes are secured by second-priority liens on the same collateral that is secured under the Credit Agreement.

Credit Agreement – As of December 31, 2023, we had no borrowings outstanding under the Credit Agreement. On February 28, 2024, we amended the Credit Agreement to extend the maturity date to March 28, 2024.

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TVPX Loan – As of December 31, 2023, we had $11.0 million of TVPX Loan principal outstanding. The TVPX Loan bears a fixed interest rate of 2.49% per annum for a term of 41 months and requires monthly amortization payments of $91.7 thousand plus accrued interest, and a balloon payment of $8.0 million at the end of the loan term.

Debt Covenants – The Term Loan, Credit Agreement and 11.75% Notes contain financial covenants calculated as of the last day of each fiscal quarter, which include thresholds on financial ratios, as defined in the respective Subsidiary Credit Agreement, the Credit Agreement and the indenture related to the 11.75% Notes. We were in compliance with all applicable covenants of the Term Loan, Credit Agreement and the 11.75% Notes indenture as of and for the period ended December 31, 2023.

Dividends

On November 8, 2023, we announced that our board of directors approved the implementation of a quarterly cash dividend payable to holders of common stock. The initial cash dividend of $0.01 per share of common stock, or $1.5 million, was paid on December 22, 2023, to shareholders of record at the close of business on November 28, 2023. 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.

Contractual Obligations and Commitments

Our material cash commitments from known contractual and other obligations consist primarily of obligations for long-term 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, 2023 are based on our estimates and assumptions about these obligations, including their duration, anticipated actions by third parties and other factors.

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The following table summarizes our significant contractual obligations as of December 31, 2023 by maturity (in millions):

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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 2 Properties, Item 1A Risk Factors and Item 7A Quantitative and Qualitative Disclosures About Market Risk and with Part II, Item 8 Financial Statements and Supplementary Data in this 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 of this Annual Report generally discusses 2022 and 2021 items and year-to-year comparisons between 2022 and 2021. Discussions of 2020 items and year-to-year comparisons between 2021 and 2020 that are not included in this Annual Report are incorporated by reference to Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of the Company’s Annual Report on Form 10-K for the year ended December 31, 2021.

Business Overview

W&T is an independent oil and natural gas producer, active in the exploration, development and acquisition of oil and natural gas properties in the Gulf of Mexico. As of December 31, 2022, we held working interests in 47 offshore producing fields in federal and state waters (45 producing fields and 2 capable of producing). Our interest in fields, leases, structures and equipment are primarily owned by W&T Offshore, Inc. and our wholly-owned subsidiaries, Aquasition LLC, Aquasition II LLC, and W & T Energy VI LLC, Delaware limited liability companies and through our proportionately consolidated interest in Monza.

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. We strive to operate within cash flow to reduce debt, optimize the balance sheet and maintain financial flexibility. A majority of our daily production is derived from wells we operate.

Outlook

During 2022, commodity prices experienced significant improvement, due to a confluence of factors that have provided positive developments to the overall pricing environment when compared to 2021. While the current outlook for commodity prices is favorable and our operations are no longer significantly impacted by COVID-19, other global factors could adversely impact our operations, and commodity prices could significantly decline from current levels.

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Our cash flows are materially impacted by the prices of commodities we produce (crude oil and natural gas, and the NGLs extracted from the natural gas). In addition, the prices of goods and services used in our business can vary and impact our cash flows. During 2022, average realized commodity prices increased from those we experienced during 2021 and 2020. Our margins in 2022 increased from 2021 primarily due to higher average realized commodity prices, partially offset by higher operating expenses. We measure margins using Adjusted EBITDA which we define net (loss) income (loss) before income tax expense (benefit), net interest expense, and depreciation, depletion, amortization and accretion, the unrealized commodity derivative gain or loss and the effects derivative premium payments, allowance for credit losses, write off of debt issuance costs, non-cash incentive compensation, non-recurring IT transition costs, release of restricted funds, non-ARO P&A costs, and other miscellaneous costs as a percent of revenue, which is not a financial measurement under GAAP. We have historically increased our reserves and production through acquisitions, our drilling program, and other projects that optimize production on existing wells. Our production increased 5.1% in 2022 from the prior year. Our proved reserves increased by 7.7 MMBoe in 2022, primarily due to the significant increase in commodity prices in 2022 as compared to 2021.

We continually monitor current and forecasted commodity prices to assess what changes, if any, should be made to our 2023 plans. See Liquidity and Capital Resources under this Item 7 in this Form 10-K for additional information.

Recent Developments

Issuance of 11.75% Senior Second Lien Notes due 2026 – On January 27, 2023, we issued $275.0 million of 11.75% Senior Second Lien Notes due 2026. The 11.75% Senior Second Lien Notes were issued at par and have a maturity date of February 1, 2026. See Financial Statements and Supplementary Data –Note 20 – Subsequent Events under Part II, Item 8 in this Form 10-K for additional information.

Redemption of 9.75% Senior Second Lien Notes due 2023 – On February 8, 2023, we redeemed all of the 9.75% Senior Second Lien Notes outstanding at a redemption price of 100.000%, plus accrued and unpaid interest to the redemption date. As of December 31, 2022, there was $552.5 million of aggregate principal outstanding. The Company used the net proceeds of $270.8 million from the issuance of the 11.75% Senior Second Lien Notes and cash on hand of $296.1 million to fund the redemption. See Financial Statements and Supplementary Data –Note 20 – Subsequent Events under Part II, Item 8 in this Form 10-K for additional information.

Reaffirmation of Credit Agreement. On February 8, 2023, the Company provided notice of the redemption of the existing 9.75% Senior Second Lien Notes and the issuance of the 11.75% Senior Second Lien Notes to Alter Domus (US) LLC and Calculus pursuant to the terms of the Credit Agreement, which reaffirmed the Credit Agreement’s maturity date of January 3, 2024.

Factors Affecting the Comparability of our Financial Condition and Results of Operations

Asset Acquisitions – During the first and second quarters of 2022, the Company acquired the Ship Shoal 230, South Marsh Island 27/Vermilion 191, and South Marsh Island 73 fields. This transaction is described in more detail under Financial Statements and Supplementary Data – Note 6 – Acquisitions, under Part II, Item 8, of this Annual Report.

Hurricanes and Severe Weather – We did not experience any significant deferred production related to named storms or other severe weather events during the year ended December 31, 2022. During 2021, some of our production from the Gulf of Mexico was impacted due to precautionary shut-ins of facilities and evacuations primarily associated with Hurricane Ida. While Company assets and infrastructure did not suffer significant damage during the storm, unplanned costs of $5.4 million for minor repairs and restoring production, as well as evacuating employees and contractors, were incurred as a result of the hurricane and reflected in lease operating expense. For the year ended December 31, 2021, we estimate deferred production related to these storms was approximately 0.8 MMBoe per day. See Part I, Item 1, Business– Insurance Coverage in this Form 10-K for additional information.

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Known Trends and Uncertainties

Volatility in Oil, NGL and Natural Gas Prices – Historically, the markets for oil and natural gas have been volatile. Our cash flows are materially impacted by the prices of commodities we produce (crude oil and natural gas, and the NGLs extracted from the natural gas). Our realized sales prices received for our crude oil, NGLs and natural gas production are affected by 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. In addition, the prices of goods and services used in our business can vary and impact our cash flows. As a result, we cannot accurately predict future commodity prices, therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our drilling program, production volumes or revenues.

In addition to such industry-specific risks, the global public health crisis associated with COVID-19 has created uncertainty for global economic activity since March 2020. Since 2021, increased mobility, deployment of vaccines and other factors have resulted in increased oil demand and commodity prices. However, new variants of the virus continue to emerge and it is difficult to assess if such variants will cause meaningful disruptions in economic activity across the world and if there will be any significant impacts in demand for energy because of the ongoing pandemic.

A high level of uncertainty remains regarding the volatility of energy supply and demand. In October 2022 OPEC Plus announced a production cut of approximately two million barrels per day. These shifts in OPEC Plus production levels as well as the Russia-Ukraine war and related sanctions, which began in the first quarter of 2022, continue to contribute to a high level of uncertainty surrounding energy supply and demand putting additional upward pressure on commodity prices. As a result, governmental authorities have implemented, and are expected to continue to implement, measures to address rising crude oil prices, including releasing emergency oil reserves.

WTI is frequently used to value domestically produced crude oil, and our crude oil production is priced using the spot price for WTI as a base price, then adjusted for the type and quality of crude oil and other factors. NYMEX WTI daily spot crude oil prices averaged $94.90 per barrel during 2022, up from $68.14 barrel during 2021. The U.S. Energy Information Administration (“EIA”) in their Short-Term Energy Outlook issued in February 2023 projects average crude oil prices for WTI to decrease to approximately $77.84 per barrel in 2023 and further decrease in 2024 to approximately $71.57 per barrel. The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. NYMEX Henry Hub spot prices averaged $6.45 per MMBtu during 2022, up from $3.89 per MMBtu during 2021. The EIA projects average natural gas prices for Henry Hub to decrease to approximately $3.40 per MMBtu in 2023 and increase in 2024 to approximately $4.04 per MMBtu. Global oil production is forecasted to outpace global oil consumption during 2023 resulting in rising global oil inventories. Oil market balances are subject to significant uncertainties which could keep oil prices volatile.

We hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Financial Statements and Supplementary Data – Note 10 – Derivative Financial Instruments, under Part II, Item 8, of this Annual Report for additional information regarding our commodity derivative positions as of December 31, 2022.

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

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Rising Interest Rates and Inflation of Cost of Goods, Services and Personnel – Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increase, while during periods of commodity price declines, decreases in oilfield costs typically lag behind commodity price decreases. Continued inflationary pressures and increased commodity prices may also result in increases to the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise.

The United States has experienced a rise in inflation since October 2021. The annual rate of inflation in the United States was at 6.5% as measured in December 2022 by the Consumer Price Index. This is down from the June 2022 peak of 9.1%. However, it is still higher than historical averages. In addition, the Federal Reserve has tightened monetary policy by approving a series of increases to the Federal Funds Rate and signaled that the Federal Reserve would continue to take necessary action to bring inflation down and to ensure price stability, including further rate increases, which could have the effects of raising the cost of capital and depressing economic growth, either or both of which could hurt our business.

As a result of these factors, we cannot accurately predict future commodity prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our drilling program, production volumes or revenues.

Inflation Reduction Act of 2022 – On August 16, 2022, President Biden signed the IRA into law. Several provisions in the IRA are expected to apply to our business. For instance, the IRA specifically directs the Department of the Interior (”DOI”) to accept the highest bids received for Lease Sale 257 which was vacated by US District Court for the District of Columbia in January 2022 and move forward with Lease Sales 259 and 261 in the Gulf of Mexico by March 31, 2023 and September 30, 2023, respectively, notwithstanding the June 30, 2022 expiration of the 2017-2022 Outer Continental Shelf Oil and Gas Leasing Program.

The IRA ties the issuance of offshore leases for wind development by the federal government to requirements to offer for sale federal oil and gas leases for a 10-year period of time. The IRA requires the federal government to offer for sale a minimum of 60 million acres for offshore oil and gas leases during the one-year period immediately preceding granting an offshore wind lease on the U.S. Outer Continental Shelf.

The IRA also increases the minimum oil and gas royalty rate for new offshore leases from the current 12.50% to 16.67% and caps the royalty rate at 18.75% for 10 years. The 18.75% cap is commensurate with existing offshore royalty rate for leases in water depth exceeding 200 meters. This provision does not affect existing offshore leases.

Furthermore, the IRA imposes a methane emissions charge. The IRA amends the federal Clean Air Act to impose a fee on emissions of methane from sources required to report their greenhouse gas emissions to the EPA, including sources in the offshore and onshore oil and gas production, and onshore processing, transmission and compression, gathering, and boosting station source categories. For such qualifying facilities, the charge starts at $900 per metric ton of methane reported for calendar year 2024. In 2025, the charge increases to $1,200 per metric ton of methane. For calendar year 2026 and thereafter, the fee will be $1,500 per metric ton of methane. Calculation of the charge is based on certain thresholds established in the IRA. The charge will be based on the prior year’s emissions, and the first fee payment will be in 2025 based on 2024 data. The methane emissions charge may increase our operating costs and adversely affect our business.

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Impairment of Oil and Natural Gas Properties – Under the full cost method of accounting that we use for our oil and gas operations, our capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. Any costs in excess of the ceiling are recognized as a non-cash “Write-down of oil and natural gas properties” on the Consolidated Statements of Operations and an increase to “Accumulated depreciation, depletion and amortization” on our Consolidated Balance Sheets. The expense may not be reversed in future periods, even though higher oil, natural gas and NGL prices may subsequently increase the ceiling. We perform this ceiling test calculation each quarter. In accordance with the SEC rules and regulations, we utilize SEC Pricing when performing the ceiling test. At December 31, 2022, the Company’s ceiling test computation was based on SEC pricing of $91.50 per Bbl of oil, $41.92 per Bbl of NGLs and $6.85 per Mcf of natural gas.

As part of our period end reserves estimation process for future periods, we expect changes in the key assumptions used, which could be significant, including updates to future pricing estimates and differentials, future production estimates to align with our anticipated five-year drilling plan and changes in our capital costs and operating expense assumptions. There is a significant degree of uncertainty with the assumptions used to estimate future undiscounted cash flows due to, but not limited to the risk factors referred to in Part I, Item 1A. Risk Factors. Any decrease in pricing, negative change in price differentials, or increase in capital or operating costs could negatively impact the estimated undiscounted cash flows related to our proved oil and natural gas properties.

Deferred Production – Our oil, NGLs and natural gas production is significantly affected by unplanned production downtime caused by events outside of our control and create uncertainties in our financial condition, cash flow and results of operations. Such events include third party downtime associated with non-operated properties and the transportation, gathering or processing of production and weather events. For the year ended December 31, 2022, we estimate deferred production was approximately 2,314 MBoe, primarily due to unplanned well maintenance.

Hurricane and Severe Weather Events – Since our operations are in the Gulf of Mexico, we are particularly vulnerable to the effects of hurricanes on production. We normally obtain insurance to reduce, but not totally mitigate, our financial exposure risk; however, affordable insurance coverage for property damage to our facilities for hurricanes is not assured. See Item 1 Business – Insurance Coverage under Part I in this Form 10-K for additional information. Significant hurricane impacts could include reductions and/or deferrals of future oil and natural gas production and revenues, increased lease operating expense for evacuations and repairs and possible acceleration of plugging and abandonment costs.

Regulations – We are subject to a number of regulations from federal and state governmental entities, which are described under Part I, Item 1, Regulations in this Form 10-K. Our Company and others like us, are exposed to a number of risks by operating in the oil and gas industry in the Gulf of Mexico, which are described in Item 1A, Risk Factors, in this Form 10-K.

BOEM Matters – 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. As of December 31, 2022, the Company is in compliance with its financial assurance obligations to BOEM and has no outstanding BOEM orders related to financial assurance obligations. We and other offshore Gulf of Mexico producers may, in the ordinary course of business, receive demands in the future for financial assurances from BOEM as BOEM continues to reevaluate its requirements for financial assurance. For more information on the BOEM and financial assurance obligations to that agency, see Business – Compliance with Government Regulations – Decommissioning and financial assurance requirements under Part I, Item 1 of this Form 10-K.

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Surety Bond Collateral – In prior years, some of the sureties that provide us surety bonds used for supplemental financial assurance purposes have requested and received collateral from us, and may request additional collateral from us in the future, which could be significant and could impact our liquidity. In addition, pursuant to the terms of our agreements with various sureties under our existing bonds or under any additional bonds we may obtain, we are required to post collateral at any time, on demand, at the surety’s discretion. In 2022 or 2021, we have not had to post collateral for sureties and we currently do not have any collateral posted for surety bonds. The issuance of any additional surety bonds or other security to satisfy future BOEM orders, collateral requests from surety bond providers, and collateral requests from other third-parties may require the posting of cash collateral, which may be significant, and may require the creation of escrow accounts.

Results of Operations

Year Ended December 31, 2022 Compared to Year Ended December 31, 2021

Revenues

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs. Our oil, natural gas and NGL revenues do not include the effects of derivatives, which are reported in “Derivative loss (gain)” in our Consolidated Statements of Operations. The following table presents our sources of revenue as a percentage of total revenue:

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The information below provides a discussion of, and an analysis of significant variance in, our oil, natural gas and NGL revenues, production volumes and average sales prices for the years ended December 31, 2022 and 2021 (in thousands):

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Changes in average sales prices and sales volumes caused the following changes to our oil, NGL and natural gas revenues between the years ended December 31, 2022 and 2021 (in thousands):

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Realized Prices on the Sale of Oil, NGLs and Natural Gas – Our average realized crude oil sales price differs from the WTI benchmark average crude price due primarily to premiums or discounts, crude oil quality adjustments, and volume weighting (collectively referred to as differentials). Crude oil quality adjustments can vary significantly by field as a result of quality and location. For example, crude oil from our East Cameron 321 field normally receives a positive quality adjustment, whereas crude oil from our Ship Shoal 349 field normally receives a negative quality adjustment. All of our crude oil is produced offshore in the Gulf of Mexico and is primarily characterized as Poseidon, Light Louisiana Sweet (“LLS”), and Heavy Louisiana Sweet (“HLS”). Similar to crude oil prices, the differentials for our offshore crude oil have also experienced volatility in the past. The monthly average differentials of WTI versus LLS and HLS for 2022 increased on average by approximately $0.43 - $0.75 per barrel compared to 2021 for these types of crude oils with LLS and HLS having positive differentials as measured on an index basis. The monthly average differentials of WTI versus Poseidon decreased by $1.91 per barrel compared to 2021 with Poseidon having a negative differential.

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Two major components of our NGLs, ethane and propane, typically make up approximately 70% of an average NGL barrel. During 2022, average prices for domestic ethane increased by 55.6% and average domestic propane prices increased by 5.6% from 2021 as measured using a price index for Mount Belvieu. The changes in the average price for other domestic NGLs components in 2022 ranged from an increase of 11.4% to 22.5% year-over-year.

The actual prices we realize from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. Currently, the sales points of our gas production are generally within close proximity to the Henry Hub which creates a minimal differential in the prices we receive for our production versus average Henry Hub prices.

Oil, NGLs, and Natural Gas Volumes – Production volumes increased by 711 MBoe to 14,624 MBoe primarily due to the acquisition of the Ship Shoal 230, South Marsh Island 27/Vermilion 191, and South Marsh Island 73 fields during the first and second quarters of 2022. The increase in production from these asset acquisitions was offset by downtime related to field and well maintenance events, primarily at Mobile Bay and other OCS fields. Deferred production for 2022 related to these events collectively resulted in deferred production of 2.3 MMBoe, compared to 2.2 MMBoe in 2021.

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:

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Lease operating expenses – Lease operating expenses include the expense of operating and maintaining our wells, platforms and other infrastructure primarily in the Gulf of Mexico. These operating costs are comprised of several components including, direct or base lease operating expenses, insurance premiums, workover costs, facilities repairs and maintenance expenses, and hurricane repair 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 $49.8 million to $224.4 million in 2022 compared to $174.6 million in 2021. On a per Boe basis, lease operating expenses increased to $15.35 per Boe during 2022 compared to $12.55 per Boe during 2021. On a component basis, base lease operating expenses increased $35.1 million, workover expenses increased $8.2 million and facilities maintenance expenses increased $11.8 million. These increases were partially offset by a decrease of $5.4 million in hurricane repairs.

Expenses for direct labor, materials, supplies, repair and third party costs comprise the most significant portion of our base lease operating expense. Base lease operating expenses increased primarily due to increased expenses related to the Ship Shoal 230, South Marsh Island 27/Vermilion 191, and South Marsh Island 73 fields acquired during the first half of 2022, increased labor costs, and increased insurance expense.

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Workovers 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. Lastly, during the year ended December 31, 2021 we incurred $5.4 million in expenses related to repairs associated with hurricanes that we did not incur during the year ended December 31, 2022.

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 and the Texas Department of Revenue on production of oil and natural gas from land or water bottoms within the boundaries of each state, respectively. Gathering, transportation and production taxes increased to $35.1 million in 2022 compared to $27.9 million in 2021, primarily due to a new transportation contract related to the properties acquired in the first half of 2022. Additionally, the increase in realized natural gas and NGL prices along with an increase in oil, NGL and natural gas production during 2022 caused gathering, transportation and production taxes to increase.

Depreciation, depletion, amortization and accretion – Depreciation, depletion and amortization expense 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. See Part II, Item 8. Financial Statements and Supplementary data — Note 1 — Summary of Significant Accounting Policies for further discussion. Accretion expense is the expensing of the changes in value of our asset retirement obligations 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. DD&A, which includes accretion for ARO, increased to $9.14 per Boe in 2022 from $8.15 per Boe in 2021. On a nominal basis, DD&A increased to $133.6 million in 2022 from $113.4 million in 2021. The DD&A rate per Boe increased mostly as a result of increases in the capital expenditures and future development costs included in the depreciable base associated with an increase in economic proved undeveloped wells due to higher oil and gas prices compared to the smaller increase in proved reserves over the comparable prior year period.

General and administrative expenses (“G&A”) – G&A expense generally consists 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, equity based compensation expense, audit and other fees for professional services and legal compliance. For 2022, G&A expenses were $73.7 million compared to $52.4 million in 2021. The increase is primarily due to non-recurring professional services costs incurred during the second half of 2022 after a review of processes and controls within our information technology department, including additional non-recurring expenses associated with the process of transitioning substantially all of our information technology infrastructure and related services internally or to other providers. Further, we have incurred additional legal expenses in conjunction therewith. Additionally, during 2022 we incurred increased costs related to salaries, benefits and incentive compensation as a result of the higher grant date fair values of stock awards granted during 2022 as compared to the value of awards granted in 2021, the lack of an employee retention credit provided under the CARES Act (which was received in 2021 and not received in 2022) and in response to wage and price inflation as compared to 2021 and as a result of inflation.

Other Income and Expense

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

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Derivative loss – During the year ended December 31, 2022, the $85.5 million derivative loss recorded for crude oil and natural gas derivative contracts consists of $125.1 million of realized losses on settled contracts and premium payments and $39.6 million of unrealized gain, net from the increase in fair value of open contracts. During the second quarter of 2022, the Company monetized a portion of existing hedge positions through restructuring of strike prices on certain outstanding purchased calls covering the second half of 2022 through the first quarter of 2025. This transaction resulted in net cash proceeds of $105.3 million, which are included as an offset to realized losses for 2022. During the year ended December 31, 2021, the $175.3 million derivative loss recorded for crude oil and natural gas derivative contracts consisted of $92.6 million in realized losses on settled contracts and premium payments and $82.8 million of unrealized losses from the decrease in the fair value of open oil and natural gas contracts.

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. 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 (loss) based on fluctuations in market prices for natural gas. As of December 31, 2022, we do not have any open oil contracts. See Financial Statements and Supplementary Data – Note 10 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K for additional information.

Interest expense, net – We finance a portion of our working capital requirements, capital expenditures and acquisitions with term-based debt and, from time to time, borrowings under our Credit Agreement. As a result, we may incur interest expense that is affected by both fluctuations in interest rates and the amount of debt outstanding. Interest expense includes interest incurred under our debt agreements, the amortization of deferred financing costs (including origination and amendment fees), commitment fees, performance bond premiums and annual agency fees. Interest expense is presented net of any interest income we may receive. Interest expense, net, was $69.4 million in 2022, decreasing $0.6 million from $70.0 million in 2021. The decrease is primarily due to an increase in interest income between the two periods offset by higher interest expense related to the full year of the Term Loan payments. See Financial Statements and Supplementary Data – Note 2 – Debt under Part II, Item 8 in this Form 10-K for additional information on our debt.

Other expense (income), net – During the year ended December 31, 2022, other expense, net, was $14.3 million, compared to $6.2 million of other income, net, for 2021. During 2022, other expense primarily consists of additional expenses for net abandonment obligations pertaining to a number of legacy Gulf of Mexico properties, partially offset by non-recurring adjustments. For 2021, the amount primarily consists of other income related to the release of restrictions on the Black Elk Escrow fund, partially offset by expenses for net abandonment obligations pertaining to a number of legacy Gulf of Mexico properties and the amortization of the brokerage fee paid in connection with the Joint Venture Drilling Program. See Financial Statements and Supplementary Data – Note 9 – Restricted Deposits for ARO in Part II, Item 8 in this Form 10-K for additional information regarding the release of the Black Elk Escrow restrictions. See Financial Statements and Supplementary Data – Note 18 – Contingencies in Part II, Item 8 in this Form 10-K for additional information regarding the asset retirement obligations recorded for legacy properties.

Income tax expense (benefit) – Our income tax expense for 2022 was $53.7 million, and the income tax benefit for 2021 was $8.1 million. For 2022 and 2021, the annual effective tax rate was 18.8% and 16.3%, respectively, and the rates differed from the federal statutory rate of 21% primarily due to adjustments in the valuation allowance and the impact of state income taxes.

During 2022, our valuation allowance decreased $9.0 million primarily due to the utilization of part of our disallowed interest expense carryover. Deferred tax assets are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or net operating losses are deductible. In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized.

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The Company assesses available positive and negative evidence regarding its ability to realize its deferred tax assets including reversing temporary differences and projections of future taxable income during the periods in which those temporary differences become deductible, as well as negative evidence such as historical losses. Assumptions about our future taxable income are consistent with the plans and estimates used to manage our business. The Company showed positive income in 2022 and continues to project similar results into the future. Based on this, we concluded that there is enough positive evidence to outweigh any negative evidence although any changes in forecasted taxable income could have a material impact on this analysis. The portion of the valuation allowance remaining relates to state net operating losses and the disallowed interest limitation carryover under IRC section 163(j). As of December 31, 2022, the Company’s valuation allowance was $15.3 million.

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 AROs. 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.

The primary sources of our liquidity are cash from operating activities and borrowings under our Credit Agreement. As of December 31, 2022, we had $461.4 million of available cash and $50.0 million available under our Credit Agreement, based on a borrowing base of $50.0 million. Additionally, we believe our access to the equity markets from our “at-the-market” equity offering program (“ATM Program”), our reserve based lending currently available under our Credit Agreement, along with our cash position, will provide us with additional liquidity to continue our growth to take advantage of the current commodity environment. During the year ended December 31, 2022, we sold an aggregate of 2,971,413 shares for an average price of $5.72 per share in connection with the ATM Offering and received proceeds, net of commissions and expenses, of $16.5 million.

As of December 31, 2022, we had outstanding $552.5 million principal of 9.75% Senior Second Lien Notes. On January 27, 2023, we issued $275.0 million of 11.75% Senior Second Lien Notes. The 11.75% Senior Second Lien Notes were issued at par and have a maturity date of February 1, 2026. On February 8, 2023, we redeemed all of the 9.75% Senior Second Lien Notes outstanding at a redemption price of 100.000%, plus accrued and unpaid interest to the redemption date. The Company used the net proceeds of $270.8 million from the issuance of the 11.75% Senior Second Lien Notes and cash on hand of $296.1 million to fund the redemption. See Financial Statements and Supplementary Data –Note 20 – Subsequent Events under Part II, Item 8 in this Form 10-K for additional information.

We believe that we will have adequate liquidity from cash flow from operations to fund our capital expenditure plans for 2023, fund our ARO spending for 2023 and fulfill our various other obligations. Our preliminary capital expenditure budget for 2023 has been established in the range of $90.0 million to $110.0 million, which excludes acquisitions. In our view of the outlook for 2023, we believe this level of capital expenditure will enhance our liquidity capacity throughout 2023 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 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.

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Sources and Uses of Cash

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

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Operating activities – Net cash provided by operating activities for 2022 was $339.5 million, increasing $205.9 million from 2021. The change between periods is primarily due to increased realized prices for crude oil, NGLs and natural gas in addition to increased volumes, decreased derivative settlement payments and derivative loss, and increased spending for ARO activities. Our combined average realized sales price per Boe increased 57.2% in 2022, which caused crude oil, NGLs and natural gas revenues to increase $314.3 million. In addition, increases of 5.1% in overall production volumes caused crude oil, NGLs and natural gas revenues to increase by $43.1 million.

These increases in operating cash flow were partially offset by (i) ARO settlements which decreased operating cash flows by $76.2 million as compared to $27.3 million during 2021; (ii) changes in operating assets and liabilities (excluding ARO settlements) which decreased operating cash flows by $7.2 million as compared to an increase of $33.7 million for the year ended December 31,  2021, primarily related to higher oil and natural gas receivables balances due to higher realized prices combined with lower payables and accrued liabilities balances.

Investing activities – Net cash used in investing activities increased $67.6 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021. The increase was primarily due to the acquisition of properties for $51.5 million along with other increases in capital spending during the year ended December 31, 2022 compared to 2021. See Financial Statements and Supplementary Data - Note 6 – Acquisitions under Part II, Item 8 in this Form 10-K for additional information. There were no asset sales of significance in 2022 or 2021. See discussion in Capital Expenditures below.

Financing activities – During the year ended December 31, 2022, net cash used in financing activities was $28.9 million, primarily due to four quarters of principal payments on the Term Loan offset by net proceeds received from the sales of equity securities under our ATM Program. During the year ended December 31, 2021, net cash provided by financing activities was $100.3 million which included the proceeds from the Term Loan of $206.8 million, offset by $24.1 million of principal payments on the Term Loan and repayment of $80.0 million of borrowings under the Credit Agreement. See Financial Statements and Supplementary Data - Note 1 – Significant Accounting Policies under Part II, Item 8 in this Form 10-K for additional information regarding our ATM Program.

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Derivative financial instruments – From time to time, we use various derivative instruments to manage a portion of our exposure to commodity price risk from sales of oil and natural gas. See Financial Statements and Supplementary Data – Note 10 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K for additional information about our derivative activities. The following table summarizes the historical results of our hedging activities:

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Income taxes – As of December 31, 2022, we have current income taxes payable of $0.4 million. During 2022, we did not receive any income tax refunds. For 2022, we made $8.2 million in income tax payments.

Dividends – During 2022, 2021 and 2020, we did not pay any dividends and a suspension of dividends remains in effect.

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 crude 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:

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The following table presents our exploration and development capital expenditures geographically:

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The capital expenditures reported in the above two tables are included within Oil and natural gas properties and other, net on the Consolidated Balance Sheets. The capital expenditures reported within the Investing section of the Consolidated Statements of Cash Flows include adjustments for payments related to capital expenditures.

Drilling Activity – We did not drill any wells during the year ended December 31, 2022. During the year ended December 31, 2022, we completed the East Cameron 349 B-1 well (“Cota”). The Cota well is in the Monza Joint Venture Drilling Program. See Financial Statements – Note 6 –Joint Venture Drilling Program Part II, Item 8 in this Form 10-K for additional information regarding Monza. See Properties – Drilling Activity under Part I, Item 2 of this Form 10-K for drilling activity information.

See Properties – Development of Proved Undeveloped Reserves under Part I, Item 2 of this Form 10-K for a discussion on activity related to proved undeveloped reserves.

Acquisitions – As described Financial Statements and Supplementary Data - Note 6 - Acquisitions under Part II, Item 8 in this Form 10-K, the Company acquired the working interest and operatorship of certain oil and natural gas producing properties in federal shallow waters in the Gulf of Mexico at Ship Shoal 230, South Marsh Island 27/Vermilion 191, and South Marsh Island 73 fields on February 1, 2022 and April 1, 2022. After normal and customary post-effective date adjustments (including net operating cash flow attributable to the properties from the effective date to the respective close date), cash consideration of approximately $34.0 million and $17.5 million was paid to the sellers. The transaction was funded using cash on hand.

Lease Acquisitions – Over the last three years, we have acquired six leases for approximately $1.5 million from the BOEM in the Federal Offshore Lease Sales. During 2021, we were the high bidder of two leases in Federal Offshore Lease Sale 257. In January 2022, a U.S District Court issued an order that could have invalidated these leases. Effective October 1, 2022, BOEM reinstated and accepted these bids and we were awarded one of these two leases in 2022 and the other in 2023 for approximately $0.1 million and $0.2 million, respectively. We acquired four leases for approximately $1.2 million in 2020.

Divestitures – From time to time, we sell various oil and gas properties for a variety of reasons including, change of focus, perception of value and to reduce debt, among other reasons. In 2022 and 2021, there were no property sales of significance.

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Asset retirement obligations – Annually, we review and revise our ARO estimates. Our ARO at December 31, 2022 and 2021 were $466.4 million and $424.5 million, respectively. The increase is primarily due to the acquisition of assets as described above. These increases were partially offset by $76.2 million related to liabilities settled. Our estimate of ARO spending in 2023 is approximately $25.0 to $35.0 million. During 2022 and 2021, we revised our estimates of costs anticipated to be charged by service providers for plugging and abandonment projects and revised estimated to actual spending as invoices were processed and projects completed. As these estimates are for work to be performed in the future, and in many cases, several years in the future, actual expenditures could be substantially different than our estimates. Additionally, we revise our estimates to account for the cost to comply with any new or revised regulations, including increases in work scope and cost changes from interpretation of work scope. See Risk Factors – Our estimates of future asset retirement obligations may vary significantly from period to period and are especially significant because our operations are concentrated in the Gulf of Mexico under Part I, Item 1A and Financial Statements and Supplementary Data – Note 7 – Asset Retirement Obligations under Part II, Item 8 in this Form 10-K for additional information regarding our ARO.

Debt

The primary terms of our long-term debt, the conditions related to incurring additional debt, and the conditions and limitations concerning early repayment of certain debt are disclosed in Financial Statements and Supplementary Data –Note 2 – Debt under Part II, Item 8 in this Form 10-K.

Term Loan – As of December 31, 2022, we had $147.9 million of Term Loan principal outstanding. The Term Loan requires quarterly amortization payments, bears interest at a fixed rate of 7.0% per annum and will mature on May 19, 2028. The Term Loan is non-recourse to the Company and its subsidiaries other than the Subsidiary Borrowers (and the subsidiary that owns the equity of the Subsidiary Borrowers), and is not secured by any assets other than first lien security interests in the equity in the Borrowers and a first lien mortgage security interest and mortgages on certain assets of the Subsidiary Borrowers.

Credit Agreement – As of December 31, 2022, we had no borrowings outstanding under the Credit Agreement. On November 7, 2022, the Company entered into the Eleventh Amendment to Sixth Amended and Restated Credit Agreement and Extension Agreement, which extended the maturity date and Lender commitment to January 3, 2024.

9.75% Senior Second Lien Notes due 2023 – As of December 31, 2022, we had $552.5 million principal outstanding of 9.75% Senior Second Lien Notes outstanding. On February 8, 2023, we redeemed all of the 9.75% Senior Second Lien Notes outstanding at a redemption price of 100.000%, plus accrued and unpaid interest to the redemption date. The Company used the net proceeds of $270.8 million from the issuance of the 11.75% Senior Second Lien Notes due 2026 and cash on hand of $296.1 million to fund the redemption and interest. See Financial Statements and Supplementary Data –Note 20 – Subsequent Events under Part II, Item 8 in this Form 10-K for additional information.

11.75% Senior Second Lien Notes due 2026 – On January 27, 2023 we issued and sold $275 million in aggregate principal amount of our 11.75% Senior Second Lien Notes at par with an interest rate of 11.75% per annum that matures on February 1, 2026. The 11.75% Senior Second Lien Notes are secured by second-priority liens on the same collateral that is secured under the Credit Agreement. See Financial Statements and Supplementary Data –Note 20 – Subsequent Events under Part II, Item 8 in this Form 10-K for additional information.

Debt Covenants – The Term Loan, Credit Agreement, and 9.75% Senior Second Lien Notes contain financial covenants calculated as of the last day of each fiscal quarter, which include thresholds on financial ratios, as defined in the respective Subsidiary Credit Agreement, the Credit Agreement and the indenture related to the 9.75% Senior Second Lien Notes. We were in compliance with all applicable covenants of the Term Loan, Credit Agreement and the 9.75% Senior Second Lien Notes indenture as of and for the period ended December 31, 2022. See Financial Statements and Supplementary Data – Note 2 – Debt under Part II, Item 8 in this Form 10-K for additional information.

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The Subsidiary Borrowers

On May 19, 2021, we formed A-I LLC and A-II LLC, both indirect, wholly-owned subsidiaries of W&T Offshore, Inc., through their parent, Aquasition Energy LLC (collectively, the Aquasition Entities”). Concurrently, A-I LLC and A-II II LLC, entered into a credit agreement providing for the Term Loan in an initial aggregate principal amount equal to $215.0 million. Proceeds of the Term Loan were used by A-I LLC and A-II LLC to fund the acquisition of the Mobile Bay Properties and the Midstream Assets, respectively, from the Company. The Term Loan is non-recourse to the Company and any subsidiaries other than the Aquasition Entities, and is secured by the first lien security interests in the equity of the Aquasition Entities and a first lien mortgage security interest in the Mobile Bay Properties. See Financial Statements and Supplementary Data – Note 4 – Subsidiary Borrowers under Part II, Item 8 in this Annual Report for additional information.

We designated the Aquasition Entities as unrestricted subsidiaries under the Indenture (the “Unrestricted Subsidiaries”). Having been so designated, the Unrestricted Subsidiaries do not guarantee the 11.75% Senior Second Lien Notes and the liens on the assets sold to the Unrestricted Subsidiaries have been released under the Credit Agreement. The Unrestricted Subsidiaries are not bound by the covenants contained in the Credit Agreement or the Indenture. Under the Subsidiary Credit Agreement and related instruments, assets of the Aquasition Entities may not be available to mortgage or pledge as security to secure new indebtedness of the Company and its other subsidiaries. See Financial Statements and Supplementary Data – Note 2 – Debt under Part II, Item 8 in this Form 10-K for additional information.

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Below is consolidating balance sheet information reflecting the elimination of the accounts of our Unrestricted Subsidiaries from our Consolidated Balance Sheet as of December 31, 2022 (in thousands):

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Below is Consolidating Statement of Operations information reflecting the elimination of the accounts of our Unrestricted Subsidiaries from our Consolidated Statement of Operations for the year ended December 31, 2022 (in thousands):

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The following table presents our produced oil, NGLs and natural gas volumes (net to our interests) from the Mobile Bay Properties for the periods indicated:

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Reserves information for the Mobile Bay properties is described in more detail under Part I Item 2, Properties, in this Form 10-K.

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Contractual Obligations

At December 31, 2022, we did not have any financing leases. The following table summarizes our significant contractual obligations by maturity as of December 31, 2022 (in millions):

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(a) interest payments for the Credit Agreement were calculated using the interest rate applied to our outstanding balance as of December 31, 2022 and assumes no change in this interest rate in future periods. In addition, a commitment fee of 3.0% was applied on the available balance as of December 31, 2022 and fees related to letters of credit were estimated at the rate incurred on December 31, 2022;​

(b) interest payments on the 9.75% Senior Second Lien Notes were calculated per the terms of the notes; and​

(c) interest payments on the Term Loan were calculated at the 7.0% interest rate set forth in the Term Loan.​

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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, Items 1 and 2 Business and Properties; Item 1A Risk Factors; and Item 7A Quantitative and Qualitative Disclosures About Market Risk and with Part II, Item 8 Financial Statements and Supplementary Data in this Annual Report. 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 Annual Report, particularly in Part I, Item 1A Risk Factors.

This section of this Annual Report generally discusses 2021 and 2020 items and year-to-year comparisons between 2021 and 2020. Discussions of 2019 items and year-to-year comparisons between 2020 and 2019 that are not included in this Annual Report are incorporated by reference to Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of the Company’s Annual Report on Form 10-K for the year ended December 31, 2020.

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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 Mexico. We have grown through acquisitions, exploration and development and currently hold working interests in 43 offshore producing fields in federal and state waters (38 producing fields and 5 capable of producing). We currently have under lease approximately 606,000 gross acres (412,000 net acres) spanning across the OCS off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 8,000 gross acres in Alabama State waters, 411,000 gross acres on the conventional shelf and approximately 187,000 gross acres in the deepwater. A majority of our daily production is derived from wells we operate. We currently own interests in 144 offshore structures, 103 of which are located in fields that we operate. We currently own interest in 178 productive wells, 142 of which we operate. Our interest in fields, leases, structures and equipment are primarily owned by W&T Offshore, Inc. and our wholly-owned subsidiaries, Aquasition LLC, Aquasition II LLC, and W & T Energy VI LLC, Delaware limited liability companies and through our proportionately consolidated interest in Monza, as described in more detail in Financial Statements and Supplementary Data – Notes 4 and 5 under Part II, Item 8 in this Annual Report.

Business Strategy

Our goal is to pursue high rate of return projects and develop oil and natural gas resources that allow us to grow our production, reserves and cash flow in a capital efficient manner, thus enhancing the value of our assets. We intend to execute the following elements of our business strategy in order to achieve this goal:

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Our focus is on making profitable investments while operating within cash flow, maintaining sufficient liquidity, cost reductions and fulfilling our contractual, legal and financial obligations. Over time, we expect to de-lever through free cash flow generated by our producing asset base, capital discipline, organic growth and acquisitions. We continue to closely monitor current and forecasted commodity prices to assess if changes are needed to be made to our plans.

In managing our business, we are focused on optimizing production and increasing reserves in a profitable and prudent manner, while managing cash flows to meet our obligations and investment needs. Our cash flows are materially impacted by the prices of commodities we produce (crude oil and natural gas, and the NGLs extracted from the natural gas). In addition, the prices of goods and services used in our business can vary and impact our cash flows. During 2021, average realized commodity prices increased from those we experienced during 2020 and 2019. Our margins in 2021 increased from 2020 primarily due to higher average realized commodity prices, partially offset by higher operating expenses as a result of our cost-cutting efforts in 2021. We measure margins using Adjusted EBITDA as a percent of revenue, which is a not a financial measurement under GAAP. We have historically increased our reserves and production through acquisitions, our drilling programs, and other projects that optimize production on existing wells. Our production decreased 9.6% in 2021 from the prior year. Our proved reserves increased by 13.2 MMBoe in 2021, primarily due to the significant increase in commodity prices in 2021 as compared to 2020.

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Factors Affecting the Comparability of our Financial Condition and Results of Operations

Mobile Bay Transaction. During the second quarter of 2021, the Company’s wholly-owned special purpose subsidiary vehicles, A-I LLC and A-II LLC (or collectively the “Subsidiary Borrowers”), entered into the Subsidiary Credit Agreement providing for a secured term loan (“Term Loan”) in an initial aggregate principal amount equal to $215.0 million. Proceeds of the Term Loan were used by the Subsidiary Borrowers to (i) fund the acquisition of the Mobile Bay Properties and the Midstream Assets from the Company and (ii) pay fees, commissions and expenses in connection with the transactions contemplated by the Subsidiary Credit Agreement and the other related loan documents, including to enter into certain swap and put derivative contracts. This transaction is described in more detail under Financial Statements and Supplementary Data – Note 4 – Mobile Bay Transaction, under Part II, Item 8, of this Annual Report.

Hurricanes and Severe Weather. During the third quarter of 2021, our production from the U.S Gulf of Mexico was impacted due to precautionary shut-ins of facilities and evacuations primarily associated with Hurricane Ida. While Company assets and infrastructure did not suffer significant damage during the storm, unplanned costs of $5.8 million for minor repairs and restoring production, as well as evacuating employees and contractors, were incurred as a result of the hurricane and reflected in lease operating expense. For the year ended December 31, 2021, we estimate deferred production related to these storms was approximately 0.8 MMBoe per day. See Liquidity and Capital Resources – Insurance Coverage under this Item 7 in this Form 10-K for additional information.

Known Trends and Uncertainties

Volatility in Oil, NGL and Natural Gas Prices. Historically, the markets for oil and natural gas has been volatile. Our realized sales prices received for our crude oil, NGLs and natural gas production are affected by 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. As a result, we cannot accurately predict future commodity prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our drilling program, production volumes or revenues.

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During 2021, commodity prices experienced significant improvement, particularly crude oil prices, due to a confluence of factors that have provided positive developments to the overall pricing environment when compared to 2020. With some exceptions, pandemic-related travel restrictions have gradually eased as governments continue to have increasing access to vaccines that help reduce the spread of COVID-19. As restrictions continue to abate, there is renewed emphasis on improving economic activity to pre-pandemic levels while managing the risk of a resurgence in COVID-19. Meanwhile, commodity prices demonstrated resiliency during the year. Producers continued to show restraint in increasing their capital expenditures even as prices increased, thereby causing a muted response in supply as demand for commodities increased. Additionally, OPEC Plus remained committed to modest increases in production during the year as the global economy recovered.‌

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While the current outlook for commodity prices is favorable and our operations are no longer significantly impacted by confinement restrictions, the risk of disruption to our operations continues as the emergence of a new variant of COVID-19 could adversely impact our operations, or commodity prices could significantly decline from current levels. The ongoing COVID-19 outbreak continues to evolve and, during the fourth quarter of 2021, a new variant emerged, the Omicron variant. It is difficult to assess if it will cause meaningful disruptions in economic activity across the world and if there will be any significant impacts in demand for energy.

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The recent invasion of parts of Ukraine by Russia, and the impact of world sanctions against Russia and the potential for retaliatory acts from Russia, are world events that can result in potential commodities and securities market disruptions that could affect world oil and natural gas markets and the volatility of oil and gas commodity prices and thus impact the Company’s business, stock trading price and availability of capital. Additionally, while OPEC Plus remained committed to steady and predictable production increases throughout 2021, it is difficult to determine whether it will change its production output policy or whether its members will remain committed to the production quotas set by the organization as a result of these events.

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WTI is frequently used to value domestically produced crude oil, and the majority of our crude oil production is priced using the spot price for WTI as a base price, then adjusted for the type and quality of crude oil and other factors. NYMEX WTI daily spot crude oil prices averaged $68.14 per barrel during 2021, up from $39.16 barrel during 2020 (74% increase). The U.S. Energy Information Administration (“EIA”) in their Short-Term Energy Outlook issued in January 2022 projects average crude oil prices for WTI to increase to approximately $71.32 per barrel in 2022, and decrease in 2023 to approximately $63.50 per barrel. The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. NYMEX Henry Hub spot prices averaged $3.89 per MMBtu during 2021, up from $2.03 per MMBtu during 2020. The EIA projects average natural gas prices for Henry Hub to decrease to approximately $3.94 per MMBtu in 2022, and decrease further in 2023 to approximately $3.77 per MMBtu. Global oil production is forecasted to outpace global oil consumption during 2022 resulting in rising global oil inventories. Oil market balances are subject to significant uncertainties which could keep oil prices volatile.

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

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Impairment of Oil and Natural Gas Properties. Under the full cost method of accounting that we use for our oil and gas operations, our capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. Any costs in excess of the ceiling are recognized as a non-cash “Write-down of oil and natural gas properties” on the Consolidated Statements of Operations and an increase to “Accumulated depreciation, depletion and amortization” on our Consolidated Balance Sheets. The expense may not be reversed in future periods, even though higher oil, natural gas and NGL prices may subsequently increase the ceiling. We perform this ceiling test calculation each quarter. In accordance with the SEC rules and regulations, we utilize SEC Pricing when performing the ceiling test. At December 31, 2021, the Company’s ceiling test computation was based on SEC pricing of $65.25 per Bbl of oil, $3.68 per Mcf of natural gas and $26.83 per Bbl of NGLs.

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As part of our period end reserves estimation process for future periods, we expect changes in the key assumptions used, which could be significant, including updates to future pricing estimates and differentials, future production estimates to align with our anticipated five-year drilling plan and changes in our capital costs and operating expense assumptions, which we expect to decrease further as a result of sustained lower commodity prices. There is a significant degree of uncertainty with the assumptions used to estimate future undiscounted cash flows due to, but not limited to the risk factors referred to in Part I, Item 1A. Risk Factors. Any decrease in pricing, negative change in price differentials, or increase in capital or operating costs could negatively impact the estimated undiscounted cash flows related to our proved oil and natural gas properties.

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Deferred Production. Our oil, NGLs and natural gas production is significantly affected by unplanned production downtime caused by events outside of our control and create uncertainties in our financial condition, cash flow and results of operations. Such events include third party downtime associated with non-operated properties and the transportation, gathering or processing of production and weather events.

Hurricane and Severe Weather Events. Since our operations are in the Gulf of Mexico, we are particularly vulnerable to the effects of hurricanes on production. We normally obtain insurance to reduce, but not totally mitigate, our financial exposure risk; however, affordable insurance coverage for property damage to our facilities for hurricanes is not assured. See Liquidity and Capital Resources – Insurance Coverage under this Item 7 in this Form 10-K for additional information. Significant hurricane impacts could include reductions and/or deferrals of future oil and natural

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gas production and revenues, increased lease operating expense for evacuations and repairs and possible acceleration of plugging and abandonment costs.

Regulations. We are subject to a number of regulations from federal and state governmental entities, which are described under Part I, Item 1, Regulations in this Form 10-K. Our Company and others like us, are exposed to a number of risks by operating in the oil and gas industry in the Gulf of Mexico, which are described in Item 1A, Risk Factors, in this Form 10-K.

BOEM Matters. As of the filing date of this Form 10-K, the Company is in compliance with its financial assurance obligations to the BOEM and has no outstanding BOEM orders related to financial assurance obligations. We and other offshore Gulf of Mexico producers may, in the ordinary course of business, receive demands in the future for financial assurances from the BOEM. For more information on the BOEM and financial assurance obligations to that agency, see Business – Compliance with Government Regulations – Decommissioning and financial assurance requirements under Part I, Item 1 of this Form 10-K.

Surety Bond Collateral. Some of the sureties that provide us surety bonds used for supplemental financial assurance purposes have requested and received collateral from us, and may request additional collateral from us in the future, which could be significant and could impact our liquidity. In addition, pursuant to the terms of our agreements with various sureties under our existing bonds or under any additional bonds we may obtain, we are required to post collateral at any time, on demand, at the surety’s discretion. In 2021 or 2020, we have not had to post collateral for sureties and we currently do not have any collateral posted for Surety Bonds. The issuance of any additional surety bonds or other security to satisfy future BOEM orders, collateral requests from surety bond providers, and collateral requests from other third-parties may require the posting of cash collateral, which may be significant, and may require the creation of escrow accounts.

Consolidated Appropriations Act, 2021. Under the Consolidated Appropriations Act, 2021 passed by the United States Congress and signed by the President on December 27, 2020, provisions of the CARES Act were extended and modified making the Company eligible for a refundable employee retention credit subject to meeting certain criteria. See Financial Statements and Supplementary Data – Note 1 – Significant Accounting Policies under Part II, Item 8, and Liquidity and Capital Resources in this Item 7 of this Form 10-K for additional information.

Results of Operations

Year Ended December 31, 2021 Compared to Year Ended December 31, 2020

Revenues

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs. Our oil, natural gas and NGL revenues do not include the effects of derivatives, which are reported in “Derivative income (expense)” in our Consolidated Statements of Operations. The following table presents our sources of revenue as a percentage of total revenue:

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The information below provides a discussion of, and an analysis of significant variance in, our oil, natural gas and NGL revenues, production volumes and sales prices for the years ended December 31, 2021 and 2020 (in thousands):

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Changes in average sales prices and sales volumes caused the following changes to our oil, NGL and natural gas revenues between the years ended December 31, 2021 and 2020 (in thousands):

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Realized Prices on the Sale of Oil, NGLs and Natural Gas. Our average realized crude oil sales price differs from the WTI benchmark average crude price due primarily to premiums or discounts, crude oil quality adjustments, and volume weighting (collectively referred to as differentials). Crude oil quality adjustments can vary significantly by field as a result of quality and location. For example, crude oil from our East Cameron 321 field normally receives a positive quality adjustment, whereas crude oil from our Mahogany field normally receives a negative quality adjustment. All of our crude oil is produced offshore in the Gulf of Mexico and is primarily characterized as Poseidon, Light Louisiana Sweet (“LLS”), and Heavy Louisiana Sweet (“HLS”). Similar to crude oil prices, the differentials for our offshore crude oil have also experienced volatility in the past. The monthly average differentials of WTI versus Poseidon, LLS and HLS for 2021 declined on average by approximately $0.63 - $1.13 per barrel compared to 2020 for these types of crude oils with the Poseidon having a negative differential and the LLS and HLS having positive differentials as measured on an index basis.

Two major components of our NGLs, ethane and propane, typically make up approximately 70% of an average NGL barrel. During 2021, average prices for domestic ethane increased by 62.7% and average domestic propane prices increased by 125.7% from 2020 as measured using a price index for Mount Belvieu. The changes in the average price for other domestic NGLs components in 2021 ranged from an increase of 100.9% to 103.7% year-over-year.

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The actual prices we realize from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. Currently, the sales points of our gas production are generally within close proximity to the Henry Hub which creates a minimal differential in the prices we receive for our production versus average Henry Hub prices.

Oil, NGLs, and Natural Gas Volumes.  Production volumes decreased by 1,476 MBoe to 13,913 MBoe primarily due to adverse weather events during the 3rd quarter of 2021, well maintenance and natural declines. Deferred production for 2021 related to these named storms and maintenance events collectively resulted in deferred production of 2.2 MMBoe, compared to 2.8 MMBoe in 2020.

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:

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Lease operating expenses. Lease operating expenses include the expense of operating and maintaining our wells, platforms and other infrastructure primarily in the Gulf of Mexico. These operating costs are comprised of several components, including direct or base lease operating expenses, insurance premiums, workover costs, facilities repairs and maintenance expenses, and hurricane repair 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 $11.7 million to $174.6 million in 2021 compared to $162.9 million in 2020. On a per Boe basis, lease operating expenses increased to $12.55 per Boe during 2021 compared to $10.58 per Boe during 2020. On a component basis, base lease operating expenses increased $5.0 million, workover expenses increased $1.8 million, facilities maintenance expenses increased $4.9 million, and hurricane repairs increased $1.0 million. These increases were partially offset by decrease of $1.0 million in insurance premiums.

Expenses for direct labor, materials and supplies, rental and third party costs comprise the most significant portion of our base lease operating expense. Base lease operating expenses increased primarily due to (i) a net increase in contract labor, equipment rental, and transportation costs of $3.6 million at various fields; (ii) increased incentive compensation costs related to field employees of $2.2 million; (iii) a reduction in credits to expense from prior period royalty adjustments of $1.5 million as compared to the prior period; and (iv) a reduction in credits to expense of $2.3 million received in prior period from the PPP funds; partially offset by (v) $4.6 million of reduced expenses related to fields that were no longer producing during the year ended December 31, 2021, cost savings from the consolidation of our two gas processing plants in Alabama, and other miscellaneous items.

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Workovers 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.

Production taxes. Production taxes consist of severance taxes levied by the Alabama 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, respectively. Production taxes were $10.1 million in 2021, an increase of $5.2 million as compared to 2020, primarily due to the increase in realized natural gas prices, partially offset by decreased natural gas production volumes.

Gathering and transportation costs. Gathering and transportation costs consist of costs incurred in the post-production shipping of oil, NGLs, and natural gas to the point of sale. Gathering and transportation costs increased to $17.8 million in 2021 compared to $16.0 million in 2020 primarily due to lower costs in the prior year that were impacted by credits to expense associated with the finalization of the Mobile Bay acquisition.

Depreciation, depletion, amortization and accretion. Depreciation, depletion and amortization expense 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. See Part II, Item 8. Financial Statements and Supplementary data — Note 1 — Summary of Significant Accounting Policies for further discussion. Accretion expense is the expensing of the changes in value of our asset retirement obligations 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. DD&A, which includes accretion for ARO, increased to $8.15 per Boe in 2021 from $7.82 per Boe in 2020. On a nominal basis, DD&A decreased to $113.4 million in 2021 from $120.3 million in 2020. The rate per Boe increased year-over-year mostly as a result of increases in the future development costs included in the depreciable base compared to the relatively smaller increase in proved reserves over the comparable prior year period.

General and administrative expenses (“G&A”). G&A expense generally consists 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, equity based compensation expense, audit and other fees for professional services and legal compliance. For 2021, G&A expenses were $52.4 million compared to $41.7 million in 2020. The increase in 2021 G&A expense compared to 2020 was primarily due to (i) a net increase of $4.4 million increase in legal costs and other miscellaneous expenses primarily related to credits to expense in the prior period to adjust for the final settlement of BEE civil penalties; (ii) a net increase of $3.4 million in payroll and incentive compensation expenses as share based compensation expense and cash incentive compensation expense did not occur in the prior period; (iii) a reduction in overhead allocations to partners (credits to expense) of $0.7 million; (iv) credits related to the PPP funds received in the prior period; partially offset by (v) the $2.1 million employee retention credit recognized during the first quarter of 2021. See Financial Statements – Note 1 – Basis of Presentation under Part 1, Item 1, and Liquidity and Capital Resources in this Item 2 of this Quarterly Report for additional information on the employee retention credit.

Other Income and Expense

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

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Derivative loss (gain). We utilize commodity derivative instruments to reduce our exposure to fluctuations in the price of oil and natural gas. We recognize gains and losses associated with our open commodity derivative contracts as

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commodity prices and the associated fair value of our commodity derivative contracts change. The commodity derivative contracts we have in place are not designated as hedges for accounting purposes. Consequently, these commodity derivative contracts are marked-to-market each quarter with fair value gains and losses recognized currently as a gain or loss in our results of operations. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty. Changes in the fair value and settlements are recorded on the Consolidated Statements of Operations in Derivative loss (gain) as an unrealized loss (gain) and a realized loss (gain), respectively. Additionally, we amortize derivative cash premiums paid for options over the life of the related contract on the Consolidated Statements of Operations in Derivative loss (gain) as a component of realized loss.

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During 2021, a $175.3 million derivative loss was recorded for crude oil and natural gas derivative contracts. Of the total derivative loss, approximately $80.1 million and $95.2 million were associated with the unrealized loss and realized loss, respectfully. The realized derivative loss recorded in 2021 includes approximately $5.1 million of derivative premium amortization. The remaining realized derivative loss and unrealized derivative loss were primarily due to crude oil and natural gas prices rising throughout 2021 as compared to prices as of December 31, 2020, which decreased the estimated fair value of open contracts and decreased the settlement value of closed contracts. During 2020, a $23.8 million derivative gain was recorded for crude oil and natural gas derivative contracts. The total derivative gain includes a $33.4 million realized derivative gain offset by a $9.6 million unrealized derivative loss. The realized derivative gain recorded in 2020 was primarily due to crude oil prices falling during the second quarter of 2020 to historic lows, which increased the settlement value of closed contracts; the realized derivative gain was offset by $1.9 million of derivative premium amortization. The unrealized derivative loss in 2020 is primarily due to crude oil prices rising in the latter months of 2020, which decreased the estimated fair value of open contracts. See Financial Statements and Supplementary Data – Note 10 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K for additional information.

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Interest expense, net. We finance a portion of our working capital requirements, capital expenditures and acquisitions with term-based debt and, from time to time, borrowings under our Credit Agreement. As a result, we may incur interest expense that is affected by both fluctuations in interest rates and the amount of debt outstanding. Interest expense includes interest incurred under our debt agreements, the amortization of deferred financing costs (including origination and amendment fees), commitment fees, performance bond premiums and annual agency fees. Interest expense is presented net of any interest income we may receive. Interest expense, net, was $70.0 million in 2021, increasing $8.7 million from $61.5 million in 2020. The increase is primarily due to interest expense on the principal balance of the Term Loan, lower interest income between the two periods, and a reduction in credits to interest expense related to the PPP funds received in the prior period; partially offset by reductions to outstanding borrowings (lower interest expense) under the Credit Agreement during 2021 and a full year of reduced interest on the lower principal balance of the Senior Second Lien Notes. See Financial Statements and Supplementary Data – Note 2 – Debt under Part II, Item 8 in this Form 10-K for additional information on our debt.

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Gain on debt transactions. During 2020, the repurchase of a portion of our Senior Second Lien Notes resulted in a gain of $47.5 million for 2020. See Financial Statements and Supplementary Data – Note 2 – Debt under Part II, Item 8 in this Form 10-K for additional information.

Other (income) expense, net. During 2021, other income, net, was $6.2 million, compared to $3.0 million of other expense, net, for 2020. For 2021, the amount primarily consists of other income related to the release of restrictions on the Black Elk Escrow fund, partially offset by expenses for net abandonment obligations pertaining to a number of legacy Gulf of Mexico properties and the amortization of the brokerage fee paid in connection with the Joint Venture Drilling Program. For 2020, the amount primarily consisted of expenses related to the amortization of the brokerage fee paid in connection with the Joint Venture Drilling Program. See Financial Statements and Supplementary Data – Note 9 – Restricted Deposits for ARO in Part II, Item 8 in this Form 10-K for additional information regarding the release of the Black Elk Escrow restrictions. See Financial Statements and Supplementary Data – Note 18 – Contingencies in Part II, Item 8 in this Form 10-K for additional information regarding the asset retirement obligations recorded for legacy properties.

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Income tax benefit (expense). Our income tax benefit for 2021 and 2020 was $8.1 million and $30.2 million, respectively. For 2021, our annual effective tax rate of 16.3% differed from the federal statutory rate of 21% primarily due to changes in our valuation allowance on our interest expense limitation carryover. Our effective tax rate for 2020 was not meaningful, and our income tax benefit was primarily due to the enactment of the Coronavirus Aid, Relief and Economic Security Act (“Cares Act”) on March 27, 2020 and the issuance by the United States Treasury Department (Treasury) of final and proposed regulations under Internal Revenue Code (“IRC”) Section 163(j) on July 28, 2020 that provided additional guidance and clarification to the business interest expense limitation.

During 2021, our valuation allowance increased $2.0 million primarily due to an increase in our disallowed interest expense limitation carryover. Deferred tax assets are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or net operating losses are deductible.  In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be realized.

The Company assesses available positive and negative evidence regarding our ability to realize our deferred tax assets including reversing temporary differences and projections of future taxable income during the periods in which those temporary differences become deductible, as well as negative evidence such as historical losses. Assumptions about our future taxable income are consistent with the plans and estimates used to manage our business. Although the Company incurred a loss in 2021, we determined that these results were not indicative of future results and concluded that the positive evidence outweighed the negative evidence although any changes in forecasted taxable income could have a material impact on this analysis. The portion of the valuation allowance remaining relates to state net operating losses, charitable contributions carryover and the disallowed interest limitation carryover under IRC section 163(j). As of December 31, 2021, the Company’s valuation allowance was $24.4 million.

Liquidity and Capital Resources

Liquidity Overview

Our primary uses of cash are for capital expenditures, working capital, debt service and for general corporate purposes. We fund capital expenditures and strategic property acquisitions to allow us to replace our oil and natural gas reserves, repay outstanding borrowings, make related interest payments and satisfy our AROs. 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 borrowings.

The primary sources of our liquidity are cash from operating activities and borrowings under our Credit Agreement. As of December 31, 2021, we had $245.8 million of available cash and $50.0 million available under our Credit Agreement, based on a borrowing base of $50.0 million. Subsequent to December 31, 2021, we have agreed to an extension of the Credit Agreement with Calculus Lending until January 3, 2023. See discussion in Credit Agreement below.

We believe that we will have adequate liquidity from cash flow from operations to fund our capital expenditure plans for 2022, fund our ARO spending for 2022 and fulfill our various other obligations. Availability under our Credit Agreement as of December 31, 2021 was $50.0 million. Our preliminary capital expenditure budget for 2022 has been established in the range of $70.0 million to $90.0 million, which includes our share of the Joint Venture Drilling Program, and excludes acquisitions. In our view of the outlook for 2022, we believe this level of capital expenditure will enhance our liquidity capacity throughout 2022 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 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 prices improve, we may increase our investments. Beyond 2022, while we expect to continue to have adequate liquidity from cash flow from operations to fulfill our future obligations, we continue to evaluate financing and refinancing alternatives on a strategic basis.

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Sources and Uses of Cash

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

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Operating activities. Net cash provided by operating activities for 2021 was $133.7 million, increasing $25.2 million from 2020. The change between periods is primarily due to increased realized prices for crude oil, NGLs and natural gas, partially offset by decreased volumes, increased derivative settlement payments, and increased spending for ARO activities. Our combined average realized sales price per Boe increased 80.9% in 2021, which caused total revenues to increase $247.2 million, partially offset by decreases of 9.6% in overall production volumes which caused revenues to decrease by $34.4 million.

Other items affecting operating cash flows for 2021 were: ARO settlements of $27.3 million, which increased from $3.3 million in 2020; cash advances from joint venture partners of $7.8 million during 2021 compared to $2.0 million during 2020; derivative cash payments, net, were $81.3 million in 2021 compared to derivative cash receipts, net, of $45.2 million in 2020; and derivative premiums of $40.5 million were paid in 2021.

Investing activities. Net cash used in investing activities during 2021 and 2020 was $27.4 million and $47.6 million, respectively, which represents our acquisitions and investments in oil and gas properties and equipment. Investments in oil and natural gas properties (including changes in operating assets and liabilities associated with investing activities) during 2021 decreased $17.4 million from 2020 primarily due to less capital projects being undertaken in 2021 as compared to 2020. During 2020, the acquisition of property interest of $2.9 million was primarily related to the additional working interest acquisitions at the Mobile Bay Properties and Magnolia field. There were no significant acquisitions in 2021. There were no asset sales of significance in 2021 or 2020. See discussion in Capital Expenditures below.

Financing activities. Net cash provided by financing activities for 2021 was $100.3 million and net cash used in financing activities for 2020 was $49.6 million. During 2021, net cash provided by financing activities included the proceeds from the Term Loan of $215.0 million, offset by $9.8 million of debt issue costs incurred related to the Term Loan and the Ninth Amendment to the Credit Agreement, the repayment of $80.0 million of borrowings under the Credit Agreement and repayments of $24.1 million of the Term Loan. During 2020, net cash used in financing activities was from repayments of funds borrowed under the Credit Agreement and the purchase of the Senior Second Lien Notes, offset by borrowings under the Credit Agreement. The purchase of the Senior Second Lien Notes are disclosed in Financial Statements and Supplementary Data - Note 2 – Debt under Part II, Item 8 in this Form 10-K.

Joint Venture Drilling Program. To provide additional financial flexibility, we created the Joint Venture Drilling Program with private investors during 2018. The Joint Venture Drilling Program enables W&T to receive returns on its investment on a promoted basis and enables private investors to participate in certain drilling projects. It also allows more projects to be taken on with our capital expenditures budget and reduces our risk via diversification. In the Joint Venture Drilling Program, four wells came on line during 2018 and five came on line during 2019. During 2020, one well was drilled, which we completed in March 2022. See Financial Statements and Supplementary Data – Note 5 – Joint Venture Drilling Program under Part II, Item 8 in this Form 10-K for additional information on the Joint Venture Drilling Program.

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Derivative financial instruments. From time to time, we use various derivative instruments to manage a portion of our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our revolving bank credit facility. During 2021 and 2020, we entered into commodity contracts for crude oil and natural gas which related to a portion of our expected production for the time frames covered by the contracts. As of December 31, 2021, we had outstanding open derivatives for crude oil and natural gas. See Financial Statements and Supplementary Data – Note 10 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K for additional information. The following table summarizes the historical results of our realized hedging activities:

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Income taxes. As of December 31, 2021, we have current income taxes payable of $0.1 million. During 2021, we did not receive any income tax refunds. For 2021, we did not make any significant income tax payments. Additionally, we do not anticipate making any significant tax payments for 2022.

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Dividends. During 2021, 2020 and 2019, we did not pay any dividends and a suspension of dividends remains in effect.

Discretionary Bonus to Employees Approved in February 2021. On February 15, 2021, the Company received approval from the Compensation Committee of the Board of Directors for the one-time payment of a discretionary cash bonus in the amount of $7.0 million, paid in equal installments on March 15, 2021 and April 15, 2021, subject to employment on those dates.

Employee Retention Credit. Under the Consolidated Appropriations Act, 2021 passed by the United States Congress and signed by the President on December 27, 2020, provisions of the CARES Act were extended and modified making the Company eligible for a refundable employee retention credit subject to meeting certain criteria. The Company recognized a $2.1 million employee retention credit during the year ended December 31, 2021 which is included as a credit to General and administrative expenses in the Consolidated Statement of Operations.

Capital Expenditures

Our preliminary capital expenditure budget for 2022 has been established in the range of $70.0 million to $90.0 million, which includes our share of the Joint Venture Drilling Program and excludes acquisitions. We strive to maintain flexibility in our capital expenditure projects and if prices improve, we may increase our investments. We have flexibility in our capital expenditure programs as we have no long-term rig commitments and our current commitments with partners are short term.

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The level of our investment in oil and natural gas properties changes from time to time depending on numerous factors including the prices of crude 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:

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The following table presents our exploration and development capital expenditures geographically:

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The capital expenditures reported in the above two tables are included within Oil and natural gas properties and other, net on the Consolidated Balance Sheets. The capital expenditures reported within the Investing section of the Consolidated Statements of Cash Flows include adjustments for payments related to capital expenditures.

The following table sets forth our drilling activity for completed wells on a gross basis:

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We had a 100% success rate in 2019. During 2020, we drilled one well, which we completed in March 2022. All of the wells drilled in 2019 and 2020 are in the Joint Venture Drilling Program. During 2021, we participated in the drilling of an exploration well which we do not plan to complete.

See Properties – Drilling Activity under Part I, Item 2 of this Form 10-K for a breakdown of exploration and development wells and additional drilling activity information.

See Properties – Development of Proved Undeveloped Reserves under Part I, Item 2 of this Form 10-K for a discussion on activity related to proved undeveloped reserves.

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Lease Acquisitions. Over the last three years, we have acquired 23 leases for approximately $5.0 million from the BOEM in the Federal Offshore Lease Sales. We acquired 4 leases ($1.2 million) and 17 leases ($3.8 million) in the years 2020 and 2019, respectively. During 2021, we were the high bidder of two leases in Federal Offshore Lease Sale 257. In January 2022, a U.S District Court issued an order that could invalidate these leases. We are evaluating the court’s opinion and considering our options, which could include participating in an appellate process with peer companies and industry groups. If we are ultimately awarded, we will pay approximately $0.3 million for the awarded leases combined, which reflect a 100% working interest in the acreage.

Divestitures. From time to time, we sell various oil and gas properties for a variety of reasons including, change of focus, perception of value and to reduce debt, among other reasons. In 2021 and 2020, there were no property sales of significance. See Financial Statements and Supplementary Data – Note 6 –Acquisitions and Divestitures under Part II, Item 8 in this Form 10-K for additional information on this divestiture.

Asset retirement obligations. Annually, we review and revise our ARO estimates. Our ARO at December 31, 2021 and 2020 were $424.5 million and $392.7 million, respectively, recorded using discounted values. We spent $27.3 million in 2021 and $3.3 million in 2020 for ARO and our estimate of ARO spending in 2022 is $55.0 million to $75.0 million. During 2021 and 2020, we revised our estimates of costs anticipated to be charged by service providers for plugging and abandonment projects and revised estimated to actual spending as invoices were processed and projects completed. As these estimates are for work to be performed in the future, and in many cases, several years in the future, actual expenditures could be substantially different than our estimates. Additionally, we revise our estimates to account for the cost to comply with any new or revised regulations, including increases in work scope and cost changes from interpretation of work scope. See Risk Factors – Our estimates of future asset retirement obligations may vary significantly from period to period and are especially significant because our operations are concentrated in the Gulf of Mexico under Part I, Item 1A and Financial Statements and Supplementary Data – Note 7 – Asset Retirement Obligations under Part II, Item 8 in this Form 10-K for additional information regarding our ARO.

Debt

We are actively monitoring the debt capital markets, and we intend to seek financings with longer tenors and market based covenants to continue to provide working and potential acquisition capital as well as provide funding for refinancing of some or all of our Second Lien Notes. The terms of such financings, which may replace or augment our Credit Agreement and refinance some or all of our Second Lien Notes, may vary significantly from those under the Credit Agreement and our Second Lien Notes.

The primary terms of our long-term debt, the conditions related to incurring additional debt, and the conditions and limitations concerning early repayment of certain debt are disclosed in Financial Statements and Supplementary Data –Note 2 – Debt under Part II, Item 8 in this Form 10-K.

Term Loan. As of December 31, 2021, we had $190.9 million of Term Loan principal outstanding. The Term Loan requires quarterly amortization payments, bears interest at a fixed rate of 7% per annum and will mature on May 19, 2028. The Term Loan is non-recourse to the Company and its subsidiaries other than the Subsidiary Borrowers (and the subsidiary that owns the equity of the Subsidiary Borrowers), and is not secured by any assets other than first lien security interests in the equity in the Borrowers and a first lien mortgage security interest and mortgages on certain assets of the Subsidiary Borrowers. See Financial Statements and Supplementary Data – Note 2 – Debt under Part II, Item 8 in this Form 10-K for additional information.

Credit Agreement. As of December 31, 2021, we had no borrowings outstanding under the Credit Agreement. During the year ended December 31, 2021, we repaid $80.0 million of borrowings.

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On November 2, 2021, the Company entered into two amendments to the Credit Agreement which effectively terminated the Company’s existing reserve based lending relationship with commercial bank lenders who have traditionally provided the Company’s revolving credit facility and established the Calculus Lending facility under the Credit Agreement. The Company has not had any borrowings under the Credit Agreement since the closing of the Mobile Bay Transaction in May 2021. The Company currently has no borrowings outstanding under the new Credit Agreement. On March 8, 2022 the Company entered into the Tenth Amendment to Sixth Amended and Restated Credit Agreement and Extension Agreement, which extended the maturity date and Lender commitment to January 3, 2023. Generally, we must be in compliance with the covenants in our Credit Agreement in order to access borrowings. See Financial Statements and Supplementary Data – Note 2 – Debt under Part II, Item 8 of this Form 10-K for additional information concerning these recent two amendments to the Credit Agreement and the Calculus Lending facility.

Senior Second Lien Notes. As of December 31, 2021, we had $552.5 million principal outstanding of Senior Second Lien Notes with an interest rate of 9.75% per annum that mature on November 1, 2023. The Senior Second Lien Notes are secured by a second-priority lien on all of our assets that are secured under the Credit Agreement. See Financial Statements and Supplementary Data – Note 2 – Debt under Part II, Item 8 in this Form 10-K for additional information.

Debt Covenants. The Term Loan, Credit Agreement, and Senior Second Lien Notes contain financial covenants calculated as of the last day of each fiscal quarter, which include thresholds on financial ratios, as defined in the respective Subsidiary Credit Agreement, the Credit Agreement and the indenture related to the Senior Second Lien Notes. We were in compliance with all applicable covenants of the Term Loan, Credit Agreement and the Senior Second Lien Notes indenture as of and for the period ended December 31, 2021. See Financial Statements and Supplementary Data – Note 2 – Debt under Part II, Item 8 in this Form 10-K for additional information.

The Subsidiary Borrowers

On May 19, 2021, we formed A-I LLC and A-II LLC, both indirect, wholly-owned subsidiaries of W&T Offshore, Inc., through their parent, Aquasition Energy LLC (collectively, the Aquasition Entities”). Concurrently, A-I LLC and A-II II LLC, entered into a credit agreement providing for the Term Loan in an initial aggregate principal amount equal to $215.0 million. Proceeds of the Term Loan were used by A-I LLC and A-II LLC to fund the acquisition of the Mobile Bay Properties and the Midstream Assets, respectively, from the Company. The Term Loan is non-recourse to the Company and any subsidiaries other than the Aquasition Entities, and is secured by the first lien security interests in the equity of the Aquasition Entities and a first lien mortgage security interest in the Mobile Bay Properties. The See Financial Statements and Supplementary Data – Note 4 – Mobile Bay Transaction under Part II, Item 8 in this Annual Report for additional information.

At that time, we designated the Aquasition Entities as unrestricted subsidiaries under Indenture governing Senior Second Lien Notes (the “Unrestricted Subsidiaries”). Having been so designated, the Unrestricted Subsidiaries do not guarantee the Senior Second Lien Notes and the liens on the assets sold to the Unrestricted Subsidiaries have been released under the Credit Agreement. The Unrestricted Subsidiaries are not bound by the covenants contained in the Credit Agreement or the Senior Second Lien Notes. Under the Subsidiary Credit Agreement and related instruments, assets of the Aquasition Entities may not be available to mortgage or pledge as security to secure new indebtedness of the Company and its other subsidiaries. See Financial Statements and Supplementary Data – Note 2 – Debt under Part II, Item 8 in this Form 10-K for additional information.

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Below is consolidating balance sheet information reflecting the elimination of the accounts of our Unrestricted Subsidiaries from our Consolidated Balance Sheet as of December 31, 2021 (in thousands):

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