W&T OFFSHORE INC (WTI) FY 2023 MD&A

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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[table omitted - see filing]