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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-K

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For the fiscal year ended December 31, 2023

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For the transition period from                      to

Commission File Number 1-32414

W&T OFFSHORE, INC.

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code: (713) 626-8525

Securities Registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.   Yes  ☐    No   ☑

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.   Yes  ☐    No  ☑

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes  ☑    No  ☐

Indicate by check mark whether the registrant has submitted electronically every interactive data file required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).   Yes  ☑    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).   Yes  ☐    No  ☑

The aggregate market value of the registrant’s common stock held by non-affiliates was approximately $337,554,623 based on the closing sale price of $3.87 per share as reported by the New York Stock Exchange on June 30, 2023.

The number of shares of the registrant’s common stock outstanding on February 29, 2024 was 146,857,277.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement relating to the Annual Meeting of Shareholders, to be filed within 120 days of the end of the fiscal year covered by this report, are incorporated by reference into Part III of this Form 10-K.

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W&T OFFSHORE, INC.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K (“Form 10-K”) contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Form 10-K, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. These forward-looking statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances. Although we believe that these forward-looking statements are based upon reasonable assumptions, they are subject to several risks and uncertainties and are made in light of information currently available to us. If the risks or uncertainties materialize or the assumptions prove incorrect, our results may differ materially from those expressed or implied by such forward-looking statements and assumptions.

Known material risks that may affect our financial condition and results of operations are discussed in Item 1A. Risk Factors, and market risks are discussed in Item 7A. Quantitative and Qualitative Disclosures About Market Risk, of this Form 10-K and may be discussed or updated from time to time in subsequent reports filed with the SEC.

When used in this Form 10-K, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “forecast,” “may,” “objective,” “plan,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We assume no obligation, nor do we intend, to update these forward-looking statements, unless required by law. Unless the context requires otherwise, references in this Form 10-K to “W&T”, “we,” “us,” “our” and the “Company” refer to W&T Offshore, Inc. and its consolidated subsidiaries.

The information included in this Form 10-K includes forward-looking statements that involve risks and uncertainties that could materially affect our expected results of operations, liquidity, cash flows and business prospects. Such statements specifically include our expectations as to our future financial position, liquidity, cash flows, results of operations and business strategy, potential acquisition opportunities, other plans and objectives for operations, capital for sustained production levels, expected production and operating costs, reserves, hedging activities, capital expenditures, return of capital, improvement of recovery factors and other guidance. Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. For any such forward-looking statement that includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases almost always vary from actual results, sometimes materially.

Factors (but not necessarily all the factors) that could cause results to differ include, among others:

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Reserve engineering is a process of estimating underground accumulations of oil, NGLs and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and our development program. Accordingly, reserve estimates may differ significantly from the quantities of natural gas, oil and NGLs that are ultimately recovered.

All forward-looking statements, expressed or implied, included in this Form 10-K are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

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SUMMARY RISK FACTORS

The following is a summary of the principal risks described in more detail under Part I, Item 1A. Risk Factors, in this Form 10-K.

Market and Competitive Risks

Operating Risks

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Capital Risks

Legal, Government and Regulatory Risks

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GLOSSARY

The following are abbreviations and definitions of certain terms used in this Annual Report on Form 10-K.

Bbl. One stock tank barrel or 42 United States gallons liquid volume.

Bcf. Billion cubic feet, typically used to describe the volume of natural gas.

Boe. Barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one barrel of oil or condensate.

Boe/d. Barrel of oil equivalent per day.

BOEM. Bureau of Ocean Energy Management.

BSEE. Bureau of Safety and Environmental Enforcement.

Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water one degree Fahrenheit.

Completion. The installation of permanent equipment for the production of oil or natural gas.

Conventional shelf. Water depths less than 500 feet.

Deep shelf. Water depths greater than 500 feet and less than 15,000 feet.

Deepwater. Water depths greater than 500 feet.

Development. The phase in which petroleum resources are brought to the status of economically producible by drilling developmental wells and installing appropriate production systems.

Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole. A well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Economically producible. Refers to a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

Exploratory well. A well drilled to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well.

Extension well. A well drilled to extend the limits of a known reservoir.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.

GAAP. Accounting principles generally accepted in the United States of America.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.

MBoe. One thousand barrels of oil equivalent.

Mcf. One thousand cubic feet, typically used to describe the volume of a gas.

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MMBbls. One million barrels of crude oil or other liquid hydrocarbons.

MMBoe. One million barrels of oil equivalent.

MMBtu. One million British thermal units.

MMcf. One million cubic feet, typically used to describe the volume of a gas.

Natural gas. A combination of light hydrocarbons that, in average pressure and temperature conditions, are found in a gaseous state. In nature, it is found in underground accumulations and may potentially be dissolved in oil or may also be found in a gaseous state.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

NGLs. Natural gas liquids. Hydrocarbons which can be extracted from wet natural gas and become liquid under various combinations of pressure and temperature. NGLs consist primarily of ethane, propane, butane and natural gasoline.

NYMEX. The New York Mercantile Exchange.

NYMEX Henry Hub. Henry Hub is the major exchange for pricing natural gas futures on the New York Mercantile Exchange.

Oil. Crude oil and condensate.

OCS. Outer continental shelf.

OCS block. A unit of defined area for purposes of management of offshore petroleum exploration and production by the BOEM.

ONRR. Office of Natural Resources Revenue. The agency performs the offshore royalty and revenue management functions of the former Minerals Management Service.

OPEC+. Organization of Petroleum Exporting Countries and other state controlled companies.

Productive well. A well that is found to have economically producible hydrocarbons.

Proved developed reserves. Proved reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. The SEC provides a complete definition of developed oil and gas reserves in Rule 4-10(a)(6) of Regulation S-X.

Proved properties. Properties with proved reserves.

Proved reserves. Those quantities of oil, NGLs and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The SEC provides a complete definition of proved reserves in Rule 4-10(a)(22) of Regulation S-X.

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Proved undeveloped reserves (“PUDs”). Proved reserves of any category that are expected to be recovered from future wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. The SEC provides a complete definition of undeveloped reserves in Rule 4-10(a)(31) of Regulation S-X.

PV-10. The present value of estimated future revenues, discounted at 10% annually, to be generated from the production of proved reserves determined in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of the estimation without future escalation. PV-10 excludes cash flows for asset retirement obligations, general and administrative expenses, derivatives, debt service and income taxes.

Recompletion. The completion for production of an existing well bore in another formation from that which the well has been previously completed.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

SEC. The Securities and Exchange Commission.

SEC pricing. The unweighted average first-day-of-the-month commodity price for crude oil and natural gas for each month within the twelve-month period preceding the reported period, adjusted by lease for market differentials (quality, transportation fees, energy content and regional price differentials). The SEC provides a complete definition of pricing in “Modernization of Oil and Gas Reporting” (Final Rule, Release Nos. 33-8995; 34-59192).

Unproved properties. Properties with no proved reserves.

WTI. West Texas Intermediate grade crude oil. A light crude oil produced in the United States with an American Petroleum Institute gravity of approximately 38-40 and the sulfur content is approximately 0.3%.

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PART I

ITEM 1. BUSINESS

W&T Offshore, Inc. is an independent oil and natural gas producer, active in the acquisition, exploration and development of oil and natural gas properties in the Gulf of Mexico. W&T Offshore, Inc. is a Texas corporation originally organized as a Nevada corporation in 1988, and successor by merger to W&T Oil Properties, Inc., a Louisiana corporation organized in 1983.

Since our founding in 1983 by our Chairman and CEO, Tracy Krohn, we have continually grown our footprint in the Gulf of Mexico through acquisitions, exploration and development. As of December 31, 2023 we held working interests in 53 offshore producing fields in federal and state waters. Our acreage, well, production and reserves information are described in more detail under Part I, Item 2. Properties, in this Form 10-K. Our working interests in fields, leases, structures and equipment are primarily owned by W&T Offshore, Inc. and our wholly-owned subsidiaries, Aquasition LLC (“A-I LLC”), Aquasition II LLC (“A-II LLC”), and W&T Energy VI, LLC, Delaware limited liability companies and through our proportionately consolidated interest in Monza Energy, LLC (“Monza”).

For the past four decades, we have developed significant technical expertise in finding and developing properties in the Gulf of Mexico with existing production which provide the best opportunity to achieve a rapid return on our invested capital. We have successfully discovered and produced properties on the conventional shelf and in the deepwater across the Gulf of Mexico.

Business Strategy

The Gulf of Mexico offers unique advantages, and we are uniquely positioned to create value with a diverse portfolio in valuable shelf, deep shelf and deepwater projects. Our diverse portfolio of operations in the Gulf of Mexico enables stacked pay development, attractive primary production, and recompletion opportunities. We use advanced seismic and geoscience tools to execute successful drilling projects.

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 goal is to pursue lower risk, 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, and organically enhance the value of our assets helping to ensure the long-term sustainability of our business.

We follow a proven and consistent business strategy:

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We intend to execute the following elements of our business strategy in order to achieve our strategic goals:

We continually monitor current and forecasted commodity prices to assess if changes to our plans are needed. Our significant inside ownership ensures that executive management’s interests are highly aligned with those of our shareholders, thus incentivizing executive management to maximize value and mitigate risk in executing our business strategy, generating shareholder value.

Competition

The oil and natural gas industry is highly competitive. We also face increasing indirect competition from alternative energy sources, including wind, solar, and electric power. We currently operate in the Gulf of Mexico and compete for the acquisition of oil and natural gas properties and lease sales primarily on the basis of price for such properties. We compete with numerous entities, including major domestic and foreign oil companies, other independent oil and natural gas companies and individual producers and operators. Many of these competitors are large, well-established companies that have financial and other resources substantially greater than ours and a greater ability to provide the extensive regulatory financial assurances required for offshore properties. Our ability to acquire additional oil and natural gas properties, acquire additional leases and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties, finance investments and consummate transactions in a highly competitive environment.

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Oil and Natural Gas Marketing and Delivery Commitments

The market for our oil, NGL and natural gas production depends on factors beyond our control, including the extent of domestic production and imports of oil, NGLs and natural gas; the proximity and capacity of natural gas pipelines and other transportation facilities; the demand for oil, NGLs and natural gas; the marketing of competitive fuels; and the effect of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

We sell our oil, NGLs and natural gas to third-party customers. The terms of sale under the majority of existing contracts are short-term, usually one year or less in duration. The prices received for oil, NGL and natural gas sales are generally tied to monthly or daily indices as quoted in industry publications.

We are not dependent upon, or contractually limited to, any one customer or small group of customers. In 2023, approximately 41% of our revenues were received from BP Products North America and approximately 13% from Chevron-Texaco, with no other customer comprising greater than 10% of our 2023 revenues. Given the commoditized nature of the products we produce and market and the location of our production in the Gulf of Mexico, we believe the loss of any of the customers above would not result in a material adverse effect on our ability to market future oil and natural gas production, as we believe that replacement customers could be obtained in a relatively short period of time on terms, conditions, and pricing substantially similar to those currently existing.

Insurance Coverage

In accordance with industry practice, we maintain insurance coverage against some, but not all, of the operating risks to which our business is exposed. In general, our current insurance policies cover risks incident to the operation of oil and natural gas wells, including, but not limited to, personal injury or loss of life, severe damage to and destruction of property and equipment, pollution or other environmental damage and the suspension of operations. We do not carry business interruption insurance.

Our general and excess liability policies, among others, provide for $300.0 million of coverage for bodily injury and property damage liability, including coverage for liability claims resulting from seepage, pollution or contamination. Our Energy Package (defined as certain insurance policies relating to our oil and natural gas properties, which include named windstorm coverage) contains multiple layers of insurance coverage for our operating activities, with higher limits of coverage for higher valued properties and wells. Under the Energy Package, the limits for well control range from $30.0 million to $500.0 million depending on the risk profile and contractual requirements. With respect to coverage for named windstorms, we have a $162.5 million aggregate limit covering one of our higher valued properties, and $150.0 million for all other properties subject to four region retentions ranging from $2.5 million to $12.5 million on the conventional shelf properties and $10.0 million on the deepwater properties.

We believe that our coverage limits are sufficient and are consistent with our exposure; however, we cannot insure against all possible losses. As a result, any damage or loss not covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flow.

We re-evaluate the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and natural gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. No assurance can be given that we will be able to insure our business activities at the levels we desire because of either limited market availability or unfavorable economics (limited coverage for the underlying cost).

Environmental, Health and Safety Matters and Government Regulations

Our operations are subject to complex and stringent federal, state and local laws and regulations that, among other things, govern the issuance of permits to conduct exploration, drilling and production operations, the amounts and types of materials that may be released into the environment and the discharge and disposal of waste materials and, to the extent waste materials are transported and disposed of in onshore facilities, remediation of any releases of those waste materials from such facilities. The federal environmental laws and regulations applicable to us and our operations include, among others, the following:

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In addition to the federal laws and regulations above, we are also subject to the requirements of the Occupational Safety and Health Administration (“OSHA”) and comparable state statutes, where applicable. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes, where applicable, require that we organize and/or disclose information about hazardous materials used or produced in our operations. Such laws and regulations also require us to ensure our workplaces meet minimum safety standards and provide for compensation to employees injured as a result of our failure to meet these standards as well as civil and/or criminal penalties in certain circumstances. We believe that we are in substantial compliance with all such existing laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations.

Numerous governmental agencies issue rules and regulations to implement and enforce such laws, which are often costly to comply with, and a failure to comply may result in substantial administrative, civil and criminal penalties; the imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures; the occurrence of restrictions, delays or cancellations in the permitting, or development or expansion of projects; and the issuance of orders enjoining some or all of our operations in affected areas. We consider the costs of environmental compliance to be a necessary and manageable part of our business. However, based on policy and regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to compliance with the protection of the environment have increased over the years and may continue to increase. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters. See Item 1A. Risk Factors contained herein for further discussion of governmental regulation and ongoing regulatory changes, including with respect to environmental matters.

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Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Rules and regulations affecting the oil and natural gas industry are under consistent review for amendment or expansion, which could increase the regulatory burden and the potential sanctions for noncompliance. Relatedly, numerous federal and state departments and agencies are authorized to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Historically, our compliance with existing requirements has not had a material adverse effect on our financial position, results of operations or cash flows. Because such laws and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Although the regulatory burden on the oil and natural gas industry may increase our cost of doing business, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Our exploration and production are subject to various types of regulation at the federal, state and local levels. These types of regulation include, but are not limited to, requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most jurisdictions in which we operate also regulate one of more of the following:

Our operations on federal oil and natural gas leases in the OCS waters of the Gulf of Mexico are subject to regulation by the BSEE, the BOEM and the ONRR, all of which are agencies of the U.S. Department of the Interior (the “DOI”). The BSEE and the BOEM work to ensure the development of energy and mineral resources on the OCS is done in a safe and environmentally and economically responsible way. The ONRR performs the offshore royalty and revenue management functions of the former Minerals Management Service.

Leasing. The federal government cannot conduct offshore lease sales without the development and approval of a National Outer Continental Shelf Oil and Gas Leasing Program (an “OCS Program”). The Outer Continental Shelf Lands Act (the “OCSLA”) authorizes the Secretary of the Interior to establish a schedule of lease sales for a five-year period. There is no requirement under the OCSLA that mandates any sales in any locations, nor does the law prescribe any specific timing for the development of the OCS Program. These leases are awarded by the BOEM based on competitive bidding and contain relatively standardized terms. Prior to commencement of offshore operations, lessees must obtain the BOEM’s approval for exploration, development and production plans. In addition to permits required from other agencies such as the U.S. Environmental Protection Agency (the “EPA”), lessees must obtain a permit from the BSEE prior to the commencement of drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the OCS, calculation of royalty payments and the valuation of production for this purpose, and decommissioning of facilities, structures and pipelines.

In January 2021, President Biden issued an executive order suspending new leasing activities for oil and natural gas exploration and production on federal lands and offshore waters pending review and reconsideration of federal oil and natural gas permitting and leasing practices. Lease Sale 257 was originally scheduled to be held in March 2021, but the decision to hold the sale was rescinded after the issuance of the executive order. After a group of states challenged the executive order and a federal judge required the DOI to stop the leasing pause, Lease Sale 257 was rescheduled and held in November 2021. In January 2022, the D.C. District Court vacated Lease Sale 257, ruling that it violated the National Environmental Policy Act. In August 2023, the D.C. Circuit Court of Appeals reversed the D.C. District Court’s order vacating Lease Sale 257 and ruled the highest bidders would receive the leases auctioned in Lease Sale 257.

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In August 2022, Congress passed the Inflation Reduction Act (the “IRA”), which required the BOEM to offer at least two million acres for oil and natural gas leasing in the OCS. The IRA required the DOI to move forward with Lease Sales 259 and 261 in the Gulf of Mexico. Lease Sale 259 was held in March 2023, and Lease Sale 261 was held in December 2023. The IRA also raised the royalty rate for certain offshore leases from the current 12.5% to 16.67% and capped the rate at 18.75% for ten years.

In November 2021, the DOI released its report on federal oil and natural gas leasing and permitting practices. The report included recommendations in respect to the offshore sector, including adjusting royalty rates to ensure that the full value of leased tracts are captured, strengthening financial assurance coverage amounts that are required by operators, and establishing “fitness to operate” criteria that companies would need to meet in respect of safety, environmental and financial responsibilities in order to operate in the OCS.

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.

Decommissioning and financial assurance requirements. The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations and provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities in the OCS. Currently the BOEM requires all lessees of an OCS oil and natural gas lease to post base bonds ranging from $50 thousand to $3.0 million in addition to supplemental financial assurance determined based on the lessee’s ability to carry out present and future financial obligations. In June 2023, the BOEM proposed a new rule that updated the criteria for determining whether oil and natural gas lessees may be required to provide supplemental financial assurance above the prescribed base financial assurance to ensure compliance with the OCSLA. The rule proposes to consider an OCS lessee’s credit rating and proved oil reserves in determining whether a lessee in the OCS is required to obtain supplemental financial assurance. A final rule is anticipated in April 2024. See Part II, Item 8. Financial Statements and Supplementary Data —Note 17 — Commitments for more information on decommissioning and financial assurance requirements.

Regulation and transportation of natural gas. Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. The Federal Energy Regulatory Commission (the “FERC”) has undertaken various initiatives to increase competition within the natural gas industry. As a result of initiatives like FERC Order No. 636, issued in 1992, the interstate natural gas transportation and marketing system allows non-pipeline natural gas sellers, including producers, to effectively compete with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order No. 636 require that interstate pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas supplies. In many instances, the effect of Order No. 636 and related initiatives have been to substantially reduce or eliminate the interstate pipelines’ traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. The rates for such storage and transportation services are subject to the FERC ratemaking authority, and the FERC may apply cost-of-service principles or allow a pipeline to negotiate rates. Similarly, the natural gas pipeline industry is subject to state regulations, which may change from time to time.

The OCSLA, which is administered by the BOEM and the FERC, requires that all pipelines operating on or across the OCS provide open access, non-discriminatory transportation service. One of the FERC’s principal goals in carrying out the OCSLA’s mandate is to increase transparency in the OCS market, to provide producers and shippers assurance of open access service on pipelines located on the OCS, and to provide non-discriminatory rates and conditions of service on such pipelines. The BOEM issued a final rule, effective August 2008, which implements a hotline, alternative dispute resolution procedures, and complaint procedures for resolving claims of having been denied open and nondiscriminatory access to pipelines in the OCS.

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In 2007, the FERC issued rules (“Order 704”) requiring that any market participant, including a producer such as us, that engages in wholesale sales or purchases of natural gas that equal or exceed 2.2 million MMBtus during a calendar year must annually report such sales and purchases to the FERC to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with the FERC’s policy statement on price reporting. These rules are intended to increase the transparency of the wholesale natural gas markets and to assist the FERC in monitoring such markets and in detecting market manipulation.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC, state legislatures, state commissions and the courts. The natural gas industry historically has been very heavily regulated. As a result, there is no assurance that the less stringent regulatory approach pursued by the FERC, Congress and the states will continue.

While these federal and state regulations for the most part affect us only indirectly, they are intended to enhance competition in natural gas markets. We cannot predict what further action the FERC, the BOEM or state regulators will take on these matters. However, we do not believe that any such action taken will affect us differently, in any material way, than other natural gas producers with which we compete.

Oil and NGLs transportation rates. Other than as described above, our sales of liquids, which include oil, condensate and NGLs, are not currently regulated and are transacted at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction. The price we receive from the sale of oil and NGLs is affected by the cost of transporting those products to market. Interstate transportation rates for oil, condensate, NGLs and other products are regulated by the FERC. In general, interstate oil, condensate and NGL pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. The FERC has established an indexing system for such transportation, which generally allows such pipelines to take an annual inflation-based rate increase.

In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes and regulations. As it relates to intrastate oil, condensate and NGL pipelines, state regulation is generally less rigorous than the federal regulation of interstate pipelines. State agencies have generally not investigated or challenged existing or proposed rates in the absence of shipper complaints or protests, which are infrequent and are usually resolved informally. We do not believe that the regulatory decisions or activities relating to interstate or intrastate oil, condensate or NGL pipelines will affect us in a way that materially differs from the way they affect other oil, condensate and NGL producers or marketers.

Climate Change. The threat of climate change continues to attract considerable public, governmental and scientific attention in the United States. President Biden has made addressing climate change, including the restriction or elimination of greenhouse gas (“GHG”) emissions, a priority in his administration.

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The IRA includes a methane emissions reduction program that amends the CAA to include a Methane Emissions and Waste Reduction Incentive Program for petroleum and natural gas systems by 2024. In July 2023, the EPA proposed to expand the scope of the Greenhouse Gas Reporting Program for petroleum and natural gas facilities, as required by the IRA. Among other things, the proposed rule would expand the emissions events that are subject to reporting requirements to include “other large release events” and apply reporting requirements to certain new sources and sectors. The rule is expected to be finalized in the spring of 2024 and become effective on January 1, 2025, in advance of the deadline for GHG reporting for 2024 (March 2025). In January 2024, the EPA proposed a new rule implementing the IRA’s methane emissions charge. The proposed rule includes potential methodologies for calculating the amount by which a facility’s reported methane emissions are below or exceed the waste emissions thresholds and contemplates approaches for implementing certain exemptions created by the IRA. The methane emissions charge imposed under the Methane Emissions and Waste Reduction Incentive Program for 2024 would be $900 per ton emitted over annual methane emissions thresholds, and would increase to $1,200 in 2025, and $1,500 in 2026. The implementation of revised air emission standards could result in stricter permitting requirements, which could delay, limit or prohibit our ability to obtain such permits and result in increased compliance costs on our operations, including expenditures for pollution control equipment, the costs of which could be significant.

In December 2023, the EPA announced new rules intended to reduce methane emissions from oil and natural gas sources. The final rule strengthens the existing emissions reduction requirements in Subpart OOOOa, expands reduction requirements for new, modified and reconstructed oil and natural gas sources in Subpart OOOOb, and imposes methane emissions limitations on existing oil and natural gas sources nationwide for the first time. In addition, the final rule establishes “Emissions Guidelines,” creating a Subpart OOOOc that requires states to develop plans to reduce methane emissions from existing sources which must be at least as effective as presumptive standards set by the EPA. The final rule also creates a third-party monitoring program to flag large emissions events, referred to as “super emitters.” Under Subparts OOOOb and OOOOc, the final rule establishes more stringent requirements for new, modified and reconstructed sources “constructed” after December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later compliance dates. The final rule gives states, along with federal tribes that wish to regulate existing sources, two years to develop and submit their plans for reducing methane emissions from existing sources. The final Emissions Guidelines under Subpart OOOOc provide three years from the plan submission deadline for existing sources to comply. The new rule is likely to increase costs and regulatory burdens on the oil and natural gas industry, especially for smaller operators and operators of older oil and natural gas wells.

In March 2022, the SEC issued a proposed rule regarding the enhancement and standardization of mandatory climate-related disclosures. The proposed rule would require registrants to include certain climate-related disclosures in their registration statements and periodic reports, including, but not limited to:

Although the proposed rule’s ultimate date of effectiveness and the final form and substance of these requirements is not yet known and the ultimate scope and impact on our business is uncertain, compliance with the proposed rule, if finalized, may result in increased legal, accounting and financial compliance costs, make some activities more difficult, time-consuming and costly, and place strain on our personnel, systems and resources.

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In addition to the regulations discussed above, the OCSLA authorizes the DOI to regulate activities authorized by the BOEM in the Central and Western Gulf of Mexico. The EPA retains jurisdiction over all other parts of the OCS. Under the OCSLA, the DOI is limited to regulating offshore emissions of criteria pollutants and their precursor-pollutants to the extent they significantly affect the air quality of any state. The BSEE conducts field inspections of emission sources installed on offshore platforms that have the potential to emit regulated air pollutants. The BSEE also reviews BOEM-mandated monitoring and reporting of air emission sources for compliance with approved plan emission limits. The BSEE may compel measures to control and bring into compliance those operations determined to be in violation of applicable regulations or plan conditions by issuing Incidents of Noncompliance or recommending further enforcement action against potential violators.

The threat of climate change also continues to attract considerable public, governmental and scientific attention in foreign countries. Numerous proposals have been made at the international levels of government to monitor and limit emissions of GHG as well as to restrict or eliminate future emissions. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, policies and incentives to encourage the use of renewable energy or alternative low-carbon fuels and regulations that directly limit GHG emissions from certain sources. In addition, there exist numerous conventions and non-binding commitments of participating nations with goals of limiting their GHG emissions and fossil fuel subsidies. These include the United Nations-sponsored Paris Agreement, which requires signatory countries to set voluntary, individually-determined reduction goals and the Glasgow Climate Pact, which stated long-term global goals (including those in the Paris Agreement) to limit the increase in the global average temperature and emphasized reductions in GHG emissions. Most recently, at the 28th Conference of the Parties (“COP28”), member countries entered into an agreement that calls for actions toward achieving, at a global scale, a tripling of renewable energy capacity and doubling energy efficiency improvements by 2030. The goals of the agreement include, among other things, accelerating efforts toward the phase-down of unabated coal power, phasing out inefficient fossil fuel subsidies and other measures that drive the transition away from fossil fuels in energy systems. In February 2021, the Biden administration rejoined the Paris Agreement. Pursuant to its obligations as a signatory to the Paris Agreement, the United States has set a target to reduce its GHG emissions by 50% to 52% by the year 2030 as compared with 2005 levels and has agreed to provide periodic updates on its progress. Various state and local governments have also publicly committed to furthering the goals of the Paris Agreement. In addition, in November 2021, the United States signed the Global Methane Pledge, a pact that aims to reduce global methane emissions by at least 30% below 2020 levels by 2030.The impacts of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, the Glasgow Climate Pact and the COP28 agreement, or other international conventions cannot be predicted at this time.

Financial Information

We operate our business as a single segment. See Financial Statements and Supplementary Data under Part II, Item 8 in this Form 10-K for our financial information.

Seasonality and Inflation

Seasonality. Generally, the demand for and price of natural gas increases during the winter months and decreases during the summer months. However, these seasonal fluctuations are somewhat reduced because during the summer, pipeline companies, utilities, local distribution companies and industrial users purchase and place into storage facilities a portion of their anticipated winter requirements of natural gas. As utilities continue to switch from coal to natural gas, some of this seasonality has been reduced as natural gas is used for both heating and cooling. In addition, the demand for oil is higher in the winter months, but does not fluctuate seasonally as much as natural gas. Seasonal weather changes affect our operations. Tropical storms and hurricanes occur in the Gulf of Mexico during the summer and fall, which can require us to evacuate personnel and shut in production until a storm subsides. Also, periodic storms during the winter often impede our ability to safely load, unload and transport personnel and equipment, which can delay production and sales of our oil and natural gas.

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Inflation. 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 increases, 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. 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 ranges 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.

Human Capital Resources

As of December 31, 2023, we had 395 employees and employed an additional 326 individuals who are employees of third parties that primarily provide skilled labor in support of our field operations. This combined workforce conducts our business in Texas, Alabama, Louisiana and the Gulf of Mexico. Our workforce in Texas is primarily composed of our corporate employees, including our executive officers, drilling and production managers, technical engineers and administrative and support staff. Our employees in Alabama, Louisiana and the Gulf of Mexico are primarily composed of skilled labor who conduct our field operations and manage third-party personnel used in support of our field operations.

We consider our employees to be our most valuable asset and believe that our success depends on our ability to attract, develop and retain our employees. We strive to provide a work environment that attracts and retains the top talent in the industry, reflects our core values and demonstrates these values to the communities in which we operate.

Diversity and Inclusion

We recognize that a diverse workforce provides the best opportunity to obtain unique perspectives, experiences and ideas to help our business succeed, and we are committed to providing a diverse and inclusive workplace to attract and retain talented employees. The key to our past and future successes is promoting a workforce culture that embraces integrity, honesty and transparency to those with whom we interact, and fosters a trusting and respectful work environment that embraces changes and moves us forward in an innovative and positive way. Our Code of Business Conduct and Ethics prohibits illegal discrimination or harassment of any kind.

Our policies and practices support diversity of thought, perspective, sexual orientation, gender, gender identity and expression, race, ethnicity, culture and professional experience. From recent graduates to experienced hires, we seek to attract and develop top talent to continue building a unique blend of cultures, backgrounds, skills and beliefs that mirror the world we live in. The tables below present, by category of employee, the gender and ethnicity composition of our employees as of December 31, 2023:

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Safety, Health and Wellness

The success of our business is fundamentally connected to the well-being of our people. We are committed to the safety, health and wellness of our employees.

Our highest priorities are the safety of all personnel and protection of the environment. We actively promote the highest standards of safety behavior and environmental awareness and strive to meet or exceed all applicable local and natural regulations. To drive a culture of personnel safety in our operations, we operate under a comprehensive Safety and Environmental Management System (“SEMS”). Our 2023 total recordable incident rate for employees was 0.25, which is far below the industry average for the Gulf of Mexico from 2022 of 0.88. Although incident reporting practices are subject to some subjectivity and vary by operator, we have historically had below average incident rates compared to the industry average for the Gulf of Mexico, and we strive to continue to excel at protecting our personnel. Our HSE&R group is comprised of a Vice President, Environmental, Safety and Regulatory Managers and 10 staff personnel. The group works with field personnel to create and regularly review safety policies and procedures, in an effort to support continuous improvement of our SEMS. Our board of directors reviews our material safety metrics on a quarterly basis. Safety and Environmental metrics are incorporated into employee evaluations when determining compensation.

Benefits and Compensation

We pride ourselves on providing an attractive compensation and benefits program that allows our employees to view working at W&T as more than where they work, but a place where they may grow and develop. Our ability to succeed depends on recruiting and retaining top talent in the industry. We believe employees choose W&T in part due to our professional advancement opportunities, on the job training, engaging culture and competitive compensation and benefits.

As part of our compensation philosophy, we believe we must offer and maintain market competitive total rewards programs in order to attract and retain superior talent. These programs not only include base wages and incentives in support of our pay for performance culture, but also health and retirement benefits. We focus many programs on employee wellness. We believe these solutions help the overall health and wellness of our employees and help us successfully manage healthcare and prescription drug costs for our employee population.

Website Access to Company Reports

We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports and amendments to those reports with the SEC. Our reports filed with the SEC are available free of charge to the general public through our website at www.wtoffshore.com. These reports are accessible on our website as soon as reasonably practicable after being filed with, or furnished to, the SEC. This Form 10-K and our other filings can also be obtained by contacting: Investor Relations, W&T Offshore, Inc., 5718 Westheimer Road, Suite 700, Houston, Texas 77057 or by calling (713) 297-8024. Information on our website is not a part of this Form 10-K.

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ITEM 1A. RISK FACTORS

In addition to risks and uncertainties in the ordinary course of business that are common to all businesses, important factors that are specific to us and our industry could materially impact our future performance and results of operations. We have provided below a list of known material risk factors that should be reviewed when considering buying or selling our securities. These are not all the risks we face, and other factors currently considered immaterial or unknown to us may impact our future operations.

Market and Competitive Risks

Oil, NGL and natural gas prices can fluctuate widely due to a number of factors that are beyond our control. Depressed oil, NGL or natural gas prices adversely affect our business, financial condition, cash flow, liquidity or results of operations and could affect our ability to fund future capital expenditures needed to find and replace reserves, meet our financial commitments and to implement our business strategy.

The price we receive for our oil, NGLs and natural gas production directly affects our revenues, profitability, access to capital, ability to produce these commodities economically and future rate of growth. Historically, oil, NGLs and natural gas prices have been volatile and subject to wide price fluctuations in response to domestic and global changes in supply and demand, economic and legal forces, events and uncertainties, and numerous other factors beyond our control, including:

These factors and the volatility of the energy markets, which we expect to continue, make it extremely difficult to predict future commodity prices with any certainty.

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If oil, NGL and natural gas prices decrease from their current levels, we may be required to further reduce the estimated volumes and future value associated with our total proved reserves or record impairments to the carrying values of our oil and natural gas properties.

Lower future oil, NGLs and natural gas prices may reduce our estimates of the proved reserve volumes that may be economically recovered, which would reduce the total volumes and future value of our proved reserves. Under the full cost method of accounting for oil and gas producing activities, a ceiling test is performed at the end of each quarter to determine if our oil and gas properties have been impaired. Capitalized costs of oil and gas properties are generally limited to the present value of future net revenues of proved reserves based on the average price of the 12-month period prior to the ending date of each quarterly assessment using the unweighted arithmetic average of the first-day-of-the-month price for each month within such period. Impairments of our oil and gas properties are more likely to occur during prolonged periods of depressed oil, NGLs and natural gas pricing. While we have not recorded an impairment of our oil and gas properties during 2023, any further decreases in commodity pricing could cause an impairment, which would result in a non-cash charge to earnings.

Commodity derivative positions may limit our potential gains.

In order to manage our exposure to price risk in the marketing of our oil and natural gas, we have entered, and may continue to enter, into oil and natural gas price commodity derivative positions with respect to a portion of our expected future production. See Financial Statements and Supplementary Data– Note 4 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K for additional information on our derivative contracts and transactions. We may enter into more derivative contracts in the future. While these commodity derivative positions are intended to reduce the effects of oil and natural gas price volatility, they may also limit future income if oil and natural gas prices were to rise substantially over the price established by such positions. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which there is a widening of price differentials between delivery points for our production and the delivery points assumed in the hedge arrangements or the counterparties to the derivative contracts fail to perform under the terms of the contracts.

Competition for oil and natural gas properties and prospects is intense; some of our competitors have larger financial, technical and personnel resources that may give them an advantage in evaluating and obtaining properties and prospects.

We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil, NGLs and natural gas and securing trained personnel. Many of our competitors have financial resources that allow them to obtain substantially greater technical expertise and personnel than we have. We actively compete with other companies in our industry when acquiring new leases or oil and natural gas properties. For example, new leases acquired from the BOEM are acquired through a “sealed bid” process and are generally awarded to the highest bidder. Our competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our competitors may also be able to pay more to acquire productive oil and natural gas properties and exploratory prospects than we are able or willing to pay or finance. Finally, companies with larger financial resources may have a significant advantage in terms of meeting any potential new bonding requirements. If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production. The marketability of our production depends mostly upon the availability, proximity, and capacity of oil and natural gas gathering systems, pipelines and processing facilities, which in some cases are owned by third parties.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends substantially on the availability and capacity of gathering systems, pipelines and processing facilities, which in some cases are owned and operated by third parties.

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We depend upon third-party pipelines that provide delivery options from our facilities. Because we do not own or operate these pipelines, their continued operation is not within our control. These pipelines may become unavailable for a number of reasons, including testing, maintenance, capacity constraints, accidents, government regulation, weather-related events or other third-party actions. If any of these third-party pipelines become partially or fully unavailable to transport oil and natural gas, or if the gas quality specification for the natural gas pipelines changes so as to restrict our ability to transport natural gas on those pipelines, our revenues could be adversely affected.

A portion of our oil and natural gas is processed for sale on platforms owned by third parties with no economic interest in our wells and no other processing facilities would be available to process such oil and natural gas without significant investment by us. In addition, third-party platforms could be damaged or destroyed by tropical storms, hurricanes or other weather events, which could reduce or eliminate our ability to market our production. As of December 31, 2023, three fields, accounting for approximately 0.2 MMBoe (or 1.4%) of our 2023 production, are tied back to separate, third-party owned platforms. Although we have entered into contracts for the process of our production with the owners of such platforms, there can be no assurance that the owners of such platforms will continue to process our oil and natural gas production.

We may be required to shut in wells because of a reduction in demand for our production or because of inadequacy or unavailability of pipelines, gathering system capacity or processing facilities. If that were to occur, then we would be unable to realize revenue from those wells until arrangements were made to process or deliver our production to market. For example, the government recently issued an order requiring the abandonment of certain facilities in the Gulf of Mexico, rendering the pipelines and other midstream assets that cross that facility incapable of operating. Our production from certain properties currently utilizes a pipeline that crosses over the facility in order for our production to reach its eventual market and, as a result of the government’s order to abandon the facilities, we are required to shut-in our production at the affected properties until we can find an alternative path to market for such production. While we are working to find an alternative path to market, we are unable to realize revenues from our production at the affected properties until such time as an alternative arrangement is made.

Furthermore, if we are forced to shut-in production, we will likely incur greater costs to bring the associated production back online. Cost increases necessary to bring the associated wells back online may be significant enough that such wells would become uneconomic at low commodity price levels, which may lead to decreases in our proved reserve estimates and potential impairments and associated charges to our earnings. If we are able to bring wells back online, there is no assurance that such wells will be as productive following recommencement as they were prior to being shut-in. We have, in the past, been required to shut in wells when tropical storms or hurricanes have caused or threatened damage to pipelines, gathering stations, and production facilities. In addition, certain third-party pipelines have submitted requests in the past to increase the fees they charge us to use these pipelines. These increased fees, if approved, could adversely impact our revenues or increase our operating costs, either of which would adversely impact our operating profits, cash flows and reserves.

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Operating Risks

Relatively short production periods for our Gulf of Mexico properties based on proved reserves subject us to high reserve replacement needs and require significant capital expenditures to replace our proved reserves at a faster rate than companies whose proved reserves have longer production periods. If we are not able to obtain new oil and gas leases or replace reserves, we will not be able to sustain production at current levels, which may have a material adverse effect on our business, financial condition, or results of operations.

Our future success depends largely upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable in order to replace or grow our produced proved reserves. Producing oil and natural gas reserves are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. High production rates generally result in recovery of a relatively higher percentage of reserves during the initial few years of production. All of our current production is from the Gulf of Mexico. Proved reserves in the Gulf of Mexico generally have shorter reserve lives than proved reserves in many other producing regions of the United States, in part due to the difference in rules related to booking proved undeveloped reserves between conventional and unconventional basins. Our independent petroleum consultant estimates that 33.2% of our total proved reserves as of December 31, 2023 will be depleted within three years. As a result, our need to replace proved reserves and production from new investments is relatively greater than that of producers who recover lower percentages of their proved reserves over a similar time period, such as those producers who have a larger portion of their proved reserves in areas other than the Gulf of Mexico. Historically, we have funded our capital expenditures and acquisitions with cash on hand, cash provided by operating activities, capital markets securities offerings and bank borrowings. The capital markets we have historically accessed may be constrained because of our leverage and also because, in recent years, institutional investors who provide financing to fossil fuel energy companies have become more attentive to sustainability lending practices and some of them may elect not to provide funding for fossil fuel energy companies. As a result, we may not be able to obtain sufficient funding to develop, find or acquire additional proved reserves in sufficient quantities to sustain our current production levels or to grow production beyond current levels. Future cash flows are subject to a number of variables, such as the level of production from existing wells, the prices of oil, NGLs and natural gas, and our success in developing and producing new reserves. Any reductions in our capital expenditures to stay within internally generated cash flow (which could be adversely affected if commodity prices decline) and cash on hand will make replacing depleted reserves more difficult.

We are not insured against all of the operating risks to which our business is exposed.

In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We insure some, but not all, of our properties from operational loss-related events. We currently carry multiple layers of insurance coverage in our Energy Package, covering our operating activities, with higher limits of coverage for higher valued properties and wells. Our insurance coverage includes deductibles that have to be met prior to recovery, as well as sub-limits or self-insurance. Additionally, our insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability from all potential consequences, damages or losses. See Part I, Item 1. Business – Insurance Coverage for more information on our insurance coverage.

In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. Currently OPA requires owners and operators of offshore oil production facilities to have ready access to between $35.0 million and $150.0 million, which amount is based on a worst case oil spill discharge volume demonstration that can be used to cover costs that could be incurred in responding to an oil spill at our facilities on the OCS. We are currently required to demonstrate that we have ready access to $35.0 million. If OPA is amended to increase the minimum level of financial responsibility, we may experience difficulty in providing financial assurances sufficient to comply with this requirement.

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In the past, tropical storms and hurricanes in the Gulf of Mexico have caused catastrophic losses and property damage. Similar events may cause damage or liability in excess of our coverage that might severely impact our financial position. We may be liable for damages from an event relating to a project in which we own a non-operating working interest. Well control insurance coverage becomes limited from time to time and the cost of such coverage becomes both more costly and more volatile. In the past, we have been able to renew our policies each annual period, but our coverage has varied depending on the premiums charged, our assessment of the risks and our ability to absorb a portion of the risks. The insurance market may further change dramatically in the future due to severe storm damage, major oil spills or other events.

Such events as noted above may also cause a significant interruption to our business, which might also severely impact our financial position. We may experience production interruptions for which we do not have business interruption insurance.

We re-evaluate the purchase of insurance, policy limits and terms annually. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable, and we may elect to maintain minimal or no insurance coverage. The occurrence of a significant event for which our losses are not fully insured or indemnified, or for which the insurance companies will not pay our claims, could have a material adverse effect on our financial condition and results of operations.

We conduct exploration, development and production operations on the deep shelf and in the deepwater of the Gulf of Mexico, which presents unique operating risks.

The deep shelf and the deepwater of the Gulf of Mexico are areas that have had less drilling activity due, in part, to their geological complexity, depth and higher cost to drill and ultimately develop. There are additional risks associated with deep shelf and deepwater drilling that could result in substantial cost overruns and/or result in uneconomic projects or wells. Deeper targets are more difficult to interpret with traditional seismic processing. Moreover, drilling costs and the risk of mechanical failure are significantly higher because of the additional depth and adverse conditions, such as high temperature and pressure. For example, the drilling of deepwater wells requires specific types of rigs with significantly higher day rates as compared to the rigs used in shallower water, sophisticated sea floor production handling equipment, expensive state-of-the-art platforms and infrastructure investments. Deepwater wells have greater mechanical risks because the wellhead equipment is installed on the sea floor. In addition, due to the significant time requirements involved with exploration and development activities, particularly for wells in the deepwater or wells not located near existing infrastructure, actual oil and natural gas production from new wells may not occur, if at all, for a considerable period of time following the commencement of any particular project. Accordingly, we cannot provide assurance that our oil and natural gas exploration activities in the deep shelf, the deepwater and elsewhere will be commercially successful.

Continuing inflation and cost increases may impact our sales margins and profitability.

Cost inflation, including significant increases in wholesale raw materials costs, labor rates, and domestic transportation costs have and could continue to impact profitability. In addition, our customers are also affected by inflation and the rising costs of goods and services used in their businesses, which could negatively impact their ability to purchase commodities such as oil and gas, which could adversely impact our revenue and profitability. Although such cost increases did not materially impact our 2023 financial condition or results of operations, and we currently do not expect them to materially impact our 2024 financial results or operations, there is no guarantee that we can increase selling prices, replace lost revenue, or reduce costs to fully mitigate the effect of inflation on our costs and business, which may adversely impact our sales margins and profitability.

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We may not be in a position to control the timing of development efforts, associated costs or the rate of production of the reserves from our non-operated properties.

As we carry out our drilling program, we may not serve as operator of all planned wells. In that case, we have limited ability to exercise influence over the operations of some non-operated properties and their associated costs. Our dependence on the operator and other working interest owners and our limited ability to influence operations and associated costs of properties operated by others could prevent the realization of anticipated results in drilling or acquisition activities.

We are subject to numerous risks inherent to the exploration and production of oil and natural gas.

Oil and natural gas exploration and production activities involve certain risks that a combination of experience, knowledge and careful evaluation may not be able to overcome. Our future success will depend on the success of our exploration and production activities and on the future existence of the infrastructure and technology that will allow us to take advantage of our findings. Additionally, our properties are located in deepwater, which generally increases the capital and operating costs, technical challenges and risks associated with exploration and production activities. As a result, our exploration and production activities are subject to numerous risks, including the risk that drilling will not result in commercially viable production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of seismic data through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations.

Furthermore, the marketability of expected production from our prospects will also be affected by numerous factors. These factors include, but are not limited to, market fluctuations of oil and natural gas prices, proximity, capacity and availability of pipelines, the availability of processing facilities, equipment availability and government regulations (including, without limitation, regulations relating to prices, taxes, royalties, allowable production, importing and exporting of hydrocarbons, environmental, safety, health and climate change). The effect of these factors, individually or jointly, may result in us not receiving an adequate return on invested capital.

We are subject to drilling and other operational hazards. The exploration, development and production of oil and gas properties involves a variety of operating risks, including the risk of fire, explosions, blowouts, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, pipeline ruptures or discharges. Additionally, our offshore operations are subject to the additional hazards of marine operations, such as capsizing, collisions and adverse weather and sea conditions, including the effects of tropical storms, hurricanes and other weather events.

If we experience any of these problems, well bores, platforms, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations. If any of these industry operating risks occur, we could have substantial losses. Substantial losses may be caused by injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension of operations and production, repairs to resume operations and loss of reserves. Any of these industry operating risks could have a material adverse effect on our business, results of operations and financial condition.

The geographic concentration of our properties in the Gulf of Mexico subjects us to an increased risk of loss of revenues or curtailment of production from factors specifically affecting the Gulf of Mexico, including hurricanes.

The geographic concentration of our properties along the U.S. Gulf Coast and adjacent waters on and beyond the OCS means that some or all of our properties could be affected by the same event should the Gulf of Mexico experience severe weather, including tropical storms and hurricanes; delays or decreases in production, the availability of equipment, facilities or services; changes in the status of pipelines that we depend on for transportation of our production to the marketplace; delays or decreases in the availability of capacity to transport, gather or process production; and changes in the regulatory environment.

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For 2023, approximately 40% of our production and 19% of our total revenue was attributable to our Mobile Bay Properties. This concentration means that any impact on our production from this field, whether because of mechanical problems, adverse weather, well containment activities, changes in the regulatory environment or otherwise, could have a material adverse effect on our business. During 2023, our Mobile Bay Properties were shut-in for 35 days for planned maintenance. The shut-in resulted in deferred production of approximately 774 MBoe based on production rates prior to the shut-in. Any additional shut-ins, depending on the duration of the shut-in, could have a material adverse impact on our business. In addition, if the actual reserves associated with the Mobile Bay Properties are less than our estimated reserves, such a reduction of reserves could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Because a majority of our properties could experience the same conditions at the same time, these conditions could have a greater impact on our results of operations than they might have on other operators who have properties over a wider geographic area.

New technologies may cause our current exploration and drilling methods to become obsolete, and we may not be able to keep pace with technological developments in our industry.

The oil and natural gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages, and that may in the future, allow them to implement new technologies before we can. We rely heavily on the use of advanced seismic technology to identify exploitation opportunities and to reduce our geological risk. Seismic technology or other technologies that we may implement in the future may become obsolete. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our business, results of operations and financial condition may be materially adversely affected.

Estimates of our proved reserves depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in the estimates or underlying assumptions will materially affect the quantities of and present value of future net revenues from our proved reserves. Our actual recovery of reserves may substantially differ from our estimated proved reserves.

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and the calculation of the present value of our reserves at December 31, 2023.

In order to prepare our year-end reserve estimates, our independent petroleum consultant projected our production rates and timing of development expenditures. Our independent petroleum consultant also analyzed available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary and may not be under our control. The process also requires economic assumptions about matters such as oil and natural gas prices, operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, our independent petroleum consultant may adjust estimates of proved reserves to reflect production history, drilling results, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

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You should not assume that the standardized measure or the present value of future net revenues from our proved oil and natural gas reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the 12-month unweighted first-day-of-the-month average price for each product and costs in effect on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.

At December 31, 2023, approximately 16% of our estimated proved reserves (by volume) were undeveloped. Any or all of our PUD reserves may not be ultimately developed or produced or may not be ultimately produced during the time periods we plan or at the costs we budget, which could result in the write-off of previously recognized reserves. Recovery of PUD reserves generally requires significant capital expenditures and successful drilling or waterflood operations. Our reserve estimates include the assumptions that we incur capital expenditures to develop these undeveloped reserves and the actual costs and results associated with these properties may not be as estimated. Any material inaccuracies in these reserve estimates or underlying assumptions materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

Prospects that we decide to drill may not yield oil or natural gas in commercial quantities or quantities sufficient to meet our targeted rates of return.

A prospect is an area in which we own an interest, could acquire an interest or have operating rights, and have what our geoscientists believe, based on available seismic and geological information, to be indications of economic accumulations of oil or natural gas. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to be drilled to a prospect that will require substantial seismic data processing and interpretation, which will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. Sustained low oil, NGLs and natural gas pricing may also significantly impact the projected rates of return of our projects without the assurance of significant reductions in costs of drilling and development. To the extent we drill additional wells in the deepwater and/or on the deep shelf, our drilling activities could become more expensive. In addition, the geological complexity of deepwater and deep shelf formations may make it more difficult for us to sustain our historical rates of drilling success. As a result, we can offer no assurance that we will find commercial quantities of oil and natural gas and, therefore, we can offer no assurance that we will achieve positive rates of return on our investments.

We may not realize all of the anticipated benefits from our targeted acquisitions. Such acquisitions could expose us to potentially significant liabilities, including plugging and abandonment and decommissioning liabilities.

We expect to grow by expanding the exploitation and development of our existing assets, in addition to making targeted acquisitions in the Gulf of Mexico. We may not realize all of the anticipated benefits from acquisitions, such as increased earnings, cost savings and revenue enhancements, for various reasons, including higher than expected acquisition and operating costs or other difficulties, unknown liabilities, inaccurate reserve estimates and fluctuations in market prices. This could lead to potential adverse short-term or long-term effects on our operating results.

Successful acquisitions of oil and natural gas properties require an assessment of a number of factors, including estimates of recoverable reserves, the timing of recovering reserves, exploration potential, future oil and natural gas prices, operating costs and potential environmental, regulatory and other liabilities, including plugging and abandonment and decommissioning liabilities. Such assessments are inexact and may not disclose all material issues or liabilities. In connection with our assessments, we also perform a review of the acquired properties. However, such a review may not reveal all existing or potential problems. Additionally, such review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities.

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There may be threatened, contemplated, asserted or other claims against the acquired assets related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations. We may be successful in obtaining contractual indemnification for preclosing liabilities, including environmental liabilities, but we expect that we will generally acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. In addition, even if we are able to obtain such indemnification from the sellers, these indemnification obligations usually expire over time and could potentially expose us to unindemnifiable liabilities, which could materially adversely affect our production, revenues and results of operations.

Our operations could be adversely impacted by security breaches, including cybersecurity breaches, which could affect the systems, processes and data needed to run our business.

We rely on our information technology infrastructure and management information systems to operate and record aspects of our business. Although we take measures to protect against cybersecurity risks, including unauthorized access to our confidential and proprietary information, our security measures may not be able to detect or prevent every attempted breach. Similar to other companies, we have experienced cyber-attacks, although we have not suffered any material losses related to such attacks. Security breaches include, among other things, illegal hacking, computer viruses, interference with treasury function, theft or acts of vandalism or terrorism. A breach could result in an interruption in our operations, malfunction of our platform control devices, disabling of our communication links, unauthorized publication of our confidential business or proprietary information, unauthorized release of customer or employee data, violation of privacy or other laws and exposure to litigation. Any of these security breaches could have a material adverse effect on our consolidated financial position, results of operations and cash flows. The invasion of Ukraine by Russia, and the impact of world sanctions against Russia and the potential for retaliatory acts from Russia, could result in increased cybersecurity attacks against U.S. companies.

We have historically outsourced substantially all of our information technology infrastructure and the management and servicing of such infrastructure to a limited number of third parties, which makes us more dependent upon such third parties and exposed to related risks. We are in the process of transitioning substantially all of such infrastructure internally or to other service providers, which subjects us to increased costs and risks.

We have historically outsourced substantially all of our information technology infrastructure and the management and servicing of such infrastructure to a limited number of third-party service providers. As a result, we previously relied on a small number of third parties that we do not control to ensure that our technology needs are sufficiently met, and cyber risks are effectively managed. This reliance has subjected us to certain cybersecurity risks arising from the loss of control over certain processes, including the potential misappropriation, destruction, corruption or unavailability of certain data and systems, such as confidential or proprietary information. A failure of any of our information technology service providers to perform its management and operational duties securely and effectively may have a material adverse effect on our financial condition, liquidity or results of operations or the integrity of the systems, processes and data needed to run our business. We also have not had written agreements with our primary service provider, which exposed us to additional risks with respect to the systems and data outsourced to such provider.

Beginning in August 2022, following the notification by our primary information technology service provider, All About IT (“AAIT”), of its intention to cease providing services to us, we began the transition of information technology services and infrastructure to us or to other providers. We have moved and are continuing to move certain services internally and are transitioning certain other services to new service providers and implementing agreements with such providers. Although the transition process is substantially complete and we no longer have a material relationship with AAIT, the transition process has disrupted, and may continue to disrupt, certain of our business operations. Any difficulties in completing such transition could impair our ability to monitor our production and accurately prepare our results of operations in a timely fashion. Moreover, such transition continues to expose us to additional risks, including increased costs, diversion of management’s attention, disruptions to certain of our business operations and loss, damage to or unavailability of data or systems, each of which could have an adverse effect on our business and results of operations.

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The loss of members of our senior management could adversely affect us.

To a large extent, we depend on the services of our senior management. The loss of the services of any of our senior management could have a negative impact on our operations. We do not maintain or plan to obtain for the benefit of the Company any insurance against the loss of any of these individuals. See our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K for more information regarding our senior management team.

There may be circumstances in which the interests of significant stockholders could conflict with the interests of our other stockholders.

Our Chairman and Chief Executive Officer (“CEO”) owns a significant portion of our common stock and an entity indirectly owned and controlled by our CEO is the sole lender under the Credit Agreement. Circumstances may arise in which he may have an interest in pursuing or preventing acquisitions, divestitures, hostile takeovers or other transactions, or conflicts of interest could arise in the future regarding, among other things, decisions related to our financing, capital expenditures and business plans, or the pursuit of certain business opportunities, including the payment of dividends or the issuance of additional equity or debt, that, in his judgment, could enhance his investment in us or in another company in which he invests.

Such circumstances or conflicts might adversely affect us or other holders of our common stock. In addition, our significant concentration of share ownership and lender relationships may adversely affect the trading price of our common stock because investors may perceive disadvantages in owning shares in companies with significant stockholder concentrations or with such potential conflicts.

Capital Risks

We have a significant amount of indebtedness and limited borrowing capacity under our current Credit Agreement. Our leverage and debt service obligations may have a material adverse effect on our financial condition, results of operations and business prospects, and we may have difficulty paying our debts as they become due.

As of December 31, 2023, we had $400.2 million of principal amount of long-term debt outstanding, including the Term Loan, the 11.75% Senior Second Lien Notes, which mature on February 1, 2026 (the “11.75% Notes”) and the TVPX Loan. We had no borrowings outstanding under our Credit Agreement.

Our leverage and debt service obligations could:

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Any of the above listed factors could have a material adverse effect on our business, financial condition, cash flows and results of operations. If new debt is added to our current debt levels, the related risks that we face could intensify. Additionally, availability of borrowings and letters of credit under our Credit Agreement is determined by establishment of a borrowing base, which is periodically redetermined in lender’s sole discretion based on our lender’s review of oil, NGLs and natural gas prices, our proved reserves and other criteria. Lower oil, NGLs and natural gas prices in the future would also adversely affect our cash flow and could result in reductions in our borrowing base and sources of alternate credit and affect our ability to satisfy the covenants and ratios required by the Credit Agreement and Indenture (as defined below). Lower oil, NGL and natural gas prices may also have ancillary impacts on us and certain subsidiaries. For example, W&T Offshore, Inc. pays certain expenses on behalf of the Aquasition Entities pursuant to a management services agreement, which expenses are repaid by the Aquasition Entities in the ordinary course from operating cash flows. Planned and unplanned facility downtime and lower gas prices in 2023 caused the Aquasition Entities to operate at a loss after servicing their debt obligations under the Subsidiary Credit Agreement, and the Aquasition Entities have been unable to fully reimburse W&T Offshore, Inc. for such expenses paid on their behalf. Because of restrictions in the Credit Agreement and in the 11.75% Notes, W&T Offshore, Inc. may not be able to fund expenses on behalf of the Aquasition Entities indefinitely.

We cannot be certain that our cash flow will be sufficient to allow us to pay the principal and interest on our debt or otherwise meet our future obligations. In such scenarios, we may be required to refinance all or part of our existing debt, sell assets, reduce capital expenditures, obtain new financing or issue equity. However, we may not be able to accomplish any of these transactions on terms acceptable to us or such actions may not yield sufficient capital to meet our obligations. Any of the above risks could have a material adverse effect on our business, financial condition, cash flows and results of operations.

Our debt agreements contain restrictions that limit our abilities to incur certain additional debt or liens or engage in other transactions, which could limit growth and our ability to respond to changing conditions.

The indenture governing our 11.75% Notes (the “Indenture”), our Credit Agreement and our Subsidiary Credit Agreement governing our indebtedness contain a number of significant restrictive covenants in addition to covenants restricting the incurrence of additional debt. These covenants limit our ability and the ability of our restricted subsidiaries, among other things, to:

Our Credit Agreement requires us, among other things, to maintain certain financial ratios and satisfy certain financial condition tests. These restrictions may also limit our ability to obtain future financings, withstand a future downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us from the restrictive covenants under our indentures governing our outstanding notes and our Credit Agreement.

A breach of any covenant in the agreements governing our debt would result in a default under such agreement after any applicable grace periods. A default, if not waived, could result in acceleration of the debt outstanding under such agreement and in a default with respect to, and acceleration of, the debt outstanding under any other debt agreements. The accelerated debt would become immediately due and payable. If that should occur, we may not be able to make all of the required payments or borrow sufficient funds to refinance such accelerated debt. Even if new financing were then available, it may not be on terms that are acceptable to us.

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We have significant capital needs, and our ability to access the capital and credit markets to raise capital or refinance our existing indebtedness on favorable terms, including our 11.75% Notes and our Credit Agreement with Calculus, may be limited by industry conditions and financial markets.

Disruptions in the capital and credit markets, in particular with respect to the energy sector, could limit our ability to access these markets or may significantly increase our cost to borrow. Volatility in the energy sector, together with the higher interest rate environment, has caused and may continue to cause lenders to increase the interest rates under our credit facilities, enact tighter lending standards, refuse to refinance existing debt around maturity on favorable terms or at all and may reduce or cease to provide funding to borrowers. Furthermore, we may not be able to refinance our 11.75% Notes or extend our Credit Agreement with Calculus on favorable terms or at all. If we are unable to access the capital and credit markets on favorable terms, it could have a material adverse effect on our business, financial condition, results of operations, cash flows and liquidity and our ability to repay or refinance our debt.

If we default on our secured debt, the value of the collateral securing our secured debt may not be sufficient to ensure repayment of all of such debt.

Our Credit Agreement and our outstanding 11.75% Notes are secured by various liens on our oil and natural gas properties, excluding our Mobile Bay assets. The oil and natural gas assets of, and equity in, certain of our subsidiaries that own our Mobile Bay assets (the Borrower Subsidiaries, as defined in Financial Statements and Supplementary Data – Note 2 – Debt under Part II, Item 8 in this Form 10-K), are pledged on a first priority basis to secure our Term Loan. Any future borrowings under our Credit Agreement would be secured on a first priority basis by the assets securing the 11.75% Notes. In addition, we have certain rights to issue or incur additional or new secured debt, which could be secured by additional liens on the collateral. An issuance or incurrence of such additional secured debt would dilute the value of the collateral securing our outstanding secured debt. If the proceeds of the sale of the collateral securing the 11.75% Notes or any future indebtedness incurred under the Credit Agreement are not sufficient to repay all amounts due in respect of such debt, then claims against our remaining assets to repay any amounts still outstanding under our secured obligations would be unsecured, and our ability to pay our other unsecured obligations and any distributions in respect of our capital stock would be significantly impaired.

With respect to some of the collateral securing our debt, any collateral trustee’s security interest and ability to foreclose on the collateral will also be limited by the need to meet certain requirements, such as obtaining third-party consents, paying court fees that may be based on the principal amount of the parity lien obligations and making additional filings. If we are unable to obtain these consents, pay such fees or make these filings, the security interests may be invalid, and the applicable holders and lenders will not be entitled to the collateral or any recovery with respect thereto. These requirements may limit the number of potential bidders for certain collateral in any foreclosure and may delay any sale, either of which events may have an adverse effect on the sale price of the collateral.

We may not be able to repurchase the 11.75% Notes upon a change of control.

If we experience certain kinds of changes of control, we must give holders of the 11.75% Notes the opportunity to sell us their notes at 101% of their principal amount, plus accrued and unpaid interest. However, in such an event, we might not be able to pay the holders the required repurchase price for the notes they present to us because we might not have sufficient funds available at that time, or the terms of our Credit Agreement or other agreements we may enter into in the future may prevent us from applying funds to repurchase the 11.75% Notes. The source of funds for any repurchase required as a result of a change of control will be our available cash or cash generated from our oil and gas operations or other sources, including:

Finally, using available cash to fund the potential consequences of a change of control may impair our ability to obtain additional financing in the future, which could negatively impact our ability to conduct our business operations.

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We may be required to post cash collateral pursuant to our agreements with sureties under our existing or future bonding arrangements, which could have a material adverse effect on our liquidity and our ability to execute our capital expenditure plan, our ARO plan and comply with our existing debt instruments.

Pursuant to the terms of our agreements with various sureties under our existing bonding arrangements, or under any future bonding arrangements we may enter into, we may be required to post collateral at any time, on demand, at the surety’s sole discretion. Additional collateral would likely be in the form of cash or letters of credit. We cannot provide assurance that we will be able to satisfy collateral demands for current bonds or for future bonds.

If we are required to provide additional collateral, our liquidity position will be negatively impacted, and we may be required to seek alternative financing. To the extent we are unable to secure adequate 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.

Legal, Government and Regulatory Risks

We are subject to numerous environmental, health and safety regulations which are subject to change and may also result in material liabilities and costs.

Our operations are subject to U.S. federal, state, local and foreign environmental laws and regulations governing, among other things, the emission and discharge of pollutants into the environment, the generation, storage, handling, use and transportation of toxic and hazardous wastes and the health and safety of our employees. Our operations in the Gulf of Mexico require permits from federal and state governmental agencies in order to perform drilling and completion activities and conduct other regulated activities. There is a risk that we have not been or will not be at all times in complete compliance with these permits and the environmental laws and regulations to which we are subject. Any failure by us to comply with applicable environmental laws and regulations may result in governmental authorities taking action against us that could adversely impact our operations and financial condition, including the:

If we fail to obtain permits in a timely manner or at all (for example, due to opposition from community or environmental groups, government delays, changes in laws or the interpretation thereof, or any other reason), such failure could impede our operations, which could have a material adverse effect on our results of operations and our financial condition.

The longer-term trend of more expansive and stringent environmental legislation and regulations is expected to continue, which makes it challenging to predict the cost or impact on our future operations. Liabilities associated with environmental matters could have a material adverse effect on our business, financial condition and results of operations. Under certain environmental laws, we could be exposed to strict, joint and several liability for cleanup costs and other damages relating to releases of hazardous materials or contamination, regardless of whether we were responsible for the release or contamination, and even if our operations were lawful or in accordance with industry standards at the time.

Additional changes in environmental laws, regulations, guidelines or enforcement interpretations could require us to devote capital or other resources to comply with those laws and regulations. These changes could also subject us to additional costs and restrictions, including increased fuel costs. In addition, such changes in laws or regulations could increase the costs of compliance and doing business for our customers and thereby decrease the demand for our services.

New laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement could significantly increase our capital expenditures and operating costs or result in delays, limitations or cancelations to our exploration and production activities, which could have an adverse effect on our financial condition, results of operations, or cash flows. See Business – Other Regulation of the Oil and Natural Gas Industry under Part I, Item 1 in this Form 10-K for a more detailed description of our environmental regulations.

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We may be unable to provide financial assurances in the amounts and under the time periods required by the BOEM if the BOEM submits future demands to cover our decommissioning obligations.

The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations and provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities in the OCS. Currently the BOEM requires all lessees of an OCS oil and natural gas lease to post base bonds ranging from $50 thousand to $3.0 million in addition to supplemental financial assurance determined based on the lessee’s ability to carry out present and future financial obligations. In June 2023, the BOEM proposed a new rule that updated the criteria for determining whether oil and natural gas lessees may be required to provide supplemental financial assurance above the prescribed base financial assurance to ensure compliance with the OCSLA. The proposed rule considers an OCS lessee’s credit rating and proved oil reserves in determining whether a lessee in the OCS is required to obtain supplemental financial assurance. A final rule is anticipated by April 2024. Additionally, the BOEM could in the future make new demands for additional financial assurances covering our obligations under our properties, which could exceed the Company’s capabilities to provide.

If we fail to comply with the proposed new rule and such future orders, the BOEM could commence enforcement proceedings or take other remedial action against us, including assessing civil penalties, suspending operations or production, or initiating procedures to cancel leases, which, if upheld, would have a material adverse effect on our business, properties, results of operations and financial condition. In addition, if we are required to provide collateral in the form of cash or letters of credit, our liquidity position could be negatively impacted, and we may be required to seek alternative financing. To the extent we are unable to secure adequate financing, we may be forced to reduce our capital expenditures. All of these factors may make it more difficult for us to obtain the financial assurances required by the BOEM to conduct operations in the OCS. These and other changes to BOEM bonding and financial assurance requirements could result in increased costs on our operations and consequently have a material adverse effect on our business and results of operations.

We may be limited in our ability to maintain or recognize additional proved undeveloped reserves under current SEC guidance.

SEC rules require that, subject to limited exceptions, proved undeveloped reserves (“PUD reserves”) may only be booked if they relate to wells scheduled to be drilled within five years after the date of initial booking. This requirement may limit our ability to book additional PUD reserves as we pursue our drilling program. Moreover, we may be required to write down our PUD reserves if we do not drill those wells within the required five-year timeframe.

Additional deepwater drilling laws, regulations and other restrictions, delays and other offshore-related developments in the Gulf of Mexico may have a material adverse effect on our business, financial condition, or results of operations.

The Biden administration has taken a number of actions that may result in stricter environmental, health and safety standards applicable to our operations and those of the oil and natural gas industry more generally. Regulatory agencies under the Biden administration may issue new or amended rulemakings regarding deepwater leasing, permitting or drilling that could result in more stringent or costly restrictions, delays or cancellations to our operations as well as those of similarly situated offshore energy companies on the OCS. Compliance with any new or more stringent regulatory requirements or enforcement initiatives and existing environmental and spill regulations, together with uncertainties or inconsistencies in decisions by governmental agencies, delays in the processing and approval of drilling permits and exploration, development, oil spill response and decommissioning plans and possible additional regulatory initiatives, could adversely affect or delay new drilling and ongoing development efforts. Moreover, governmental agencies under the Biden administration are expected to continue to evaluate aspects of safety and operational performance in the Gulf of Mexico that could result in new, more restrictive requirements.

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These regulatory actions, or any new rules, regulations, or legal or enforcement initiatives that impose more stringent operational standards could delay or disrupt our operations; result in increased supplemental bonding and costs; and limit activities in certain areas or cause us to incur penalties or fines; shut-in production at one or more of our facilities; or result in the suspension or cancellation of leases. Also, if material spill incidents were to occur in the future, the United States could elect to issue directives to temporarily cease drilling activities and, in any event, issue further safety and environmental laws and regulations regarding offshore oil and natural gas exploration and development, any of which could have a material adverse effect on our business. We cannot predict with any certainty the full impact of any new laws or regulations on our drilling operations or on the cost or availability of insurance to cover some or all of the risks associated with such operations. See Part I, Item 1. Business – Environmental, Health and Safety Matters and Regulations and Other Regulation of the Oil and Natural Gas Industry for more discussion on orders and regulatory initiatives impacting the oil and natural gas industry that are being pursued under the Biden administration.

Our estimates of future ARO may vary significantly from period to period, and unanticipated decommissioning costs could materially adversely affect our future financial position and results of operations.

We are required to record a liability for the present value of our ARO to plug and abandon inactive non-producing wells, to remove inactive or damaged platforms, and inactive or damaged facilities and equipment, collectively referred to as “idle iron,” and to restore the land or seabed at the end of oil and natural gas production operations. An existing BSEE NTL describes the obligations of offshore operators to timely decommission idle iron by means of abandonment and removal. Pursuant to these idle iron NTL requirements, BSEE issued us letters, directing us to plug and abandon certain wells that the agency identified as no longer capable of production in paying quantities by specified timelines. In response, we are currently evaluating the list of wells proposed as idle iron by BSEE and currently anticipate that those wells determined to be idle iron will be decommissioned by the specified timelines or at times as otherwise determined by BSEE following further discussions with the agency. While we have established AROs for well decommissioning, additional AROs, significant in amount, may be necessary to conduct plugging and abandonment of the wells designated in the future as idle iron, but we do not expect the costs to plug and abandon such additional wells will have a material effect on our financial condition, results of operations or cash flows. Nevertheless, these decommissioning activities are typically considerably more expensive for offshore operations as compared to most land-based operations due to increased regulatory scrutiny and the logistical issues associated with working in waters of various depths, and there exists the possibility that increased liabilities beyond what we established as AROs may arise and the pace for completing these activities could be adversely affected by idle iron decommissioning activities being pursued by other offshore oil and gas lessees that may also have received similar BSEE directives, which could restrict the availability of equipment and experienced workforce necessary to accomplish this work.

Estimating future restoration and removal costs in the Gulf of Mexico is especially difficult because most of the removal obligations may be many years in the future, regulatory requirements are subject to change or such requirements may be interpreted more restrictively, and asset removal technologies are constantly evolving, which may result in additional, increased or decreased costs. As a result, we may make significant increases or decreases to our estimated ARO in future periods. For example, because we operate in the Gulf of Mexico, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes and other adverse weather conditions. The estimated cost to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was anticipated to be performed is damaged or toppled rather than structurally intact. Accordingly, our estimate of future ARO could differ dramatically from what we may ultimately incur as a result of damage from a hurricane or other natural disaster. Additionally, a sustained lower commodity price environment may cause our non-operator partners to be unable to pay their fair share of costs, which may require us to pay our proportionate share of the defaulting party’s share of costs.

We have divested, as assignor, various leases, wells and facilities located in the Gulf of Mexico where the purchasers, as assignees, typically assume all abandonment obligations acquired. Certain of these counterparties in these divestiture transactions or third parties in existing leases have filed for bankruptcy protection or undergone associated reorganizations and may not be able to perform required abandonment obligations. Under certain circumstances, regulations or federal laws, such as the OCSLA, could impose joint and several strict liability and require predecessor assignors, such as us, to assume such obligations. As of December 31, 2023, we have $18.0 million of loss contingency recorded related to anticipated decommissioning obligations. See Part II, Item 8. Financial Statements and Supplementary Data — Note 19 — Contingencies for more information.

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We are subject to numerous laws and regulations that can adversely affect the cost, manner or feasibility of doing business.

Our operations and facilities are subject to extensive federal, state and local laws and regulations relating to the exploration, development, production and transportation of oil and natural gas and operational safety. Future laws or regulations, any adverse change in the interpretation of existing laws and regulations or our failure to comply with such legal requirements may harm our business, results of operations and financial condition.

Our operations could be significantly delayed or curtailed, and our cost of operations could significantly increase as a result of regulatory requirements or restrictions. Regulated matters include lease permit restrictions; limitations on our drilling activities in environmentally sensitive areas, such as marine habitats, and restrictions governing the discharge of materials into the environment; bonds or other financial responsibility requirements to cover drilling contingencies and well decommissioning costs; the spacing of wells; operational reporting; reporting of natural gas sales for resale; and taxation. Under these laws and regulations, we could be liable for personal injuries, property and natural resource damages, well site reclamation costs, and governmental sanctions, such as fines and penalties.

Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that could substantially increase our costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could have a material adverse effect on our results of operations and financial condition, as well as the market price of our common stock. We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. See Business – Environmental, Health and Safety Matters and Regulations and Other Regulation of the Oil and Natural Gas Industry under Part I, Item 1 in this Form 10-K for a more detailed explanation of regulations impacting our business.

We are subject to laws, rules, regulations and policies regarding data privacy and security. Many of these laws and regulations are subject to change and reinterpretation, and could result in claims, changes to our business practices, monetary penalties, increased cost of operations or other harm to our business.

We are subject to a variety of federal, state and local laws, directives, rules and policies relating to data privacy and cybersecurity. The regulatory framework for data privacy and cybersecurity worldwide is continuously evolving and developing, and, as a result, interpretation and implementation standards and enforcement practices are likely to remain uncertain for the foreseeable future. It is also possible that inquiries from governmental authorities regarding cybersecurity breaches increase in frequency and scope. These data privacy and cybersecurity laws also are not uniform, which may complicate and increase our costs for compliance. Any failure or perceived failure by us or our third-party service providers to comply with any applicable laws relating to data privacy and cybersecurity, or any compromise of security that results in the unauthorized access, improper disclosure, or misappropriation of data, could result in significant liabilities and negative publicity and reputational harm, one or all of which could have an adverse effect on our reputation, business, financial condition and operations.

The Inflation Reduction Act of 2022 could accelerate the transition to a low carbon economy and could impose new costs on our operations.

The IRA contains hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, amongst other provisions. In addition, the IRA imposes the first ever federal fee on the emission of GHGs through a methane emissions charge. The IRA amends the federal CAA to impose a fee on the emission of methane from sources required to report their GHG emissions to the EPA, including those sources in the onshore petroleum and natural gas production categories. In January 2024, the EPA proposed a rule implementing the IRA’s methane emissions charge. The methane emissions charge would start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025, and be set at $1,500 for 2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA. In addition, the multiple incentives offered for various clean energy industries referenced above could further accelerate the transition of the economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives. This could decrease demand for oil and natural gas, increase our compliance and operating costs and consequently adversely affect our business.

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We are subject to risks arising from climate change, including risks related to energy transition, which could result in increased costs and reduced demand for the oil and natural gas we produce and physical risks which could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

President Biden has made addressing the threat of climate change from GHG emissions a priority under his administration. Regulatory agencies under the Biden administration have issued proposed rulemakings and may issue new or amended rulemakings in support of President Biden’s regulatory and political agenda, which include reducing dependence on, and use of, fossil fuels and curtailment of hydraulic fracturing on federal lands.

Numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs as well as to eliminate such future emissions. Accordingly, our operations are subject to a series of climate-related transition risks, including regulatory, political and litigation and financial risks associated with the production and processing of fossil fuels and emission of GHGs. See Part I, Item 1. Business – Other Regulation of the Oil and Natural Gas Industry for more discussion on the threat of climate change and restriction of GHG emissions.

The adoption and implementation of any international, federal, regional or state legislation, executive actions, regulations, policies or other regulatory initiatives that impose more stringent standards for GHG emissions on our operations or in areas where we produce oil and natural gas could result in increased compliance costs or costs of consuming fossil fuels, and thereby reduce demand for the oil and natural gas that we produce. Companies in the oil and natural gas industry are often the target of activist efforts from both individuals and non-governmental organizations regarding climate change and environmental and sustainability matters. Activism could materially and adversely impact our ability to operate our business and raise capital. The foregoing factors may cause operational delays or restrictions, increased operating costs and additional regulatory burden. Additionally, litigation risks to oil and natural gas companies are increasing, as a number of cities, local governments and other plaintiffs have sought to bring suit against oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts. We are not currently a defendant in any of these lawsuits but could be named in actions making similar allegations.

Further, stockholders and bondholders currently invested in fossil fuel energy companies such as ours but concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-fossil fuel energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices, and some of them may elect not to provide funding for fossil fuel energy companies. Many of the largest U.S. banks have made emission reduction commitments and have announced that they will be assessing financed emissions across their portfolios and are taking steps to quantify and reduce those emissions. There is also a risk that financial institutions may be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector, and more broadly, some investors, including investment advisors and certain sovereign wealth funds, pension funds, university endowments and family foundations, have stated policies to disinvest in the oil and natural gas sector based on their social and environmental considerations. Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas production and related infrastructure projects. These and other developments in the financial sector could lead to some lenders and investors restricting access to capital for or divesting from certain industries or companies, including the oil and natural gas sector, or requiring that borrowers take additional steps to reduce their GHG emissions. Such developments could result in downward pressure on the stock prices of oil and natural gas companies, including ours. This could also result in an increase in our expenses and a reduction of available capital funding for potential development projects, impacting our future financial results.

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Additionally, increasing attention from consumers and other stakeholders on combating climate change, together with changes in consumer and industrial/commercial preferences and behavior and societal pressure on companies to address climate change may result in increased availability of, and increased demand from consumers and industry for, energy sources other than oil and natural gas (including wind, solar, geothermal, tidal and biofuels as well as electric vehicles) and development of, and increased demand from consumers and industry for, lower-emission products and services (including electric vehicles and renewable residential and commercial power supplies) as well as more efficient products and services. These developments may in the future adversely affect the demand for products manufactured with, or powered by, petroleum products, as well as the demand for, and in turn the prices of, oil and natural gas products.

Lastly, most scientists have concluded that increasing concentrations of GHG in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, rising sea levels and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for oil or natural gas products or cause us to incur significant costs in preparing for or responding to the effects of climatic events themselves, which may not be fully insured. Potential adverse effects could include disruption of our production activities, including, for example, damages to our facilities from winds or floods, increases in our costs of operation, or reductions in the efficiency of our operations, impacts on our personnel, supply chain, or distribution chain, as well as potentially increased costs for insurance coverages in the aftermath of such effects. Any of these effects could have an adverse effect on our assets and operations. Our ability to mitigate the adverse physical impacts of climate change depends in part upon our disaster preparedness and response and business continuity planning. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties.

Each of these developments may in the future adversely affect the demand for products manufactured with, or powered by, petroleum products, as well as the demand for, and in turn the prices of, oil and natural gas products. Additionally, political, financial and litigation risks may result in us having to restrict, delay or cancel production activities, incur liability for infrastructure damages as a result of climatic changes, or impair the ability to continue to operate in an economic manner, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Increasing attention to ESG matters may impact our business.

Increasing scrutiny related to ESG matters, societal expectations for companies to address climate change and sustainability concerns, and investor, societal, and other stakeholder expectations regarding ESG and sustainability practices and related disclosures may result in increased costs, reduced demand for the oil and natural gas we produce, reduced profits, increased risks of governmental investigations and private party litigation, and negative impacts on our stock price and access to capital markets. Increasing attention to climate change, for example, may result in demand shifts for the hydrocarbon products we produce as well as additional governmental investigations and private litigation against us. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the assented damage, or to other mitigating factors.

If we do not adapt to or comply with investor or other stakeholder expectations and standards on ESG matters as they continue to evolve, or if we are perceived to have not responded appropriately or quickly enough to growing concern for ESG and sustainability issues, regardless of whether there is a regulatory or legal requirement to do so, we may suffer from reputational damage and our business, financial condition and/or stock price could be materially and adversely affected.

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Further, our operations, projects and growth opportunities require us to have strong relationships with various key stakeholders, including our shareholders, employees, suppliers, customers, local communities and others. We may face pressure from stakeholders, including activist investors, many of whom are increasingly focused on climate change, to prioritize sustainable energy practices, reduce our carbon footprint and promote sustainability while at the same time remaining a successfully operating public company. Responses to such pressure could adversely impact our business by distracting management and other personnel from their primary responsibilities, require us to incur increased costs, and/or result in reputational harm. Moreover, if we do not successfully manage expectations across these varied stakeholder interests, it could erode stakeholder trust and thereby affect our brand and reputation. Such erosion of confidence could negatively impact our business through decreased demand and growth opportunities, delays in projects, increased legal action and regulatory oversight, adverse press coverage and other adverse public statements, difficulty hiring and retaining top talent, difficulty obtaining necessary approvals and permits from governments and regulatory agencies on a timely basis and on acceptable terms and difficulty securing investors and access to capital.

Organizations that provide information to investors on corporate governance, climate change, health and safety and other ESG related factors have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with fossil energy-related assets could lead to increased negative investor sentiment toward us or our customers and to the diversion of investment to other industries, which could have a negative impact on our unit price and/or our access to and costs of capital.

In addition, our continuing efforts to research, establish, accomplish and accurately report on the implementation of our ESG strategy, including any specific ESG objectives, may also create additional operational risks and expenses and expose us to reputational, legal and other risks. While we create and publish voluntary disclosures regarding ESG matters from time to time, some of the statements in those voluntary disclosures may be based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. In addition, our current ESG governance structure may not allow us to adequately identify or manage ESG-related risks and opportunities, which may include failing to achieve ESG-related strategies and goals.

Certain U.S. federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated as a result of future legislation.

In recent years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including certain key U.S. federal income tax provisions currently available to oil and gas companies. Such legislative changes have included, but have not been limited to, (i) the repeal of the percentage depletion allowance for natural gas and oil properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. Although these provisions were largely unchanged in recent federal tax legislation such as the IRA, Congress could consider, and could include, some or all of these proposals as part of future tax reform legislation. Moreover, other more general features of any additional tax reform legislation, including changes to cost recovery rules, may be developed that also would change the taxation of oil and gas companies. It is unclear whether these or similar changes will be enacted in future legislation and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development or increase costs, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.

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Unanticipated changes in effective tax rates or adverse outcomes resulting from examination of our income or other tax returns could adversely affect our financial condition and results of operations.

We are subject to taxes by U.S. federal, state and local tax authorities. Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including changes in the valuation of our deferred tax assets and liabilities, expected timing and amount of the release of any tax valuation allowances, or changes in tax laws, regulations, or interpretations thereof. In addition, we may be subject to audits of our income, sales and other transaction taxes by U.S. federal, state and local taxing authorities. Outcomes from these audits could have an adverse effect on our financial condition and results of operations.

Our articles of incorporation and bylaws, as well as Texas law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

Certain provisions of our articles of incorporation and bylaws could make it more difficult for a third-party to acquire control of us, even if the change of control would be beneficial to our stockholders. Among other things, our articles of incorporation and bylaws:

Further, we are incorporated in Texas. The Texas Business Organizations Code contains certain provisions that could make an acquisition by a third party more difficult.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None

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ITEM 1C. CYBERSECURITY

We maintain a cyber risk management program designed to identify, assess, manage, mitigate, and respond to cybersecurity threats. This program is integrated within our information technology (“IT”) and risk management systems and addresses both the corporate and the operational IT environment.

  The underlying controls of the cyber risk management program are based on recognized best practices and standards for cybersecurity and IT, including the National Institute of Standards and Technology (the “NIST”), the Control Objectives for Information Technologies (“COBIT”) framework and the International Organization Standardization 27001, Information Security Management System requirements. We have an annual assessment, performed by our internal audit department, of our cyber risk management program against the NIST and COBIT frameworks. 

 Our information security practices include development, implementation, and improvement of policies and procedures to safeguard information and ensure availability of critical data and systems. We have adopted a Cybersecurity Incident Response Plan that applies if a security event occurs. Our Incident Response Plan provides a common framework for responding to security incidents. This framework establishes procedures for identifying, validating, categorizing, documenting, and responding to security events that are identified by or reported to the Chief Information Officer (CIO). Our Incident Response Plan applies to W&T personnel including contractors and partners that perform functions or services that require securing W&T information assets, and to all devices and networks that are owned by W&T. The Incident Response Plan details the coordinated, multi-functional approach for investigating, containing, and mitigating incidents. Under our Incident Response Plan, cybersecurity incidents are escalated based on a defined incident categorization to the CIO and the General Counsel. Regular updates are provided by the Cybersecurity team to the CIO, who will maintain communication and information flow to senior leadership including the General Counsel, Chief Financial Officer, and other cybersecurity program stakeholders as well as the Audit Committee and/or the Board of Directors as appropriate. Generally, our incident response process follows the National Institute of Standards and Technology (NIST) framework and focuses on preparation; detection and analysis; containment, eradication, recovery and post-incident remediation.

We conduct mandatory security training during new employee onboarding, as well as require our employees to complete annual security risk training and, when necessary, perform additional updated training. We also engage certain third-parties in assessing, identifying and managing cyber-security risks. These third parties perform a number of services, including managed detection and response services for information technology endpoints, anti-virus monitoring, penetration testing, and other miscellaneous cyber security programs and services. We maintain specific policies and practices governing our third-party security risks, including our third-party assessment process. Under our third-party assessment process, we gather information from certain third parties who contract with us and share or receive data, or have access to or integrate with our systems, in order to help us assess potential risks associated with their security controls. We require each third-party service provider to certify that it has the ability to implement and maintain appropriate security measures, consistent with all applicable laws, to implement and maintain reasonable security measures in connection with their work with us, and to promptly report any suspected breach of its security measures that may affect us.

 The Audit Committee of our board of directors oversees our cybersecurity policies, procedures, risk exposures and the steps taken by management to monitor and mitigate cybersecurity risks. Our executive management, including our Vice President and Chief Information Officer, periodically updates and reports to the Audit Committee and the board of directors regarding cybersecurity risk exposure and our cybersecurity risk management strategy (at a minimum, once per quarter). Additionally, all members of the board of directors attend quarterly training sessions through internal and external IT specialists, which include review of IT whitepapers, presentations, and other learning materials. Each of the members of the board of directors has also completed certificated training concerning IT security, IT fraud, and other common enterprise-level IT threats. 

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 We face risks from cybersecurity threats that could have a material adverse effect on our business, financial condition, results of operations, cash flows or reputation. In the past three years, we have not experienced a material information security breach but may in the future. See Risk Factors in Part I, Item 1A in this Form 10-K for additional information.

ITEM 2. PROPERTIES

We lease our corporate headquarters in Houston, Texas. We own and lease our operating and administrative facilities in Alabama and Louisiana, respectively. We believe our properties and facilities are suitable and adequate for their present and intended purposes and are operating at a level consistent with the requirements of the industry in which we operate.

Oil and Natural Gas Producing Activities

Our producing fields are located in federal and state waters in the Gulf of Mexico in water depths ranging from less than 10 feet up to 7,300 feet. The reservoirs in our offshore fields are generally characterized as having high porosity and permeability, with higher initial production rates relative to other domestic reservoirs.

As of December 31, 2023, two of our fields located in the conventional shelf accounted for approximately 64.6% of our proved reserves on an energy equivalent basis. The following table provides information for these fields:

​

The Mobile Bay Properties (as defined below) and Ship Shoal 349 field are two areas of operations of major significance, which we define as having year-end proved reserves of 10% or more of the Company’s total proved reserves on an energy equivalent basis. Each area of operation of major significance is described in detail below. Unless indicated otherwise, “drilling” or “drilled” in the descriptions below refers to when the drilling reached target depth, as this measurement usually has a higher correlation to changes in proved reserves compared to using the SEC’s definition for completion. The following are descriptions of these areas of operations:

Mobile Bay Properties

Our interests in certain oil and gas leasehold interests and associated wells and units located off the coast of Alabama, in state coastal and federal Gulf of Mexico waters approximately 70 miles south of Mobile, Alabama, are referred to as the “Mobile Bay Properties.” Cumulative field production for the Mobile Bay Properties through 2023 is approximately 896.6 MMBoe gross. The Mobile Bay Properties produce from the Jurassic age Norphlet eolian sandstone at an average depth of 21,000 feet total vertical depth. As of December 31, 2023, 56 Norphlet wells have been drilled on the Mobile Bay Properties, 45 of which were successful and 27 of which are currently producing.

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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 over the past three years:

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Ship Shoal 349 Field (Mahogany)

Ship Shoal 349 field is located off the coast of Louisiana, approximately 235 miles southeast of New Orleans, Louisiana. The field area covers Ship Shoal federal OCS blocks 349 and 359, with a single production platform on Ship Shoal block 349 in 375 feet of water (the “Ship Shoal 349”). We own a 100% working interest in this field except for an interest in one well owned by Monza. Cumulative field production through 2023 is approximately 62.4 MMBoe gross. This field is a sub-salt development with nine productive horizons below salt at depths up to 18,000 feet. As of December 31, 2023, 31 wells have been drilled and 26 were successful. Since acquiring an interest and subsequently taking over as operator, we have directly participated in drilling 17 wells with a 100% success rate. There has been no drilling activity since 2019 at Ship Shoal 349.

The following table presents our produced oil, NGLs and natural gas volumes (net to our interests) from the Ship Shoal 349 field over the past three years:

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Proved Reserves

Our proved reserves were estimated by Netherland, Sewell & Associates, Inc (“NSAI”), our independent petroleum consultant, and amounts provided in this Form 10-K are consistent with filings we make with other federal agencies. Our proved reserves as of December 31, 2023, 2022 and 2021 are summarized below:

In accordance with guidelines established by the SEC, our estimated proved reserves as of December 31, 2023 were determined to be economically producible under existing economic conditions, which requires the use of SEC pricing. Applying this methodology, the WTI oil average spot price of $78.21 per barrel and the Henry Hub natural gas average spot price of $2.64 per MMBtu were utilized as the referenced price and, after adjusting for quality, transportation, fees, energy content and regional price differences, the adjusted average product prices were $74.79 per barrel for oil, $24.08 per barrel for NGLs and $2.74 per Mcf for natural gas. In determining the estimated price for NGLs, a ratio was computed for each field of the NGL realized price compared to the oil realized price. This ratio was then applied to the oil price using SEC guidance. Such prices were held constant throughout the estimated lives of the reserves. Future production and development costs are based on year-end costs with no escalation.

Reconciliation of Standardized Measure to PV-10

Neither PV-10 nor PV-10 after ARO are financial measures defined under GAAP; therefore, the following table reconciles these amounts to the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. Management believes that the non-GAAP financial measures of PV-10 and PV-10 after ARO are relevant and useful for evaluating the relative monetary significance of oil and natural gas properties. PV-10 and PV-10 after ARO are used internally when assessing the potential return on investment related to oil and natural gas properties and in evaluating acquisition opportunities. We believe the use of pre-tax measures is valuable because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid. Management believes that the presentation of PV-10 and PV-10 after ARO provide useful information to investors because they are widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. PV-10 and PV-10 after ARO are not measures of financial or operating performance under GAAP, nor are they intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 and PV-10 after ARO should not be considered in isolation or as substitutes for the standardized measure of discounted future net cash flows as defined under GAAP. Investors should not assume that PV-10, or PV-10 after ARO, of our proved oil and natural gas reserves shown above represent a current market value of our estimated oil and natural gas reserves.

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The reconciliation of PV-10 and PV-10 after ARO to the standardized measure of discounted future net cash flows relating to our estimated proved oil and natural gas reserves is as follows (in millions):

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Changes in Proved Reserves

The following table discloses our estimated changes in proved reserves during 2023:

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See Proved Undeveloped Reserves below for a table reconciling the change in proved undeveloped reserves during 2023. See Financial Statements and Supplementary Data – Note 20 – Supplemental Oil and Gas Disclosures under Part II, Item 8 in this Form 10-K for additional information.

Our estimates of proved reserves, PV-10 and the standardized measure as December 31, 2023 are calculated based upon SEC mandated 2023 unweighted average first-day-of-the-month oil and natural gas benchmark prices, and adjusting for quality, transportation fees, energy content and regional price differentials, which may or may not represent current prices. If prices fall below the 2023 levels, absent significant proved reserve additions, this may reduce future estimated proved reserve volumes due to lower economic limits and economic return thresholds for undeveloped reserves, as well as impact our results of operations, cash flows, quarterly full cost impairment ceiling tests and volume-dependent depletion cost calculations. See Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 in this Form 10-K for additional information.

Proved Undeveloped Reserves

Our PUDs were estimated by NSAI, our independent petroleum consultant. Future development costs associated with our PUDs at December 31, 2023 were estimated at $437.9 million.

The following table presents changes in our PUDs (in MMBoe):

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The revisions of previous estimates during 2023 were due to changes in SEC pricing. The revisions in 2022 and 2021 were primarily due to technical revisions and revisions due to changes in SEC pricing at certain of our Ship Shoal fields.

The following table presents our estimates as to the timing of converting our PUDs to proved developed reserves:

​

As of December 31, 2023, we believe that we will be able to develop all but 3.1 MMBoe (approximately 16%) of the total 19.7 MMBoe classified as PUDs within five years from the date such PUDs were initially recorded. The lone exceptions are at the Mississippi Canyon 243 field (“Matterhorn”), Ship Shoal 349 and Viosca Knoll 823 field (“Virgo”) where future development drilling has been planned as sidetracks of existing wellbores due to conductor slot limitations and rig availability. Three sidetrack PUD locations, one each at Matterhorn, Ship Shoal 349 and Virgo, will be delayed until an existing well is depleted and available to sidetrack. We also plan to recomplete and convert an existing producer at Matterhorn to water injection for improved recovery following depletion of the existing well. Based on the latest reserve report, these PUD locations are expected to be developed in 2025 and 2035.

Qualifications of Technical Persons and Internal Controls over Reserves Estimation Process

Our estimated proved reserve information as of December 31, 2023 included in this Form 10-K was prepared by our independent petroleum consultants, NSAI, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. The NSAI report is based on its independent evaluation of engineering and geophysical data, product pricing, operating expenses, and the reasonableness of future capital requirements and development timing estimates provided by W&T. The scope and results of their procedures are summarized in a letter included as an exhibit to this Form 10-K. The primary technical person at NSAI responsible for overseeing the preparation of the reserves estimates presented herein has been practicing consulting petroleum engineering at NSAI since 2013 and has over 14 years of prior industry experience. NSAI has informed us that he meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in the application of industry standard practices to engineering evaluations as well as the application of SEC and other industry definitions and guidelines.

We maintain an internal staff of reservoir engineers and geoscience professionals who work closely with our independent petroleum consultant to ensure the integrity, accuracy and timeliness of the data, methods and assumptions used in the preparation of the reserves estimates. Additionally, our senior management reviews any significant changes to our proved reserves on a quarterly basis. Our Director of Reservoir Engineering has over 30 years of oil and gas industry experience and has managed the preparation of public company reserve estimates the last 18 years. He joined the Company in 2016 after spending the preceding 12 years as Director of Corporate Engineering for Freeport-McMoRan Oil & Gas. He has also served in various engineering and strategic planning roles with both Kerr-McGee and with Conoco, Inc. He earned a Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1989 and a master’s degree in Business Administration from the University of Houston in 1999.

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Reserve Technologies

Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, consistent with the definition in Rule 4-10(a)(24) of Regulation S-X. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our independent petroleum consultant employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the estimates of our reserves is a function of:

Because these estimates depend on many assumptions, any or all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered.

Reporting of Natural Gas and Natural Gas Liquids

We produce NGLs as part of the processing of our natural gas. The extraction of NGLs in the processing of natural gas reduces the volume of natural gas available for sale. We report all natural gas production information net of the effect of any reduction in natural gas volumes resulting from the processing of NGLs.

Developed and Undeveloped Acreage

The following table summarizes our developed and undeveloped acreage at December 31, 2023:

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​

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Our net acreage decreased 15,026 net acres (3%) from December 31, 2022 due to lease expirations offset by leases acquired in the September 2023 acquisition.

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Approximately 88.3% of our net acreage is held by production. We have the right to propose future exploration and development projects on the majority of our acreage. The following table presents the timing of expiration of our undeveloped leasehold acreage: