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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, 2019

2022

or

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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)

(713) 626-8525

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

Reserve engineering is a process of estimating underground accumulations of natural gas, oil and NGLs 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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Capital Risks

Legal and Regulatory Risks

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

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.

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 MMS Minerals Revenue Management Program.

OPEC. Organization of Petroleum Exporting Countries.

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. 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 (“API”) gravity of approximately 38-40 and the sulfur content is approximately 0.3%.

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We intend to execute the following elements of our business strategy in order to achieve this goal:

our strategic goals:

Our focus is on making profitable investments while operating within cash flow, maintaining sufficient liquidity, cost reductions and fulfilling our contractual, legal and financial obligations.  We continue to closelycontinually monitor current and forecasted commodity prices to assess if changes are needed to our plans. 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.

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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 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.

Oil and Natural Gas Marketing and Delivery Commitments

We sell our crude oil, NGLs and natural gas to third-party customers. We are not dependent upon, or contractually limited to, any one customer or small group of customers. However, in 2019,In 2022, approximately 40%31% of our revenues were toreceived from BP Products North America 12% to Vitol Inc. and 11% to Shell Trading (US) Co.,approximately 13% from Chevron-Texaco, with no other customer comprising greater than 10% of our 20192022 revenues. Due toGiven the free tradingcommoditized nature of the oilproducts we produce and natural gas marketsmarket and the location of our production in the Gulf of Mexico, we do not believe the loss of any of the customers above would not result in a single customer or a few customers would materially affectmaterial adverse effect on our ability to sell our production.market future oil and natural gas, provided that replacement customers could be obtained in a relatively short period of time on terms, conditions, and pricing substantially similar to those currently existing. We do not have any agreements which obligate us to deliver material quantitiesa fixed volume of physical products to third parties.customers.

Compliance with Government Regulations

Regulation

General. Various aspects of our oil and natural gas operations are subject to extensive and continually changing regulations as legislation affecting the oil and natural gas industry is under constant review for amendment or expansion. Numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding upon the oil and natural gas industry and its individual members. The Bureau of Ocean Energy Management (“BOEM”)BOEM and the Bureau of Safety and Environmental Enforcement (“BSEE”),BSEE, both agencies under the U.S. Department of the Interior (“DOI”), have adopted regulations pursuant to the Outer Continental Shelf Lands Act (“OCSLA”) that apply to our operations on federal leases in the Gulf of Mexico.

The Federal Energy Regulatory Commission (“FERC”) regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”).1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and non-price controls affecting wellhead sales of natural gas, effective January 1, 1993. Sales by producers of natural gas and all sales of crude oil, condensate and NGLs can currently be made at uncontrolled market prices. The FERC also regulates rates and service conditions for the interstate transportation of liquids, including crude oil, condensate and NGLs, under various statutes.

The Federal Trade Commission (“FTC”), the FERC and the Commodity Futures Trading Commission (“CFTC”) hold statutory authority to monitor certain segments of the physical and futures energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. We are required to observe the market related regulations enforced by these agencies with regard to our physical sales of crude oil or other energy commodities, and any related hedging activities that we undertake. Any violation of the FTC, FERC, and CFTC prohibitions on market manipulation can result in substantial civil penalties amounting to over $1.0almost $1.5 million per violation per day.

These departments and agencies have substantial enforcement authority and the ability to grant and suspend operations, and to levy substantial penalties for non-compliance. Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations and financial condition.

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Federal leases. Most of our offshore operations are conducted on federal oil and natural gas leases in the OCS waters of the Gulf of Mexico. The DOI has delegated its authority to issue federal leases granted under the OCSLA to the BOEM, which has adopted and implemented regulations relating to the issuance and operation of oil and natural gas leases on the OCS. These leases are awarded by the BOEM based on competitive bidding and contain relatively standardized terms. These leases require compliance with the BOEM, the BSEE, and other government agency regulations and orders that are subject to interpretation and change. The BSEE also regulates the plugging and abandonment of wells located on the OCS and, following cessation of operations, the removal or appropriate abandonment of all production facilities, structures and pipelines on the OCS (collectively, these activities are referred to as “decommissioning”), while the BOEM governs financial assurance requirements associated with those decommissioning obligations.

President Biden has made tackling climate change, including the restriction or elimination of future greenhouse gas (“GHGs”) emissions, a priority in his administration. The Biden Administration has already adopted several executive orders and is expected to pursue additional orders and pursue legislation, regulations or other regulatory initiatives in support of this regulatory agenda. Notably, President Biden issued an executive order in January 2021 suspending new leasing activities for oil and gas exploration and production on federal lands and offshore waters pending review and reconsideration of federal oil and gas permitting and leasing practices. The suspension of these federal leasing activities prompted legal action by several states against the Biden Administration, resulting in issuance of a nationwide preliminary injunction by a federal district court in June 2021, effectively halting implementation of the leasing suspension. Subsequent federal litigation, however has impeded the most recent federal oil and gas lease sale (Lease Sale 257) in the Gulf of Mexico requiring the DOI to conduct a new environmental analysis that takes into consideration such climate effects before holding another sale. In August 2022, the Fifth Circuit vacated the injunction blocking the leasing moratorium, allowing the Biden Administration to continue implementing the pause. However, in compliance with the Inflation Reduction Act of 2022, the BOEM reinstated Lease Sale 257 in September 2022. The BOEM has continued to plan for upcoming offshore lease sales as required by the OCSLA. In July 2022, the BOEM published the 2023-2028 National Outer Continental Shelf Drilling and Leasing Proposed Program, which contemplates eleven future lease sales. In November 2021, the DOI released its report on federal oil and gas leasing and permitting practices. The report includes recommendations in respect to offshore sector, including adjusting royalty rates to ensure that the full value of the tracts being leased are captured, strengthening financial assurance coverage amounts that are required by operators, establishing a “fitness to operate” criteria that companies would need to meet in respect of safety, environmental and financial responsibilities in order to operate on the OCS. Several of the report recommendations require action by the Congress and cannot be implemented unilaterally by the Biden Administration; however, in April 2022, the DOI published sale notices for June 2022 onshore lease sales that incorporated certain recommendations in the DOI’s report, including significantly reduced acreage of land available for leasing on public lands and an increased royalty rate of 18.75%,up from the current rates of 12.50% to 16.67%. We continue to conduct our operations on our existing leases in the OCS; however, uncertainty on future Biden Administration actions with regard to offshore oil and gas activities on the OCS together with the issuance of any future executive orders or adoption and implementation of laws, rules or initiatives that further restrict, delay or result in cancellation of existing oil and gas activities on the OCS could have a material adverse effect on our business and operations.

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 on the OCS. In 2016, the BOEM under the Obama Administration issued Notice to Lessees and Operators (“2016-N01 (the “2016 NTL”) #2016-N01 (“NTL #2016-N01”) to clarify the procedures and guidelines that BOEM Regional Directors use to determine if and when additional financial assurances may be required for OCS leases, rights of way (“ROWs”) and rights of use and easement (“RUEs”). The 2016 NTL #2016-N01 became effective in September 2016, but in the Spring of 2017,was not fully implemented as the BOEM under the Trump Administration rescinded the 2016 NTL in 2020. In October 2020, BOEM published jointly with BSEE a proposed rule that sought to clarify and provide greater transparency to decommissioning and related financial assurance requirements imposed on record title owners and operating rights owners of interests in federal OCS leases and RUE and ROW grant holders conducting operations on the federal OCS. A final rule was expected by December 2022 but has since extended indefinitely the start date for implementation.  This extension currently remains in effect; however,not yet been published. In August 2021, the BOEM reservedannounced expanded requirements for supplemental financial assurance for properties with property owners who are not deemed to be financially strong by the rightBOEM. In addition to re-issuesole liability properties where the owner is not financially strong, the BOEM will require supplemental financial assurance for certain high-risk, non-sole liability properties.

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Consistent with the November 2021 DOI leasing report recommendations and in response to President Biden’s January 2021 executive order, the Biden Administration could pursue more stringent decommissioning and financial assurance requirements that could increase our operating costs. According to the federal government’s Fall 2022 Unified Regulatory Agenda, the BOEM and the BSEE are expected to finalize the policies and procedures concerning compliance with OCS oil and gas decommissioning obligations originally proposed under the Trump Administration. In addition, BOEM is expected to propose a new rule in respect of financial assurance requirements to ensure compliance with OCS obligations. The BOEM has the authority to issue liability orders in the future, including if it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities.

Reporting of decommissioning expenditures. Under applicable BSEE regulations, lessees operating on the OCS and conducting decommissioning activities are required to submit summaries of actual expenditures for decommissioning of subject wells, platforms, and other facilities. The BSEE has reported that it uses this summary information to better estimate future decommissioning liabilities. See Risk Factors under Part I, Item 1A, Management’s Discussion and Analysis of Financial Condition and Results of Operations in Part II, Item 7 and Financial Statements and Supplementary Data under Part II, Item 8 in this Form 10-K for more discussion on decommissioning and financial assurance requirements.

Reporting of decommissioning expenditures.  During late 2015, the BSEE issued a final rule requiring lessees to submit summaries of actual expenditures for decommissioning of wells, platforms, and other facilities required under the BSEE’s existing regulations. The BSEE has reported that it will use this summary information to better estimate future decommissioning costs, and the BOEM typically relies upon the BSEE’s estimates to set the amount of required bonds or other forms of financial security in order to minimize the government’s perceived risk of potential decommissioning liability.

“Unbundling.”The Office of Natural Resources Revenue (the “ONRR”) has publicly announced an “unbundling” initiative to revise the methodology employed by producers in determining the appropriate allowances for transportation and processing costs that are permitted to be deducted in determining royalties under Federal oil and gas leases.  The ONRR’s initiative requires re-computing allowable transportation and processing costs using revised guidance from the ONRR going back 84 months for every gas processing plant utilized during that period.

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 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 FERC ratemaking authority, and FERC exercises its authority either by applyingmay apply cost-of-service principles or granting market basedallow 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 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 on the OCS.

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 British thermal units (“MMBtu”)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 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.

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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. OurOther than as described above, our sales of liquids, which include crude 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 crude oil and NGLs is affected by the cost of transporting those products to market. Interstate transportation rates for crude oil, condensate, NGLs and other products are regulated by the FERC. In general, interstate crude 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 crude 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 crude oil, condensate or NGL pipelines will affect us in a way that materially differs from the way they affect other crude oil, condensate and NGL producers or marketers.

Regulation of oil and natural gas exploration and production.Our exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulations include requiring permits, bonds and pollution liability insurance for the drilling of wells, regulating the location of wells, the method of drilling, casing, operating, plugging and abandoning wells, and governing the surface use and restoration of properties upon which wells are drilled. Many states also have statutes or regulations addressing conservation of oil and gas resources, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells and the regulation of spacing of such wells.

HurricanesTropical storms, hurricanes and other weather events in the Gulf of Mexico can have a significant impact on oil and gas operations on the OCS. The effects from past tropical storms and hurricanes have included structural damage to fixed production facilities, semi-submersibles and jack-up drilling rigs. Damage can occur both above the water line and to subsea infrastructure. The BOEM and the BSEE continue to be concerned about the loss of these facilities and rigs as well as the potential for catastrophic damage to key infrastructure and the resultant pollution from future storms. In an effort to reduce the potential for future damage, the BOEM and the BSEE have periodically issued guidance aimed at improving platform survivability by taking into account environmental and oceanic conditions in the design of platforms and related structures.

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Compliance with Environmental Regulations

General. We are subject to complex and stringent federal, state and local environmental laws. These laws, among other things, govern the issuance of permits to conduct exploration, drilling and producingproduction 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 contaminated sites and the reclamation and abandonmentany releases of wells, sites andthose waste materials from such facilities. Numerous governmental departmentsagencies 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. SomeCertain environmental laws, rules and regulations relating to protectionsuch as the federal Oil Pollution Act of the environment may, in certain circumstances,1990, as amended (“OPA”) impose strict joint and several liability for environmental contamination, such as may arise in the event of an accidental spill on the OCS, rendering a person liable for environmental damagesdamage and cleanup costs without regard to negligence or fault on the part of such person.  Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration and production activities in sensitive areas.  In addition, state laws often require various forms of remedial action to prevent and address pollution, such as the closure of inactive oil and gas waste pits and the plugging of abandoned wells. The regulatory burden on the oil and gas industry increases our cost of doing business and consequently affects our profitability. The cost of remediation, reclamation and decommissioning, including abandonment of wells, platforms and other facilities in the Gulf of Mexico is significant. These costs are considered a normal, recurring cost of our on-going operations. Our competitors are subject to the same laws and regulations.

Hazardous Substances and Wastes.The federal Comprehensive Environmental Response, Compensation, and Liability Act, as amended, (“CERCLA”) imposes liability, without regard to fault, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances. Under CERCLA, such persons are subject to strict joint and several liability for the cost of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the cost of certain health studies.

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Insurance Coverage

Our oil and natural gas operations are subject to risks incident to the operation of oil and gas wells, including, but not limited to, uncontrolled flows of oil, gas, brine or well fluids into the environment, blowouts, cratering, mechanical difficulties, fires, explosions or other physical damage, pollution or other risks, any of which could result in substantial losses to us. In addition, our oil and natural gas properties are located in the Gulf of Mexico, which makes us more vulnerable to tropical storms and hurricanes. These hazards can cause 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. Damages arising from such occurrences may result in lawsuits asserting large claims. Insurance may not be sufficient or effective under all circumstances or against all hazards to which we may be subject. A successful claim for which we are not fully insured could have a material adverse effect on our financial condition, results of operations and cash flow. Although we obtain insurance against some of these risks, 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 have insurance policies to cover some of our risk of loss associated with our operations, and we maintain the amount of insurance we believe is prudent. However, not all of our business activities can be insured at the levels we desire because of either limited market availability or unfavorable economics (limited coverage for the underlying cost). Our general and excess liability policies, among others, are effective for one year beginning May 1, 2022 and 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. With respect to the Oil Spill Financial Responsibility requirement under the OPA of 1990, we are required to evidence $35.0 million of financial responsibility to the BSEE and we have insurance coverage of such amount. We currently carry multiple layers of insurance coverage in our Energy Package (defined as certain insurance policies relating to our oil and gas properties which include named windstorm coverage) covering our operating activities, with higher limits of coverage for higher valued properties and wells. The Energy Package is effective for one year beginning June 1, 2022 and 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 a retention of $17.5 million on the conventional shelf properties and $12.5 million on the deepwater properties. The operational and named windstorm coverages are effective for one year beginning June 1, 2022. Coverage for pollution causing a negative environmental impact is provided under the well control and other sections within the policy. We do not carry business interruption insurance.

Financial Information

We operate our business as a single segment. SeeSelected Financial Data under Part II, Item 6 and Financial Statements and Supplementary Data under Part II, Item 8 in this Form 10-K for our financial information.

Seasonality and Inflation

Seasonality

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 thea storm subsides. Also, periodic storms during the winter often impede our ability to safely load, unload and transport personnel and equipment, which delays the installation of production facilities, thereby delayingcan delay production and sales of our oil and natural gas.

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Inflation. The United States has experienced a rise in inflation since October 2021. The annual rate of inflation in the United States was measured at 6.5% in December 2022 by the Consumer Price Index. This is down from the June 2022 peak of 9.1% and represents the smallest twelve-month increase since the period ending October 2021. While currently on the decline, the annual inflation rate remains at its highest level since the early 1980s. For 2022, our realized prices for crude oil increased 41.9%, NGLs increased 19.8% and natural gas increased 86.3% from 2021. Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increase, while during periods of commodity price declines, decreases in oilfield costs typically lag behind commodity price decreases. Continued inflationary pressures and increased commodity prices may also result in increases to the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise.

EmployeesWe are experiencing some inflationary pressure for certain costs, including employees and vendors, although such cost increases did not materially impact our 2022 financial condition or results of operations, and we currently do not expect them to materially impact our 2023 financial results or operations. However, to the extent elevated inflation remains, we may experience further cost increases for our operations, including natural gas purchases and oilfield services and equipment as increasing oil, natural gas and NGL prices increase drilling activity in our areas of operations, as well as increased labor costs. An increase in oil, natural gas and NGL prices may cause the costs of materials and services to rise. We cannot predict any future trends in the rate of inflation and a significant increase in inflation, to the extent we are unable to recover higher costs through higher commodity prices and revenues, would negatively impact our business, financial condition and results of operation.

Human Capital Resources

At W&T Offshore, people are our most valuable asset. 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.

As of December 31, 2019,2022, we had 365 employees and employed 291 people. Wean additional 302 individuals who are notemployees 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.

Health and Safety. Our highest priorities are the safety of all personnel and protection of the environment. To drive a partyculture of personnel safety in our operations, we operate under a comprehensive Safety and Environmental Management System (“SEMS”). Our 2022 total recordable incident rate for employees was 0.54, which is far below the industry average for the Gulf of Mexico from 2021 of 9.9. Although incident reporting practices are subject to any collective bargaining agreementssome 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 have not experienced any strikes or work stoppages.strive to continue to excel at protecting our personnel. Our Health, Safety, Environmental and Regulatory (“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 consider our relations withpride ourselves on providing an attractive compensation and benefits program that allows our employees to be good.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.

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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.

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.

Additional InformationOur 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 mirrors 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, 2022:

Low prices for our products relative to the cost to find, develop and produce products reduces our profitability and can materially and adversely affect our future business, financial condition, resultsTable of operations, liquidity, ability to finance planned capital expenditures, ability to fund our ARO, ability to repay any borrowings per our debt agreements, ability to secure supplemental bonding, ability to secure collateral for such bonding, if required, and ability to meet our other financial obligations.Contents

The borrowing base under our Credit Agreement may be reduced by our lenders.

Availability of borrowings and letters of credit under our Credit Agreement is determined by establishment of a borrowing base, which is periodically redetermined during the year based on our lenders’ review of crude oil, NGLs and natural gas prices and on our proved reserves.  During 2019, there were no changes to our borrowing base under the Credit Agreement, but during 2018, the borrowing base was increased from $150.0 million to $250.0 million.  The borrowing base is subject to scheduled semi-annual redeterminations to occur around May 15^th and November 14^th of each year and additional redeterminations that may be requested at the discretion of either the lenders or the Company.  The borrowing base could be reduced in the future as a result of lower commodity prices, our lenders’ outlook for future prices or our inability to replace reserves as a result of constrained capital spending.  To the extent borrowings and letters of credit outstanding exceed the redetermined borrowing base; such excess (referred to as a “Borrowing Base Deficiency”) is required to be repaid within 150 days in five equal monthly payments.  In addition to the borrowing base limitation, the Credit Agreement limits our ability to incur additional indebtedness if we cannot comply with specified baskets, financial covenants or ratios.

We may not have the financial resources in the future to repay a Borrowing Base Deficiency resulting from a borrowing base redetermination as required under our Credit Agreement, which could result in an event of default.  Additionally, a material reduction of our current cash position could substantially limit our ability to comply with other cash needs, such as collateral needs for existing or additional supplemental surety bonds or other financial assurances issued to the BOEM for our decommissioning obligations.  Further, the failure to repay a Borrowing Base Deficiency that may result from a borrowing base redetermination under our Credit Agreement may result in a cross-default under our other debt agreement.  If crude oil, NGLs and natural gas prices fall back to the levels experienced in 2016, this would adversely affect our cash flow, which could result in reductions in our borrowing base, adversely affect prospects for alternative credit availability or affect our ability to satisfy our covenants and ratios under our Credit Agreement.

We have a significant amount of indebtedness and limited borrowing capacity under our 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, 2019, we had $730.0 million principal amount of indebtedness outstanding, all of which was secured, and additionally had $5.8 million of letters of credit obligations outstanding.  Our borrowing availability under our Credit Agreement was $139.2 million as of December 31, 2019, as we had $105.0 million in borrowings in addition to the letters of credit obligations outstanding.  Our leverage and debt service obligations could:

Any of the above listed factors could have a material adverse effect on our business, financial condition, cash flows and results of operations.

Our ability to pay our expenses and fund our working capital needs and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors.  We will not be able to control many of these factors, such as commodity prices, other economic conditions and governmental regulation.  Substantially all of our oil, NGLs and natural gas properties are pledged as collateral under our Credit Agreement and are also pledged as collateral on a subordinate basis under the Indenture of the Senior Second Lien Notes (the “Indenture”) dated as of October 18, 2018, entered into by and among the Company, the Guarantors, and Wilmington Trust, National Association, as trustee (the “Trustee”).  Lower crude oil, NGLs and natural gas prices in the future would adversely affect our cash flow and could result in reductions in our borrowing base, reduce prospects for alternate credit availability, and affect our ability to satisfy the covenants and ratios under our Credit Agreement.  Asset sales may also reduce available collateral and availability under our Credit Agreement.  In addition, we cannot be certain that our cash flow will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations.

If we are unable to service our indebtedness and other obligations, we may be required to further refinance all or part of our existing debt, sell assets, reduce capital expenditures, borrow more money or raise equity.  However, we may not be able to accomplish any of these transactions on terms acceptable to us, if at all, or such alternative strategies may yield insufficient funds to make required payments on our indebtedness.  In addition, our ability to comply with the financial and other restrictive covenants in our debt instruments is uncertain and will be affected by our future performance and events or circumstances beyond our control.  Failure to comply with these covenants would result in an event of default under such indebtedness, the potential acceleration of our obligation to repay outstanding debt and the potential foreclosure on the collateral securing such debt, and could cause a cross-default under our other outstanding indebtedness.  Any of the above risks could have a material adverse effect on our business, financial condition, cash flows and results of operations.

We may incur substantially more debt. This could exacerbate the risks associated with our indebtedness.

We and our subsidiaries may incur substantial additional indebtedness in the future, subject to the terms of our debt agreements. As of December 31, 2019, we had $730.0 million principal amount of secured indebtedness. The components of our indebtedness are:

If new debt is added to our current debt levels, the related risks that we face could intensify.  Our level of indebtedness may prevent us from engaging in certain transactions that might otherwise be beneficial to us by limiting our ability to obtain additional financing, limiting our flexibility in operating our business or otherwise.  In addition, we could be at a competitive disadvantage against other less leveraged competitors that have more cash flow to devote to their business.

Restrictions in our existing and future debt agreements could limit our growth and our ability to respond to changing conditions.

The indentures and credit agreements 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 or reduce our debt.  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.

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.

We may be unable to access the equity or debt capital markets to meet our obligations.

Lower crude oil, NGLs and natural gas prices will adversely affect our cash flow and may lead to further reductions in the borrowing base, which could also lead to reduced prospects for alternate credit availability.  The capital markets we have historically accessed as an alternative source of equity and debt capital may be constrained.  Other capital sources may arise with significantly different terms and conditions. Certain investors may exclude oil and gas companies from their investing portfolios due to environmental, social and governance factors.  These limitations in the capital markets may affect our ability to grow and limit our ability to replace our reserves of oil and gas. 

Our plans for growth may include accessing the equity and debt capital markets.  If those markets are unavailable, or if we are unable to access alternative means of financing on acceptable terms, we may be unable to implement all of our drilling and development plans, make acquisitions or otherwise carry out our business strategy, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

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.

As of December 31, 2019, we had $730.0 million principal amount of secured indebtedness outstanding.  If in the future we default on any of our secured debt, we cannot provide assurance that the proceeds from the sale of the collateral will be sufficient to repay all of our secured debt in full.  In addition, we have certain rights to issue or incur additional secured debt, including up to $139.2 million as of December 31, 2019, available for borrowing under our Credit Agreement, that would be secured by additional liens on the collateral and 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 any sale of the collateral are not sufficient to repay all amounts due in respect of our secured 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.

The collateral securing the various issues of our secured debt has not been appraised.  The value of the collateral at any time will depend on market and other economic conditions, including the availability of suitable buyers for the collateral.  The value of the assets pledged as collateral for our secured debt could be impaired in the future as a result of changing economic conditions, commodity prices, competition or other future trends.  Likewise, we cannot provide assurance that the pledged assets will be saleable or, if saleable, that there will not be substantial delays in their liquidation.  In addition, to the extent that third parties hold prior liens, such third parties may have rights and remedies with respect to the property subject to such liens that, if exercised, could adversely affect the value of the collateral securing our secured debt.

With respect to some of the collateral securing our secured 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.  We cannot provide assurance that any such required consents, fee payments or filings can be obtained on a timely basis or at all.  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.  Therefore, the practical aspect of realizing value from the collateral may, without the appropriate consents, fees and filings, be limited.

We may be unable to provide the financial assurancesin the amounts and under the time periods required by the BOEM if the BOEM submits future demands to cover our decommissioning obligations.  If in the future the BOEM issues orders to provide additional financial assurances and we fail to comply with such future orders, the BOEM could elect to take actions that would materially adversely impact our operations and our properties, including commencing proceedings to suspend our operations or cancel our federal offshore leases.

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 on the OCS.  As of the filing date of this Form 10-K, we are in compliance with our financial assurance obligations to the BOEM and have no outstanding BOEM orders, requests or financial assurance obligations.  The BOEM, however, could in the future make demands for additional financial assurances covering our obligations under our properties, which could exceed the Company’s capabilities to provide.  If the BOEM issues future orders to provide additional surety bonds or other additional financial assurances to cover these obligations and we fail to comply with such future orders, the BOEM could commence enforcement proceedings or take other remedial action, 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.

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, including the arrangements entered into in connection with our acquisition of the Mobile Bay Properties, 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.  If additional collateral is required to support surety bond obligations, this collateral would probably 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.   See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources under Part II, Item 7 in this Form 10-K for additional information.

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

Accounting rules applicable to us require that we review the carrying value of our oil and natural gas properties quarterly for possible impairment.  Impairment of proved properties under our full cost oil and gas accounting method is largely driven by the present value ofLower future net revenues of proved reserves estimated using the SEC mandated 12-month unweighted first-day-of-the-month commodity prices.  In addition to commodity prices, impairment assessments of proved properties include the evaluation of development plans, production data, economics and other factors.  Such write-downs associated with impairments would constitute a non-cash charge to earnings.  We experienced impairment write-downs of our oil and gas properties in 2016 and 2015 primarily as a result of oil and natural gas price declines, but did not incur any write-downs during 2019, 2018 or 2017.  If prices fall significantly below current levels, this may cause write-downs during 2020 or in future periods.  In addition, lower crude 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.

No assurance can be given that we will not experience additionalUnder the full cost method of accounting for oil and gas producing activities, a ceiling test impairments in future periods, which couldis performed at the end of each quarter to determine if our oil and gas properties have a material adverse effect on our results of operations in the periods taken.  Also, no assurance can be given that commodity price decreases will not affect our reserve volumes.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview and Critical Accounting Policies – Impairmentbeen impaired. Capitalized costs of oil and natural gas properties under Part II, Item 7 and Financial Statements and Supplementary Data – Note 1 – Significant Accounting Policies under Part II, Item 8 in this Form 10-K for additional information are generally limited to the present value of future net revenues of proved reserves based on the ceiling test.

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

Current SEC guidance requires that proved undeveloped reserves (“PUDs”) may only be classified as such if a development plan has been adopted indicating that they are reasonably certain to be drilled within five yearsaverage price of the 12-month period prior to the ending date of booking.  This rule may limit our potential to book additional PUDs as we pursue our drilling program.  If current prices decline, we also may be compelled to postponeeach quarterly assessment using the drillingunweighted arithmetic average of PUDs until prices recover.  If we postpone drilling of PUDs beyond this five-year development horizon, we may have to write off reserves previously recognized as proved undeveloped.  In addition, if we are unable to demonstrate funding sourcesthe first-day-of-the-month price for our development plan with reasonable certainty, we may have to write-off all or a portioneach month within such period. Impairments of our PUDs.

Our PUDs comprised 15% of our total proved reserves as of December 31, 2019 and require additional expenditures and/or activities to convert these into producing reserves.  As circumstances change, we cannot provide assurance that all future expenditures will be made and that activities will be entirely successful in converting these reserves into proved producing reserves or PUDs during the time periods we have planned, at the costs we have budgeted, which could result in the write-off of previously recognized proved reserves.  We are the operator for substantially all of our PUDs as of December 31, 2019.  In the future, however, we could have more of our PUDs in non-operated fields, which may put us in a position of not being able to control the timing of development activities for the non-operated fields.

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.  Our failure to replace those proved reserves would result in decreasing proved reserves, production and cash flows over time.

Unless we conduct successful development and exploration activities at sufficient levels or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced.  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 due to the difference in rules related to booking proved undeveloped reserves between conventional and unconventional basins.  Our independent petroleum consultant estimates that 35% of our total proved reserves 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.  We may not be able to develop, find or acquire additional proved reserves in sufficient quantities to sustain our current production levels or to grow production beyond current levels.  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. 

Significant capital expenditures are required to replace our reserves.  If we are not able to obtain new oil and gas leases or replace reserves, we will not be ableproperties are more likely to sustain production at current levels, which may have a material adverse effect on our business, financial condition, or resultsoccur during prolonged periods 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.  Unless we replace the reserves we produce through successful exploration, development or acquisition activities, our proved reserves and production will decline over time.  Our exploration, development and acquisition activities require substantial capital expenditures.  Historically, we have funded our capital expenditures and acquisitions with cash on hand, cash provided by operating activities, securities offerings and bank borrowings.  The capital markets we have historically accessed may be constrained because of our leverage and we believe our access to capital markets may be limited in the future.  Excluding acquisitions, our capital expenditures in 2019 were higher than the amount spent in 2018.  The higher end of our capital expenditure budget range for 2020 is substantially the same as the amount spent in 2019, excluding acquisitions.  Future cash flows are subject to a number of variables, such as the level of production from existing wells, the prices ofdepressed crude 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.  These limitations in the capital markets and our current capital budget may adversely affect our production levels.  We cannot be certain that financing for future capital expenditures will be available if needed, and to the extent required, on acceptable terms.  For additional financing risks, see “–Risks Relating to Our Industry, Our Business and Our Financial Condition.”

Additional deepwater drilling laws, regulations and other restrictions, delays in the processing and approval of drilling permits and exploration, development, oil spill-response and decommissioning plans, 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.

In recent years, our drilling efforts have included deepwater projects in the Gulf of Mexico.  The BSEE and the BOEM have over time imposed new and more stringent permitting procedures, safety regulations and environmental regulations for wells in the deepwater of federal waters.  Compliance with these regulatory requirements, and together with uncertainties or inconsistencies in decisions and rulings by governmental agencies, have impacted the manner in whichpricing. While we have conducted our business in the past.  Examplesnot recorded an impairment of areas where these stringent regulations have affected operations include new or amended measures for obtaining approval of drilling permits, exploration plans, development plans, oil spill-response submissions and decommissioning plans.  These stringent regulations, and possible additional regulatory initiatives, could result in increased cost to our development efforts and ongoing business operations.

Moreover, the trend in the United States over the past decade has been for these governmental agencies to continue to evaluate and, as necessary, develop and implement new, more restrictive requirements, although in recent years under the Trump Administration, there have been actions seeking to mitigate certain of those more rigorous standards.  For example, in 2016, the BSEE under the Obama Administration published a final rule on well control that, among other things, imposed rigorous standards relating to the design, operation and maintenance of blow-out preventers, real-time monitoring of deepwater and high temperature, high pressure drilling activities, and enhanced reporting requirements.  Pursuant to certain executive orders issued by President Trump in 2017, however, the BSEE initiated a review of the well control rule and other offshore rules and initiatives to determine whether they are consistent with the stated policy of encouraging energy exploration and production, while ensuring that any such activity is safe and environmentally responsible.  One consequence of this review is that in May 2019, the BSEE published final revisions to the existing 2016 rule on well control that, among other things, eliminated the requirement for a BSEE-approved verification organization to oversee third parties which provide certifications of certain critical well control functions.  Another consequence of this BSEE review was an indefinite delay in implementation of NTL #2016-N01 that, if implemented, could result in significant increases in financial assurances for our operating on the OCS.  There exists the possibility that certain of these recent mitigatory actions under the Trump Administration could be withdrawn or revised in the future as a result of litigation or by a different presidential administration to impose or re-implement more stringent standards.  Moreover, due primarily to the threat of climate change arising from GHG emissions, certain candidates seeking the office of President of the United States in 2020 have pledged to take actions to ban new mineral leases on federal properties, including offshore leases on the OCS.  Additionally, litigation risks are also increasing, as a number of cities and other local governments have sought to bring suit against the largest oil and natural gas exploration and production 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 by failing to adequately disclose those impacts.

These regulatory actions, or any new rules, regulations, or legal initiatives or controls, whether under the Trump Administration or another administration, that impose increased costs or 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, fines, or 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, may from time to time 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.

Losses and liabilities from uninsured or underinsured drilling and operating activities could have a material adverse effect on our financial condition and operations.

We are and could be exposed to uninsured losses in the future. We currently carry multiple layers of insurance coverage in our Energy Package (defined as certain insurance policies relating to our oil and gas properties during the year-ended December 31, 2022, any further decreases in commodity pricing could cause an impairment, which include named windstorm coverage) covering our operating activities, with higher limits of coverage for higher valued properties and wells.  The current policy limits for well control range from $30.0 millionwould result in a non-cash charge 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 all of our higher valued properties, and a $150.0 million aggregate limit for all of our other properties, subject to a retention of $30.0 million. Included within the $162.5 million aggregate limit is total loss only (“TLO”) coverage on our Mahogany platform, which has no retention.earnings.

The occurrence of a significant accident or other event not covered in whole or in part by our insurance could have a material adverse impact on our financial condition and operations.  Our insurance does not protect us against all operational risks.  We do not carry business interruption insurance.  In May and June 2019, we entered into our insurance policies covering well control and hurricane damage (described above) and for general liability and pollution.  These policies are effective for one year from their respective execution date.  These policies reduce, but in no way totally mitigate our risk as we are exposed to amounts for retention and co-insurance, limits on coverage and events that are not insured.  Renewal of these policies at a cost commensurate with current premiums is not assured.  We also have other smaller per-occurrence retention amounts for various other events.  In addition, pollution and environmental risks are generally not fully insurable, as gradual seepage and pollution are not covered under our policies.  Because third-party drilling contractors are used to drill our wells, we may not realize the full benefit of workmen’s compensation laws in dealing with their employees.

OPA requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill.  We are currently required to demonstrate, on an annual basis, that we have ready access to $150.0 million that can be used to respond to an oil spill from our facilities on the OCS.  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.  We cannot predict at this time whether OPA will be amended, or whether the level of financial responsibility required for companies operating on the OCS will be increased. In any event, if an oil discharge or substantial threat of discharge were to occur, we may be liable for costs and damages, which costs and liabilities could be material to our results of operations and financial position.

For some risks, we have not obtained insurance as we believe the cost of available insurance is excessive relative to the risks presented.  We may take on further risks in the future if we believe the cost is excessive to the risks.  The occurrence of a significant event not fully insured or indemnified against losses could have a material adverse effect on our financial condition and results of operations.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Hurricane Remediation, Insurance Claimsand Insurance Coverage under Part II, Item 7 in this Form 10-K for additional information on insurance coverage.

Insurance for well control and hurricane damage may become significantly more expensive for less coverage and some losses currently covered by insurance may not be covered in the future.

In the past, hurricanes in the Gulf of Mexico have caused catastrophic losses and property damage.  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 hurricane damage, major oil spills or other events.

In the future, our insurers may not continue to offer what we view as reasonable coverage, or our costs may increase substantially as a result of increased premiums.  There could be an increased risk of uninsured losses that may have been previously insured.  We are also exposed to the possibility that in the future we will be unable to buy insurance at any price or that if we do have claims, the insurance companies will not pay our claims.  The occurrence of any or all of these possibilities could have a material adverse effect on our financial condition and results of operations.

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 as required under our Credit Agreement, we periodicallymay continue to enter, into oil and natural gas price commodity derivative positions with respect to a portion of our expected future production. During the fourth quarter of 2019, we entered intoSee Financial Statements and Supplementary Data– Note 10 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K for additional information on our derivative contracts for natural gas, which expire in December 2022 and crude oil derivative contracts, which expire in December 2020.  During the fourth quarter of 2018, we entered into commodity derivative contracts for crude oil, which will expire in May 2020.transactions. We may enter into more derivative contracts in the future. While these commodity derivative positions are intended to reduce the effects of volatile crude oil and natural gas prices,price volatility, they may also limit future income if crude 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: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.

See Financial Statements and Supplementary Data– Note 10 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K for additional information on derivative transactions. 

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 forto acquire productive oil and natural gas properties and exploratory prospects than we are able or willing to pay or finance. On the acquisition opportunities made available to us, we competeFinally, companies with other companies in our industry for such properties through a private bidding process, direct negotiations or some combination thereof.  Our competitorslarger financial resources may have significantly more capital resources and less expensive sourcesa significant advantage in terms of capital.  In addition, they may be able to generate acceptable rates of return from marginal prospects due to their lower costs of capital.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.  The availability of properties for acquisition depends largely on the divesting practices of other

Market conditions or operational impediments may hinder our access to oil and natural gas companies, commodity prices, general economicmarkets 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 factors we cannot controlthird-party actions. If any of these third-party pipelines become partially or influence.  Additional requirements imposed on usfully unavailable to transport crude oil and natural gas, or if the gas quality specification for the natural gas pipelines changes so as to restrict our ability to financetransport 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 acquisitionsoil 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, 2022, three fields, accounting for approximately 0.2 MMBoe (or 1.2%) of our 2022 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 putbe 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. 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.

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 competitive disadvantagefaster 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 26.3% of our total proved reserves as of December 31, 2022 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 acquiring properties.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.

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Losses and liabilities from uninsured or underinsured drilling and operating activities could have a material adverse effect on our financial condition and operations.

We are and could be exposed to uninsured losses in the future. We currently carry multiple layers of insurance coverage in our Energy Package (defined as certain insurance policies relating to our oil and gas properties which include named windstorm coverage) covering our operating activities, with higher limits of coverage for higher valued properties and wells. Our insurance does not protect us against all operational risks. We do not carry business interruption insurance. Pollution and environmental risks are generally not fully insurable, as gradual seepage and pollution are not covered under our policies. Because third-party drilling contractors are used to drill our wells, we may not realize the full benefit of workmen’s compensation laws in dealing with their employees.

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.

For some risks, we have not obtained insurance as we believe the cost of available insurance is excessive relative to the risks presented. We reevaluate 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 not fully insured or indemnified against losses 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.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. DeepwaterIn addition, due to the significant time requirements involved with exploration and development costs can be significantly higher than development costsactivities, particularly for wells drilled onin the conventional shelf because deepwater drilling requires larger installation equipment, sophisticated sea flooror wells not located near existing infrastructure, actual oil and natural gas production handling equipment, expensive state-of-the-art platforms and infrastructure investments.  Deep shelf development can also be more expensive than conventional shelf projects because deep shelf development requires more drilling days and higher drilling and service costs due to extreme pressure and temperatures associated with greater depths.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 2022 financial condition or results of operations, and we currently do not expect them to materially impact our 2023 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.

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.

Our business involves many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

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. Environmental hazards include oil spills, gas leaks, pipeline ruptures or discharges of toxic gases. 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.

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.

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Insurance for well control and hurricane damage may become significantly more expensive for less coverage and some losses currently covered by insurance may not be covered in the future.

In the past, tropical storms and hurricanes in the Gulf of Mexico have caused catastrophic losses and property damage. 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.

In the future, our insurers may not continue to offer what we view as reasonable coverage, or our costs may increase substantially as a result of increased premiums. There could be an increased risk of uninsured losses that may have been previously insured. We are also exposed to the possibility that in the future we will be unable to buy insurance at any price or that if we do have claims, the insurance companies will not pay our claims. The occurrence of any or all of these possibilities could have a material adverse effect on our financial condition and results of operations.

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, 2022.

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 crude 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, crude 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.

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.

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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 crude 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.

A pandemic, such as the COVID-19 pandemic, may have an adverse effect on our business, liquidity, results of operations and financial condition.

The COVID-19 pandemic has resulted in periodic disruptions in demand for oil and gas commodities as various jurisdictions have attempted to implement or have implemented measures designed to contain the spread of the virus. Ongoing pandemics may have related economic repercussions that could adversely impact our business, results of operations, financial condition and cash flows. Our supply chain could be disrupted if our vendors have limited access to their facilities or labor shortages adversely affecting the price or availability of products, which could result in a loss of revenue and profitability. While demand for and prices for oil, NGLs and gas generally improved during 2022 as travel restrictions, business closures and other restrictions were lifted, an increase in infections or the onset of a new variant of the virus could again reduce demand for and prices of oil, NGLs and gas. Persistently weak or additional declines in commodity prices could adversely affect the economics of our existing operations and planned future operations. If our customers also face liquidity challenges, we could experience delays or defaults in customer payments, and we may incur increased exposure to credit risk and bad debts. Further, workforce availability may be impaired due to exposure to the pandemic, reluctance to comply with governmental, legal or contractual mandates, or other restrictions, which may adversely impact our employees’ wellness and employee retention, productivity and culture, which could negatively affect our costs and profitability or negatively impact our ability to operate at full capacity and reduce our revenue.

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 recent 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.

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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 owns a significant portion of our common stock. 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 may adversely affect the trading price of our common stock because investors may perceive disadvantages in owning shares in companies with significant stockholder concentrations.

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, 2022, we had 9.75% Senior Second Lien Notes due 2023 (the “9.75% Senior Second Lien Notes”) and a term loan of certain of our subsidiaries that is non-recourse to the Company (the “Term Loan”). We have no borrowings outstanding on our revolving credit facility under our Credit Agreement, which lending commitment and final maturity is set to expire on January 3, 2024. On February 8, 2023, we redeemed all of the outstanding $552.5 million 9.75% Senior Second Lien Notes using cash on hand and the net proceeds from the offering of the $275.0 million 11.75% Senior Second Lien Notes, which notes mature on February 1, 2026 (the “11.75% Senior Second Lien Notes”).

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 lenders’ review of crude oil, NGLs and natural gas prices, our proved reserves and other criteria. Lower crude 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).

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% Senior Second Lien 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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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% Senior Second Lien Notes are secured by various liens on our oil, natural gas and NGL properties, excluding our Mobile Bay assets. Our 11.75% Senior Second Lien Notes are secured by a second priority lien on substantially all of such properties. The oil and 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% Senior Second Lien Notes. In addition, we have certain rights to issue or incur additional or new secured debt, that could be secured by additional liens on the collateral and 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% Senior Second Lien 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% Senior Second Lien Notes upon a change of control.

If we experience certain kinds of changes of control, we must give holders of the 11.75% Senior Second Lien 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 the Calculus Lending facility or other agreements we may enter into in the future may prevent us from applying funds to repurchase the 11.75% Senior Second Lien 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.

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.

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Legal and Regulatory Risks

The Biden Administration may pursue significant regulatory and political actions that could adversely affect our results of operations, and our ability to implement our business strategy.

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. 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 and the Biden Administration may continue pursuing actions that delay or refuse approval of new leases for hydrocarbon exploration and development on federal lands and waters or delay or fail to grant approvals required for development of existing leases on such lands and waters. See Part I, Item 1, Business – Compliance with Governmental Regulations for more discussion on orders and regulatory initiatives impacting the oil and natural gas industry pursued under the Biden Administration. To the extent that our operations in federal waters are restricted, delayed for varying lengths of time or cancelled, such developments could have a material adverse effect on our results of operations, our ability to replace reserves and the ability to implement our business strategy.

Environmental regulations and liabilities, including those related to climate change, may increase our costs and adversely affect our business.

Our operations are subject to U.S. federal, state and local and foreign environmental laws and regulations governing the protection of the environment and health and safety that impose limitations on the discharge of pollutants into the environment and establish standards for the treatment, storage, recycling and disposal of toxic and hazardous wastes. The nature of our business requires that we use, store and dispose of materials that are subject to environmental regulation. 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 at the time or in accordance with industry standards. Additionally, 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:

In certain instances, citizen groups also have the ability to bring legal proceedings against us regarding our compliance with certain environmental laws, or to challenge our ability to receive permits that we need to operate.

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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. In addition, in September 2021, President Biden publicly announced the Global Methane Pledge, a pact that aims to reduce global methane emissions at least 30% below 2020 levels by 2030. Since its formal launch at the United Nations Climate Change Conference (COP26), over 150 countries have joined the pledge. COP26 concluded with the finalization of 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 27th conference of parties, President Biden announced the Environmental Protection Agency’s (“EPA”) proposed standards to reduce methane emissions from existing oil and gas sources, and agreed, in conjunction with the European Union and a number of other partner countries, to develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. Additionally, in August 2022, President Biden signed into law the Inflation Reduction Act of 2022 (the “IRA”). Among other things, the IRA includes a methane emissions reduction program. Additionally, while the pause on new oil and natural gas leases on public lands and offshore waters has been lifted subject to certain limitations, the impacts of these and other future orders or legislation or regulation remain unclear at this time and could have an impact on our customers, and in turn have negative effect on our business, financial conditions, results of operations, and cash flows.

Further, on March 21, 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, information about the registrant’s governance of climate-related risks and relevant risk management processes; climate-related risks that are reasonably likely to have a material impact on the registrant’s business, results of operations, or financial condition and their actual and likely climate-related impacts on the registrant’s business strategy, model, and outlook; climate-related targets, goals and transition plan (if any); certain climate-related financial statement metrics in a note to their audited financial statements; Scope 1 and Scope 2 GHG emissions; and Scope 3 GHG emissions and intensity, if material, or if the registrant has set a GHG emissions reduction target, goal or plan that includes Scope 3 GHG emissions. 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.

Additional changes in environmental laws, regulations, guidelines or enforcement interpretations, including relating to the emission of carbon dioxide and other greenhouse gases or climate change-related concerns, 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 costs of compliance and doing business for our customers and thereby decrease the demand for our services. Because our business depends on the level of activity in the offshore oil and gas industry, existing or future laws, regulations, guidelines, enforcement interpretations, treaties or international agreements related to greenhouse gases and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our business and ability to execute our business strategy, including if such laws, regulations, treaties or international agreements reduce the worldwide demand for oil and gas or limit drilling opportunities.

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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. If in the future the BOEM issues orders to provide additional financial assurances and we fail to comply with such future orders, the BOEM could elect to take actions that would materially adversely impact our operations and our properties, including commencing proceedings to suspend our operations or cancel our federal offshore leases.

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 on the OCS. As of December 31, 2022, we are in compliance with our financial assurance obligations to the BOEM and have no outstanding BOEM orders, requests or financial assurance obligations. BOEM under the Obama and Trump Administrations had sought to implement varying levels of stringent and costly standards under the existing federal financial assurance requirements, either through issuance and implementation of NTL #2016-N01 as was the case under the Obama Administration, or proposing rulemaking to revise the decommissioning and related financial assurance regulations as was the case under the Trump Administration. However, BOEM under the Biden Administration is expected to propose new financial assurance requirements that, if adopted as proposed, could increase our operating costs. See Part I, Item 1, Business – Compliance with Governmental Regulations for more discussion on financial assurance regulatory initiatives impacting the oil and natural gas industry that may be pursued under the Biden Administration. Additionally, 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 such future orders, BOEM could commence enforcement proceedings or take other remedial action, 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.

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.

In January 2021, President Biden suspended new oil and natural gas leases on federal lands and waters, including the OCS pending review and reconsideration of federal oil and gas leasing and permitting practices. While this suspension was challenged and enjoined in June 2021 by a federal district court, the Biden Administration is appealing the court decision. Additionally, regulatory agencies under the Biden Administration may issue new or amended rulemakings regarding deep water 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. The BSEE and the BOEM have over the past decade, primarily under the Obama Administration, imposed more stringent permitting procedures and regulatory safety and performance requirements with respect to new wells drilled in federal deepwater. While actions by BSEE or BOEM under the former Trump Administration sought to mitigate or delay certain of those more rigorous standards, the Biden Administration could reconsider rules and regulatory initiatives implemented under the Trump Administration and replace them with new, more stringent requirements and also provide more rigorous enforcement of existing regulatory requirements. Compliance with any added or more stringent Biden Administration regulatory requirements or enforcement initiatives and existing environmental and spill regulations, together with uncertainties or inconsistencies in decisions and rulings by governmental agencies and delays in the processing and approval of drilling permits and exploration, development, oil spill response and decommissioning plans and possible additional regulatory initiatives could result in difficult and more costly actions and 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 United States 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 or controls that impose increased costs or 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, fines, or 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 – Compliance with Governmental Regulations 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 are especially significant because our operations are concentrated in the Gulf of Mexico.

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. In December 2018,An existing BSEE issued an updated NTL reaffirmingdescribes the obligations of offshore operators to timely decommission idle iron by means of abandonment and removal. Pursuant to thethese idle iron NTL requirements, in September 2019, 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, with the earliest deadline being December 31, 2020.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 by BSEEin the future as idle iron, but we do not expect the costs to plug and abandon thesesuch 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.

Moreover, BSEE under the Biden Administration could also reconsider its current NTL on idle iron removal or existing idle iron-related regulations and establish new, more stringent decommissioning requirements on an expedited basis. 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 or increased 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. 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 will differ dramatically from our recorded estimate if we have a damaged platform.

TheAny additional requirements under the BOEM’s formerly issued NTL #2016-N01, if everit were re-issued and fully implemented, or in the event BOEM under the Biden Administration were to issue new, more stringent financial assurance guidance or requirements, would increase our operating costs and reduce the availability of surety bonds due to the increased demands for such bonds in a low-price commodity environment.  While the current implementation timeline has been extended indefinitely, except in certain circumstances where there was a substantial risk of nonperformance of the interest holder’s decommissioning liabilities, this timeline could change at the BOEM’s discretion and the BOEM may re-issue liability orders in the future, including if it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities.  Under NTL #2016-N01, the BOEM has given broader interpretation authority to the BOEM’s district personnel, which increases the difficulty in complying with this NTL should it be fully implemented. In addition, increased demand for salvage contractors and equipment could result in increased costs for decommissioning activities, including plugging and abandonment operations. These items have, and may further, increase our costs and may impact our liquidity adversely.

We may be obligated to pay costs related to other companies that have filed for bankruptcy or have indicated they are unable to pay their shareTable of costs in joint ownership arrangements.Contents

In our contractual arrangements of joint ownership of oil and natural gas interests with other companies, we are obligated to pay our share of operating, capital and decommissioning costs, and have the right to a share of revenues after royalties and certain other cash inflows.  If one of the companies in the arrangement is unable to pay its agreed upon share of costs, generally the other companies in the arrangement are obligated to pay the non-paying company’s obligations.  Under joint operating agreements among working interest owners, the non-paying company would typically lose the right to future revenues, which would be applied to the non-paying company’s share of operating, capital and decommissioning costs.  If future revenues are insufficient to defray these additional costs, especially in cases where the well has stopped producing and is being decommissioned, we could be obligated to pay certain costs of the defaulting party.  In addition, the liability to the U.S. Government for obligationsimposes strict joint and several liability under the OCSLA on the various lessees of lessees undera federal oil and gas leases,lease for lease obligations, including obligations for decommissioning costs, is generally joint and several among the various co-owners of the lease,activities, which means that any single ownerco-lessee may be liable to the U.S. Government for the full amount of all of the multiple lessees’ obligations under the lease. In certain circumstances, we also could be liable for accrued decommissioning liabilities on federal oil and gas leases that we previously owned and assigned to an unrelated third party should the assignee to whom we assigned the leases or any future assignee of those leases is bankrupt or unable to payperform its decommissioning costs.obligations (including payment of costs incurred by unrelated parties in decommissioning such lease facilities). For example, we have in the past received a demand for payment of decommissioning costs related to accrued liabilities for property interests that were sold several years prior. These indirect obligations would affect our costs, operating profits and cash flows negatively and could be substantial.material.

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.  The success and timing of exploration and development activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:

Our business involves many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

Our development activities may be unsuccessful for many reasons, including adverse weather conditions, cost overruns, equipment shortages, geological issues, technical difficulties and mechanical difficulties.  Moreover, the successful drilling of a natural gas or oil well does not assure us that we will realize a profit on our investment.  A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economical. In addition to their costs, unsuccessful wells hinder our efforts to replace reserves.

Our oil and natural gas exploration and production activities, including well stimulation and completion activities, involve a variety of operating risks, including:

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. We could also incur substantial losses as a result of:

Offshore operations are also subject to a variety of operating risks related to the marine environment, such as capsizing, collisions and damage or loss from tropical storms, hurricanes or other adverse weather conditions.  These conditions can cause substantial damage to facilities and interrupt production.  Companies that incur environmental liabilities frequently also confront third-party claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment from a polluted site.  Despite the “petroleum exclusion” of Section 101(14) of CERCLA, which currently encompasses crude oil and natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may have strict joint and several liability under CERCLA or similar state statues for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

Legislation has been proposed from time to time in Congress that would revoke or alter the current exclusion of exploration, development and production wastes from the RCRA definition of “hazardous wastes.”  A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could potentially subject such wastes to more stringent handling, disposal and cleanup requirements.  Other wastes handled at exploration and production sites or generated in the course of providing well services also may not fall within the RCRA oil and gas wastes exclusion.  Stricter standards for waste handling, disposal and cleanup may be imposed on the oil and natural gas industry in the future.  Additionally, NORM may contaminate minerals extraction and processing equipment used in the oil and natural gas industry.  We may have liability for releases of hazardous substances at our properties by prior owners, operators, other third parties, or at properties we have sold.  As a result, we could incur substantial liabilities that could reduce or eliminate funds available for exploration, development and acquisitions or result in the loss of property and equipment.

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.

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:

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.  For example, during 2019, net production of approximately 2.1 MMBoe was deferred during 2019 due to pipeline issues, maintenance and well issues.  During 2018, net production of approximately 1.6 MMBoe was deferred during 2018 due to pipeline issues, maintenance, well issues and other events; and during 2017, net production of approximately 1.7 MMBoe was deferred due to Hurricane Nate, pipeline issues and other events.

Properties that we acquire may not produce as projected and we may be unable to immediately identify liabilities associated with these properties or obtain protection from sellers of such properties.

Our business strategy includes growing by making acquisitions, which may include acquisitions of exploration and production companies, producing properties and undeveloped leasehold interests.  Our acquisition of oil and natural gas properties requires assessments of many factors that are inherently inexact and may be inaccurate, including the following:

Our assessment of the acquired properties will not reveal all existing or potential problems, nor will it permit us to become familiar enough with the properties to fully assess their capabilities and deficiencies.  In the course of our due diligence, we have historically not physically inspected every well, platform or pipeline.  Even if we had physically inspected each of these, our inspections may not have revealed structural and environmental problems, such as pipeline corrosion, well bore issues or groundwater contamination.  We may not be able to obtain contractual indemnities from the seller for liabilities associated with such risks.  We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

We may encounter difficulties integrating the operations of newly acquired oil and natural gas properties or businesses.

Increasing our reserve base through acquisitions has historically been an important part of our business strategy.  We may encounter difficulties integrating the operations of newly acquired oil and natural gas properties or businesses, such as our recent acquisition of the Mobile Bay Properties.  In particular, we may face significant challenges in consolidating functions and integrating procedures, personnel and operations in an effective manner.  The failure to successfully integrate such properties or businesses into our business may adversely affect our business and results of operations.  Any acquisition we make may involve numerous risks, including:

Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or be in different geographic locations than our existing properties.  To the extent that we acquire properties substantially different from the properties in our primary operating region or acquire properties that require different technical expertise, we may not be able to realize the economic benefits of these acquisitions as efficiently as with acquisitions within our primary operating region.  We may not be successful in addressing these risks or any other problems encountered in connection with any acquisition we may make.

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.

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, 2019.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies – Oil and natural gas reserve quantities, under Part II, Item 7 for a discussion of the estimates and assumptions about our estimated oil and natural gas reserves information reported in Business under Part I, Item 1, Properties under Part I, Item 2 and Financial Statements and Supplementary Data – Note 20 – Supplemental Oil and Gas Disclosures under Part II, Item 8 in this Form 10-K.

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 crude 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, crude 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.

You should not assume that 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.

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.  There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling and completion costs or to be economically viable.  The use of seismic data and other technologies and the study of producing fields in the same area 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.  We cannot assure that the analysis we perform using data from other wells, more fully explored prospects and/or producing fields will accurately predict the characteristics and potential reserves associated with our drilling prospects.  Sustained low crude oil, NGLs and natural gas pricing will 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.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

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 most cases are owned and operated by third parties.  Our failure to obtain such services on acceptable terms could materially harm our business.  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 or gathering system capacity.  If that were to occur, then we would be unable to realize revenue from those wells until arrangements were made to deliver our production to market.  We have, in the past, been required to shut in wells when hurricanes have caused or threatened damage to pipelines and gathering stations.  For example, we shut in wells during 2017 from Hurricane Nate and in 2018 from Hurricane Michael for several days.

In some cases, our wells are tied back to platforms owned by third-parties who do not have an economic interest in our wells and we cannot be assured that such parties will continue to process our oil and natural gas.

Currently, 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 hurricanes which could reduce or eliminate our ability to market our production.  As of December 31, 2019, six fields, accounting for approximately 0.9 MMBoe (or 6.2%) of our 2019 production, are tied back to separate, third-party owned platforms.  There can be no assurance that the owners of such platforms will continue to process our oil and natural gas production.  If any of these platform operators ceases to operate their processing equipment, we may be required to shut in the associated wells, construct additional facilities or assume additional liability to reestablish production.

If third-party pipelines connected to our facilities become partially or fully unavailable to transport our crude oil and natural gas or if the prices charged by these third-party pipelines increase, our revenues or costs could be adversely affected.

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 crude 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.  For example, in 2019 and 2018, various pipelines were shut down at various times causing production deferral of approximately 0.5 MMBoe and 0.4 MMBoe, respectively.

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.

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 crude 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.  We may be required to make large and unanticipated capital expenditures to comply with governmental regulations, such as:

Under these laws and regulations, we could be liable for:

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 on the way we can discharge 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.

We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. It is also possible that a portion of our oil and natural gas properties could be subject to eminent domain proceedings or other government takings for which we may not be adequately compensated. See Business – RegulationCompliance with Government Regulations under Part I, Item 1 in this Form 10-K for a more detailed explanation of regulations impacting our business.

Our operations may incur substantial liabilities to comply with environmental laws and regulations as well as legal requirements applicable to MPAs and endangered and threatened species.

Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations:

Failure to comply with these laws and regulations may result in:

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Under these environmental laws and regulations, we could incur strict joint and several liability for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination

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and regardless of whether our operations met previous standards in the industry at the time they were conducted. Our permits require that we report any incidents that cause or could cause environmental damages.

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 could 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 – Compliance with Environmental Regulations under Part I, Item 1 in this Form 10-K for a more detailed description of our environmental, marine species, and endangered and threatened species regulations.

The ONRR’s revised interpretations on determining appropriate allowances related to transportation and processing costs for natural gas could cause us to pay substantial amounts in back royalties and in future royalties.

The ONRR has publicly announced an “unbundling” initiative to revise the methodology employed by producers in determining the appropriate allowances for transportation and processing costs that are permitted to be deducted in determining royalties under federal oil and gas leases.  The ONRR’s initiative requires re-computing allowable transportation and processing costs using revised guidance from the ONRR going back 84 months for every gas processing plant for which we had gas processed.  In 2015, pursuantResponses to the initiative, the Company received requests from the ONRR for additional data regarding the Company’s transportation and processing allowances on natural gas production that was processed through a specific processing plant.  The Company also received a preliminary determination notice from the ONRR asserting its preliminary determination that the Company’s allocationthreat of certain processing costs and plant fuel use at another processing plant were impermissibly allowed as deductions in the determination of royalties owed under federal oil and gas leases.  The Company has submitted responses covering certain plants and certain time periods and has not yet received responses as to the preliminary determination asserting the reasonableness of its revised allocation methodology of such costs.  These open ONRR unbundling reviews, and any further similar reviews, could ultimately result in an order for payment of additional royalties under the Company’s Federal oil and gas leases for current and prior periods.  Through December 31, 2019, we paid $3.1 million of additional royalties and expect to pay more in the future.  We are not able to determine the range of any additional royalties or if such amounts would be material.

Should we fail to comply with all applicable FERC, CFTC and FTC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the Energy Policy Act of 2005, FERC has civil penalty authority under the NGA and NGPA to impose penalties for current violations of up to $1.2 million per day for each violation and disgorgement of profits associated with any violation.  While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements.  We also must comply with the anti-market manipulation rules enforced by FERC.  Under the Commodity Exchange Act and regulations promulgated thereunder by the CFTC and under the Energy Independence and Security Act of 2007 and regulations promulgated thereunder by the FERC, the CFTC and FTC have adopted anti-market manipulation rules relating to the prices or futures of commodities.  Additional rules and legislation pertaining to those and other matters may be considered or adopted by Congress, the FERC, the CFTC or the FTC from time to time.  Failure to comply with those regulations in the future could subject us to civil penalty liability.  See Business – Regulation under Part I, Item 1 in this Form 10-K for further description of our regulations.

Our operations are subject to various risks thatclimate change, including energy transition, could result in increasing operatingincreased costs limiting the areas in which oil and natural gas production may occur, and reducingreduced demand for the oil and natural gas that we produce.produce, which could have a material adverse effect on our business, results of operations, financial condition and cash flows while physical risks related to climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

ClimateThe threat of climate change continues to attract considerable public, governmentalattention in the United States and scientific attention.foreign countries. As a result, numerous proposals have been made and couldare likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHG.  These efforts have included considerationGHGs as well as to eliminate such future emissions. Accordingly, our operations are subject to a series of cap-and-trade programs, carbon taxes, GHG reportingclimate-related transition risks, including regulatory, political and tracking programs,litigation and regulations that directly limit GHG emissions from certain sources.  Atfinancial risks associated with the federal level,production and processing of fossil fuels and emission of GHGs. See Part I, Item 1. “Business – Compliance with Environmental Regulations” for more discussion on the U.S. Congress has from time to time consideredthreat of climate change and restriction of GHG emissions.

The adoption and implementation of any international, federal, regional or state legislation, but no comprehensive climate change legislation has been adopted.  The EPA, however, has adoptedexecutive actions, regulations, under the existing CAA to restrict emissions of GHG.  For example, the EPA imposes preconstruction and operating permit requirements on certain large stationary sourcespolicies or other regulatory initiatives that are already potential sources of certain other significant pollutant emissions.  The EPA also adopted rules requiring the monitoring and reporting ofimpose more stringent standards for GHG emissions on an annual basis from specified large GHG emission sourcesour operations or in the United States, including onshore and offshoreareas where we produce oil and natural gas production facilities.  Federal agencies have also begun directly regulating emissions of methane, a GHG, from oil and natural gas operations as described above.  Compliance with these rules could result in increased compliance costs on our operations.

State implementation of these revised air emission standards could result in stricter permitting requirements, delay, limit or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant.  Atconsuming fossil fuels, and thereby reduce demand for the international level, there exists the United Nations-sponsored “Paris Agreement,” which is a non-binding agreement for nations to limit their GHG emissions through individually determined reduction goals every five years after 2020, although the United States has announced its withdrawal from such agreement, effective November 4, 2020.

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in federal political risks in the United States in the form of pledges made by certain candidates seeking the office of the President of the United States in 2020.  Critical declarations made by one or more presidential candidates include proposals to ban hydraulic fracturing of oil and natural gas wells and ban new leases for production of minerals on federal properties, including onshore lands and offshore waters.  Other actionsthat we produce. Additionally, litigation risks to oil and natural gas production activities that could be pursued by presidential candidates may include more restrictive requirements for the establishment of pipeline infrastructure or the permitting of liquefied natural gas export facilities, as well as the rescission of the United States’ withdrawal from the Paris Agreement in November 2020.  Litigation riskscompanies are also increasing, as a number of cities, local governments and other plaintiffs have sought to bring suit against oil and natural gas exploration and production 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.

Increasing attention 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. Further, 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. Moreover, the increased competitiveness of alternative energy sources (such as wind, solar geothermal, tidal and biofuels) could reduce demand for the oil and natural gas we produce, which would lead to a reduction in our revenues.

There are also increasing financial risks for fossil fuel producers asFor example, 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 fuelfossil-fuel energy companies also have become more attentive to sustainable lending practices that favor “clean” power sources, such as wind and solar, making those sources more attractive, and some of them may elect not to provide funding for fossil fuel energy companies. Additionally, the lending practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in nature, by environmental activists, proponentsMany of the international Paris Agreement,largest U.S. banks have made “net zero” carbon emission commitments and foreign citizenry concerned abouthave announced that they will be assessing financed emissions across their portfolios and are taking steps to quantify and reduce those emissions. These and other developments in the financial sector could lead to some lenders and investors restricting

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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.

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, not to provide funding for fossil fuel producers.  Limitation of investments inprioritize sustainable energy practices, reduce our carbon footprint and financings for fossil fuel energy companiespromote sustainability while at the same time remaining a successfully operating public company. Responses to such pressure could result in the restriction, delay or cancellation of drilling programs or development or production activities.

The adoption of legislation or regulatory programs to reduce or eliminate future emissions of GHG couldadversely impact our business by distracting management and other personnel from their primary responsibilities, require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances and/or comply with new regulatory or reporting requirements.  Any such legislation or regulatory programsresult in reputational harm. Moreover, if we do not successfully manage expectations across these varied stakeholder interests, it could also increase the cost of consuming,erode stakeholder trust and thereby reduceaffect our brand and reputation. Such erosion of confidence could negatively impact our business through decreased demand for, the oil and natural gas we produce.  Consequently, legislationgrowth opportunities, delays in projects, increased legal action and regulatory programsoversight, 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 reducecapital.

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 eliminate future emissionsour customers and to the diversion of GHGinvestment to other industries, which could have an adverse effecta negative impact on our business, financial conditionunit price and/or our access to and resultscosts of operations.  Additionally, political, financialcapital.

In addition, the Company’s continuing efforts to research, establish, accomplish and litigationaccurately 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 result inbe 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 restrictingcurrent ESG governance structure may not allow us to adequately identify or canceling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing the abilitymanage ESG-related risks and opportunities, which may include failing to continue to operate in an economic manner.  Finally, it should be noted that someachieve ESG-related strategies and goals.

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.  Our offshore operations are particularly at risk from severe climatic events. If any such climate 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 business, financial conditionassets and results of operations. See – Our business involves many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses. – under this Item 1A.

Derivatives legislation could have an adverse effect on our ability to use derivative instrumentsmitigate the adverse physical impacts of climate change depends in part upon our disaster preparedness and response and business continuity planning. Due to reduce the effectconcentrated nature of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Act, among other things, establishes federal oversight and regulationportfolio of properties, a number of our properties could experience any of the over-the-counter derivatives market and entities, such as us, that participatesame conditions at the same time, resulting in that market.  The CFTC has finalized most of its regulations under the Dodd-Frank Act, but others remain to be finalized or implemented.  It is not possible to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules or the timing of such effects.

The CFTC has designated certain types of swaps (thus far, only certain interest rate swaps and credit default swaps) for mandatory clearing and exchange trading, and may designate other types of swaps for mandatory clearing and exchange trading in the future.  To the extent we engage in such transactions or transactions that become subject to such rules in the future, we will be required to comply with or to take steps to qualify for an exemption to such requirements.  Although we are availing ourselves of the end-user exception to the mandatory clearing and exchange trading requirements for swaps designed to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging.  If any of our swaps do not qualify for the commercial end-user exception, or if the cost of entering into uncleared swaps becomes prohibitive, we may be required to clear such transactions or execute thema relatively greater impact on a derivatives contract or swap facility market.  In addition, certain banking regulators and the CFTC have adopted final rules establishing minimum margin requirements for uncleared swaps.  Although we expect to qualify for the end-user exception from margin requirements for swaps to other market participants, such as swap dealers, these rules may change the cost and availability of the swaps we use for hedging.  If any of our swaps do not qualify for the commercial end-user exception, we could be required to post initial or variation margin, which would impact our liquidity and reduce our cash. This would in turn reduce our ability to execute hedges to reduce risk and protect cash flows.

The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter and reduce our ability to monetize or restructure our existing commodity price contracts.  If we reduce our use of commodity price contracts as a result of the legislation and regulations, our results of operations than they might have on other companies that have a more diversified portfolio of properties.

Each of these developments may become more volatile and our cash flows may be less predictable, which couldin the future adversely affect our ability to planthe demand for products manufactured with, or powered by, petroleum products, as well as the demand for, and fund capital expenditures and make cash distributions to our unitholders.  Further, toin turn the extent our revenues are unhedged, they could be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices.

Our operations could be adversely impacted by security breaches, including cyber-security breaches, which could affect our productionprices of, oil and natural gas products. Additionally, political, financial and litigation risks may result in us having to restrict, delay or could affect other partscancel production activities, incur liability for infrastructure damages as a result of our business.

We rely on our information technology infrastructure and management information systemsclimatic changes, or impair the ability to continue 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, 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 breacheseconomic manner, which could have a material adverse effect on our consolidatedbusiness, financial condition, results of operations and cash flows.

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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.

From time to time, 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.

The loss of membersUnanticipated changes in effective tax rates or adverse outcomes resulting from examination of our senior managementincome or other tax returns could adversely affect us.our financial condition and results of operations.

ToWe 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 large extent, we depend onnumber of factors, including changes in the servicesvaluation of our senior management.  The lossdeferred tax assets and liabilities, expected timing and amount of the servicesrelease of any tax valuation allowances, or changes in tax laws, regulations, or interpretations thereof. In addition, we may be subject to audits of our senior management, including Tracy W. Krohn, our Founder, Chairman of the Board, Chief Executive Officerincome, sales, and President; Janet Yang, our Executive Vice Presidentother transaction taxes by U.S. federal, state, and Chief Financial Officer; William J. Williford, our Executive Vice President and General Manager of Gulf of Mexico; Stephen L. Schroeder, our Senior Vice President and Chief Technical Officer; and Shahid A. Ghauri, our Vice President, General Counsel and Corporate Secretary,local taxing authorities. Outcomes from these audits could have a negative impactan adverse effect on our financial condition and results of operations.  We do not maintain

Our articles of incorporation and bylaws, as well as Texas law, contain provisions that could discourage acquisition bids or plan to obtain formerger proposals, which may adversely affect the benefit of the Company any insurance against the loss of any of these individuals.  See Executive Officers of the Registrant under Part I following Item 3 in this Form 10-K for more information regarding our senior management team.

Counterparty credit risk may negatively impact the conversionmarket price of our accounts receivables to cash.common stock.

Substantially allCertain provisions of our accounts receivable result from crude oil, NGLsarticles of incorporation and natural gas sales or joint interest billingsbylaws 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:

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Further, we are incorporated in Texas. The Texas Business Organizations Code contains certain provisions that could make an acquisition by a third parties in the energy industry.  This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by any adverse changes in economic or other conditions.  In recent years, market conditions resulted in downgrades to credit ratings of some of our oil and gas customers and joint interest partners.  While we have not experienced collection issues from our customers, we have experienced collection issues from several of our joint interest partners.party more difficult.

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ItemItem 1B. Unresolved Staff Comments

None

None.​

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.

Item 2. Properties

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 highhigher initial production rates relative to other domestic reservoirs. AtAs of December 31, 2019,2022, two of our fields located in the following two areas of operationsconventional shelf accounted for approximately 67%66.7% our proved reserves determined using quantities of proved net reserves on an energy equivalent basis.  “Shelf” refers to acreage under 500 feet of water. The following table provides information for these fields:

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Our Fields​

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On December 31, 2019, we had​

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The Mobile Bay Properties (as defined below) and Ship Shoal 349 (Mahogany) (as defined below) 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 calculated on an energy equivalent basis. These areas are the Mobile Bay Properties, which are offshore Alabama but also include the associated gas treatment plant located onshoreEach area of operation of major significance is described in Alabama, and the Ship Shoal 349 field (Mahogany) located on the conventional shelf in the Gulf of Mexico.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. Following are descriptions of these areas of operations:

Mobile Bay Properties

The recently acquired Mobile Bay Properties consistA-I LLC and all of its 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.  TheAlabama are referred to as the “Mobile Bay Properties.” In 2021, we consolidated the Fairway field area includes 16 Alabama state water lease blocks and four Federal OCS lease blocks.  These properties include seven major platforms and 27 flowing wells,into the Mobile Bay Properties in up to 50 feet of water.  Exxon first discovered Norphlet gas play in 1978conjunction with the firstsale of the Mobile Bay Properties to the Subsidiary Borrowers as described in Financial Statements and Supplementary Data – Note 4 – Subsidiary Borrowers under Part II, Item 8 in this Form 10-K.

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We acquired our initial 64.3% working interest, along with operatorship, in the Fairway field and associated Yellowhammer gas productionprocessing plant, from Shell Offshore, Inc. in August 2011 and acquired the Mary Ann Fieldremaining working interest of 35.7% in 1988.  WeSeptember 2014. In August 2019, we acquired varied operated working interests in the other Mobile Bay Properties ranging from 25% to 100% in nine producing fields from Exxon effective(effective January 1, 2019,2019), and we became the operator of the fields in December 2019.  Cumulative field production through 2019 is approximately 576.6 MMBoe gross.  The Mobile Bay Properties produce from the Jurassic age Norphlet eolian sandstone at an average depth of 21,000’ total vertical depth.  As of December 31, 2019, 56 Norphlet wells have been drilled on the Mobile Bay Properties, 45 wells were successful and 27 wells are currently producing.  

We acquired the Mobile Bay Properties at the end of August 2019 and included the results of operations effective September 1, 2019 within our Consolidated Results of Operations. During September 2019 to December 2019, transitioning activities occurred to transfer operatorship of the Mobile Bay Properties from Exxon to W&T. GivenDuring 2020, we completed the limited historypurchase of the remaining interest in two federal Mobile Bay fields from Chevron U.S.A. Inc. Cumulative field production for the combined Mobile Bay and Fairway properties through 2022 is approximately 854.7 MMBoe gross. The Mobile Bay Properties produce from the change in operatorship, productionJurassic age Norphlet eolian sandstone at an average depth of 21,000 feet total vertical depth. As of December 31, 2022, 56 Norphlet wells have been drilled on the Mobile Bay Properties, 45 of which were successful and 27 of which are currently producing.

The following table presents our produced oil, NGLs and natural gas volumes realized prices received and production costs are omitted.(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.water (the “Ship Shoal 349”). Phillips Petroleum Company discovered the field in 1993.Ship Shoal 349. We initially acquired a 25% working interest in the field from BP Amoco in 1999. In 2003, we acquired an additional 34% working interest through a transaction with ConocoPhillips that increased our working interest to approximately 59%, and we became the operator of the field in December 2004. In early 2008, we acquired the remaining working interest from Apache Corporation (“Apache”) and we now own a 100% working interest in this field except for an interest in one well owned inby the Joint Venture Drilling Program. Cumulative field production through 20192022 is approximately 53.2approximately 61.4 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, 2019,2022, 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. During 2018, one well was completed which hadThere has been drilled to target depth during 2017, and in addition, two wells were drilled and completed during 2018.  Duringno drilling activity since 2019 one well was drilled, completed and producing in 2019, and significant workover activities were done to increase production.at Ship Shoal 349.

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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: