Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Form 10-K
☑
☐
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2023
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number 1-32414
W&T OFFSHORE, INC.
(Exact name of registrant as specified in its charter)
Texas
(State or other jurisdiction of incorporation or organization)
5718 Westheimer Road, Suite 700 Houston, Texas
(Address of principal executive offices)
72-1121985
(I.R.S. Employer Identification Number)
77057-5745
(Zip Code)
Registrant’s telephone number, including area code: (713) 626-8525
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Stock, par value $0.00001
Securities Registered pursuant to Section 12(g) of the Act: None
Trading Symbol(s)
WTI
Name of each exchange on which registered
New York Stock Exchange
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☑
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☑
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such
shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐
Indicate by check mark whether the registrant has submitted electronically every interactive data file required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during
the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions
of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Non-accelerated filer
☐
☐
Accelerated filer
Smaller reporting company
Emerging growth company
☑
☐
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards
provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under
Section 404(b) of Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to
previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers
during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☑
The aggregate market value of the registrant’s common stock held by non-affiliates was approximately $337,554,623 based on the closing sale price of $3.87 per share as reported by the New York
Stock Exchange on June 30, 2023.
The number of shares of the registrant’s common stock outstanding on February 29, 2024 was 146,857,277.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s Proxy Statement relating to the Annual Meeting of Shareholders, to be filed within 120 days of the end of the fiscal year covered by this report, are incorporated by
reference into Part III of this Form 10-K.
Table of Contents
W&T OFFSHORE, INC.
TABLE OF CONTENTS
Cautionary Statements Regarding Forward-Looking Statements
Summary of Risk Factors
Glossary
PART I
Item 1.
Item 1A.
Item 1B.
Item 1C.
Item 2.
Item 3.
Item 4.
PART II
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 9C.
PART III
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
PART IV
Item 15.
Item 16.
Signatures
Business
Risk Factors
Unresolved Staff Comments
Cybersecurity
Properties
Legal Proceedings
Mine Safety Disclosures
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
[Reserved]
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Quantitative and Qualitative Disclosures About Market Risk
Financial Statements and Supplementary Data
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Directors, Executive Officers and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Certain Relationships and Related Transactions, and Director Independence
Principal Accountant Fees and Services
Exhibits and Financial Statement Schedules
Form 10-K Summary
i
Page
ii
iv
vii
1
12
31
32
33
40
40
41
42
42
59
60
102
102
102
103
103
103
103
103
103
104
109
110
Table of Contents
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K (“Form 10-K”) contains forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All
statements, other than statements of historical fact included in this Form 10-K, regarding our strategy, future operations, financial position,
estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. These
forward-looking statements are based on certain assumptions and analyses made by us in light of our experience and perception of
historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances.
Although we believe that these forward-looking statements are based upon reasonable assumptions, they are subject to several risks and
uncertainties and are made in light of information currently available to us. If the risks or uncertainties materialize or the assumptions prove
incorrect, our results may differ materially from those expressed or implied by such forward-looking statements and assumptions.
Known material risks that may affect our financial condition and results of operations are discussed in Item 1A. Risk Factors, and
market risks are discussed in Item 7A. Quantitative and Qualitative Disclosures About Market Risk, of this Form 10-K and may be
discussed or updated from time to time in subsequent reports filed with the SEC.
When used in this Form 10-K, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “forecast,” “may,”
“objective,” “plan,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking
statements contain such identifying words. Readers are cautioned not to place undue reliance on forward-looking statements, which speak
only as of the date hereof. We assume no obligation, nor do we intend, to update these forward-looking statements, unless required by law.
Unless the context requires otherwise, references in this Form 10-K to “W&T”, “we,” “us,” “our” and the “Company” refer to W&T
Offshore, Inc. and its consolidated subsidiaries.
The information included in this Form 10-K includes forward-looking statements that involve risks and uncertainties that could
materially affect our expected results of operations, liquidity, cash flows and business prospects. Such statements specifically include our
expectations as to our future financial position, liquidity, cash flows, results of operations and business strategy, potential acquisition
opportunities, other plans and objectives for operations, capital for sustained production levels, expected production and operating costs,
reserves, hedging activities, capital expenditures, return of capital, improvement of recovery factors and other guidance. Actual results may
differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. For
any such forward-looking statement that includes a statement of the assumptions or bases underlying such forward-looking statement, we
caution that, while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases almost
always vary from actual results, sometimes materially.
Factors (but not necessarily all the factors) that could cause results to differ include, among others:
● the regulatory environment, including availability or timing of, and conditions imposed on, obtaining and/or maintaining permits
and approvals, including those necessary for drilling and/or development projects;
● the impact of current, pending and/or future laws and regulations, and of legislative and regulatory changes and other government
activities, including those related to permitting, drilling, completion, well stimulation, operation, maintenance or abandonment of
wells or facilities, managing energy, water, land, greenhouse gases or other emissions, protection of health, safety and the
environment, or transportation, marketing and sale of our products;
● inflation levels;
● global economic trends, geopolitical risks and general economic and industry conditions, such as the global supply chain
disruptions and the government interventions into the financial markets and economy in response to inflation levels and world
health events;
● volatility of oil, NGL and natural gas prices;
● the global energy future, including the factors and trends that are expected to shape it, such as concerns about climate change and
other air quality issues, the transition to a low-emission economy and the expected role of different energy sources;
ii
Table of Contents
● supply of and demand for oil, NGLs and natural gas, including due to the actions of foreign producers, importantly including
OPEC and other major oil producing companies (“OPEC+”) and change in OPEC+’s production levels;
● disruptions to, capacity constraints in, or other limitations on the pipeline systems that deliver our oil and natural gas and other
processing and transportation considerations;
● inability to generate sufficient cash flow from operations or to obtain adequate financing to fund capital expenditures, meet our
working capital requirements or fund planned investments;
● price fluctuations and availability of natural gas and electricity;
● our ability to use derivative instruments to manage commodity price risk;
● our ability to meet our planned drilling schedule, including due to our ability to obtain permits on a timely basis or at all, and to
successfully drill wells that produce oil and natural gas in commercially viable quantities;
● uncertainties associated with estimating proved reserves and related future cash flows;
● our ability to replace our reserves through exploration and development activities;
● drilling and production results, lower–than–expected production, reserves or resources from development projects or higher–than–
expected decline rates;
● our ability to obtain timely and available drilling and completion equipment and crew availability and access to necessary
resources for drilling, completing and operating wells;
● changes in tax laws;
● effects of competition;
● uncertainties and liabilities associated with acquired and divested assets;
● our ability to make acquisitions and successfully integrate any acquired businesses;
● asset impairments from commodity price declines;
● large or multiple customer defaults on contractual obligations, including defaults resulting from actual or potential insolvencies;
● geographical concentration of our operations;
● the creditworthiness and performance of our counterparties with respect to our hedges;
● impact of derivatives legislation affecting our ability to hedge;
● failure of risk management and ineffectiveness of internal controls;
● catastrophic events, including tropical storms, hurricanes, earthquakes, pandemics or other world health events;
● environmental risks and liabilities under U.S. federal, state, tribal and local laws and regulations (including remedial actions);
● potential liability resulting from pending or future litigation;
● our ability to recruit and/or retain key members of our senior management and key technical employees;
● information technology failures or cyberattacks; and
● governmental actions and political conditions, as well as the actions by other third parties that are beyond our control.
Reserve engineering is a process of estimating underground accumulations of oil, NGLs and natural gas that cannot be measured in an
exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost
assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of
estimates that were made previously. If significant, such revisions would change the schedule of any further production and our
development program. Accordingly, reserve estimates may differ significantly from the quantities of natural gas, oil and NGLs that are
ultimately recovered.
All forward-looking statements, expressed or implied, included in this Form 10-K are expressly qualified in their entirety by this
cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-
looking statements that we or persons acting on our behalf may issue.
iii
Table of Contents
The following is a summary of the principal risks described in more detail under Part I, Item 1A. Risk Factors, in this Form 10-K.
SUMMARY RISK FACTORS
Market and Competitive Risks
● Oil, NGL and natural gas prices can fluctuate widely due to a number of factors that are beyond our control. Depressed oil, NGL
and natural gas prices adversely affect our business, financial condition, cash flow, liquidity or results of operations and could
affect our ability to fund future capital expenditures needed to find and replace reserves, meet our financial commitments and to
implement our business strategy.
● If oil, NGL and natural gas prices decrease from their current levels, we may be required to further reduce the estimated volumes
and future value associated with our total proved reserves or record impairments to the carrying values of our oil and natural gas
properties.
● Commodity derivative positions may limit our potential gains.
● 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.
● Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production. The
marketability of our production depends mostly upon the availability, proximity, and capacity of oil and natural gas gathering
systems, pipelines and processing facilities, which in some cases are owned by third parties.
Operating Risks
● Relatively short production periods for our Gulf of Mexico properties based on proved reserves subject us to high reserve
replacement needs and require significant capital expenditures to replace our proved reserves at a faster rate than companies
whose proved reserves have longer production periods. If we are not able to obtain new oil and gas leases or replace reserves, we
will not be able to sustain production at current levels, which may have a material adverse effect on our business, financial
condition, or results of operations.
● We are not insured against all of the operating risks to which our business is exposed.
● 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.
● Continuing inflation and cost increases may 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.
● We are subject to numerous risks inherent to the exploration and production of oil and natural gas.
● 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.
● 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.
● 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.
● 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.
iv
Table of Contents
● We may not realize all of the anticipated benefits from our targeted acquisitions. Such acquisitions could expose us to potentially
significant liabilities, including plugging and abandonment and decommissioning liabilities.
● 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 have historically outsourced substantially all of our information technology infrastructure and the management and servicing
of such infrastructure to a limited number of third parties, which makes us more dependent upon such third parties and exposed to
related risks. We are in the process of transitioning substantially all of such infrastructure internally or to other service providers,
which subjects us to increased costs and risks.
● The loss of members of our senior management could adversely affect us.
● There may be circumstances in which the interests of significant stockholders could conflict with the interests of our other
stockholders.
Capital Risks
● 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.
● 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.
● We have significant capital needs, and our ability to access the capital and credit markets to raise capital or refinance our existing
indebtedness on favorable terms, including our 11.75% Notes and our Credit Agreement with Calculus, may be limited by
industry conditions and financial markets.
● 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 such debt.
● We may not be able to repurchase the 11.75% Senior Second Lien Notes upon a change of control.
● 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.
Legal, Government and Regulatory Risks
● We are subject to numerous environmental, health and safety regulations which are subject to change and may also result in
material liabilities and costs.
● 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.
● We may be limited in our ability to maintain or recognize additional proved undeveloped reserves under current SEC guidance.
● 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.
● Our estimates of future ARO may vary significantly from period to period, and unanticipated decommissioning costs could
materially adversely affect our future financial position and results of operations.
v
Table of Contents
● We are subject to numerous laws and regulations that can adversely affect the cost, manner or feasibility of doing business.
● We are subject to laws, rules, regulations and policies regarding data privacy and security. Many of these laws and regulations are
subject to change and reinterpretation, and could result in claims, changes to our business practices, monetary penalties, increased
cost of operations or other harm to our business.
● The Inflation Reduction Act of 2022 could accelerate the transition to a low-carbon economy and could impose new costs on our
operations.
● We are subject to risks arising from climate change, including risks related to energy transition, which could result in increased
costs and reduced demand for the oil and natural gas we produce and physical risks which could disrupt our production and cause
us to incur significant costs in preparing for or responding to those effects.
● Increasing attention to ESG matters may impact our business.
● 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.
● Unanticipated changes in effective tax rates or adverse outcomes resulting from examination of our income or other tax returns
could adversely affect our financial condition and results of operations.
● Our articles of incorporation and bylaws, as well as Texas law, contain provisions that could discourage acquisition bids or merger
proposals, which may adversely affect the market price of our common stock.
vi
Table of Contents
GLOSSARY
The following are abbreviations and definitions of certain terms used in this Annual Report on Form 10-K.
Bbl. One stock tank barrel or 42 United States gallons liquid volume.
Bcf. Billion cubic feet, typically used to describe the volume of natural gas.
Boe. Barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one barrel of oil or condensate.
Boe/d. Barrel of oil equivalent per day.
BOEM. Bureau of Ocean Energy Management.
BSEE. Bureau of Safety and Environmental Enforcement.
Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water one degree Fahrenheit.
Completion. The installation of permanent equipment for the production of oil or natural gas.
Conventional shelf. Water depths less than 500 feet.
Deep shelf. Water depths greater than 500 feet and less than 15,000 feet.
Deepwater. Water depths greater than 500 feet.
Development. The phase in which petroleum resources are brought to the status of economically producible by drilling developmental
wells and installing appropriate production systems.
Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known
to be productive.
Dry hole. A well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil
or natural gas well.
Economically producible. Refers to a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of
the operation.
Exploratory well. A well drilled to find a new reservoir in a field previously found to be productive of oil or natural gas in another
reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test
well.
Extension well. A well drilled to extend the limits of a known reservoir.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological
structural feature or stratigraphic condition.
GAAP. Accounting principles generally accepted in the United States of America.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
MBoe. One thousand barrels of oil equivalent.
Mcf. One thousand cubic feet, typically used to describe the volume of a gas.
vii
Table of Contents
MMBbls. One million barrels of crude oil or other liquid hydrocarbons.
MMBoe. One million barrels of oil equivalent.
MMBtu. One million British thermal units.
MMcf. One million cubic feet, typically used to describe the volume of a gas.
Natural gas. A combination of light hydrocarbons that, in average pressure and temperature conditions, are found in a gaseous state. In
nature, it is found in underground accumulations and may potentially be dissolved in oil or may also be found in a gaseous state.
Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.
NGLs. Natural gas liquids. Hydrocarbons which can be extracted from wet natural gas and become liquid under various combinations
of pressure and temperature. NGLs consist primarily of ethane, propane, butane and natural gasoline.
NYMEX. The New York Mercantile Exchange.
NYMEX Henry Hub. Henry Hub is the major exchange for pricing natural gas futures on the New York Mercantile Exchange.
Oil. Crude oil and condensate.
OCS. Outer continental shelf.
OCS block. A unit of defined area for purposes of management of offshore petroleum exploration and production by the BOEM.
ONRR. Office of Natural Resources Revenue. The agency performs the offshore royalty and revenue management functions of the
former Minerals Management Service.
OPEC+. Organization of Petroleum Exporting Countries and other state controlled companies.
Productive well. A well that is found to have economically producible hydrocarbons.
Proved developed reserves. Proved reserves of any category that can be expected to be recovered: (i) through existing wells with
existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new
well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by
means not involving a well. The SEC provides a complete definition of developed oil and gas reserves in Rule 4-10(a)(6) of Regulation S-
X.
Proved properties. Properties with proved reserves.
Proved reserves. Those quantities of oil, NGLs and natural gas, which, by analysis of geoscience and engineering data, can be
estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing
economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate
expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used
for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will
commence the project within a reasonable time. The SEC provides a complete definition of proved reserves in Rule 4-10(a)(22) of
Regulation S-X.
viii
Table of Contents
Proved undeveloped reserves (“PUDs”). Proved reserves of any category that are expected to be recovered from future wells on
undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. The SEC provides a complete
definition of undeveloped reserves in Rule 4-10(a)(31) of Regulation S-X.
PV-10. The present value of estimated future revenues, discounted at 10% annually, to be generated from the production of proved
reserves determined in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs
as of the date of the estimation without future escalation. PV-10 excludes cash flows for asset retirement obligations, general and
administrative expenses, derivatives, debt service and income taxes.
Recompletion. The completion for production of an existing well bore in another formation from that which the well has been
previously completed.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that
is confined by impermeable rock or water barriers and is individual and separate from other reserves.
SEC. The Securities and Exchange Commission.
SEC pricing. The unweighted average first-day-of-the-month commodity price for crude oil and natural gas for each month within the
twelve-month period preceding the reported period, adjusted by lease for market differentials (quality, transportation fees, energy content
and regional price differentials). The SEC provides a complete definition of pricing in “Modernization of Oil and Gas Reporting” (Final
Rule, Release Nos. 33-8995; 34-59192).
Unproved properties. Properties with no proved reserves.
WTI. West Texas Intermediate grade crude oil. A light crude oil produced in the United States with an American Petroleum Institute
gravity of approximately 38-40 and the sulfur content is approximately 0.3%.
ix
Table of Contents
ITEM 1. BUSINESS
PART I
W&T Offshore, Inc. is an independent oil and natural gas producer, active in the acquisition, exploration and development of oil and
natural gas properties in the Gulf of Mexico. W&T Offshore, Inc. is a Texas corporation originally organized as a Nevada corporation in
1988, and successor by merger to W&T Oil Properties, Inc., a Louisiana corporation organized in 1983.
Since our founding in 1983 by our Chairman and CEO, Tracy Krohn, we have continually grown our footprint in the Gulf of Mexico
through acquisitions, exploration and development. As of December 31, 2023 we held working interests in 53 offshore producing fields in
federal and state waters. Our acreage, well, production and reserves information are described in more detail under Part I, Item 2.
Properties, in this Form 10-K. Our working interests in fields, leases, structures and equipment are primarily owned by W&T
Offshore, Inc. and our wholly-owned subsidiaries, Aquasition LLC (“A-I LLC”), Aquasition II LLC (“A-II LLC”), and W&T Energy VI,
LLC, Delaware limited liability companies and through our proportionately consolidated interest in Monza Energy, LLC (“Monza”).
For the past four decades, we have developed significant technical expertise in finding and developing properties in the Gulf of Mexico
with existing production which provide the best opportunity to achieve a rapid return on our invested capital. We have successfully
discovered and produced properties on the conventional shelf and in the deepwater across the Gulf of Mexico.
Business Strategy
The Gulf of Mexico offers unique advantages, and we are uniquely positioned to create value with a diverse portfolio in valuable shelf,
deep shelf and deepwater projects. Our diverse portfolio of operations in the Gulf of Mexico enables stacked pay development, attractive
primary production, and recompletion opportunities. We use advanced seismic and geoscience tools to execute successful drilling projects.
In managing our business, we are focused on optimizing production and increasing reserves in a profitable and prudent manner, while
managing cash flows to meet our obligations and investment needs. Our goal is to pursue lower risk, high rate of return projects and
develop oil and natural gas resources that allow us to grow our production, reserves and cash flow in a capital efficient manner, and
organically enhance the value of our assets helping to ensure the long-term sustainability of our business.
We follow a proven and consistent business strategy:
● Focus on Free Cash Flow generation. Our strong production base and cost optimization has generated steady free cash flows. The
Gulf of Mexico is an area where we have developed significant technical expertise and where high production rates associated
with hydrocarbon deposits have historically provided us the best opportunity to achieve high rates of return on our invested
capital.
● Maintain high-quality conventional asset base with low decline. We generate incremental production from probable reserves and
possible reserves due to natural drive mechanisms. Typical fields with high-quality sands offer mechanisms superior to primary
depletion and they often enjoy incremental reserve adds annually. Fewer conventional wells are required to develop these fields.
While we continue to utilize proven techniques and technologies, we will also continuously seek efficiencies in our drilling,
completion and production techniques in order to optimize ultimate resource recoveries, rates of return and cash flows.
● Capitalize on unique and accretive acquisition opportunities. We strategically pursue the acquisition of compelling producing
assets that generate cash flows at attractive valuations with upside potential and optimization opportunities. We may also use our
capital flexibility to pursue value-enhancing, bolt-on acquisitions to opportunistically improve our positions in existing assets.
1
Table of Contents
● Reduce costs to improve margins. We grow in opportunistic ways as we manage our balance sheet prudently and reinvest free
cash flow. Our existing portfolio of 169 structures (108 of which we operate) provides a key advantage when evaluating and
developing prospect opportunities and serves to reduce capital expenditures and maximize our returns on capital expenditures.
● Preserve ample liquidity and maintain financial flexibility. By operating within our free cash flow, we are able to improve
liquidity and optimize our balance sheet.
● Manage environmental, social, and governance matters. With ultimate oversight by our board of directors, Environmental, Social
& Governance (“ESG”) matters are an integral part of our day-to-day operations and are incorporated into the strategic decision-
making process across our business. We have established a managerial ESG Task Force composed of cross-functional
management-level employees in Operations, Health, Safety, Environmental and Regulatory (“HSE&R”), Legal, Human
Resources and Finance. This task force is responsible for overseeing and managing our ESG reporting initiatives and suggesting
areas of focus to our executive management. Executive management in turn reports on those activities to the ESG Committee of
our board of directors. We strive to execute our business plan while simultaneously reducing our environmental footprint,
including emissions, potential spills and other impacts. With respect to social priorities, we maintain a company-wide diversity
training program and focus on promoting diversity and inclusion. Relating to governance, our fundamental policy is to conduct
our business with honesty and integrity in accordance with high legal and ethical standards. In 2023, we published our third
annual ESG report highlighting our performance and initiatives across ESG categories for the period of 2020 to 2022, which is not
incorporated into, and does not form a part of, this Form 10-K. Finally, ESG performance scores are a factor in determining
compensation for all management-level employees.
We intend to execute the following elements of our business strategy in order to achieve our strategic goals:
● Exploiting existing and acquired properties to add additional reserves and production;
● Exploring for reserves on our extensive acreage holdings and in other areas of the Gulf of Mexico;
● Acquiring reserves with substantial upside potential and additional leasehold acreage complementary to our existing acreage
position at attractive prices;
● Continuing to manage our balance sheet in a prudent manner and continuing our track record of financial flexibility in any
commodity price environment; and
● Carrying out our business strategy in a safe and socially responsible manner.
We continually monitor current and forecasted commodity prices to assess if changes to our plans are needed. Our significant inside
ownership ensures that executive management’s interests are highly aligned with those of our shareholders, thus incentivizing executive
management to maximize value and mitigate risk in executing our business strategy, generating shareholder value.
Competition
The oil and natural gas industry is highly competitive. We also face increasing indirect competition from alternative energy sources,
including wind, solar, and electric power. We currently operate in the Gulf of Mexico and compete for the acquisition of oil and natural gas
properties and lease sales primarily on the basis of price for such properties. We compete with numerous entities, including major domestic
and foreign oil companies, other independent oil and natural gas companies and individual producers and operators. Many of these
competitors are large, well-established companies that have financial and other resources substantially greater than ours and a greater
ability to provide the extensive regulatory financial assurances required for offshore properties. Our ability to acquire additional oil and
natural gas properties, acquire additional leases and to discover reserves in the future will depend upon our ability to evaluate and select
suitable properties, finance investments and consummate transactions in a highly competitive environment.
2
Table of Contents
Oil and Natural Gas Marketing and Delivery Commitments
The market for our oil, NGL and natural gas production depends on factors beyond our control, including the extent of domestic
production and imports of oil, NGLs and natural gas; the proximity and capacity of natural gas pipelines and other transportation facilities;
the demand for oil, NGLs and natural gas; the marketing of competitive fuels; and the effect of state and federal regulation. The oil and
natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and
individual consumers.
We sell our oil, NGLs and natural gas to third-party customers. The terms of sale under the majority of existing contracts are short-
term, usually one year or less in duration. The prices received for oil, NGL and natural gas sales are generally tied to monthly or daily
indices as quoted in industry publications.
We are not dependent upon, or contractually limited to, any one customer or small group of customers. In 2023, approximately 41% of
our revenues were received from BP Products North America and approximately 13% from Chevron-Texaco, with no other customer
comprising greater than 10% of our 2023 revenues. Given the commoditized nature of the products we produce and market and the location
of our production in the Gulf of Mexico, we believe the loss of any of the customers above would not result in a material adverse effect on
our ability to market future oil and natural gas production, as we believe that replacement customers could be obtained in a relatively short
period of time on terms, conditions, and pricing substantially similar to those currently existing.
Insurance Coverage
In accordance with industry practice, we maintain insurance coverage against some, but not all, of the operating risks to which our
business is exposed. In general, our current insurance policies cover risks incident to the operation of oil and natural gas wells, including,
but not limited to, personal injury or loss of life, severe damage to and destruction of property and equipment, pollution or other
environmental damage and the suspension of operations. We do not carry business interruption insurance.
Our general and excess liability policies, among others, provide for $300.0 million of coverage for bodily injury and property damage
liability, including coverage for liability claims resulting from seepage, pollution or contamination. Our Energy Package (defined as certain
insurance policies relating to our oil and natural gas properties, which include named windstorm coverage) contains multiple layers of
insurance coverage for our operating activities, with higher limits of coverage for higher valued properties and wells. Under the Energy
Package, the limits for well control range from $30.0 million to $500.0 million depending on the risk profile and contractual requirements.
With respect to coverage for named windstorms, we have a $162.5 million aggregate limit covering one of our higher valued properties,
and $150.0 million for all other properties subject to four region retentions ranging from $2.5 million to $12.5 million on the conventional
shelf properties and $10.0 million on the deepwater properties.
We believe that our coverage limits are sufficient and are consistent with our exposure; however, we cannot insure against all possible
losses. As a result, any damage or loss not covered by insurance could have a material adverse effect on our financial condition, results of
operations and cash flow.
We re-evaluate the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and natural
gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become
unavailable in the future or unavailable on terms that are economically acceptable. No assurance can be given that we will be able to insure
our business activities at the levels we desire because of either limited market availability or unfavorable economics (limited coverage for
the underlying cost).
Environmental, Health and Safety Matters and Government Regulations
Our operations are subject to complex and stringent federal, state and local laws and regulations that, among other things, govern the
issuance of permits to conduct exploration, drilling and production operations, the amounts and types of materials that may be released into
the environment and the discharge and disposal of waste materials and, to the extent waste materials are transported and disposed of in
onshore facilities, remediation of any releases of those waste materials from such facilities. The federal environmental laws and regulations
applicable to us and our operations include, among others, the following:
3
Table of Contents
● The Resource Conservation and Recovery Act, as amended, regulates the generation, transportation, storage, treatment and
disposal of non-hazardous and hazardous wastes and can require cleanup of hazardous waste disposal sites;
● The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, (“CERCLA”) and comparable state
laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are
considered to be responsible for the release of a “hazardous substance” into the environment;
● The Clean Air Act, as amended (the “CAA”), and comparable state and local requirements restrict the emission of air pollutants
from many sources through the imposition of air emission standards, construction and operating permitting programs and other
compliance requirements;
● The Clean Water Act, as amended, and analogous state laws, prohibit any discharge of pollutants, including spills and leaks of oil
and other substances, into waters of the United States, except in compliance with permits issued by federal and state governmental
agencies;
● The Oil Pollution Act of 1990, as amended (the “OPA”), holds owners and operators of offshore oil production or handling
facilities, including the lessee or permittee of the area where an offshore facility is located, strictly liable for the costs of removing
oil discharged into waters of the United States, including the OCS or adjoining shorelines, and for certain damages from such
spills;
● The Endangered Species Act, as amended, restricts activities that may affect federally identified endangered and threatened
species or their habitats;
● The Migratory Bird Treaty Act, as amended, implements various treaties and conventions between the United States and certain
other nations for the protection of migratory birds; and
● The National Environmental Policy Act, as amended, requires careful evaluation of the environmental impacts of oil and natural
gas production activities on federal lands.
In addition to the federal laws and regulations above, we are also subject to the requirements of the Occupational Safety and Health
Administration (“OSHA”) and comparable state statutes, where applicable. These laws and the implementing regulations strictly govern the
protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right-to-know
regulations under Title III of CERCLA and similar state statutes, where applicable, require that we organize and/or disclose information
about hazardous materials used or produced in our operations. Such laws and regulations also require us to ensure our workplaces meet
minimum safety standards and provide for compensation to employees injured as a result of our failure to meet these standards as well as
civil and/or criminal penalties in certain circumstances. We believe that we are in substantial compliance with all such existing laws and
regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material
adverse impact on our financial condition and results of operations.
Numerous governmental agencies issue rules and regulations to implement and enforce such laws, which are often costly to comply
with, and a failure to comply may result in substantial administrative, civil and criminal penalties; the imposition of investigatory, remedial
and corrective action obligations or the incurrence of capital expenditures; the occurrence of restrictions, delays or cancellations in the
permitting, or development or expansion of projects; and the issuance of orders enjoining some or all of our operations in affected areas.
We consider the costs of environmental compliance to be a necessary and manageable part of our business. However, based on policy and
regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to compliance with the protection
of the environment have increased over the years and may continue to increase. We cannot predict with any reasonable degree of certainty
our future exposure concerning such matters. See Item 1A. Risk Factors contained herein for further discussion of governmental regulation
and ongoing regulatory changes, including with respect to environmental matters.
4
Table of Contents
Other Regulation of the Oil and Natural Gas Industry
The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Rules and regulations
affecting the oil and natural gas industry are under consistent review for amendment or expansion, which could increase the regulatory
burden and the potential sanctions for noncompliance. Relatedly, numerous federal and state departments and agencies are authorized to
issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties
for failure to comply. Historically, our compliance with existing requirements has not had a material adverse effect on our financial
position, results of operations or cash flows. Because such laws and regulations are frequently amended or reinterpreted, we are unable to
predict the future cost or impact of complying with such laws. Although the regulatory burden on the oil and natural gas industry may
increase our cost of doing business, these burdens generally do not affect us any differently or to any greater or lesser extent than they
affect other companies in the industry with similar types, quantities and locations of production.
Our exploration and production are subject to various types of regulation at the federal, state and local levels. These types of regulation
include, but are not limited to, requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most
jurisdictions in which we operate also regulate one of more of the following:
● the location of wells;
● the method of drilling and casing wells;
● the plugging and abandonment of wells and, following cessation of operations, the removal or appropriate abandonment of all
production facilities, structures and pipelines; and
● the produced water and disposal of wastewater, drilling fluids and other liquids and solids utilized or produced in the drilling and
extraction process.
Our operations on federal oil and natural gas leases in the OCS waters of the Gulf of Mexico are subject to regulation by the BSEE, the
BOEM and the ONRR, all of which are agencies of the U.S. Department of the Interior (the “DOI”). The BSEE and the BOEM work to
ensure the development of energy and mineral resources on the OCS is done in a safe and environmentally and economically responsible
way. The ONRR performs the offshore royalty and revenue management functions of the former Minerals Management Service.
Leasing. The federal government cannot conduct offshore lease sales without the development and approval of a National Outer
Continental Shelf Oil and Gas Leasing Program (an “OCS Program”). The Outer Continental Shelf Lands Act (the “OCSLA”) authorizes
the Secretary of the Interior to establish a schedule of lease sales for a five-year period. There is no requirement under the OCSLA that
mandates any sales in any locations, nor does the law prescribe any specific timing for the development of the OCS Program. These leases
are awarded by the BOEM based on competitive bidding and contain relatively standardized terms. Prior to commencement of offshore
operations, lessees must obtain the BOEM’s approval for exploration, development and production plans. In addition to permits required
from other agencies such as the U.S. Environmental Protection Agency (the “EPA”), lessees must obtain a permit from the BSEE prior to
the commencement of drilling and comply with regulations governing, among other things, engineering and construction specifications for
production facilities, safety procedures, plugging and abandonment of wells on the OCS, calculation of royalty payments and the valuation
of production for this purpose, and decommissioning of facilities, structures and pipelines.
In January 2021, President Biden issued an executive order suspending new leasing activities for oil and natural gas exploration and
production on federal lands and offshore waters pending review and reconsideration of federal oil and natural gas permitting and leasing
practices. Lease Sale 257 was originally scheduled to be held in March 2021, but the decision to hold the sale was rescinded after the
issuance of the executive order. After a group of states challenged the executive order and a federal judge required the DOI to stop the
leasing pause, Lease Sale 257 was rescheduled and held in November 2021. In January 2022, the D.C. District Court vacated Lease Sale
257, ruling that it violated the National Environmental Policy Act. In August 2023, the D.C. Circuit Court of Appeals reversed the D.C.
District Court’s order vacating Lease Sale 257 and ruled the highest bidders would receive the leases auctioned in Lease Sale 257.
5
Table of Contents
In August 2022, Congress passed the Inflation Reduction Act (the “IRA”), which required the BOEM to offer at least two million acres
for oil and natural gas leasing in the OCS. The IRA required the DOI to move forward with Lease Sales 259 and 261 in the Gulf of Mexico.
Lease Sale 259 was held in March 2023, and Lease Sale 261 was held in December 2023. The IRA also raised the royalty rate for certain
offshore leases from the current 12.5% to 16.67% and capped the rate at 18.75% for ten years.
In November 2021, the DOI released its report on federal oil and natural gas leasing and permitting practices. The report included
recommendations in respect to the offshore sector, including adjusting royalty rates to ensure that the full value of leased tracts are
captured, strengthening financial assurance coverage amounts that are required by operators, and establishing “fitness to operate” criteria
that companies would need to meet in respect of safety, environmental and financial responsibilities in order to operate in the OCS.
In September 2023, consistent with the requirements of the IRA concerning offshore conventional and renewable energy leasing, the
DOI announced its proposed 2024 – 2029 OCS Program. The proposed OCS Program includes a maximum of three potential oil and
natural gas lease sales in the Gulf of Mexico scheduled in 2025, 2027 and 2029.
Decommissioning and financial assurance requirements. The BOEM requires that lessees demonstrate financial strength and reliability
according to its regulations and provide acceptable financial assurances to assure satisfaction of lease obligations, including
decommissioning activities in the OCS. Currently the BOEM requires all lessees of an OCS oil and natural gas lease to post base bonds
ranging from $50 thousand to $3.0 million in addition to supplemental financial assurance determined based on the lessee’s ability to carry
out present and future financial obligations. In June 2023, the BOEM proposed a new rule that updated the criteria for determining whether
oil and natural gas lessees may be required to provide supplemental financial assurance above the prescribed base financial assurance to
ensure compliance with the OCSLA. The rule proposes to consider an OCS lessee’s credit rating and proved oil reserves in determining
whether a lessee in the OCS is required to obtain supplemental financial assurance. A final rule is anticipated in April 2024. See Part II,
Item 8. Financial Statements and Supplementary Data —Note 17 — Commitments for more information on decommissioning and financial
assurance requirements.
Regulation and transportation of natural gas. Our sales of natural gas are affected by the availability, terms and cost of transportation.
The price and terms for access to pipeline transportation are subject to extensive regulation. The Federal Energy Regulatory Commission
(the “FERC”) has undertaken various initiatives to increase competition within the natural gas industry. As a result of initiatives like FERC
Order No. 636, issued in 1992, the interstate natural gas transportation and marketing system allows non-pipeline natural gas sellers,
including producers, to effectively compete with interstate pipelines for sales to local distribution companies and large industrial and
commercial customers. The most significant provisions of Order No. 636 require that interstate pipelines provide firm and interruptible
transportation service on an open access basis that is equal for all natural gas supplies. In many instances, the effect of Order No. 636 and
related initiatives have been to substantially reduce or eliminate the interstate pipelines’ traditional role as wholesalers of natural gas in
favor of providing only storage and transportation services. The rates for such storage and transportation services are subject to the FERC
ratemaking authority, and the FERC may apply cost-of-service principles or allow a pipeline to negotiate rates. Similarly, the natural gas
pipeline industry is subject to state regulations, which may change from time to time.
The OCSLA, which is administered by the BOEM and the FERC, requires that all pipelines operating on or across the OCS provide
open access, non-discriminatory transportation service. One of the FERC’s principal goals in carrying out the OCSLA’s mandate is to
increase transparency in the OCS market, to provide producers and shippers assurance of open access service on pipelines located on the
OCS, and to provide non-discriminatory rates and conditions of service on such pipelines. The BOEM issued a final rule, effective
August 2008, which implements a hotline, alternative dispute resolution procedures, and complaint procedures for resolving claims of
having been denied open and nondiscriminatory access to pipelines in the OCS.
6
Table of Contents
In 2007, the FERC issued rules (“Order 704”) requiring that any market participant, including a producer such as us, that engages in
wholesale sales or purchases of natural gas that equal or exceed 2.2 million MMBtus during a calendar year must annually report such sales
and purchases to the FERC to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the
responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704.
Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting
complies with the FERC’s policy statement on price reporting. These rules are intended to increase the transparency of the wholesale
natural gas markets and to assist the FERC in monitoring such markets and in detecting market manipulation.
Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC, state
legislatures, state commissions and the courts. The natural gas industry historically has been very heavily regulated. As a result, there is no
assurance that the less stringent regulatory approach pursued by the FERC, Congress and the states will continue.
While these federal and state regulations for the most part affect us only indirectly, they are intended to enhance competition in natural
gas markets. We cannot predict what further action the FERC, the BOEM or state regulators will take on these matters. However, we do not
believe that any such action taken will affect us differently, in any material way, than other natural gas producers with which we compete.
Oil and NGLs transportation rates. Other than as described above, our sales of liquids, which include oil, condensate and NGLs, are
not currently regulated and are transacted at market prices. In a number of instances, however, the ability to transport and sell such products
is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction. The price we receive from the sale
of oil and NGLs is affected by the cost of transporting those products to market. Interstate transportation rates for oil, condensate, NGLs
and other products are regulated by the FERC. In general, interstate oil, condensate and NGL pipeline rates must be cost-based, although
settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. The FERC has
established an indexing system for such transportation, which generally allows such pipelines to take an annual inflation-based rate
increase.
In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service
are subject to regulation by state regulatory bodies under state statutes and regulations. As it relates to intrastate oil, condensate and NGL
pipelines, state regulation is generally less rigorous than the federal regulation of interstate pipelines. State agencies have generally not
investigated or challenged existing or proposed rates in the absence of shipper complaints or protests, which are infrequent and are usually
resolved informally. We do not believe that the regulatory decisions or activities relating to interstate or intrastate oil, condensate or NGL
pipelines will affect us in a way that materially differs from the way they affect other oil, condensate and NGL producers or marketers.
Climate Change. The threat of climate change continues to attract considerable public, governmental and scientific attention in the
United States. President Biden has made addressing climate change, including the restriction or elimination of greenhouse gas (“GHG”)
emissions, a priority in his administration.
7
Table of Contents
The IRA includes a methane emissions reduction program that amends the CAA to include a Methane Emissions and Waste Reduction
Incentive Program for petroleum and natural gas systems by 2024. In July 2023, the EPA proposed to expand the scope of the Greenhouse
Gas Reporting Program for petroleum and natural gas facilities, as required by the IRA. Among other things, the proposed rule would
expand the emissions events that are subject to reporting requirements to include “other large release events” and apply reporting
requirements to certain new sources and sectors. The rule is expected to be finalized in the spring of 2024 and become effective on January
1, 2025, in advance of the deadline for GHG reporting for 2024 (March 2025). In January 2024, the EPA proposed a new rule implementing
the IRA’s methane emissions charge. The proposed rule includes potential methodologies for calculating the amount by which a facility’s
reported methane emissions are below or exceed the waste emissions thresholds and contemplates approaches for implementing certain
exemptions created by the IRA. The methane emissions charge imposed under the Methane Emissions and Waste Reduction Incentive
Program for 2024 would be $900 per ton emitted over annual methane emissions thresholds, and would increase to $1,200 in 2025, and
$1,500 in 2026. The implementation of revised air emission standards could result in stricter permitting requirements, which could delay,
limit or prohibit our ability to obtain such permits and result in increased compliance costs on our operations, including expenditures for
pollution control equipment, the costs of which could be significant.
In December 2023, the EPA announced new rules intended to reduce methane emissions from oil and natural gas sources. The final
rule strengthens the existing emissions reduction requirements in Subpart OOOOa, expands reduction requirements for new, modified and
reconstructed oil and natural gas sources in Subpart OOOOb, and imposes methane emissions limitations on existing oil and natural gas
sources nationwide for the first time. In addition, the final rule establishes “Emissions Guidelines,” creating a Subpart OOOOc that requires
states to develop plans to reduce methane emissions from existing sources which must be at least as effective as presumptive standards set
by the EPA. The final rule also creates a third-party monitoring program to flag large emissions events, referred to as “super emitters.”
Under Subparts OOOOb and OOOOc, the final rule establishes more stringent requirements for new, modified and reconstructed sources
“constructed” after December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later
compliance dates. The final rule gives states, along with federal tribes that wish to regulate existing sources, two years to develop and
submit their plans for reducing methane emissions from existing sources. The final Emissions Guidelines under Subpart OOOOc provide
three years from the plan submission deadline for existing sources to comply. The new rule is likely to increase costs and regulatory
burdens on the oil and natural gas industry, especially for smaller operators and operators of older oil and natural gas wells.
In March 2022, the SEC issued a proposed rule regarding the enhancement and standardization of mandatory climate-related
disclosures. The proposed rule would require registrants to include certain climate-related disclosures in their registration statements and
periodic reports, including, but not limited to:
● climate-related risks and their actual or likely material impacts on the registrant’s business, strategy, and outlook;
● the registrant’s governance of climate-related risks and relevant risk management processes;
● the registrant’s GHG emissions, which, for accelerated and large accelerated filers and with respect to certain emissions, would be
subject to assurance;
● certain climate-related financial statement metrics and related disclosures in a note to its audited financial statements; and
● information about climate-related targets and goals, and the registrant’s transition plan, if any.
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.
8
Table of Contents
In addition to the regulations discussed above, the OCSLA authorizes the DOI to regulate activities authorized by the BOEM in the
Central and Western Gulf of Mexico. The EPA retains jurisdiction over all other parts of the OCS. Under the OCSLA, the DOI is limited to
regulating offshore emissions of criteria pollutants and their precursor-pollutants to the extent they significantly affect the air quality of any
state. The BSEE conducts field inspections of emission sources installed on offshore platforms that have the potential to emit regulated air
pollutants. The BSEE also reviews BOEM-mandated monitoring and reporting of air emission sources for compliance with approved plan
emission limits. The BSEE may compel measures to control and bring into compliance those operations determined to be in violation of
applicable regulations or plan conditions by issuing Incidents of Noncompliance or recommending further enforcement action against
potential violators.
The threat of climate change also continues to attract considerable public, governmental and scientific attention in foreign countries.
Numerous proposals have been made at the international levels of government to monitor and limit emissions of GHG as well as to restrict
or eliminate future emissions. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and
tracking programs, policies and incentives to encourage the use of renewable energy or alternative low-carbon fuels and regulations that
directly limit GHG emissions from certain sources. In addition, there exist numerous conventions and non-binding commitments of
participating nations with goals of limiting their GHG emissions and fossil fuel subsidies. These include the United Nations-sponsored
Paris Agreement, which requires signatory countries to set voluntary, individually-determined reduction goals and the Glasgow Climate
Pact, which stated long-term global goals (including those in the Paris Agreement) to limit the increase in the global average temperature
and emphasized reductions in GHG emissions. Most recently, at the 28th Conference of the Parties (“COP28”), member countries entered
into an agreement that calls for actions toward achieving, at a global scale, a tripling of renewable energy capacity and doubling energy
efficiency improvements by 2030. The goals of the agreement include, among other things, accelerating efforts toward the phase-down of
unabated coal power, phasing out inefficient fossil fuel subsidies and other measures that drive the transition away from fossil fuels in
energy systems. In February 2021, the Biden administration rejoined the Paris Agreement. Pursuant to its obligations as a signatory to the
Paris Agreement, the United States has set a target to reduce its GHG emissions by 50% to 52% by the year 2030 as compared with 2005
levels and has agreed to provide periodic updates on its progress. Various state and local governments have also publicly committed to
furthering the goals of the Paris Agreement. In addition, in November 2021, the United States signed the Global Methane Pledge, a pact
that aims to reduce global methane emissions by at least 30% below 2020 levels by 2030.The impacts of these orders, pledges, agreements
and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, the Glasgow Climate
Pact and the COP28 agreement, or other international conventions cannot be predicted at this time.
Financial Information
We operate our business as a single segment. See Financial Statements and Supplementary Data under Part II, Item 8 in this Form 10-
K for our financial information.
Seasonality and Inflation
Seasonality. Generally, the demand for and price of natural gas increases during the winter months and decreases during the
summer months. However, these seasonal fluctuations are somewhat reduced because during the summer, pipeline companies, utilities,
local distribution companies and industrial users purchase and place into storage facilities a portion of their anticipated winter requirements
of natural gas. As utilities continue to switch from coal to natural gas, some of this seasonality has been reduced as natural gas is used for
both heating and cooling. In addition, the demand for oil is higher in the winter months, but does not fluctuate seasonally as much as
natural gas. Seasonal weather changes affect our operations. Tropical storms and hurricanes occur in the Gulf of Mexico during the summer
and fall, which can require us to evacuate personnel and shut in production until a storm subsides. Also, periodic storms during the winter
often impede our ability to safely load, unload and transport personnel and equipment, which can delay production and sales of our oil and
natural gas.
9
Table of Contents
Inflation. Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on
the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increases, while
during periods of commodity price declines, decreases in oilfield costs typically lag behind commodity price decreases. Continued
inflationary pressures and increased commodity prices may also result in increases to the costs of our oilfield goods, services and
personnel, which would in turn cause our capital expenditures and operating costs to rise.
The United States has experienced a rise in inflation since October 2021. Inflation peaked during mid-2022 at 9.1% but the rate of
inflation has been gradually declining since the second half of 2022 according to the Consumer Price Index (the “CPI”). The annual
inflation rate for December 2023 was 3.4%. These inflationary pressures have caused the Federal Reserve to tighten monetary policy by
approving a series of increases to the Federal Funds Rate. As of December 31, 2023, the Federal Reserve benchmark rate ranges from
5.25% to 5.50%. Although the Federal Reserve has stated that they will begin reducing the benchmark rate in 2024, if inflation were to
continue to rise, it is possible the Federal Reserve would continue to take action they deem necessary to bring inflation down and to ensure
price stability, including further rate increases, which could have the effects of raising the cost of capital and depressing economic growth,
either or both of which could negatively impact our business.
Human Capital Resources
As of December 31, 2023, we had 395 employees and employed an additional 326 individuals who are employees of third parties that
primarily provide skilled labor in support of our field operations. This combined workforce conducts our business in Texas, Alabama,
Louisiana and the Gulf of Mexico. Our workforce in Texas is primarily composed of our corporate employees, including our executive
officers, drilling and production managers, technical engineers and administrative and support staff. Our employees in Alabama, Louisiana
and the Gulf of Mexico are primarily composed of skilled labor who conduct our field operations and manage third-party personnel used in
support of our field operations.
We consider our employees to be our most valuable asset and believe that our success depends on our ability to attract, develop and
retain our employees. We strive to provide a work environment that attracts and retains the top talent in the industry, reflects our core
values and demonstrates these values to the communities in which we operate.
Diversity and Inclusion
We recognize that a diverse workforce provides the best opportunity to obtain unique perspectives, experiences and ideas to help our
business succeed, and we are committed to providing a diverse and inclusive workplace to attract and retain talented employees. The key to
our past and future successes is promoting a workforce culture that embraces integrity, honesty and transparency to those with whom we
interact, and fosters a trusting and respectful work environment that embraces changes and moves us forward in an innovative and positive
way. Our Code of Business Conduct and Ethics prohibits illegal discrimination or harassment of any kind.
Our policies and practices support diversity of thought, perspective, sexual orientation, gender, gender identity and expression, race,
ethnicity, culture and professional experience. From recent graduates to experienced hires, we seek to attract and develop top talent to
continue building a unique blend of cultures, backgrounds, skills and beliefs that mirror the world we live in. The tables below present, by
category of employee, the gender and ethnicity composition of our employees as of December 31, 2023:
Category
Exec/Sr. Manager
Mid-Level Manager
Professionals
All Other
Female
Male
17 %
27 %
37 %
8 %
83 %
73 %
63 %
92 %
10
Table of Contents
US Ethnicity
Asian
Black/African American
Hispanic/Latino
Two or more races
White
Safety, Health and Wellness
Exec/ Sr.
Manager
Mid-Level
Manager
Professionals
All Other
17 %
17 %
17 %
—
50 %
8 %
6 %
6 %
2 %
79 %
13 %
16 %
6 %
—
64 %
<1 %
5 %
6 %
<1 %
88 %
The success of our business is fundamentally connected to the well-being of our people. We are committed to the safety, health and
wellness of our employees.
Our highest priorities are the safety of all personnel and protection of the environment. We actively promote the highest standards of
safety behavior and environmental awareness and strive to meet or exceed all applicable local and natural regulations. To drive a culture of
personnel safety in our operations, we operate under a comprehensive Safety and Environmental Management System (“SEMS”). Our
2023 total recordable incident rate for employees was 0.25, which is far below the industry average for the Gulf of Mexico from 2022 of
0.88. Although incident reporting practices are subject to some subjectivity and vary by operator, we have historically had below average
incident rates compared to the industry average for the Gulf of Mexico, and we strive to continue to excel at protecting our personnel. Our
HSE&R group is comprised of a Vice President, Environmental, Safety and Regulatory Managers and 10 staff personnel. The group works
with field personnel to create and regularly review safety policies and procedures, in an effort to support continuous improvement of our
SEMS. Our board of directors reviews our material safety metrics on a quarterly basis. Safety and Environmental metrics are incorporated
into employee evaluations when determining compensation.
Benefits and Compensation
We pride ourselves on providing an attractive compensation and benefits program that allows our employees to view working at W&T
as more than where they work, but a place where they may grow and develop. Our ability to succeed depends on recruiting and retaining
top talent in the industry. We believe employees choose W&T in part due to our professional advancement opportunities, on the job
training, engaging culture and competitive compensation and benefits.
As part of our compensation philosophy, we believe we must offer and maintain market competitive total rewards programs in order to
attract and retain superior talent. These programs not only include base wages and incentives in support of our pay for performance culture,
but also health and retirement benefits. We focus many programs on employee wellness. We believe these solutions help the overall health
and wellness of our employees and help us successfully manage healthcare and prescription drug costs for our employee population.
Website Access to Company Reports
We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports and
amendments to those reports with the SEC. Our reports filed with the SEC are available free of charge to the general public through our
website at www.wtoffshore.com. These reports are accessible on our website as soon as reasonably practicable after being filed with, or
furnished to, the SEC. This Form 10-K and our other filings can also be obtained by contacting: Investor Relations, W&T Offshore, Inc.,
5718 Westheimer Road, Suite 700, Houston, Texas 77057 or by calling (713) 297-8024. Information on our website is not a part of this
Form 10-K.
11
Table of Contents
ITEM 1A. RISK FACTORS
In addition to risks and uncertainties in the ordinary course of business that are common to all businesses, important factors that are
specific to us and our industry could materially impact our future performance and results of operations. We have provided below a list of
known material risk factors that should be reviewed when considering buying or selling our securities. These are not all the risks we face,
and other factors currently considered immaterial or unknown to us may impact our future operations.
Market and Competitive Risks
Oil, NGL and natural gas prices can fluctuate widely due to a number of factors that are beyond our control. Depressed oil, NGL or
natural gas prices adversely affect our business, financial condition, cash flow, liquidity or results of operations and could affect our
ability to fund future capital expenditures needed to find and replace reserves, meet our financial commitments and to implement our
business strategy.
The price we receive for our oil, NGLs and natural gas production directly affects our revenues, profitability, access to capital, ability
to produce these commodities economically and future rate of growth. Historically, oil, NGLs and natural gas prices have been volatile and
subject to wide price fluctuations in response to domestic and global changes in supply and demand, economic and legal forces, events and
uncertainties, and numerous other factors beyond our control, including:
● changes in global supply and demand for oil, NGLs and natural gas;
● events that impact global market demand, such as a pandemic or other world health event;
● the actions of OPEC+;
● the price and quantity of imports of foreign oil, NGLs, natural gas and liquefied natural gas into the U.S.;
● acts of war, terrorism or political instability in oil producing countries (e.g. the invasion of Ukraine by Russia);
● domestic and foreign governmental regulations and taxes;
● U.S. federal, state and foreign government policies and regulations regarding current and future exploration and development of
oil and gas;
● political conditions and events, including embargoes and moratoriums, affecting oil-producing activities;
● the level of domestic and global oil and natural gas exploration and production activities;
● the level of global oil, NGLs and natural gas inventories;
● adverse weather conditions and exceptional weather conditions, including severe weather events in the U.S. Gulf Coast;
● technological advances affecting energy consumption and the availability and cost of alternative energy sources;
● the price, availability and acceptance of alternative fuels;
● speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;
● cyberattacks on our information infrastructure or systems controlling offshore equipment;
● activities by non-governmental organizations to restrict the exploration and production of oil and natural gas so as to minimize or
eliminate future emissions of carbon dioxide, methane gas and other GHGs;
● the effect of energy conservation efforts;
● the availability of pipeline and other transportation alternatives and third-party processing capacity; and
● geographic differences in pricing.
These factors and the volatility of the energy markets, which we expect to continue, make it extremely difficult to predict future
commodity prices with any certainty.
12
Table of Contents
If oil, NGL and natural gas prices decrease from their current levels, we may be required to further reduce the estimated volumes and
future value associated with our total proved reserves or record impairments to the carrying values of our oil and natural gas
properties.
Lower future oil, NGLs and natural gas prices may reduce our estimates of the proved reserve volumes that may be economically
recovered, which would reduce the total volumes and future value of our proved reserves. Under the full cost method of accounting for oil
and gas producing activities, a ceiling test is performed at the end of each quarter to determine if our oil and gas properties have been
impaired. Capitalized costs of oil and gas properties are generally limited to the present value of future net revenues of proved reserves
based on the average price of the 12-month period prior to the ending date of each quarterly assessment using the unweighted arithmetic
average of the first-day-of-the-month price for each month within such period. Impairments of our oil and gas properties are more likely to
occur during prolonged periods of depressed oil, NGLs and natural gas pricing. While we have not recorded an impairment of our oil and
gas properties during 2023, any further decreases in commodity pricing could cause an impairment, which would result in a non-cash
charge to earnings.
Commodity derivative positions may limit our potential gains.
In order to manage our exposure to price risk in the marketing of our oil and natural gas, we have entered, and may continue to enter,
into oil and natural gas price commodity derivative positions with respect to a portion of our expected future production. See Financial
Statements and Supplementary Data– Note 4 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K for additional
information on our derivative contracts and transactions. We may enter into more derivative contracts in the future. While these commodity
derivative positions are intended to reduce the effects of oil and natural gas price volatility, they may also limit future income if oil and
natural gas prices were to rise substantially over the price established by such positions. In addition, such transactions may expose us to the
risk of financial loss in certain circumstances, including instances in which there is a widening of price differentials between delivery
points for our production and the delivery points assumed in the hedge arrangements or the counterparties to the derivative contracts fail to
perform under the terms of the contracts.
Competition for oil and natural gas properties and prospects is intense; some of our competitors have larger financial, technical and
personnel resources that may give them an advantage in evaluating and obtaining properties and prospects.
We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil, NGLs and natural gas
and securing trained personnel. Many of our competitors have financial resources that allow them to obtain substantially greater technical
expertise and personnel than we have. We actively compete with other companies in our industry when acquiring new leases or oil and
natural gas properties. For example, new leases acquired from the BOEM are acquired through a “sealed bid” process and are generally
awarded to the highest bidder. Our competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects
than our financial or personnel resources permit. Our competitors may also be able to pay more to acquire productive oil and natural gas
properties and exploratory prospects than we are able or willing to pay or finance. Finally, companies with larger financial resources may
have a significant advantage in terms of meeting any potential new bonding requirements. If we are unable to compete successfully in these
areas in the future, our future revenues and growth may be diminished or restricted.
Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production. The
marketability of our production depends mostly upon the availability, proximity, and capacity of oil and natural gas gathering systems,
pipelines and processing facilities, which in some cases are owned by third parties.
Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and
natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number
of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our
ability to market our production depends substantially on the availability and capacity of gathering systems, pipelines and processing
facilities, which in some cases are owned and operated by third parties.
13
Table of Contents
We depend upon third-party pipelines that provide delivery options from our facilities. Because we do not own or operate these
pipelines, their continued operation is not within our control. These pipelines may become unavailable for a number of reasons, including
testing, maintenance, capacity constraints, accidents, government regulation, weather-related events or other third-party actions. If any of
these third-party pipelines become partially or fully unavailable to transport oil and natural gas, or if the gas quality specification for the
natural gas pipelines changes so as to restrict our ability to transport natural gas on those pipelines, our revenues could be adversely
affected.
A portion of our oil and natural gas is processed for sale on platforms owned by third parties with no economic interest in our wells
and no other processing facilities would be available to process such oil and natural gas without significant investment by us. In addition,
third-party platforms could be damaged or destroyed by tropical storms, hurricanes or other weather events, which could reduce or
eliminate our ability to market our production. As of December 31, 2023, three fields, accounting for approximately 0.2 MMBoe (or 1.4%)
of our 2023 production, are tied back to separate, third-party owned platforms. Although we have entered into contracts for the process of
our production with the owners of such platforms, there can be no assurance that the owners of such platforms will continue to process our
oil and natural gas production.
We may be required to shut in wells because of a reduction in demand for our production or because of inadequacy or unavailability of
pipelines, gathering system capacity or processing facilities. If that were to occur, then we would be unable to realize revenue from those
wells until arrangements were made to process or deliver our production to market. For example, the government recently issued an order
requiring the abandonment of certain facilities in the Gulf of Mexico, rendering the pipelines and other midstream assets that cross that
facility incapable of operating. Our production from certain properties currently utilizes a pipeline that crosses over the facility in order for
our production to reach its eventual market and, as a result of the government’s order to abandon the facilities, we are required to shut-in
our production at the affected properties until we can find an alternative path to market for such production. While we are working to find
an alternative path to market, we are unable to realize revenues from our production at the affected properties until such time as an
alternative arrangement is made.
Furthermore, if we are forced to shut-in production, we will likely incur greater costs to bring the associated production back online.
Cost increases necessary to bring the associated wells back online may be significant enough that such wells would become uneconomic at
low commodity price levels, which may lead to decreases in our proved reserve estimates and potential impairments and associated charges
to our earnings. If we are able to bring wells back online, there is no assurance that such wells will be as productive following
recommencement as they were prior to being shut-in. We have, in the past, been required to shut in wells when tropical storms or
hurricanes have caused or threatened damage to pipelines, gathering stations, and production facilities. In addition, certain third-party
pipelines have submitted requests in the past to increase the fees they charge us to use these pipelines. These increased fees, if approved,
could adversely impact our revenues or increase our operating costs, either of which would adversely impact our operating profits, cash
flows and reserves.
14
Table of Contents
Operating Risks
Relatively short production periods for our Gulf of Mexico properties based on proved reserves subject us to high reserve replacement
needs and require significant capital expenditures to replace our proved reserves at a faster rate than companies whose proved reserves
have longer production periods. If we are not able to obtain new oil and gas leases or replace reserves, we will not be able to sustain
production at current levels, which may have a material adverse effect on our business, financial condition, or results of operations.
Our future success depends largely upon our ability to find, develop or acquire additional oil and natural gas reserves that are
economically recoverable in order to replace or grow our produced proved reserves. Producing oil and natural gas reserves are generally
characterized by declining production rates that vary depending upon reservoir characteristics and other factors. High production rates
generally result in recovery of a relatively higher percentage of reserves during the initial few years of production. All of our current
production is from the Gulf of Mexico. Proved reserves in the Gulf of Mexico generally have shorter reserve lives than proved reserves in
many other producing regions of the United States, in part due to the difference in rules related to booking proved undeveloped reserves
between conventional and unconventional basins. Our independent petroleum consultant estimates that 33.2% of our total proved reserves
as of December 31, 2023 will be depleted within three years. As a result, our need to replace proved reserves and production from new
investments is relatively greater than that of producers who recover lower percentages of their proved reserves over a similar time period,
such as those producers who have a larger portion of their proved reserves in areas other than the Gulf of Mexico. Historically, we have
funded our capital expenditures and acquisitions with cash on hand, cash provided by operating activities, capital markets securities
offerings and bank borrowings. The capital markets we have historically accessed may be constrained because of our leverage and also
because, in recent years, institutional investors who provide financing to fossil fuel energy companies have become more attentive to
sustainability lending practices and some of them may elect not to provide funding for fossil fuel energy companies. As a result, we may
not be able to obtain sufficient funding to develop, find or acquire additional proved reserves in sufficient quantities to sustain our current
production levels or to grow production beyond current levels. Future cash flows are subject to a number of variables, such as the level of
production from existing wells, the prices of oil, NGLs and natural gas, and our success in developing and producing new reserves. Any
reductions in our capital expenditures to stay within internally generated cash flow (which could be adversely affected if commodity prices
decline) and cash on hand will make replacing depleted reserves more difficult.
We are not insured against all of the operating risks to which our business is exposed.
In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is
exposed. We insure some, but not all, of our properties from operational loss-related events. We currently carry multiple layers of insurance
coverage in our Energy Package, covering our operating activities, with higher limits of coverage for higher valued properties and wells.
Our insurance coverage includes deductibles that have to be met prior to recovery, as well as sub-limits or self-insurance. Additionally, our
insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability
from all potential consequences, damages or losses. See Part I, Item 1. Business – Insurance Coverage for more information on our
insurance coverage.
In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations.
Currently OPA requires owners and operators of offshore oil production facilities to have ready access to between $35.0 million and $150.0
million, which amount is based on a worst case oil spill discharge volume demonstration that can be used to cover costs that could be
incurred in responding to an oil spill at our facilities on the OCS. We are currently required to demonstrate that we have ready access to
$35.0 million. If OPA is amended to increase the minimum level of financial responsibility, we may experience difficulty in providing
financial assurances sufficient to comply with this requirement.
15
Table of Contents
In the past, tropical storms and hurricanes in the Gulf of Mexico have caused catastrophic losses and property damage. Similar events
may cause damage or liability in excess of our coverage that might severely impact our financial position. We may be liable for damages
from an event relating to a project in which we own a non-operating working interest. Well control insurance coverage becomes limited
from time to time and the cost of such coverage becomes both more costly and more volatile. In the past, we have been able to renew our
policies each annual period, but our coverage has varied depending on the premiums charged, our assessment of the risks and our ability to
absorb a portion of the risks. The insurance market may further change dramatically in the future due to severe storm damage, major oil
spills or other events.
Such events as noted above may also cause a significant interruption to our business, which might also severely impact our financial
position. We may experience production interruptions for which we do not have business interruption insurance.
We re-evaluate the purchase of insurance, policy limits and terms annually. Future insurance coverage for our industry could increase
in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or
unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in
the future at rates that we consider reasonable, and we may elect to maintain minimal or no insurance coverage. The occurrence of a
significant event for which our losses are not fully insured or indemnified, or for which the insurance companies will not pay our claims,
could have a material adverse effect on our financial condition and results of operations.
We conduct exploration, development and production operations on the deep shelf and in the deepwater of the Gulf of Mexico, which
presents unique operating risks.
The deep shelf and the deepwater of the Gulf of Mexico are areas that have had less drilling activity due, in part, to their geological
complexity, depth and higher cost to drill and ultimately develop. There are additional risks associated with deep shelf and deepwater
drilling that could result in substantial cost overruns and/or result in uneconomic projects or wells. Deeper targets are more difficult to
interpret with traditional seismic processing. Moreover, drilling costs and the risk of mechanical failure are significantly higher because of
the additional depth and adverse conditions, such as high temperature and pressure. For example, the drilling of deepwater wells requires
specific types of rigs with significantly higher day rates as compared to the rigs used in shallower water, sophisticated sea floor production
handling equipment, expensive state-of-the-art platforms and infrastructure investments. Deepwater wells have greater mechanical risks
because the wellhead equipment is installed on the sea floor. In addition, due to the significant time requirements involved with exploration
and development activities, particularly for wells in the deepwater or wells not located near existing infrastructure, actual oil and natural
gas production from new wells may not occur, if at all, for a considerable period of time following the commencement of any particular
project. Accordingly, we cannot provide assurance that our oil and natural gas exploration activities in the deep shelf, the deepwater and
elsewhere will be commercially successful.
Continuing inflation and cost increases may impact our sales margins and profitability.
Cost inflation, including significant increases in wholesale raw materials costs, labor rates, and domestic transportation costs have and
could continue to impact profitability. In addition, our customers are also affected by inflation and the rising costs of goods and services
used in their businesses, which could negatively impact their ability to purchase commodities such as oil and gas, which could adversely
impact our revenue and profitability. Although such cost increases did not materially impact our 2023 financial condition or results of
operations, and we currently do not expect them to materially impact our 2024 financial results or operations, there is no guarantee that we
can increase selling prices, replace lost revenue, or reduce costs to fully mitigate the effect of inflation on our costs and business, which
may adversely impact our sales margins and profitability.
16
Table of Contents
We may not be in a position to control the timing of development efforts, associated costs or the rate of production of the reserves from
our non-operated properties.
As we carry out our drilling program, we may not serve as operator of all planned wells. In that case, we have limited ability to
exercise influence over the operations of some non-operated properties and their associated costs. Our dependence on the operator and
other working interest owners and our limited ability to influence operations and associated costs of properties operated by others could
prevent the realization of anticipated results in drilling or acquisition activities.
We are subject to numerous risks inherent to the exploration and production of oil and natural gas.
Oil and natural gas exploration and production activities involve certain risks that a combination of experience, knowledge and careful
evaluation may not be able to overcome. Our future success will depend on the success of our exploration and production activities and on
the future existence of the infrastructure and technology that will allow us to take advantage of our findings. Additionally, our properties
are located in deepwater, which generally increases the capital and operating costs, technical challenges and risks associated with
exploration and production activities. As a result, our exploration and production activities are subject to numerous risks, including the risk
that drilling will not result in commercially viable production. Our decisions to purchase, explore, develop or otherwise exploit prospects or
properties will depend in part on the evaluation of seismic data through geophysical and geological analyses, production data and
engineering studies, the results of which are often inconclusive or subject to varying interpretations.
Furthermore, the marketability of expected production from our prospects will also be affected by numerous factors. These factors
include, but are not limited to, market fluctuations of oil and natural gas prices, proximity, capacity and availability of pipelines, the
availability of processing facilities, equipment availability and government regulations (including, without limitation, regulations relating
to prices, taxes, royalties, allowable production, importing and exporting of hydrocarbons, environmental, safety, health and climate
change). The effect of these factors, individually or jointly, may result in us not receiving an adequate return on invested capital.
We are subject to drilling and other operational hazards. The exploration, development and production of oil and gas properties
involves a variety of operating risks, including the risk of fire, explosions, blowouts, pipe failure, abnormally pressured formations and
environmental hazards such as oil spills, gas leaks, pipeline ruptures or discharges. Additionally, our offshore operations are subject to the
additional hazards of marine operations, such as capsizing, collisions and adverse weather and sea conditions, including the effects of
tropical storms, hurricanes and other weather events.
If we experience any of these problems, well bores, platforms, gathering systems and processing facilities could be affected, which
could adversely affect our ability to conduct operations. If any of these industry operating risks occur, we could have substantial losses.
Substantial losses may be caused by injury or loss of life, severe damage to or destruction of property, natural resources and equipment,
pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension of operations and
production, repairs to resume operations and loss of reserves. Any of these industry operating risks could have a material adverse effect on
our business, results of operations and financial condition.
The geographic concentration of our properties in the Gulf of Mexico subjects us to an increased risk of loss of revenues or curtailment
of production from factors specifically affecting the Gulf of Mexico, including hurricanes.
The geographic concentration of our properties along the U.S. Gulf Coast and adjacent waters on and beyond the OCS means that
some or all of our properties could be affected by the same event should the Gulf of Mexico experience severe weather, including tropical
storms and hurricanes; delays or decreases in production, the availability of equipment, facilities or services; changes in the status of
pipelines that we depend on for transportation of our production to the marketplace; delays or decreases in the availability of capacity to
transport, gather or process production; and changes in the regulatory environment.
17
Table of Contents
For 2023, approximately 40% of our production and 19% of our total revenue was attributable to our Mobile Bay Properties. This
concentration means that any impact on our production from this field, whether because of mechanical problems, adverse weather, well
containment activities, changes in the regulatory environment or otherwise, could have a material adverse effect on our business. During
2023, our Mobile Bay Properties were shut-in for 35 days for planned maintenance. The shut-in resulted in deferred production of
approximately 774 MBoe based on production rates prior to the shut-in. Any additional shut-ins, depending on the duration of the shut-in,
could have a material adverse impact on our business. In addition, if the actual reserves associated with the Mobile Bay Properties are less
than our estimated reserves, such a reduction of reserves could have a material adverse effect on our business, financial condition, results of
operations and cash flows.
Because a majority of our properties could experience the same conditions at the same time, these conditions could have a greater
impact on our results of operations than they might have on other operators who have properties over a wider geographic area.
New technologies may cause our current exploration and drilling methods to become obsolete, and we may not be able to keep pace
with technological developments in our industry.
The oil and natural gas industry is subject to rapid and significant advancements in technology, including the introduction of new
products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive
disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may
have greater financial, technical and personnel resources that allow them to enjoy technological advantages, and that may in the future,
allow them to implement new technologies before we can. We rely heavily on the use of advanced seismic technology to identify
exploitation opportunities and to reduce our geological risk. Seismic technology or other technologies that we may implement in the future
may become obsolete. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable
to us. If we are unable to maintain technological advancements consistent with industry standards, our business, results of operations and
financial condition may be materially adversely affected.
Estimates of our proved reserves depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in the
estimates or underlying assumptions will materially affect the quantities of and present value of future net revenues from our proved
reserves. Our actual recovery of reserves may substantially differ from our estimated proved reserves.
The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many
assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could
materially affect the estimated quantities and the calculation of the present value of our reserves at December 31, 2023.
In order to prepare our year-end reserve estimates, our independent petroleum consultant projected our production rates and timing of
development expenditures. Our independent petroleum consultant also analyzed available geological, geophysical, production and
engineering data. The extent, quality and reliability of this data can vary and may not be under our control. The process also requires
economic assumptions about matters such as oil and natural gas prices, operating expenses, capital expenditures, taxes and availability of
funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of
recoverable oil and natural gas reserves will most likely vary from our estimates. Any significant variance could materially affect the
estimated quantities and present value of our reserves. In addition, our independent petroleum consultant may adjust estimates of proved
reserves to reflect production history, drilling results, prevailing oil and natural gas prices and other factors, many of which are beyond our
control.
18
Table of Contents
You should not assume that the standardized measure or the present value of future net revenues from our proved oil and natural gas
reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we base the
estimated discounted future net cash flows from our proved reserves on the 12-month unweighted first-day-of-the-month average price for
each product and costs in effect on the date of the estimate. Actual future prices and costs may differ materially from those used in the
present value estimate.
At December 31, 2023, approximately 16% of our estimated proved reserves (by volume) were undeveloped. Any or all of our PUD
reserves may not be ultimately developed or produced or may not be ultimately produced during the time periods we plan or at the costs we
budget, which could result in the write-off of previously recognized reserves. Recovery of PUD reserves generally requires significant
capital expenditures and successful drilling or waterflood operations. Our reserve estimates include the assumptions that we incur capital
expenditures to develop these undeveloped reserves and the actual costs and results associated with these properties may not be as
estimated. Any material inaccuracies in these reserve estimates or underlying assumptions materially affect the quantities and present value
of our reserves, which could adversely affect our business, results of operations and financial condition.
Prospects that we decide to drill may not yield oil or natural gas in commercial quantities or quantities sufficient to meet our targeted
rates of return.
A prospect is an area in which we own an interest, could acquire an interest or have operating rights, and have what our geoscientists
believe, based on available seismic and geological information, to be indications of economic accumulations of oil or natural gas. Our
prospects are in various stages of evaluation, ranging from a prospect that is ready to be drilled to a prospect that will require substantial
seismic data processing and interpretation, which will not enable us to know conclusively prior to drilling whether oil or natural gas will be
present or, if present, whether oil or natural gas will be present in commercial quantities. Sustained low oil, NGLs and natural gas pricing
may also significantly impact the projected rates of return of our projects without the assurance of significant reductions in costs of drilling
and development. To the extent we drill additional wells in the deepwater and/or on the deep shelf, our drilling activities could become
more expensive. In addition, the geological complexity of deepwater and deep shelf formations may make it more difficult for us to sustain
our historical rates of drilling success. As a result, we can offer no assurance that we will find commercial quantities of oil and natural gas
and, therefore, we can offer no assurance that we will achieve positive rates of return on our investments.
We may not realize all of the anticipated benefits from our targeted acquisitions. Such acquisitions could expose us to potentially
significant liabilities, including plugging and abandonment and decommissioning liabilities.
We expect to grow by expanding the exploitation and development of our existing assets, in addition to making targeted acquisitions in
the Gulf of Mexico. We may not realize all of the anticipated benefits from acquisitions, such as increased earnings, cost savings and
revenue enhancements, for various reasons, including higher than expected acquisition and operating costs or other difficulties, unknown
liabilities, inaccurate reserve estimates and fluctuations in market prices. This could lead to potential adverse short-term or long-term
effects on our operating results.
Successful acquisitions of oil and natural gas properties require an assessment of a number of factors, including estimates of
recoverable reserves, the timing of recovering reserves, exploration potential, future oil and natural gas prices, operating costs and potential
environmental, regulatory and other liabilities, including plugging and abandonment and decommissioning liabilities. Such assessments are
inexact and may not disclose all material issues or liabilities. In connection with our assessments, we also perform a review of the acquired
properties. However, such a review may not reveal all existing or potential problems. Additionally, such review may not permit us to
become sufficiently familiar with the properties to fully assess their deficiencies and capabilities.
19
Table of Contents
There may be threatened, contemplated, asserted or other claims against the acquired assets related to environmental, title, regulatory,
tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and
results of operations. We may be successful in obtaining contractual indemnification for preclosing liabilities, including environmental
liabilities, but we expect that we will generally acquire interests in properties on an “as is” basis with limited remedies for breaches of
representations and warranties. In addition, even if we are able to obtain such indemnification from the sellers, these indemnification
obligations usually expire over time and could potentially expose us to unindemnifiable liabilities, which could materially adversely affect
our production, revenues and results of operations.
Our operations could be adversely impacted by security breaches, including cybersecurity breaches, which could affect the systems,
processes and data needed to run our business.
We rely on our information technology infrastructure and management information systems to operate and record aspects of our
business. Although we take measures to protect against cybersecurity risks, including unauthorized access to our confidential and
proprietary information, our security measures may not be able to detect or prevent every attempted breach. Similar to other companies, we
have experienced cyber-attacks, although we have not suffered any material losses related to such attacks. Security breaches include,
among other things, illegal hacking, computer viruses, interference with treasury function, theft or acts of vandalism or terrorism. A breach
could result in an interruption in our operations, malfunction of our platform control devices, disabling of our communication links,
unauthorized publication of our confidential business or proprietary information, unauthorized release of customer or employee data,
violation of privacy or other laws and exposure to litigation. Any of these security breaches could have a material adverse effect on our
consolidated financial position, results of operations and cash flows. The invasion of Ukraine by Russia, and the impact of world sanctions
against Russia and the potential for retaliatory acts from Russia, could result in increased cybersecurity attacks against U.S. companies.
We have historically outsourced substantially all of our information technology infrastructure and the management and servicing of
such infrastructure to a limited number of third parties, which makes us more dependent upon such third parties and exposed to related
risks. We are in the process of transitioning substantially all of such infrastructure internally or to other service providers, which
subjects us to increased costs and risks.
We have historically outsourced substantially all of our information technology infrastructure and the management and servicing of
such infrastructure to a limited number of third-party service providers. As a result, we previously relied on a small number of third parties
that we do not control to ensure that our technology needs are sufficiently met, and cyber risks are effectively managed. This reliance has
subjected us to certain cybersecurity risks arising from the loss of control over certain processes, including the potential misappropriation,
destruction, corruption or unavailability of certain data and systems, such as confidential or proprietary information. A failure of any of our
information technology service providers to perform its management and operational duties securely and effectively may have a material
adverse effect on our financial condition, liquidity or results of operations or the integrity of the systems, processes and data needed to run
our business. We also have not had written agreements with our primary service provider, which exposed us to additional risks with respect
to the systems and data outsourced to such provider.
Beginning in August 2022, following the notification by our primary information technology service provider, All About IT (“AAIT”),
of its intention to cease providing services to us, we began the transition of information technology services and infrastructure to us or to
other providers. We have moved and are continuing to move certain services internally and are transitioning certain other services to new
service providers and implementing agreements with such providers. Although the transition process is substantially complete and we no
longer have a material relationship with AAIT, the transition process has disrupted, and may continue to disrupt, certain of our business
operations. Any difficulties in completing such transition could impair our ability to monitor our production and accurately prepare our
results of operations in a timely fashion. Moreover, such transition continues to expose us to additional risks, including increased costs,
diversion of management’s attention, disruptions to certain of our business operations and loss, damage to or unavailability of data or
systems, each of which could have an adverse effect on our business and results of operations.
20
Table of Contents
The loss of members of our senior management could adversely affect us.
To a large extent, we depend on the services of our senior management. The loss of the services of any of our senior management
could have a negative impact on our operations. We do not maintain or plan to obtain for the benefit of the Company any insurance against
the loss of any of these individuals. See our definitive proxy statement to be filed with the SEC within 120 days after the end of our
fiscal year covered by this Form 10-K for more information regarding our senior management team.
There may be circumstances in which the interests of significant stockholders could conflict with the interests of our other stockholders.
Our Chairman and Chief Executive Officer (“CEO”) owns a significant portion of our common stock and an entity indirectly owned
and controlled by our CEO is the sole lender under the Credit Agreement. Circumstances may arise in which he may have an interest in
pursuing or preventing acquisitions, divestitures, hostile takeovers or other transactions, or conflicts of interest could arise in the future
regarding, among other things, decisions related to our financing, capital expenditures and business plans, or the pursuit of certain business
opportunities, including the payment of dividends or the issuance of additional equity or debt, that, in his judgment, could enhance his
investment in us or in another company in which he invests.
Such circumstances or conflicts might adversely affect us or other holders of our common stock. In addition, our significant
concentration of share ownership and lender relationships may adversely affect the trading price of our common stock because investors
may perceive disadvantages in owning shares in companies with significant stockholder concentrations or with such potential conflicts.
Capital Risks
We have a significant amount of indebtedness and limited borrowing capacity under our current Credit Agreement. Our leverage and
debt service obligations may have a material adverse effect on our financial condition, results of operations and business prospects, and
we may have difficulty paying our debts as they become due.
As of December 31, 2023, we had $400.2 million of principal amount of long-term debt outstanding, including the Term Loan, the
11.75% Senior Second Lien Notes, which mature on February 1, 2026 (the “11.75% Notes”) and the TVPX Loan. We had no borrowings
outstanding under our Credit Agreement.
Our leverage and debt service obligations could:
● increase our vulnerability to general adverse economic and industry conditions;
● limit our ability to fund future working capital requirements, capital expenditures and ARO, to engage in future acquisitions or
development activities, or to otherwise realize the value of our assets;
● limit our opportunities because of the need to dedicate a substantial portion of our cash flow from operations to payments of
interest and principal on our debt obligations or to comply with any restrictive terms of our debt obligations;
● limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
● limit or impair our ability to obtain additional financing or refinancing in the future or require us to seek alternative financing,
which may be more restrictive or expensive; and
● place us at a competitive disadvantage compared to our competitors that have less debt.
21
Table of Contents
Any of the above listed factors could have a material adverse effect on our business, financial condition, cash flows and results of
operations. If new debt is added to our current debt levels, the related risks that we face could intensify. Additionally, availability of
borrowings and letters of credit under our Credit Agreement is determined by establishment of a borrowing base, which is periodically
redetermined in lender’s sole discretion based on our lender’s review of oil, NGLs and natural gas prices, our proved reserves and other
criteria. Lower oil, NGLs and natural gas prices in the future would also adversely affect our cash flow and could result in reductions in our
borrowing base and sources of alternate credit and affect our ability to satisfy the covenants and ratios required by the Credit Agreement
and Indenture (as defined below). Lower oil, NGL and natural gas prices may also have ancillary impacts on us and certain subsidiaries.
For example, W&T Offshore, Inc. pays certain expenses on behalf of the Aquasition Entities pursuant to a management services agreement,
which expenses are repaid by the Aquasition Entities in the ordinary course from operating cash flows. Planned and unplanned facility
downtime and lower gas prices in 2023 caused the Aquasition Entities to operate at a loss after servicing their debt obligations under the
Subsidiary Credit Agreement, and the Aquasition Entities have been unable to fully reimburse W&T Offshore, Inc. for such expenses paid
on their behalf. Because of restrictions in the Credit Agreement and in the 11.75% Notes, W&T Offshore, Inc. may not be able to fund
expenses on behalf of the Aquasition Entities indefinitely.
We cannot be certain that our cash flow will be sufficient to allow us to pay the principal and interest on our debt or otherwise meet our
future obligations. In such scenarios, we may be required to refinance all or part of our existing debt, sell assets, reduce capital
expenditures, obtain new financing or issue equity. However, we may not be able to accomplish any of these transactions on terms
acceptable to us or such actions may not yield sufficient capital to meet our obligations. Any of the above risks could have a material
adverse effect on our business, financial condition, cash flows and results of operations.
Our debt agreements contain restrictions that limit our abilities to incur certain additional debt or liens or engage in other transactions,
which could limit growth and our ability to respond to changing conditions.
The indenture governing our 11.75% Notes (the “Indenture”), our Credit Agreement and our Subsidiary Credit Agreement governing
our indebtedness contain a number of significant restrictive covenants in addition to covenants restricting the incurrence of additional debt.
These covenants limit our ability and the ability of our restricted subsidiaries, among other things, to:
● make loans and investments;
● incur additional indebtedness or issue preferred stock;
● create certain liens;
● sell assets;
● enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;
● consolidate, merge or transfer all or substantially all of the assets of the Company;
● engage in transactions with our affiliates;
● pay dividends or make other distributions on capital stock or indebtedness; and
● create unrestricted subsidiaries.
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.
22
Table of Contents
We have significant capital needs, and our ability to access the capital and credit markets to raise capital or refinance our existing
indebtedness on favorable terms, including our 11.75% Notes and our Credit Agreement with Calculus, may be limited by industry
conditions and financial markets.
Disruptions in the capital and credit markets, in particular with respect to the energy sector, could limit our ability to access these
markets or may significantly increase our cost to borrow. Volatility in the energy sector, together with the higher interest rate environment,
has caused and may continue to cause lenders to increase the interest rates under our credit facilities, enact tighter lending standards, refuse
to refinance existing debt around maturity on favorable terms or at all and may reduce or cease to provide funding to borrowers.
Furthermore, we may not be able to refinance our 11.75% Notes or extend our Credit Agreement with Calculus on favorable terms or at all.
If we are unable to access the capital and credit markets on favorable terms, it could have a material adverse effect on our business,
financial condition, results of operations, cash flows and liquidity and our ability to repay or refinance our debt.
If we default on our secured debt, the value of the collateral securing our secured debt may not be sufficient to ensure repayment of all
of such debt.
Our Credit Agreement and our outstanding 11.75% Notes are secured by various liens on our oil and natural gas properties, excluding
our Mobile Bay assets. The oil and natural gas assets of, and equity in, certain of our subsidiaries that own our Mobile Bay assets (the
Borrower Subsidiaries, as defined in Financial Statements and Supplementary Data – Note 2 – Debt under Part II, Item 8 in this Form 10-
K), are pledged on a first priority basis to secure our Term Loan. Any future borrowings under our Credit Agreement would be secured on a
first priority basis by the assets securing the 11.75% Notes. In addition, we have certain rights to issue or incur additional or new secured
debt, which could be secured by additional liens on the collateral. An issuance or incurrence of such additional secured debt would dilute
the value of the collateral securing our outstanding secured debt. If the proceeds of the sale of the collateral securing the 11.75% Notes or
any future indebtedness incurred under the Credit Agreement are not sufficient to repay all amounts due in respect of such debt, then claims
against our remaining assets to repay any amounts still outstanding under our secured obligations would be unsecured, and our ability to
pay our other unsecured obligations and any distributions in respect of our capital stock would be significantly impaired.
With respect to some of the collateral securing our debt, any collateral trustee’s security interest and ability to foreclose on the
collateral will also be limited by the need to meet certain requirements, such as obtaining third-party consents, paying court fees that may
be based on the principal amount of the parity lien obligations and making additional filings. If we are unable to obtain these consents, pay
such fees or make these filings, the security interests may be invalid, and the applicable holders and lenders will not be entitled to the
collateral or any recovery with respect thereto. These requirements may limit the number of potential bidders for certain collateral in any
foreclosure and may delay any sale, either of which events may have an adverse effect on the sale price of the collateral.
We may not be able to repurchase the 11.75% Notes upon a change of control.
If we experience certain kinds of changes of control, we must give holders of the 11.75% Notes the opportunity to sell us their notes at
101% of their principal amount, plus accrued and unpaid interest. However, in such an event, we might not be able to pay the holders the
required repurchase price for the notes they present to us because we might not have sufficient funds available at that time, or the terms of
our Credit Agreement or other agreements we may enter into in the future may prevent us from applying funds to repurchase the 11.75%
Notes. The source of funds for any repurchase required as a result of a change of control will be our available cash or cash generated from
our oil and gas operations or other sources, including:
● borrowings under the Credit Agreement or other sources;
● sales of assets; or
● sales of equity.
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.
23
Table of Contents
We may be required to post cash collateral pursuant to our agreements with sureties under our existing or future bonding
arrangements, which could have a material adverse effect on our liquidity and our ability to execute our capital expenditure plan, our
ARO plan and comply with our existing debt instruments.
Pursuant to the terms of our agreements with various sureties under our existing bonding arrangements, or under any future bonding
arrangements we may enter into, we may be required to post collateral at any time, on demand, at the surety’s sole discretion. Additional
collateral would likely be in the form of cash or letters of credit. We cannot provide assurance that we will be able to satisfy collateral
demands for current bonds or for future bonds.
If we are required to provide additional collateral, our liquidity position will be negatively impacted, and we may be required to seek
alternative financing. To the extent we are unable to secure adequate financing, we may be forced to reduce our capital expenditures in the
current year or future years, may be unable to execute our ARO plan or may be unable to comply with our existing debt instruments.
Legal, Government and Regulatory Risks
We are subject to numerous environmental, health and safety regulations which are subject to change and may also result in material
liabilities and costs.
Our operations are subject to U.S. federal, state, local and foreign environmental laws and regulations governing, among other things,
the emission and discharge of pollutants into the environment, the generation, storage, handling, use and transportation of toxic and
hazardous wastes and the health and safety of our employees. Our operations in the Gulf of Mexico require permits from federal and state
governmental agencies in order to perform drilling and completion activities and conduct other regulated activities. There is a risk that we
have not been or will not be at all times in complete compliance with these permits and the environmental laws and regulations to which we
are subject. Any failure by us to comply with applicable environmental laws and regulations may result in governmental authorities taking
action against us that could adversely impact our operations and financial condition, including the:
● issuance of administrative, civil and criminal penalties;
● denial or revocation of permits or other authorizations;
● imposition of limitations on our operations; and
● performance of site investigatory, remedial or other corrective actions.
If we fail to obtain permits in a timely manner or at all (for example, due to opposition from community or environmental groups,
government delays, changes in laws or the interpretation thereof, or any other reason), such failure could impede our operations, which
could have a material adverse effect on our results of operations and our financial condition.
The longer-term trend of more expansive and stringent environmental legislation and regulations is expected to continue, which makes
it challenging to predict the cost or impact on our future operations. Liabilities associated with environmental matters could have a material
adverse effect on our business, financial condition and results of operations. Under certain environmental laws, we could be exposed to
strict, joint and several liability for cleanup costs and other damages relating to releases of hazardous materials or contamination, regardless
of whether we were responsible for the release or contamination, and even if our operations were lawful or in accordance with industry
standards at the time.
Additional changes in environmental laws, regulations, guidelines or enforcement interpretations could require us to devote capital or
other resources to comply with those laws and regulations. These changes could also subject us to additional costs and restrictions,
including increased fuel costs. In addition, such changes in laws or regulations could increase the costs of compliance and doing business
for our customers and thereby decrease the demand for our services.
New laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased
governmental enforcement could significantly increase our capital expenditures and operating costs or result in delays, limitations or
cancelations to our exploration and production activities, which could have an adverse effect on our financial condition, results of
operations, or cash flows. See Business – Other Regulation of the Oil and Natural Gas Industry under Part I, Item 1 in this Form 10-K for a
more detailed description of our environmental regulations.
24
Table of Contents
We may be unable to provide financial assurances in the amounts and under the time periods required by the BOEM if the BOEM
submits future demands to cover our decommissioning obligations.
The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations and provide acceptable
financial assurances to assure satisfaction of lease obligations, including decommissioning activities in the OCS. Currently the BOEM
requires all lessees of an OCS oil and natural gas lease to post base bonds ranging from $50 thousand to $3.0 million in addition to
supplemental financial assurance determined based on the lessee’s ability to carry out present and future financial obligations. In June
2023, the BOEM proposed a new rule that updated the criteria for determining whether oil and natural gas lessees may be required to
provide supplemental financial assurance above the prescribed base financial assurance to ensure compliance with the OCSLA. The
proposed rule considers an OCS lessee’s credit rating and proved oil reserves in determining whether a lessee in the OCS is required to
obtain supplemental financial assurance. A final rule is anticipated by April 2024. Additionally, the BOEM could in the future make new
demands for additional financial assurances covering our obligations under our properties, which could exceed the Company’s capabilities
to provide.
If we fail to comply with the proposed new rule and such future orders, the BOEM could commence enforcement proceedings or take
other remedial action against us, including assessing civil penalties, suspending operations or production, or initiating procedures to cancel
leases, which, if upheld, would have a material adverse effect on our business, properties, results of operations and financial condition. In
addition, if we are required to provide collateral in the form of cash or letters of credit, our liquidity position could be negatively impacted,
and we may be required to seek alternative financing. To the extent we are unable to secure adequate financing, we may be forced to reduce
our capital expenditures. All of these factors may make it more difficult for us to obtain the financial assurances required by the BOEM to
conduct operations in the OCS. These and other changes to BOEM bonding and financial assurance requirements could result in increased
costs on our operations and consequently have a material adverse effect on our business and results of operations.
We may be limited in our ability to maintain or recognize additional proved undeveloped reserves under current SEC guidance.
SEC rules require that, subject to limited exceptions, proved undeveloped reserves (“PUD reserves”) may only be booked if they relate
to wells scheduled to be drilled within five years after the date of initial booking. This requirement may limit our ability to book additional
PUD reserves as we pursue our drilling program. Moreover, we may be required to write down our PUD reserves if we do not drill those
wells within the required five-year timeframe.
Additional deepwater drilling laws, regulations and other restrictions, delays and other offshore-related developments in the Gulf of
Mexico may have a material adverse effect on our business, financial condition, or results of operations.
The Biden administration has taken a number of actions that may result in stricter environmental, health and safety standards
applicable to our operations and those of the oil and natural gas industry more generally. Regulatory agencies under the Biden
administration may issue new or amended rulemakings regarding deepwater leasing, permitting or drilling that could result in more
stringent or costly restrictions, delays or cancellations to our operations as well as those of similarly situated offshore energy companies on
the OCS. Compliance with any new or more stringent regulatory requirements or enforcement initiatives and existing environmental and
spill regulations, together with uncertainties or inconsistencies in decisions by governmental agencies, delays in the processing and
approval of drilling permits and exploration, development, oil spill response and decommissioning plans and possible additional regulatory
initiatives, could adversely affect or delay new drilling and ongoing development efforts. Moreover, governmental agencies under the
Biden administration are expected to continue to evaluate aspects of safety and operational performance in the Gulf of Mexico that could
result in new, more restrictive requirements.
25
Table of Contents
These regulatory actions, or any new rules, regulations, or legal or enforcement initiatives that impose more stringent operational
standards could delay or disrupt our operations; result in increased supplemental bonding and costs; and limit activities in certain areas or
cause us to incur penalties or fines; shut-in production at one or more of our facilities; or result in the suspension or cancellation of leases.
Also, if material spill incidents were to occur in the future, the United States could elect to issue directives to temporarily cease drilling
activities and, in any event, issue further safety and environmental laws and regulations regarding offshore oil and natural gas exploration
and development, any of which could have a material adverse effect on our business. We cannot predict with any certainty the full impact
of any new laws or regulations on our drilling operations or on the cost or availability of insurance to cover some or all of the risks
associated with such operations. See Part I, Item 1. Business – Environmental, Health and Safety Matters and Regulations and Other
Regulation of the Oil and Natural Gas Industry for more discussion on orders and regulatory initiatives impacting the oil and natural gas
industry that are being pursued under the Biden administration.
Our estimates of future ARO may vary significantly from period to period, and unanticipated decommissioning costs could materially
adversely affect our future financial position and results of operations.
We are required to record a liability for the present value of our ARO to plug and abandon inactive non-producing wells, to remove
inactive or damaged platforms, and inactive or damaged facilities and equipment, collectively referred to as “idle iron,” and to restore the
land or seabed at the end of oil and natural gas production operations. An existing BSEE NTL describes the obligations of offshore
operators to timely decommission idle iron by means of abandonment and removal. Pursuant to these idle iron NTL requirements, BSEE
issued us letters, directing us to plug and abandon certain wells that the agency identified as no longer capable of production in paying
quantities by specified timelines. In response, we are currently evaluating the list of wells proposed as idle iron by BSEE and currently
anticipate that those wells determined to be idle iron will be decommissioned by the specified timelines or at times as otherwise determined
by BSEE following further discussions with the agency. While we have established AROs for well decommissioning, additional AROs,
significant in amount, may be necessary to conduct plugging and abandonment of the wells designated in the future as idle iron, but we do
not expect the costs to plug and abandon such additional wells will have a material effect on our financial condition, results of operations or
cash flows. Nevertheless, these decommissioning activities are typically considerably more expensive for offshore operations as compared
to most land-based operations due to increased regulatory scrutiny and the logistical issues associated with working in waters of various
depths, and there exists the possibility that increased liabilities beyond what we established as AROs may arise and the pace for completing
these activities could be adversely affected by idle iron decommissioning activities being pursued by other offshore oil and gas lessees that
may also have received similar BSEE directives, which could restrict the availability of equipment and experienced workforce necessary to
accomplish this work.
Estimating future restoration and removal costs in the Gulf of Mexico is especially difficult because most of the removal obligations
may be many years in the future, regulatory requirements are subject to change or such requirements may be interpreted more restrictively,
and asset removal technologies are constantly evolving, which may result in additional, increased or decreased costs. As a result, we may
make significant increases or decreases to our estimated ARO in future periods. For example, because we operate in the Gulf of Mexico,
platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes and other adverse weather conditions. The
estimated cost to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was
anticipated to be performed is damaged or toppled rather than structurally intact. Accordingly, our estimate of future ARO could differ
dramatically from what we may ultimately incur as a result of damage from a hurricane or other natural disaster. Additionally, a sustained
lower commodity price environment may cause our non-operator partners to be unable to pay their fair share of costs, which may require us
to pay our proportionate share of the defaulting party’s share of costs.
We have divested, as assignor, various leases, wells and facilities located in the Gulf of Mexico where the purchasers, as assignees,
typically assume all abandonment obligations acquired. Certain of these counterparties in these divestiture transactions or third parties in
existing leases have filed for bankruptcy protection or undergone associated reorganizations and may not be able to perform required
abandonment obligations. Under certain circumstances, regulations or federal laws, such as the OCSLA, could impose joint and several
strict liability and require predecessor assignors, such as us, to assume such obligations. As of December 31, 2023, we have $18.0 million
of loss contingency recorded related to anticipated decommissioning obligations. See Part II, Item 8. Financial Statements and
Supplementary Data — Note 19 — Contingencies for more information.
26
Table of Contents
We are subject to numerous laws and regulations that can adversely affect the cost, manner or feasibility of doing business.
Our operations and facilities are subject to extensive federal, state and local laws and regulations relating to the exploration,
development, production and transportation of oil and natural gas and operational safety. Future laws or regulations, any adverse change in
the interpretation of existing laws and regulations or our failure to comply with such legal requirements may harm our business, results of
operations and financial condition.
Our operations could be significantly delayed or curtailed, and our cost of operations could significantly increase as a result of
regulatory requirements or restrictions. Regulated matters include lease permit restrictions; limitations on our drilling activities in
environmentally sensitive areas, such as marine habitats, and restrictions governing the discharge of materials into the environment; bonds
or other financial responsibility requirements to cover drilling contingencies and well decommissioning costs; the spacing of wells;
operational reporting; reporting of natural gas sales for resale; and taxation. Under these laws and regulations, we could be liable for
personal injuries, property and natural resource damages, well site reclamation costs, and governmental sanctions, such as fines and
penalties.
Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to
administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that could substantially increase
our costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could have a material adverse effect on our results
of operations and financial condition, as well as the market price of our common stock. We are unable to predict the ultimate cost of
compliance with these requirements or their effect on our operations. See Business – Environmental, Health and Safety Matters and
Regulations and Other Regulation of the Oil and Natural Gas Industry under Part I, Item 1 in this Form 10-K for a more detailed
explanation of regulations impacting our business.
We are subject to laws, rules, regulations and policies regarding data privacy and security. Many of these laws and regulations are
subject to change and reinterpretation, and could result in claims, changes to our business practices, monetary penalties, increased cost
of operations or other harm to our business.
We are subject to a variety of federal, state and local laws, directives, rules and policies relating to data privacy and cybersecurity. The
regulatory framework for data privacy and cybersecurity worldwide is continuously evolving and developing, and, as a result, interpretation
and implementation standards and enforcement practices are likely to remain uncertain for the foreseeable future. It is also possible that
inquiries from governmental authorities regarding cybersecurity breaches increase in frequency and scope. These data privacy and
cybersecurity laws also are not uniform, which may complicate and increase our costs for compliance. Any failure or perceived failure by
us or our third-party service providers to comply with any applicable laws relating to data privacy and cybersecurity, or any compromise of
security that results in the unauthorized access, improper disclosure, or misappropriation of data, could result in significant liabilities and
negative publicity and reputational harm, one or all of which could have an adverse effect on our reputation, business, financial condition
and operations.
The Inflation Reduction Act of 2022 could accelerate the transition to a low carbon economy and could impose new costs on our
operations.
The IRA contains hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels,
electric vehicles and supporting infrastructure and carbon capture and sequestration, amongst other provisions. In addition, the IRA
imposes the first ever federal fee on the emission of GHGs through a methane emissions charge. The IRA amends the federal CAA to
impose a fee on the emission of methane from sources required to report their GHG emissions to the EPA, including those sources in the
onshore petroleum and natural gas production categories. In January 2024, the EPA proposed a rule implementing the IRA’s methane
emissions charge. The methane emissions charge would start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025,
and be set at $1,500 for 2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA. In addition,
the multiple incentives offered for various clean energy industries referenced above could further accelerate the transition of the economy
away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives. This could decrease demand for oil and natural gas,
increase our compliance and operating costs and consequently adversely affect our business.
27
Table of Contents
We are subject to risks arising from climate change, including risks related to energy transition, which could result in increased costs
and reduced demand for the oil and natural gas we produce and physical risks which could disrupt our production and cause us to
incur significant costs in preparing for or responding to those effects.
President Biden has made addressing the threat of climate change from GHG emissions a priority under his administration. Regulatory
agencies under the Biden administration have issued proposed rulemakings and may issue new or amended rulemakings in support of
President Biden’s regulatory and political agenda, which include reducing dependence on, and use of, fossil fuels and curtailment of
hydraulic fracturing on federal lands.
Numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of
government to monitor and limit emissions of GHGs as well as to eliminate such future emissions. Accordingly, our operations are subject
to a series of climate-related transition risks, including regulatory, political and litigation and financial risks associated with the production
and processing of fossil fuels and emission of GHGs. See Part I, Item 1. Business – Other Regulation of the Oil and Natural Gas Industry
for more discussion on the threat of climate change and restriction of GHG emissions.
The adoption and implementation of any international, federal, regional or state legislation, executive actions, regulations, policies or
other regulatory initiatives that impose more stringent standards for GHG emissions on our operations or in areas where we produce oil and
natural gas could result in increased compliance costs or costs of consuming fossil fuels, and thereby reduce demand for the oil and natural
gas that we produce. Companies in the oil and natural gas industry are often the target of activist efforts from both individuals and non-
governmental organizations regarding climate change and environmental and sustainability matters. Activism could materially and
adversely impact our ability to operate our business and raise capital. The foregoing factors may cause operational delays or restrictions,
increased operating costs and additional regulatory burden. Additionally, litigation risks to oil and natural gas companies are increasing, as
a number of cities, local governments and other plaintiffs have sought to bring suit against oil and natural gas companies in state or federal
court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming
effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the
companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to
adequately disclose those impacts. We are not currently a defendant in any of these lawsuits but could be named in actions making similar
allegations.
Further, stockholders and bondholders currently invested in fossil fuel energy companies such as ours but concerned about the
potential effects of climate change may elect in the future to shift some or all of their investments into non-fossil fuel energy related
sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending
practices, and some of them may elect not to provide funding for fossil fuel energy companies. Many of the largest U.S. banks have made
emission reduction commitments and have announced that they will be assessing financed emissions across their portfolios and are taking
steps to quantify and reduce those emissions. There is also a risk that financial institutions may be required to adopt policies that have the
effect of reducing the funding provided to the fossil fuel sector, and more broadly, some investors, including investment advisors and
certain sovereign wealth funds, pension funds, university endowments and family foundations, have stated policies to disinvest in the oil
and natural gas sector based on their social and environmental considerations. Certain other stakeholders have also pressured commercial
and investment banks to stop financing oil and gas production and related infrastructure projects. These and other developments in the
financial sector could lead to some lenders and investors restricting access to capital for or divesting from certain industries or companies,
including the oil and natural gas sector, or requiring that borrowers take additional steps to reduce their GHG emissions. Such
developments could result in downward pressure on the stock prices of oil and natural gas companies, including ours. This could also result
in an increase in our expenses and a reduction of available capital funding for potential development projects, impacting our future
financial results.
28
Table of Contents
Additionally, increasing attention from consumers and other stakeholders on combating climate change, together with changes in
consumer and industrial/commercial preferences and behavior and societal pressure on companies to address climate change may result in
increased availability of, and increased demand from consumers and industry for, energy sources other than oil and natural gas (including
wind, solar, geothermal, tidal and biofuels as well as electric vehicles) and development of, and increased demand from consumers and
industry for, lower-emission products and services (including electric vehicles and renewable residential and commercial power supplies)
as well as more efficient products and services. These developments may in the future adversely affect the demand for products
manufactured with, or powered by, petroleum products, as well as the demand for, and in turn the prices of, oil and natural gas products.
Lastly, most scientists have concluded that increasing concentrations of GHG in the Earth’s atmosphere may produce climate changes
that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, rising sea levels and other
climatic events. If any such effects were to occur, they could adversely affect or delay demand for oil or natural gas products or cause us to
incur significant costs in preparing for or responding to the effects of climatic events themselves, which may not be fully insured. Potential
adverse effects could include disruption of our production activities, including, for example, damages to our facilities from winds or floods,
increases in our costs of operation, or reductions in the efficiency of our operations, impacts on our personnel, supply chain, or distribution
chain, as well as potentially increased costs for insurance coverages in the aftermath of such effects. Any of these effects could have an
adverse effect on our assets and operations. Our ability to mitigate the adverse physical impacts of climate change depends in part upon our
disaster preparedness and response and business continuity planning. Due to the concentrated nature of our portfolio of properties, a
number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our
results of operations than they might have on other companies that have a more diversified portfolio of properties.
Each of these developments may in the future adversely affect the demand for products manufactured with, or powered by, petroleum
products, as well as the demand for, and in turn the prices of, oil and natural gas products. Additionally, political, financial and litigation
risks may result in us having to restrict, delay or cancel production activities, incur liability for infrastructure damages as a result of
climatic changes, or impair the ability to continue to operate in an economic manner, which could have a material adverse effect on our
business, financial condition, results of operations and cash flows.
Increasing attention to ESG matters may impact our business.
Increasing scrutiny related to ESG matters, societal expectations for companies to address climate change and sustainability concerns,
and investor, societal, and other stakeholder expectations regarding ESG and sustainability practices and related disclosures may result in
increased costs, reduced demand for the oil and natural gas we produce, reduced profits, increased risks of governmental investigations and
private party litigation, and negative impacts on our stock price and access to capital markets. Increasing attention to climate change, for
example, may result in demand shifts for the hydrocarbon products we produce as well as additional governmental investigations and
private litigation against us. To the extent that societal pressures or political or other factors are involved, it is possible that such liability
could be imposed without regard to our causation of or contribution to the assented damage, or to other mitigating factors.
If we do not adapt to or comply with investor or other stakeholder expectations and standards on ESG matters as they continue to
evolve, or if we are perceived to have not responded appropriately or quickly enough to growing concern for ESG and sustainability issues,
regardless of whether there is a regulatory or legal requirement to do so, we may suffer from reputational damage and our business,
financial condition and/or stock price could be materially and adversely affected.
29
Table of Contents
Further, our operations, projects and growth opportunities require us to have strong relationships with various key stakeholders,
including our shareholders, employees, suppliers, customers, local communities and others. We may face pressure from stakeholders,
including activist investors, many of whom are increasingly focused on climate change, to prioritize sustainable energy practices, reduce
our carbon footprint and promote sustainability while at the same time remaining a successfully operating public company. Responses to
such pressure could adversely impact our business by distracting management and other personnel from their primary responsibilities,
require us to incur increased costs, and/or result in reputational harm. Moreover, if we do not successfully manage expectations across these
varied stakeholder interests, it could erode stakeholder trust and thereby affect our brand and reputation. Such erosion of confidence could
negatively impact our business through decreased demand and growth opportunities, delays in projects, increased legal action and
regulatory oversight, adverse press coverage and other adverse public statements, difficulty hiring and retaining top talent, difficulty
obtaining necessary approvals and permits from governments and regulatory agencies on a timely basis and on acceptable terms and
difficulty securing investors and access to capital.
Organizations that provide information to investors on corporate governance, climate change, health and safety and other ESG related
factors have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some
investors to inform their investment decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from
companies with fossil energy-related assets could lead to increased negative investor sentiment toward us or our customers and to the
diversion of investment to other industries, which could have a negative impact on our unit price and/or our access to and costs of capital.
In addition, our continuing efforts to research, establish, accomplish and accurately report on the implementation of our ESG strategy,
including any specific ESG objectives, may also create additional operational risks and expenses and expose us to reputational, legal and
other risks. While we create and publish voluntary disclosures regarding ESG matters from time to time, some of the statements in those
voluntary disclosures may be based on hypothetical expectations and assumptions that may or may not be representative of current or
actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions
are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an
established single approach to identifying, measuring and reporting on many ESG matters. In addition, our current ESG governance
structure may not allow us to adequately identify or manage ESG-related risks and opportunities, which may include failing to achieve
ESG-related strategies and goals.
Certain U.S. federal income tax deductions currently available with respect to natural gas and oil exploration and development may be
eliminated as a result of future legislation.
In recent years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including
certain key U.S. federal income tax provisions currently available to oil and gas companies. Such legislative changes have included, but
have not been limited to, (i) the repeal of the percentage depletion allowance for natural gas and oil properties, (ii) the elimination of
current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and
geophysical expenditures. Although these provisions were largely unchanged in recent federal tax legislation such as the IRA, Congress
could consider, and could include, some or all of these proposals as part of future tax reform legislation. Moreover, other more general
features of any additional tax reform legislation, including changes to cost recovery rules, may be developed that also would change the
taxation of oil and gas companies. It is unclear whether these or similar changes will be enacted in future legislation and, if enacted, how
soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal
income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development or
increase costs, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.
30
Table of Contents
Unanticipated changes in effective tax rates or adverse outcomes resulting from examination of our income or other tax returns could
adversely affect our financial condition and results of operations.
We are subject to taxes by U.S. federal, state and local tax authorities. Our future effective tax rates could be subject to volatility or
adversely affected by a number of factors, including changes in the valuation of our deferred tax assets and liabilities, expected timing and
amount of the release of any tax valuation allowances, or changes in tax laws, regulations, or interpretations thereof. In addition, we may be
subject to audits of our income, sales and other transaction taxes by U.S. federal, state and local taxing authorities. Outcomes from these
audits could have an adverse effect on our financial condition and results of operations.
Our articles of incorporation and bylaws, as well as Texas law, contain provisions that could discourage acquisition bids or merger
proposals, which may adversely affect the market price of our common stock.
Certain provisions of our articles of incorporation and bylaws could make it more difficult for a third-party to acquire control of us,
even if the change of control would be beneficial to our stockholders. Among other things, our articles of incorporation and bylaws:
● provide advance notice procedures with regard to stockholder nominations of candidates for election as directors or other
stockholder proposals to be brought before meetings of our stockholders, which may preclude our stockholders from bringing
certain matters before our stockholders at an annual or special meeting;
● provide our board of directors the ability to authorize issuance of preferred stock in one or more series, which makes it possible
for our board of directors to issue, without stockholder approval, preferred stock with voting or other rights or preferences that
could impede the success of any attempt to change control of us and which may have the effect of deterring hostile takeovers or
delaying changes in control or management of us;
● provide that the authorized number of directors may be changed only by resolution of our board of directors;
● provide that, subject to the rights of holders of any series of preferred stock to elect directors or fill vacancies in respect of such
directors as specified in the related preferred stock designation, all vacancies, including newly created directorships be filled by
the affirmative vote of holders of a majority of directors then in office, even if less than a quorum, or by the sole remaining
director, and will not be filled by our stockholders;
● no cumulative voting in the election of directors, which limits the ability of minority stockholders to elect director candidates;
● provide that, subject to the rights of the holders of shares of any series of preferred stock, if any, to remove directors elected by
such series of preferred stock pursuant to our articles of incorporation (including any preferred stock designation thereunder),
directors may be removed from office at any time, only for cause and by the holders of 60% of the voting power of all outstanding
voting shares entitled to vote generally in the election of directors;
● provide that special meetings of our stockholders may be called by the Chairman of our board of directors, our President, by our
Secretary upon the written request of a majority of the total number of directors of our board of directors, or at least 25% of the
voting power of all outstanding shares entitled to vote generally at the special meeting; and
● provide that the provisions of our articles of incorporation can only be amended or repealed by the affirmative vote of the holders
of at least a majority in voting power of the outstanding shares of our common stock entitled to vote thereon, voting together as a
single class.
Further, we are incorporated in Texas. The Texas Business Organizations Code contains certain provisions that could make an
acquisition by a third party more difficult.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None
31
Table of Contents
ITEM 1C. CYBERSECURITY
We maintain a cyber risk management program designed to identify, assess, manage, mitigate, and respond to cybersecurity threats.
This program is integrated within our information technology (“IT”) and risk management systems and addresses both the corporate and
the operational IT environment.
The underlying controls of the cyber risk management program are based on recognized best practices and standards for cybersecurity
and IT, including the National Institute of Standards and Technology (the “NIST”), the Control Objectives for Information Technologies
(“COBIT”) framework and the International Organization Standardization 27001, Information Security Management System requirements.
We have an annual assessment, performed by our internal audit department, of our cyber risk management program against the NIST and
COBIT frameworks.
Our information security practices include development, implementation, and improvement of policies and procedures to safeguard
information and ensure availability of critical data and systems. We have adopted a Cybersecurity Incident Response Plan that applies if a
security event occurs. Our Incident Response Plan provides a common framework for responding to security incidents. This framework
establishes procedures for identifying, validating, categorizing, documenting, and responding to security events that are identified by or
reported to the Chief Information Officer (CIO). Our Incident Response Plan applies to W&T personnel including contractors and partners
that perform functions or services that require securing W&T information assets, and to all devices and networks that are owned by W&T.
The Incident Response Plan details the coordinated, multi-functional approach for investigating, containing, and mitigating incidents.
Under our Incident Response Plan, cybersecurity incidents are escalated based on a defined incident categorization to the CIO and the
General Counsel. Regular updates are provided by the Cybersecurity team to the CIO, who will maintain communication and information
flow to senior leadership including the General Counsel, Chief Financial Officer, and other cybersecurity program stakeholders as well as
the Audit Committee and/or the Board of Directors as appropriate. Generally, our incident response process follows the National Institute
of Standards and Technology (NIST) framework and focuses on preparation; detection and analysis; containment, eradication, recovery and
post-incident remediation.
We conduct mandatory security training during new employee onboarding, as well as require our employees to complete annual
security risk training and, when necessary, perform additional updated training. We also engage certain third-parties in assessing,
identifying and managing cyber-security risks. These third parties perform a number of services, including managed detection and response
services for information technology endpoints, anti-virus monitoring, penetration testing, and other miscellaneous cyber security programs
and services. We maintain specific policies and practices governing our third-party security risks, including our third-party assessment
process. Under our third-party assessment process, we gather information from certain third parties who contract with us and share or
receive data, or have access to or integrate with our systems, in order to help us assess potential risks associated with their security controls.
We require each third-party service provider to certify that it has the ability to implement and maintain appropriate security measures,
consistent with all applicable laws, to implement and maintain reasonable security measures in connection with their work with us, and to
promptly report any suspected breach of its security measures that may affect us.
The Audit Committee of our board of directors oversees our cybersecurity policies, procedures, risk exposures and the steps taken by
management to monitor and mitigate cybersecurity risks. Our executive management, including our Vice President and Chief Information
Officer, periodically updates and reports to the Audit Committee and the board of directors regarding cybersecurity risk exposure and our
cybersecurity risk management strategy (at a minimum, once per quarter). Additionally, all members of the board of directors attend
quarterly training sessions through internal and external IT specialists, which include review of IT whitepapers, presentations, and other
learning materials. Each of the members of the board of directors has also completed certificated training concerning IT security, IT fraud,
and other common enterprise-level IT threats.
32
Table of Contents
We face risks from cybersecurity threats that could have a material adverse effect on our business, financial condition, results of
operations, cash flows or reputation. In the past three years, we have not experienced a material information security breach but may in the
future. See Risk Factors in Part I, Item 1A in this Form 10-K for additional information.
ITEM 2. PROPERTIES
We lease our corporate headquarters in Houston, Texas. We own and lease our operating and administrative facilities in Alabama and
Louisiana, respectively. We believe our properties and facilities are suitable and adequate for their present and intended purposes and are
operating at a level consistent with the requirements of the industry in which we operate.
Oil and Natural Gas Producing Activities
Our producing fields are located in federal and state waters in the Gulf of Mexico in water depths ranging from less than 10 feet up to
7,300 feet. The reservoirs in our offshore fields are generally characterized as having high porosity and permeability, with higher initial
production rates relative to other domestic reservoirs.
As of December 31, 2023, two of our fields located in the conventional shelf accounted for approximately 64.6% of our proved
reserves on an energy equivalent basis. The following table provides information for these fields:
Mobile Bay Properties
Ship Shoal 349 (Mahogany)
Oil
(MMBbls)
0.2
11.7
NGLs
(MMBbls)
10.1
1.0
Natural Gas Equivalent
Oil
(Bcf)
320.4
18.7
(MMBoe)
63.7
15.8
Percent of
Total
Company
Proved
Reserves
51.8 %
12.8 %
The Mobile Bay Properties (as defined below) and Ship Shoal 349 field are two areas of operations of major significance, which we
define as having year-end proved reserves of 10% or more of the Company’s total proved reserves on an energy equivalent basis. Each area
of operation of major significance is described in detail below. Unless indicated otherwise, “drilling” or “drilled” in the descriptions below
refers to when the drilling reached target depth, as this measurement usually has a higher correlation to changes in proved reserves
compared to using the SEC’s definition for completion. The following are descriptions of these areas of operations:
Mobile Bay Properties
Our interests in certain oil and gas leasehold interests and associated wells and units located off the coast of Alabama, in state coastal
and federal Gulf of Mexico waters approximately 70 miles south of Mobile, Alabama, are referred to as the “Mobile Bay Properties.”
Cumulative field production for the Mobile Bay Properties through 2023 is approximately 896.6 MMBoe gross. The Mobile Bay
Properties produce from the Jurassic age Norphlet eolian sandstone at an average depth of 21,000 feet total vertical depth. As of
December 31, 2023, 56 Norphlet wells have been drilled on the Mobile Bay Properties, 45 of which were successful and 27 of which are
currently producing.
33
Table of Contents
The following table presents our produced oil, NGLs and natural gas volumes (net to our interests) from the Mobile Bay Properties
over the past three years:
Net Sales:
Oil (MBbls)
NGLs (MBbls)
Natural gas (MMcf)
Total oil equivalent (MBoe)
Average realized sales prices:
Oil ($/Bbl)
NGLs ($/Bbl)
Natural gas ($/Mcf)
Oil equivalent ($/Boe)
Average production costs: (1)
Oil equivalent ($/Boe)
Year Ended December 31,
2022
2023
2021
15
925
24,826
5,078
17
941
30,052
5,967
$
41.12
22.53
3.02
18.98
$
51.60
35.45
7.45
43.25
29
998
32,940
6,516
27.49
30.84
3.92
24.68
17.39
$
11.81
$
7.34
$
$
(1)
Includes lease operating expenses, gathering and transportation costs and plugging and abandonment costs.
Ship Shoal 349 Field (Mahogany)
Ship Shoal 349 field is located off the coast of Louisiana, approximately 235 miles southeast of New Orleans, Louisiana. The field area
covers Ship Shoal federal OCS blocks 349 and 359, with a single production platform on Ship Shoal block 349 in 375 feet of water (the
“Ship Shoal 349”). We own a 100% working interest in this field except for an interest in one well owned by Monza. Cumulative field
production through 2023 is approximately 62.4 MMBoe gross. This field is a sub-salt development with nine productive horizons below
salt at depths up to 18,000 feet. As of December 31, 2023, 31 wells have been drilled and 26 were successful. Since acquiring an interest
and subsequently taking over as operator, we have directly participated in drilling 17 wells with a 100% success rate. There has been no
drilling activity since 2019 at Ship Shoal 349.
The following table presents our produced oil, NGLs and natural gas volumes (net to our interests) from the Ship Shoal 349 field over
the past three years:
Net Sales:
Oil (MBbls)
NGLs (MBbls)
Natural gas (MMcf)
Total oil equivalent (MBoe)
Average realized sales prices:
Oil ($/Bbl)
NGLs ($/Bbl)
Natural gas ($/Mcf)
Oil equivalent ($/Boe)
Average production costs: (1)
Oil equivalent ($/Boe)
Year Ended December 31,
2022
2023
2021
1,269
68
1,709
1,622
70.86
28.17
3.41
60.22
$
1,313
104
1,827
1,722
88.36
40.50
7.15
71.03
$
1,667
88
2,565
2,182
65.27
36.85
4.00
56.05
7.61
$
7.63
$
6.60
$
$
(1)
Includes lease operating expenses, gathering and transportation costs and plugging and abandonment costs.
34
Table of Contents
Proved Reserves
Our proved reserves were estimated by Netherland, Sewell & Associates, Inc (“NSAI”), our independent petroleum consultant, and
amounts provided in this Form 10-K are consistent with filings we make with other federal agencies. Our proved reserves as of December
31, 2023, 2022 and 2021 are summarized below:
December 31, 2023
Proved developed producing
Proved developed non-producing
Total proved developed
Proved undeveloped
Total proved
December 31, 2022
Proved developed producing
Proved developed non-producing
Total proved developed
Proved undeveloped
Total proved
December 31, 2021
Proved developed producing
Proved developed non-producing
Total proved developed
Proved undeveloped
Total proved
Oil
(MMBbls)
NGLs
(MMBbls)
Natural
Gas (Bcf)
MMBoe
PV-10
(in millions)
22.2
5.2
27.4
9.6
37.0
23.7
7.4
31.1
9.5
40.6
20.8
6.8
27.6
9.6
37.2
10.0
2.7
12.7
1.0
13.7
16.1
1.5
17.6
1.3
18.9
16.4
1.4
17.8
1.3
19.1
299.4
80.0
379.4
54.6
434.0
499.2
76.8
576.0
58.6
634.6
507.9
41.3
549.2
58.4
607.6
82.1
21.2
103.3
19.7
123.0
123.0
21.8
144.8
20.5
165.3
121.9
15.1
137.0
20.6
157.6
$
$
$
$
$
$
750.1
204.1
954.2
126.7
1,080.9
2,280.8
457.6
2,738.4
390.2
3,128.6
1,185.3
222.9
1,408.2
213.7
1,621.9
In accordance with guidelines established by the SEC, our estimated proved reserves as of December 31, 2023 were determined to be
economically producible under existing economic conditions, which requires the use of SEC pricing. Applying this methodology, the WTI
oil average spot price of $78.21 per barrel and the Henry Hub natural gas average spot price of $2.64 per MMBtu were utilized as the
referenced price and, after adjusting for quality, transportation, fees, energy content and regional price differences, the adjusted average
product prices were $74.79 per barrel for oil, $24.08 per barrel for NGLs and $2.74 per Mcf for natural gas. In determining the estimated
price for NGLs, a ratio was computed for each field of the NGL realized price compared to the oil realized price. This ratio was then
applied to the oil price using SEC guidance. Such prices were held constant throughout the estimated lives of the reserves. Future
production and development costs are based on year-end costs with no escalation.
Reconciliation of Standardized Measure to PV-10
Neither PV-10 nor PV-10 after ARO are financial measures defined under GAAP; therefore, the following table reconciles these
amounts to the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure.
Management believes that the non-GAAP financial measures of PV-10 and PV-10 after ARO are relevant and useful for evaluating the
relative monetary significance of oil and natural gas properties. PV-10 and PV-10 after ARO are used internally when assessing the
potential return on investment related to oil and natural gas properties and in evaluating acquisition opportunities. We believe the use of
pre-tax measures is valuable because there are many unique factors that can impact an individual company when estimating the amount of
future income taxes to be paid. Management believes that the presentation of PV-10 and PV-10 after ARO provide useful information to
investors because they are widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies.
PV-10 and PV-10 after ARO are not measures of financial or operating performance under GAAP, nor are they intended to represent the
current market value of our estimated oil and natural gas reserves. PV-10 and PV-10 after ARO should not be considered in isolation or as
substitutes for the standardized measure of discounted future net cash flows as defined under GAAP. Investors should not assume that PV-
10, or PV-10 after ARO, of our proved oil and natural gas reserves shown above represent a current market value of our estimated oil and
natural gas reserves.
35
Table of Contents
The reconciliation of PV-10 and PV-10 after ARO to the standardized measure of discounted future net cash flows relating to our
estimated proved oil and natural gas reserves is as follows (in millions):
PV-10
Future income taxes, discounted at 10%
PV-10 before ARO
Present value of estimated ARO, discounted at 10%
Standardized measure
Changes in Proved Reserves
2023
1,080.9
(151.0)
929.9
(246.7)
683.2
$
$
December 31,
2022
$
$
3,128.6
(594.1)
2,534.5
(271.5)
2,263.0
$
$
2021
1,621.9
(224.8)
1,397.1
(241.1)
1,156.0
The following table discloses our estimated changes in proved reserves during 2023:
Proved reserves at December 31, 2022
Reserves additions (reductions):
Revisions (1)
Purchases of minerals in place
Production
Net reserve additions (reductions)
Total proved reserves at December 31, 2023
(1) Net revisions are primarily attributable to lower commodity prices.
MMBoe
165.3
(32.2)
2.6
(12.7)
(42.3)
123.0
See Proved Undeveloped Reserves below for a table reconciling the change in proved undeveloped reserves during 2023.
See Financial Statements and Supplementary Data – Note 20 – Supplemental Oil and Gas Disclosures under Part II, Item 8 in this
Form 10-K for additional information.
Our estimates of proved reserves, PV-10 and the standardized measure as December 31, 2023 are calculated based upon SEC
mandated 2023 unweighted average first-day-of-the-month oil and natural gas benchmark prices, and adjusting for quality, transportation
fees, energy content and regional price differentials, which may or may not represent current prices. If prices fall below the 2023 levels,
absent significant proved reserve additions, this may reduce future estimated proved reserve volumes due to lower economic limits and
economic return thresholds for undeveloped reserves, as well as impact our results of operations, cash flows, quarterly full cost impairment
ceiling tests and volume-dependent depletion cost calculations. See Management’s Discussion and Analysis of Financial Condition and
Results of Operations in Part II, Item 7 in this Form 10-K for additional information.
Proved Undeveloped Reserves
Our PUDs were estimated by NSAI, our independent petroleum consultant. Future development costs associated with our PUDs at
December 31, 2023 were estimated at $437.9 million.
The following table presents changes in our PUDs (in MMBoe):
PUDs, beginning of year
Revisions of previous estimates
Purchase of minerals in place
PUDs, end of year
2023
December 31,
2022
20.5
(1.3)
0.5
19.7
20.6
(0.1)
—
20.5
2021
12.2
8.4
—
20.6
36
Table of Contents
The revisions of previous estimates during 2023 were due to changes in SEC pricing. The revisions in 2022 and 2021 were primarily
due to technical revisions and revisions due to changes in SEC pricing at certain of our Ship Shoal fields.
The following table presents our estimates as to the timing of converting our PUDs to proved developed reserves:
Year Scheduled for Development
2024
2025
2026
2027
2028+
Total
Number of PUD
Locations
Percentage of
PUD Reserves
Scheduled to be
Developed
1
6
4
—
1
12
14 %
35 %
48 %
— %
3 %
100 %
As of December 31, 2023, we believe that we will be able to develop all but 3.1 MMBoe (approximately 16%) of the total 19.7
MMBoe classified as PUDs within five years from the date such PUDs were initially recorded. The lone exceptions are at the Mississippi
Canyon 243 field (“Matterhorn”), Ship Shoal 349 and Viosca Knoll 823 field (“Virgo”) where future development drilling has been
planned as sidetracks of existing wellbores due to conductor slot limitations and rig availability. Three sidetrack PUD locations, one each at
Matterhorn, Ship Shoal 349 and Virgo, will be delayed until an existing well is depleted and available to sidetrack. We also plan to
recomplete and convert an existing producer at Matterhorn to water injection for improved recovery following depletion of the existing
well. Based on the latest reserve report, these PUD locations are expected to be developed in 2025 and 2035.
Qualifications of Technical Persons and Internal Controls over Reserves Estimation Process
Our estimated proved reserve information as of December 31, 2023 included in this Form 10-K was prepared by our independent
petroleum consultants, NSAI, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and
guidelines established by the SEC. The NSAI report is based on its independent evaluation of engineering and geophysical data, product
pricing, operating expenses, and the reasonableness of future capital requirements and development timing estimates provided by W&T.
The scope and results of their procedures are summarized in a letter included as an exhibit to this Form 10-K. The primary technical person
at NSAI responsible for overseeing the preparation of the reserves estimates presented herein has been practicing consulting petroleum
engineering at NSAI since 2013 and has over 14 years of prior industry experience. NSAI has informed us that he meets or exceeds the
education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas
Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in the application of industry standard practices
to engineering evaluations as well as the application of SEC and other industry definitions and guidelines.
We maintain an internal staff of reservoir engineers and geoscience professionals who work closely with our independent petroleum
consultant to ensure the integrity, accuracy and timeliness of the data, methods and assumptions used in the preparation of the reserves
estimates. Additionally, our senior management reviews any significant changes to our proved reserves on a quarterly basis. Our Director of
Reservoir Engineering has over 30 years of oil and gas industry experience and has managed the preparation of public company reserve
estimates the last 18 years. He joined the Company in 2016 after spending the preceding 12 years as Director of Corporate Engineering for
Freeport-McMoRan Oil & Gas. He has also served in various engineering and strategic planning roles with both Kerr-McGee and with
Conoco, Inc. He earned a Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1989 and a master’s degree
in Business Administration from the University of Houston in 1999.
37
Table of Contents
Reserve Technologies
Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated
with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic
conditions, operating methods, and government regulations, consistent with the definition in Rule 4-10(a)(24) of Regulation S-X. The term
“reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or
exceed the estimate. To achieve reasonable certainty, our independent petroleum consultant employed technologies that have been
demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved
reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost
information and property ownership interests. The accuracy of the estimates of our reserves is a function of:
● the quality and quantity of available data and the engineering and geological interpretation of that data;
● estimates regarding the amount and timing of future operating costs, severance taxes, development costs and workovers, all of
which may vary considerably from actual results;
● the accuracy of various mandated economic assumptions such as the future prices of oil, NGLs and natural gas; and
● the judgment of the persons preparing the estimates.
Because these estimates depend on many assumptions, any or all of which may differ substantially from actual results, reserve
estimates may be different from the quantities of oil and natural gas that are ultimately recovered.
Reporting of Natural Gas and Natural Gas Liquids
We produce NGLs as part of the processing of our natural gas. The extraction of NGLs in the processing of natural gas reduces the
volume of natural gas available for sale. We report all natural gas production information net of the effect of any reduction in natural gas
volumes resulting from the processing of NGLs.
Developed and Undeveloped Acreage
The following table summarizes our developed and undeveloped acreage at December 31, 2023:
Shelf
Deepwater
Alabama State Waters
Total
Developed Acreage
Net
326,652
56,540
5,144
388,336
Gross
386,916
141,929
8,038
536,883
Undeveloped Acreage
Net
Gross
45,935
5,760
—
51,695
48,698
11,520
—
60,218
Total Acreage
Gross
435,614
153,449
8,038
597,101
Net
372,587
62,300
5,144
440,031
Our net acreage decreased 15,026 net acres (3%) from December 31, 2022 due to lease expirations offset by leases acquired in the
September 2023 acquisition.
38
Table of Contents
Approximately 88.3% of our net acreage is held by production. We have the right to propose future exploration and development
projects on the majority of our acreage. The following table presents the timing of expiration of our undeveloped leasehold acreage:
2024
2025
2026
2027
Thereafter
Total
Undeveloped Acreage
Net
17,122
8,813
—
15,760
10,000
51,695
Percent of
Total
34%
17%
0%
30%
19%
100%
In making decisions regarding drilling and operations activity for 2024 and beyond, we give consideration to undeveloped leasehold
interests that may expire in the near term in order that we might retain the opportunity to extend such acreage.
Drilling Activity
The information presented below is based on the SEC’s criteria of completion or abandonment to determine wells drilled. Of the two
gross (0.6 net) exploratory wells completed during 2022, one gross (0.3 net) well is currently producing. The following table sets forth our
drilling activity for completed wells on a gross basis:
Conventional shelf
Deepwater
Wells operated by W&T
2023
—
—
—
Completed
2022
2021
1
1
1
The following table summarizes our development and exploration offshore wells completed over the past three years:
Development wells completed:
Gross wells
Net wells
Exploration wells completed:
Gross wells
Net wells
Year Ended December 31,
2022
2023
2021
—
—
—
—
—
—
2
0.6
—
—
—
—
—
—
—
During 2022, we completed one well and abandoned one well in which we had a 25% working interest. During 2021, we participated
in the drilling of an exploration well which was non-commercial. Our success rate related to our development and exploration wells was
50% in 2022.
Capital Expenditures
See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources –
Capital Expenditures under Part II, Item 7 in this Form 10-K for capital expenditure information.
39
Table of Contents
Productive Wells
Productive wells consist of producing wells and wells capable of production. Gross wells are the total number of productive wells in
which we have a working interest, regardless of our percentage interest. A net well is not a physical well, but is a concept that reflects
actual working interest we hold in a given well. Our wells may produce both oil and natural gas. We classify a well as an oil well if the net
equivalent production of oil was greater than natural gas for the well.
The following table sets forth information relating to the productive wells in which we owned a working interest as of December 31,
2023:
Operated
Non-operated
Total
Oil Wells (1)
Gas Wells (2)
Total Wells
Gross
Net
Gross
Net
Gross
110.0
33.0
143.0
101.3
5.8
107.1
86.0
12.0
98.0
76.8
5.4
82.2
196.0
45.0
241.0
Net
178.1
11.2
189.3
(1)
(2)
Includes 10 gross (9.1 net) oil wells with multiple completions.
Includes 6 gross (5.1 net) natural gas wells with multiple completions.
Production Data
See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations under Part II,
Item 7 in this Form 10-K for additional information.
ITEM 3. LEGAL PROCEEDINGS
See Financial Statements and Supplementary Data – Note 19 – Contingencies under Part II, Item 8 in this Form 10-K for information
on various legal proceedings to which we are party or our properties are subject.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
40
Table of Contents
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
PURCHASES OF EQUITY SECURITIES
Our common stock is listed and principally traded on the NYSE under the symbol “WTI.” As of March 1, 2024, there were 134
PART II
registered holders of our common stock.
Dividends
On November 8, 2023, we announced that our board of directors approved the implementation of a quarterly cash dividend payable to
holders of our common stock. The initial cash dividend of $0.01 per share of common stock, or $1.5 million, was paid on December 22,
2023, to shareholders of record at the close of business on November 28, 2023. Other than this dividend, we did not declare or pay any cash
dividends on our common stock during 2023 and 2022. The decision to pay additional dividends on our common stock is at the discretion
of our board of directors and is subject to periodic review of our performance, which includes the current economic environment and
applicable debt agreement restrictions.
Stock Performance Graph
The graph below shows the cumulative total shareholder return assuming the investment of $100 in our common stock and the
reinvestment of all dividends thereafter. The information contained in the graph below is furnished and not filed and is not incorporated by
reference into any document that incorporates this Form 10-K by reference.
Issuer Purchases of Equity Securities
None.
Unregistered Sales of Equity Securities
None.
41
Table of Contents
ITEM 6. [RESERVED]
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations is based on, and should be read in
conjunction with Part I, Item 1. Business, Item 2. Properties, Item 1A. Risk Factors and Item 7A. Quantitative and Qualitative Disclosures
About Market Risk and with Part 1I, Item 8. Financial Statements and Supplementary Data and other financial information appearing
elsewhere in this 2023 Form 10-K. The following discussion and analysis includes forward-looking statements that reflect our plans,
estimates and beliefs. Our actual results could differ materially from those anticipated in these forward-looking statements. Factors that
could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this Form 10-K,
particularly in Part I, Item 1A. Risk Factors.
This section primarily discusses 2023 and 2022 items and comparisons between 2023 and 2022. Discussions of 2021 items and
comparisons between 2022 and 2021 that are not included in the Form 10-K are incorporated by reference to Part II, Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations of our Annual Report on Form 10-K for the year ended
December 31, 2022.
Business Overview
We are an independent oil and natural gas producer, active in the exploration, development and acquisition of oil and natural gas
properties in the Gulf of Mexico. As of December 31, 2023, we held working interests in 53 offshore producing fields in federal and state
waters (which include 44 fields in federal waters and nine in state waters). We currently have under lease approximately 597,100 gross
acres (440,000 net acres) spanning across the outer continental shelf off the coasts of Louisiana, Texas, Mississippi and Alabama, with
approximately 8,000 gross acres in Alabama state waters, 435,600 gross acres on the conventional shelf and approximately 153,500 gross
acres in the deepwater. A majority of our daily production is derived from wells we operate. Our interests in fields, leases, structures and
equipment are primarily owned by our wholly-owned subsidiaries and through our proportionately consolidated interest in Monza.
In managing our business, we are focused on optimizing production and making profitable investments, pursuing high rate of return
projects and developing oil and natural gas resources in a manner that allows us to grow our production, reserves and cash flow in a capital
efficient manner, organically enhancing the value of our assets.
Business Outlook
Our cash flows are materially impacted by the prices of commodities we produce (oil, NGLs and natural gas). During 2023,
commodity prices experienced significant declines from those experienced during 2022. The average WTI oil price for 2023 was
approximately 18% lower than the average for 2022 and the average Henry Hub natural gas price for 2023 was approximately 61% lower
than the average for 2022. While the current outlook for commodity prices is favorable, other global factors could adversely impact our
operations, and commodity prices could significantly decline from current levels.
In addition, the prices of goods and services used in our business can vary and impact our cash flows and margins. Our margins in
2023 decreased from 2022 primarily due to lower average realized commodity prices, coupled with higher operating expenses. We measure
margins using an Adjusted EBITDA margin which we define as net income (loss) before income tax expense, net interest expense,
depreciation, depletion, amortization and accretion, unrealized commodity derivative gain or loss and the effects of derivative premium
payments, allowance for credit losses, non-cash incentive compensation, non-recurring costs related to IT services transition, non-ARO
P&A costs, and other miscellaneous costs as a percent of revenue, which is not a financial measurement under GAAP.
Although we have historically increased our reserves and production through acquisitions, our drilling program, and other projects that
optimize production on existing wells, our production decreased 13% in 2023 from the prior year. Our proved reserves also decreased by
42.3 MMBoe in 2023, primarily due to the significant decrease in commodity prices in 2023 as compared to 2022.
42
Table of Contents
We continually monitor current and forecasted commodity prices to assess what changes, if any, should be made to our 2024 plans. See
Liquidity and Capital Resources under this Item 7 in this Form 10-K for additional information.
Recent Developments
On December 13, 2023, we entered into a purchase and sale agreement to acquire rights, titles and interest in and to certain leases,
wells and personal property in the central shelf region of the Gulf of Mexico, among other assets, for a gross purchase price of $72.0
million, subject to customary purchase price adjustments. The transaction closed on January 16, 2024 and was funded using cash on hand.
The Company also assumed the related AROs associated with these assets.
On February 28, 2024, we amended the Credit Agreement to extend the maturity date to March 28, 2024.
On March 5, 2024, we declared a first quarter dividend of $0.01 per share. We expect to pay the dividend on March 25, 2024, to
stockholders of record as of the close of business on March 18, 2024.
Factors Affecting the Comparability of our Financial Condition and Results of Operations
In January 2023, we issued $275.0 million of 11.75% Notes. The 11.75% Notes were issued at par and have a maturity date of
February 1, 2026. In February 2023, we redeemed all of the 9.75% Notes outstanding at a redemption price of 100.000%, plus accrued and
unpaid interest to the redemption date. We used the net proceeds from the issuance of the 11.75% Notes and $296.1 million of cash on hand
to fund the redemption. See Financial Statements and Supplementary Data –Note 2 – Debt under Part II, Item 8 in this Form 10-K for
additional information.
In September 2023, we acquired working interests in certain oil and natural gas producing assets in the central and eastern shelf region
of the Gulf of Mexico for $27.4 million. This transaction is described in more detail under Financial Statements and Supplementary Data –
Note 7 – Acquisitions, under Part II, Item 8 of this Annual Report.
Known Trends and Uncertainties
Volatility in Oil, NGL and Natural Gas Prices – Historically, the markets for oil and natural gas have been volatile. Our cash flows are
materially impacted by the prices of commodities we produce (oil and natural gas, and the NGLs extracted from the natural gas). Our
realized sales prices received for our oil, NGLs and natural gas production are affected by many factors outside of our control, including
changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels,
domestic production activities and political issues, and international geopolitical and economic events. For 2023, our realized prices for oil
decreased 19%, NGLs decreased 38% and natural gas decreased 59% from 2022, having an adverse impact on our margins in addition to
increased operating expenses. As a result, we cannot accurately predict future commodity prices, therefore, we cannot determine with any
degree of certainty what effect increases or decreases in these prices will have on our drilling program, production volumes or revenues.
The U.S. Energy Information Administration (“EIA”) published its latest Short-Term Energy Outlook in February 2024. Spot prices for
WTI oil averaged $77.58 per barrel in 2023, and the EIA is forecasting WTI spot prices to average $77.68 for 2024. The WTI oil spot price
increased in January 2024 compared with the December 2023 average price of $71.89 per barrel, averaging $73.82 per barrel because of
heightened uncertainty about global oil shipments as attacks to vessels in the Red Sea intensified. The EIA is forecasting WTI spot prices
will rise into the mid-$80 per barrel range in the coming months, but downward pressures may emerge in 2024 as global oil inventories
increase. Ongoing risks of supply disruptions in the Middle East could create the potential for oil prices to be higher than the EIA has
forecasted.
Spot prices for Henry Hub natural gas averaged $2.53 per MMBtu in 2023, and the EIA is forecasting that Henry Hub prices will
average $2.65 in 2024. The Henry Hub spot price averaged $3.23 per MMBtu in January 2024; however, spot prices were volatile, rising
sharply to $13.20 per MMBtu on January 12 in anticipation of severely cold weather throughout the U.S. for the following weekend. After
the weekend, prices quickly fell and continued to decrease until January 23, when the price hit the monthly low of $2.15 per MMBtu. Mild
weather for the remainder of the first quarter of 2024 could keep the average Henry Hub spot price near $2.40 per MMBtu during February
and March, but volatility could return if severely cold weather emerges, even for a short period.
43
Table of Contents
We hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Financial Statements
and Supplementary Data – Note 4 – Derivative Financial Instruments, under Part II, Item 8 of this Annual Report for additional
information regarding our commodity derivative positions as of December 31, 2023.
A prolonged period of weak commodity prices may create uncertainties in our financial condition and results of operations. Such
uncertainties may include:
● ceiling test write-downs of the carrying value of our oil and gas properties;
● reductions in our proved reserves and the estimated value thereof;
● additional supplemental bonding and potential collateral requirements;
● reductions in our borrowing base under the Credit Agreement; and
● our ability to fund capital expenditures needed to replace produced reserves, which must be replaced on a long-term basis to
provide cash to fund liquidity needs described above.
Rising Interest Rates and Inflation of Cost of Goods, Services and Personnel – Due to the cyclical nature of the oil and gas industry,
fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise,
the cost of oilfield goods and services generally also increase, while during periods of commodity price declines, decreases in oilfield costs
typically lag behind commodity price decreases. Continued inflationary pressures and increased commodity prices may also result in
increases in the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs
to rise.
The United States has experienced a rise in inflation since October 2021. Inflation peaked during mid-2022 at 9.1% but the rate of
inflation has been gradually declining since the second half of 2022 according to the Consumer Price Index (the “CPI”). The annual
inflation rate for December 2023 was 3.4%. These inflationary pressures have caused the Federal Reserve to tighten monetary policy by
approving a series of increases to the Federal Funds Rate. As of December 31, 2023, the Federal Reserve benchmark rate ranged from
5.25% to 5.50%. Although the Federal Reserve has stated that they will begin reducing the benchmark rate in 2024, if inflation were to
continue to rise, it is possible the Federal Reserve would continue to take action they deem necessary to bring inflation down and to ensure
price stability, including further rate increases, which could have the effects of raising the cost of capital and depressing economic growth,
either or both of which could negatively impact our business.
Inflation Reduction Act of 2022 – In August 2022, President Biden signed the IRA into law. Several provisions in the IRA are expected
to apply to our business. For instance, the IRA specifically directs the DOI to accept the highest bids received for Lease Sale 257, which
was vacated by U.S. District Court for the District of Columbia in January 2022, and move forward with Lease Sales 259 and 261 in the
Gulf of Mexico, notwithstanding the June 30, 2022 expiration of the 2017-2022 Outer Continental Shelf Oil and Gas Leasing Program.
Lease Sale 259 was held in March 2023, and Lease Sale 261 was held in December 2023.
In September 2023, consistent with the requirements of the IRA concerning offshore conventional and renewable energy leasing, the
DOI announced its proposed 2024 – 2029 OCS Program. The proposed OCS Program includes a maximum of three potential oil and
natural gas lease sales in the Gulf of Mexico scheduled in 2025, 2027 and 2029. In compliance with the IRA, these three lease sales are the
minimum number that will enable the DOI to continue to expand its offshore wind leasing program through 2030. The reduction of the
proposed OCS Program to a maximum of three potential lease sales will bring the federal oil and natural gas program in line with the Biden
administration’s goal of net zero emissions by 2050 and meet the IRA’s requirement for future offshore renewable energy leasing.
The IRA also increases the minimum oil and gas royalty rate for new offshore leases from the current 12.50% to 16.67% and caps the
royalty rate at 18.75% for 10 years. The 18.75% cap is commensurate with existing offshore royalty rate for leases in water depth
exceeding 200 meters. This provision does not affect existing offshore leases.
44
Table of Contents
Furthermore, the IRA amends the federal Clean Air Act to impose a fee on emissions of methane from sources required to report their
greenhouse gas emissions to the EPA, including sources in the offshore and onshore oil and gas production, and onshore processing,
transmission and compression, gathering, and boosting station source categories. For such qualifying facilities, the charge starts at $900 per
metric ton of methane reported for calendar year 2024. In 2025, the charge increases to $1,200 per metric ton of methane. For calendar year
2026 and thereafter, the fee will be $1,500 per metric ton of methane. Calculation of the charge is based on certain thresholds established in
the IRA. The charge will be based on the prior year’s emissions, and the first fee payment will be in 2025 based on 2024 data. The methane
emissions charge may increase our operating costs and adversely affect our business.
Impairment of Oil and Natural Gas Properties – Under the full cost method of accounting that we use for our oil and gas operations,
our capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a
discount factor of 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized
less the related tax effects. Any costs in excess of the ceiling are recognized as a non-cash “Write-down of oil and natural gas properties”
on the Consolidated Statements of Operations and an increase to “Accumulated depreciation, depletion and amortization” on our
Consolidated Balance Sheets. The expense may not be reversed in future periods, even though higher oil, NGL and natural gas prices may
subsequently increase the ceiling. We perform this ceiling test calculation each quarter. In accordance with SEC rules and regulations, we
utilize SEC pricing when performing the ceiling test. At December 31, 2023, our ceiling test computation was based on SEC pricing of
$78.21 per Bbl of oil and $2.64 per Mcf of natural gas.
As part of our period end reserves estimation process for future periods, we expect changes in the key assumptions used, which could
be significant, including updates to future pricing estimates and differentials, future production estimates to align with our anticipated five-
year drilling plan and changes in our capital costs and operating expense assumptions. There is a significant degree of uncertainty with the
assumptions used to estimate future undiscounted cash flows due to, but not limited to, the risk factors referred to in Part I, Item 1A. Risk
Factors. Any decrease in pricing, negative change in price differentials, or increase in capital or operating costs could negatively impact the
estimated undiscounted cash flows related to our proved oil and natural gas properties.
Deferred Production – Our oil, NGLs and natural gas production is significantly affected by both planned and unplanned production
downtime caused by events such as planned repairs and upgrades, third-party downtime associated with non-operated properties, the
transportation, gathering or processing of production and weather events. For 2023, we estimate deferred production was approximately
2,541 MBoe.
Regulations – We are subject to a number of regulations from federal and state governmental entities, which are described under Part I,
Item 1. Business ‒ Environmental, Health and Safety Matters and Government Regulations in this Form 10-K. We and others like us,
are exposed to a number of risks by operating in the oil and natural gas industry in the Gulf of Mexico, which are described in Item 1A.
Risk Factors, in this Form 10-K.
BOEM Matters – The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations or provide
acceptable financial assurances to satisfy lease obligations, including decommissioning activities on the OCS. As of December 31, 2023,
we are in compliance with our financial assurance obligations to the BOEM and have no outstanding BOEM orders related to financial
assurance obligations. We and other offshore Gulf of Mexico producers may, in the ordinary course of business, receive demands in the
future for financial assurances from the BOEM as the BOEM continues to reevaluate its requirements for financial assurance. For more
information on the BOEM and financial assurance obligations to that agency, see Business – Environmental, Health and Safety Matters and
Government Regulations – Other Regulation of the Oil and Natural Gas Industry under Part I, Item 1 of this Form 10-K.
45
Table of Contents
Surety Bond Collateral – In prior years, some of the sureties that provide us surety bonds used for supplemental financial assurance
purposes have requested and received collateral from us and may request additional collateral from us in the future, which could be
significant and could impact our liquidity. In addition, pursuant to the terms of our agreements with various sureties under our existing
bonds or under any additional bonds we may obtain, we are required to post collateral at any time, on demand, at the surety’s discretion. In
both 2023 and 2022, we have not had to post collateral for sureties, and we currently do not have any collateral posted for surety bonds.
The issuance of any additional surety bonds or other security to satisfy future BOEM orders, collateral requests from surety bond providers
and collateral requests from other third-parties may require the posting of cash collateral, which may be significant, and may require the
creation of escrow accounts.
RESULTS OF OPERATIONS
Year Ended December 31, 2023 Compared to Year Ended December 31, 2022
Revenues
Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs. Our oil, NGL and natural gas
revenues do not include the effects of derivatives, which are reported in Derivative (gain) loss, net in our Consolidated Statements of
Operations. The following table presents our sources of revenue as a percentage of total revenue:
Oil
NGLs
Natural gas
Other
Year Ended December 31,
2022
2023
71.6 %
6.1 %
20.7 %
1.6 %
56.9 %
6.2 %
35.2 %
1.7 %
46
Table of Contents
The information below provides a discussion of, and an analysis of significant variance in, our oil, NGL and natural gas revenues,
production volumes and average sales prices for 2023 and 2022 (in thousands):
Revenues:
Oil
NGLs
Natural gas
Other
Total revenues
Production Volumes:
Oil (MBbls)
NGLs (MBbls)
Natural gas (MMcf)
Total oil equivalent (MBoe)
Average daily equivalent sales (Boe/day)
Average realized sales prices:
Oil ($/Bbl)
NGLs ($/Bbl)
Natural gas ($/Mcf)
Oil equivalent ($/Boe)
Oil equivalent ($/Boe), including realized commodity derivatives
Year Ended December 31,
2023
2022
Change
$
$
$
$
$
$
381,389
32,446
110,158
8,663
532,656
5,050
1,415
37,591
12,730
34,877
75.52
22.93
2.93
41.16
40.84
$
$
$
524,274
56,964
323,831
15,928
920,997
5,602
1,554
44,808
14,624
40,067
93.59
36.66
7.23
61.89
59.15
(142,885)
(24,518)
(213,673)
(7,265)
(388,341)
(552)
(139)
(7,217)
(1,894)
(5,190)
(18.07)
(13.73)
(4.30)
(20.73)
(18.31)
Changes in average sales prices and sales volumes caused the following changes to our oil, NGL and natural gas revenues between
2023 and 2022 (in thousands):
Oil
NGLs
Natural gas
Price
Volume
Total
$
$
(91,250)
(19,398)
(161,513)
(272,161)
$
$
(51,635)
(5,120)
(52,160)
(108,915)
$
$
(142,885)
(24,518)
(213,673)
(381,076)
Realized Prices on the Sale of Oil, NGLs and Natural Gas – Our average realized sales price for oil differs from the WTI average spot
price primarily due to premiums or discounts, quality adjustments, location adjustments and volume weighting (collectively referred to as
differentials). Oil quality adjustments can vary significantly by field as a result of quality and location. All of our oil is produced offshore in
the Gulf of Mexico and is primarily characterized as Poseidon, Light Louisiana Sweet and Heavy Louisiana Sweet. Similar to oil prices, the
differentials for these types of oil can vary based on the aforementioned factors and have experienced volatility in the past.
Two major components of our NGLs, ethane and propane, typically make up over 70% of an average NGL barrel. The changes in
realized sales prices for NGLs are mostly a function of the change in oil prices combined with changes in supply and demand for propane
and ethane.
The prices we realize for sales of natural gas differ from quoted Henry Hub spot prices as a result of quality and location differentials.
During 2023, we experienced a positive natural gas differential due to approximately 70% of our natural gas being sold in a Florida market
area, which had a premium to Henry Hub.
47
Table of Contents
Oil, NGLs, and Natural Gas Volumes – Production volumes decreased by 1,894 MBoe to 12,730 MBoe during 2023 primarily due to
downtime related to field and well maintenance events, primarily at Mobile Bay and other OCS fields, and natural production declines,
partially offset by production from the acquisition completed in September 2023.
Operating Expenses
The following table presents information regarding costs and expenses and selected average costs and expenses per Boe sold for the
periods presented and corresponding changes (in thousands):
Operating expenses:
Lease operating expenses
Gathering, transportation and production taxes
Depreciation, depletion and amortization
Asset retirement obligations accretion expense
General and administrative expenses
Total operating expenses
Average per Boe ($/Boe):
Lease operating expenses
Gathering, transportation and production taxes
Depreciation, depletion and amortization
Asset retirement obligations accretion expense
General and administrative expenses
Total operating expenses
Year Ended December 31,
2022
2023
Change
$
$
$
$
257,676
26,250
114,677
29,018
75,541
503,162
20.24
2.06
9.01
2.28
5.93
39.52
$
$
$
$
224,414
35,128
107,122
26,508
73,747
466,919
15.35
2.40
7.33
1.81
5.04
31.93
$
$
$
$
33,262
(8,878)
7,555
2,510
1,794
36,243
4.89
(0.34)
1.68
0.47
0.89
7.59
Lease operating expenses – Lease operating expenses include the expense of operating and maintaining our wells, platforms and other
infrastructure primarily in the Gulf of Mexico. These operating costs are comprised of several components including direct or base lease
operating expenses, insurance premiums, workover costs and facility maintenance expenses. Our lease operating costs, which depend in
part on the type of commodity produced, the level of workover activity and the geographical location of the properties, increased
$33.3 million to $257.7 million in 2023 compared to $224.4 million in 2022. On a per Boe basis, lease operating expenses increased to
$20.24 per Boe during 2023 compared to $15.35 per Boe during 2022. On a component basis, base lease operating expenses increased
$15.2 million, workover expenses increased $9.7 million and facility maintenance expenses increased $8.7 million. These increases were
partially offset by a decrease of $0.3 million in hurricane repairs.
Expenses for direct labor, materials, supplies, repair, third-party costs and insurance comprise the most significant portion of our base
lease operating expense. Base lease operating expenses increased primarily due to a full year of expenses at the fields acquired in February
2022 and three months of expenses at the fields acquired in September 2023, as well as higher repair, maintenance and labor costs at other
fields. In addition, expenses related to our insurance coverage also increased due to higher premiums on our policies that were renewed in
June 2023.
Workover and facility maintenance expenses consist of costs associated with major remedial operations on completed wells to restore,
maintain or improve the well’s production. Since these remedial operations are not regularly scheduled, workover and maintenance expense
are not necessarily comparable from period to period. During 2023, we incurred $12.0 million in workover expenses primarily at our
Mobile Bay Properties due to numerous workover projects including well cleanout, recovering of fishing tools and stimulating to return the
wells back to production.
Gathering, transportation and production taxes – Gathering and transportation consist of costs incurred in the post-production
shipping of oil, NGLs, and natural gas to the point of sale. Production taxes consist of severance taxes levied by the Alabama Department
of Revenue and the Texas Department of Revenue on production of oil and natural gas from land or water bottoms within the boundaries of
each state, respectively. Gathering, transportation and production taxes decreased to $26.3 million in 2023 compared to $35.1 million in
2022, primarily due to lower production volumes and realized prices partially offset by the transportation contract related to the properties
acquired in 2022.
48
Table of Contents
Depreciation, depletion and amortization – Depreciation, depletion and amortization expense (“DD&A”) is the expensing of the
capitalized costs incurred to acquire, explore and develop oil and natural gas reserves. We use the full cost method of accounting for oil and
natural gas activities. See Part II, Item 8. Financial Statements and Supplementary Data — Note 1 — Summary of Significant Accounting
Policies for further discussion. DD&A increased to $114.7 million in 2023 from $107.1 million in 2022. The DD&A rate increased to $9.01
per Boe in 2023 from $7.33 per Boe in 2022. The DD&A rate per Boe increased primarily as a result of a higher depreciable base due to
increases in capital expenditures, future development costs and capitalized ARO and lower proved reserves.
Asset retirement obligations accretion expense – Accretion expense is the expensing of the changes in value of our ARO as a result of
the passage of time over the estimated productive life of the related assets as the discounted liabilities are accreted to their expected
settlement values. Accretion expense increased to $29.0 million in 2023 compared to $26.5 million in 2022 primarily due to the increase in
our ARO liability (see Part II, Item 8. Financial Statements and Supplementary Data — Note 8 — Asset Retirement Obligations).
General and administrative expenses (“G&A”) – G&A expense generally consists of costs incurred for overhead, including payroll
and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production operations, bad debt expense,
share-based compensation costs, audit and other fees for professional services and legal compliance. For 2023, G&A expenses
were $75.5 million compared to $73.7 million in 2022. The increase is primarily due to increased payroll costs, share-based compensation
costs and professional fees, partially offset by a decrease in legal expenses and a $2.2 million employee retention credit recorded in 2023.
Share-based compensation costs were higher due to the higher grant date fair values of share-based compensation awards outstanding
during 2023 as compared to the value of awards outstanding during 2022. Legal expenses decreased primarily due to non-recurring legal
fees incurred during 2022 related to a review of processes and controls within our information technology department.
Other Income and Expense
The following table presents the components of other income and expense for the periods presented and corresponding changes (in
thousands):
Derivative (gain) loss, net
Interest expense, net
Other expense, net
Income tax expense
Year Ended December 31,
2022
2023
$
$
(54,759)
44,689
5,621
18,345
$
85,533
69,441
14,295
53,660
Change
(140,292)
(24,752)
(8,674)
(35,315)
Derivative (gain) loss – During 2023, the $54.8 million derivative gain consisted of $4.1 million of realized losses on settled contracts
and $58.9 million of unrealized gain, net, from the increase in the fair value of the open contracts. During 2022, the $85.5 million
derivative loss recorded for oil and natural gas derivative contracts consisted of $125.1 million of premium payments and realized losses on
settled contracts and $39.6 million of unrealized gain, net from the increase in fair value of open contracts. During the second quarter of
2022, the Company monetized a portion of existing hedge positions through restructuring of strike prices on certain outstanding purchased
calls covering the second half of 2022 through the first quarter of 2025. This transaction resulted in net cash proceeds of $105.3 million,
which are included as an offset to realized losses for 2022.
Unrealized gains or losses on open derivative contracts relate to production for future periods; however, changes in the fair value of all
of our open derivative contracts are recorded as a gain or loss on our Consolidated Statements of Operations at the end of each month. As a
result of the derivative contracts we have on our anticipated natural gas production volumes through April 2028, we expect these activities
to continue to impact net income based on fluctuations in market prices for natural gas. As of December 31, 2023, we do not have any open
oil contracts. See Financial Statements and Supplementary Data – Note 4 – Derivative Financial Instruments under Part II, Item 8 in this
Form 10-K for additional information.
49
Table of Contents
Interest expense, net – Interest expense, net of interest income, was $44.7 million during 2023, decreasing $24.8 million from
$69.4 million during 2022. The decrease is primarily due to the redemption of the 9.75% Notes in February 2023, decreased interest
expense on the lower outstanding principal balance of the Term Loan and an increase in interest income, partially offset by interest expense
incurred on the 11.75% Notes issued in late January 2023. See Financial Statements and Supplementary Data – Note 2 – Debt under Part
II, Item 8 in this Form 10-K for additional information on our debt.
Other expense, net – During 2023, other expense, net, was $5.6 million, compared to $14.3 million for 2022. During both 2023 and
2022, other expense primarily consisted of additional expenses for net abandonment obligations pertaining to a number of legacy Gulf of
Mexico properties.
Income tax expense – Our effective tax rates for 2023 and 2022 were 54.0% and 18.8%, respectively. In 2023, the rate differed from
the federal statutory rate of 21% primarily due to adjustments in the valuation allowance, compensation adjustments and the impact of state
income taxes. In 2022, the rate differed from the federal statutory rate primarily due to adjustments in the valuation allowance and the
impact of state income taxes.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity Overview
Our primary liquidity needs are to fund capital and operating expenditures and strategic acquisitions to allow us to replace our oil and
natural gas reserves, repay and service outstanding borrowings, operate our properties and satisfy our ARO. We have funded such activities
in the past with cash on hand, net cash provided by operating activities, sales of property, securities offerings and bank and other
borrowings, and expect to continue to do so in the future.
We expect to support our business requirements primarily with cash on hand and cash generated from operations. As of
December 31, 2023, we had $173.3 million of available cash on hand and $50.0 million available under our Credit Agreement, based on a
borrowing base of $50.0 million. We also have up to approximately $83.0 million of availability through our “at-the-market” equity
offering program, pursuant to which we may offer and sell shares of our common stock from time to time. Based on our current financial
condition and current expectations of future market conditions, we believe our cash on hand, cash flows from operating activities and
access to the equity markets from our “at-the-market” equity offering program will provide us with additional liquidity to continue our
growth to take advantage of the current commodity environment and will allow us to meet our cash requirements for at least the next 12
months.
We continuously review our liquidity and capital resources. If market conditions were to change, for instance, due to uncertainty
created by geopolitical events, a pandemic or a significant prolonged decline in oil and natural gas prices, and our revenue was reduced
significantly or operating costs were to increase significantly, our cash flows and liquidity could be negatively impacted.
Cash Flow Information
The following table summarizes cash flows provided by (used in) by type of activity for the following periods (in thousands):
Operating activities
Investing activities
Financing activities
Year Ended December 31,
2022
2023
$
$
115,326
(81,608)
(321,737)
$
339,530
(95,080)
(28,892)
Change
(224,204)
13,472
(292,845)
50
Table of Contents
Operating activities – Net cash provided by operating activities for 2023 was $115.3 million, decreasing $224.2 million from 2022.
The change between periods is primarily due to (i) a $388.3 million decrease in revenues and (ii) a $36.2 million increase in operating
expenses, partially offset by (iii) a $79.1 million decrease in derivative cash settlements, including premium payments, and (iv) a $29.0
million decrease in interest paid. These decreases in operating cash flow were partially offset by the changes in operating assets and
liabilities which increased operating cash flows by $25.1 million primarily related to (i) lower accounts receivable balance due to decreased
realized prices, (ii) and lower accounts payable and accrued liabilities balances in the current period and (iii) a $42.3 million decrease in
ARO settlements.
Investing activities – Net cash used in investing activities for 2023 decreased $13.5 million compared to 2022. This was primarily due
to decreases of $24.1 million in acquisition of property interests and $1.7 million in investment in oil and natural gas properties, partially
offset by the purchase of the corporate aircraft and furniture, fixtures and other.
Financing activities – Net cash used in financing activities during 2023 increased by $292.8 million compared to 2022. This was
primarily due to long-term debt repayments of $544.0 million, primarily due to the redemption of the $552.5 million principal amount
outstanding 9.75% Notes and the $16.5 million of net proceeds received from the sales of equity securities under our at-the-market equity
offering program in 2022, partially offset by the $275.0 million in proceeds from the issuance of the 11.75% Notes.
Capital Expenditures
The level of our investment in oil and natural gas properties changes from time to time depending on numerous factors including the
prices of oil, NGLs and natural gas, acquisition opportunities, liquidity and financing options and the results of our exploration and
development activities. The following table presents our investments in oil and gas properties and equipment for exploration, development,
acquisitions and other leasehold costs (in thousands):
Exploration (1)
Development (1)
Acquisitions of interests
Seismic and other
Investments in oil and gas property/equipment – accrual basis
(1)
Reported geographically in the subsequent table.
Year Ended December 31,
2022
2023
4,659
35,356
27,384
1,263
68,662
$
$
13,339
20,390
51,474
7,903
93,106
$
$
The following table presents our exploration and development capital expenditures geographically (in thousands):
Conventional shelf (1)
Deepwater
Exploration and development capital expenditures – accrual basis
(1)
Includes exploration and development capital expenditures in Alabama state waters.
Year Ended December 31,
2022
2023
14,464
25,551
40,015
$
17,264
16,465
33,729
$
Our preliminary capital expenditure budget for 2024 has been established in the range of $35.0 million to $45.0 million, which
excludes acquisitions. In our view of the outlook for 2024, we believe this level of capital expenditure will enhance our liquidity capacity
throughout 2024 and beyond while providing liquidity to make strategic acquisitions. At current pricing levels, we expect our cash flows to
cover our liquidity requirements, and we expect additional financing sources to be available if needed. If our liquidity becomes stressed
from significant or prolonged reductions in realized prices, we have flexibility in our capital expenditure budget to reduce investments. We
strive to maintain flexibility in our capital expenditure projects and if commodity prices improve, we may increase our investments.
51
Table of Contents
Acquisitions
We have grown by making strategic acquisitions of producing properties in the Gulf of Mexico. We seek opportunities where we can
exploit additional drilling projects and reduce costs. In September 2023, we acquired eight shallow water oil and natural gas producing
assets in the central and eastern shelf region of the Gulf of Mexico for $27.4 million, after normal and customary post-effective date
adjustments (including net operating cash flow attributable to the properties from the effective date to the respective closing date). The
transaction was funded with cash on hand.
On December 13, 2023, we entered into a purchase and sale agreement to acquire rights, titles and interest in and to certain leases,
wells and personal property in the central shelf region of the Gulf of Mexico, among other assets, for a gross purchase price of $72.0
million, subject to customary purchase price adjustments. The transaction closed on January 16, 2024 and was funded using cash on hand.
Any future acquisitions are subject to the completion of satisfactory due diligence, the negotiation and resolution of significant legal
issues, the negotiation, documentation and completion of mutually satisfactory definitive agreements among the parties, the consent of our
lenders, our ability to finance the acquisition and approval of our board of directors. We cannot guarantee that any such potential
transaction would be completed on acceptable terms, if at all.
Asset Retirement Obligations
Annually, we review and revise our ARO estimates. Our ARO at December 31, 2023 and 2022 were $498.8 million and
$466.4 million, respectively. The increase is primarily due to revisions in expected timing and amount of costs to be incurred. These
increases were partially offset by $34.0 million related to liabilities settled during 2023. Our estimate of ARO spending in 2024 is
approximately $35.0 to $45.0 million. During 2023 and 2022, we revised our estimates of costs anticipated to be charged by service
providers for plugging and abandonment projects and revised our estimates to actual spending as invoices were processed and projects
were completed. As these estimates are for work to be performed in the future, and in many cases, several years in the future, actual
expenditures could be substantially different than our estimates. Additionally, we revise our estimates to account for the cost to comply
with any new or revised regulations, including increases in work scope and cost changes from interpretation of work scope. See Part I,
Item 1A. Risk Factors and Financial Statements and Supplementary Data – Note 8 – Asset Retirement Obligations under Part II, Item 8 in
this Form 10-K for additional information regarding our ARO.
Debt
The primary terms of our long-term debt, the conditions related to incurring additional debt, and the conditions and limitations
concerning early repayment of certain debt are disclosed in Financial Statements and Supplementary Data –Note 2 – Debt under Part II,
Item 8 in this Form 10-K.
Term Loan – As of December 31, 2023, we had $114.2 million of Term Loan principal outstanding. The Term Loan requires quarterly
amortization payments, bears interest at a fixed rate of 7.0% per annum and will mature on May 19, 2028. The Term Loan is non-recourse
to us and our subsidiaries other than the Subsidiary Borrowers (and the subsidiary that owns the equity of the Subsidiary Borrowers) and is
not secured by any assets other than first lien security interests in the equity in the Borrowers and a first lien mortgage security interest and
mortgages on certain assets of the Subsidiary Borrowers.
11.75% Senior Second Lien Notes due 2026 – As of December 31, 2023, we had $275.0 million in aggregate principal amount of our
11.75% Notes issued and outstanding. The 11.75% Notes were issued at par with an interest rate of 11.75% per annum that matures on
February 1, 2026. The 11.75% Senior Second Lien Notes are secured by second-priority liens on the same collateral that is secured under
the Credit Agreement.
Credit Agreement – As of December 31, 2023, we had no borrowings outstanding under the Credit Agreement. On February 28, 2024,
we amended the Credit Agreement to extend the maturity date to March 28, 2024.
52
Table of Contents
TVPX Loan – As of December 31, 2023, we had $11.0 million of TVPX Loan principal outstanding. The TVPX Loan bears a fixed
interest rate of 2.49% per annum for a term of 41 months and requires monthly amortization payments of $91.7 thousand plus accrued
interest, and a balloon payment of $8.0 million at the end of the loan term.
Debt Covenants – The Term Loan, Credit Agreement and 11.75% Notes contain financial covenants calculated as of the last day of
each fiscal quarter, which include thresholds on financial ratios, as defined in the respective Subsidiary Credit Agreement, the Credit
Agreement and the indenture related to the 11.75% Notes. We were in compliance with all applicable covenants of the Term Loan, Credit
Agreement and the 11.75% Notes indenture as of and for the period ended December 31, 2023.
Dividends
On November 8, 2023, we announced that our board of directors approved the implementation of a quarterly cash dividend payable to
holders of common stock. The initial cash dividend of $0.01 per share of common stock, or $1.5 million, was paid on December 22, 2023,
to shareholders of record at the close of business on November 28, 2023. The amount and frequency of future dividends is subject to the
discretion of our board of directors and primarily depends on earnings, capital expenditures, debt covenants, and various other factors.
Contractual Obligations and Commitments
Our material cash commitments from known contractual and other obligations consist primarily of obligations for long-term debt and
related interest, operating leases, ARO and other obligations as part of normal operations. Certain amounts included in our contractual
obligations as of December 31, 2023 are based on our estimates and assumptions about these obligations, including their duration,
anticipated actions by third parties and other factors.
53
Table of Contents
The following table summarizes our significant contractual obligations as of December 31, 2023 by maturity (in millions):
Long-term debt – principal
Long-term debt – interest (1)
Operating leases
Asset retirement obligations (2)
Drilling rig commitment (3)
Other liabilities and commitments (4)
Total
Total
400.2
85.5
21.7
498.8
9.9
99.9
1,116.0
$
$
$
$
Less than
One Year
One to
Three
Years
Three to
Five Years
More Than
Five Years
31.2
39.7
2.2
31.6
—
8.0
112.7
$
$
338.0
43.8
3.2
64.4
9.9
14.4
473.7
$
$
31.0
2.0
3.4
87.8
—
13.1
137.3
$
$
—
—
12.9
315.0
—
64.4
392.3
(1) Amounts represent the expected cash payments for interest based on the principal amounts outstanding and the stated interest rates and were calculated through the
stated maturity date of the related debt.
(2) Amounts represent estimates of future payments and are presented on a discounted basis, consistent with the amount reported on our Consolidated Balance sheet. Actual
payments and the timing of the payments may be significantly different than our estimates.
(3) During 2023, we entered into a contract for a drilling rig. The contract is to begin in February 2025 and terminate in October 2025.
(4) Other liabilities and commitments primarily consist of estimated fees for surety bonds related to obligations under certain purchase and sale agreements and for
supplemental bonding for plugging and abandonment. As of December 31, 2023, we had approximately $454.2 million of bonds outstanding, with the majority related to
plugging and abandonment obligations. The amounts are based on current market rates and conditions for these types of bonds and are subject to change. Excluded are
potential increases in surety bond requirements which cannot be determined. Additionally, other liabilities and commitments include estimates of minimum quantities
obligations for certain pipeline contracts which were assumed in conjunction with the purchase of an interest in the Heidelberg field. These amounts exclude our
obligations under joint interest arrangements related to commitments that have not yet been incurred. In these instances, we are obligated to pay, according to our interest
ownership, a portion of exploration and development costs, and operating costs, which potentially could be offset by our interest in future revenue from these non-
operated properties. These joint interest obligations for future commitments cannot be determined due to the variability of factors involved. See Financial Statements
and Supplementary Data – Note 17 – Commitments under Part II, Item 8 in this 10-K for additional information.
THE SUBSIDIARY BORROWERS
During 2021, we formed A-I LLC and A-II LLC, both indirect, wholly-owned subsidiaries, through their parent, Aquasition Energy
LLC (collectively, the “Aquasition Entities”). Concurrently, we designated the Aquasition Entities as unrestricted subsidiaries under the
Indenture (the “Unrestricted Subsidiaries”). Having been so designated, the Unrestricted Subsidiaries do not guarantee the 11.75% Notes.
The Unrestricted Subsidiaries are not bound by the covenants contained in the indenture related to our 11.75% Notes. Under the credit
agreement the Aquasition Entities are party to (the “Subsidiary Credit Agreement”) and related instruments, assets of the Aquasition
Entities may not be available to mortgage or pledge as security to secure new indebtedness of us and our other subsidiaries. See Financial
Statements and Supplementary Data – Note 2 – Debt under Part II, Item 8 in this Form 10-K for additional information.
54
Table of Contents
Below is consolidating balance sheet information reflecting the elimination of the accounts of our Unrestricted Subsidiaries from our
Consolidated Balance Sheet as of December 31, 2023 (in thousands):
Assets
Current assets:
Cash and cash equivalents
Restricted cash
Receivables:
Oil and natural gas sales
Joint interest, net
Other
Prepaid expenses and other current assets
Total current assets
Oil and natural gas properties and other, net
Restricted deposits for asset retirement obligations
Deferred income taxes
Other assets
Total assets
Liabilities and Shareholders’ Equity (Deficit)
Current liabilities:
Accounts payable
Accrued liabilities
Undistributed oil and natural gas proceeds
Advances from joint interest partners
Income tax payable
Current portion of asset retirement obligation
Current portion of long-term debt, net
Total current liabilities
Asset retirement obligations, less current portion
Long-term debt, net
Deferred income taxes
Other liabilities
Shareholders' equity (deficit):
Common stock
Additional paid-in capital
Retained deficit
Treasury stock, at cost
Total shareholders’ equity (deficit)
Total liabilities and shareholders’ equity (deficit)
Consolidated
Elimination of
Unrestricted
Subsidiaries
Restricted
Subsidiaries
$
$
$
$
173,338
4,417
$
(600)
—
$
52,080
15,480
2,218
17,447
264,980
749,056
22,272
38,774
38,923
1,114,005
78,857
31,879
42,134
2,962
99
31,553
29,368
216,852
467,262
361,236
51
37,412
1
586,014
(530,656)
(24,167)
31,192
1,114,005
$
$
$
(19,171)
33,151
—
(612)
12,768
(287,313)
—
—
(8,097)
(282,642)
(4,473)
(7,152)
(4,359)
$
$
—
—
(44)
(28,872)
(44,900)
(67,771)
(82,317)
—
(6,749)
—
—
(80,905)
—
(80,905)
(282,642)
$
172,738
4,417
32,909
48,631
2,218
16,835
277,748
461,743
22,272
38,774
30,826
831,363
74,384
24,727
37,775
2,962
99
31,509
496
171,952
399,491
278,919
51
30,663
1
586,014
(611,561)
(24,167)
(49,713)
831,363
55
Table of Contents
Information reflecting the elimination of the accounts of our Unrestricted Subsidiaries from our Consolidated Statement of Operations
for the year ended December 31, 2023 is as follows (in thousands):
Revenues:
Oil
NGLs
Natural gas
Other
Total revenues
Operating expenses:
Lease operating expenses
Gathering, transportation and production taxes
Depreciation, depletion, and amortization
Asset retirement obligations accretion
General and administrative expenses
Total operating expenses
Operating income
Interest expense, net
Derivative (gain) loss, net
Other expense, net
Income (loss) before income taxes
Income tax expense
Net income (loss)
Consolidated
Elimination of
Unrestricted
Subsidiaries
Restricted
Subsidiaries
$
$
381,389
32,446
110,158
8,663
532,656
257,676
26,250
114,677
29,018
75,541
503,162
29,494
44,689
(54,759)
5,621
33,943
18,345
15,598
$
$
$
(622)
(20,849)
(74,900)
(4,506)
(100,877)
(79,824)
(8,169)
3,383
(5,980)
(1,330)
(91,920)
(8,957)
(10,400)
71,724
—
(70,281)
—
$
(70,281)
380,767
11,597
35,258
4,157
431,779
177,852
18,081
118,060
23,038
74,211
411,242
20,537
34,289
16,965
5,621
(36,338)
18,345
(54,683)
Produced oil, NGLs and natural gas volumes (net to our interests) from the Mobile Bay Properties are as follows:
Production Volumes:
Oil (MBbls)
NGLs (MBbls)
Natural gas (MMcf)
Total oil equivalent (MBoe)
Year Ended December 31,
2022
2023
15
925
24,826
5,078
17
941
30,052
5,967
Reserves information for the Mobile Bay properties is described in more detail under Part I, Item 2. Properties, in this Form 10-K.
56
Table of Contents
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
This discussion of financial condition and results of operations is based upon the information reported in our consolidated financial
statements, which have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make informed
judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of
contingent assets and liabilities at the date of our financial statements. We base our estimates on historical experience and other sources that
we believe to be reasonable at the time. Changes in the facts and circumstances or the discovery of new information may result in revised
estimates and actual results may vary from our estimates. Our significant accounting policies are detailed in Financial Statements and
Supplementary Data – Note 1 – Significant Accounting Policies under Part II, Item 8 in this Form 10-K. We have outlined below certain
accounting policies that are of particular importance to the presentation of our financial position and results of operations and require the
application of significant judgment or estimates by our management.
Full Cost Accounting
We account for our oil and natural gas operations using the full cost method of accounting. Under this method, substantially all costs
incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized
amounts include the internal costs directly related to acquisition, development and exploration activities, asset retirement costs, and
capitalized interest. Under the full cost method, dry hole costs, geological and geophysical costs, and overhead costs directly related to
these activities are capitalized into the full cost pool, which is subject to amortization and assessed for impairment on a quarterly basis
through a ceiling test calculation as discussed below.
Capitalized costs associated with proved reserves are amortized over the life of the total proved reserves using the unit of production
method, computed quarterly. Additionally, the amortizable base includes future development costs. The cost of unproved properties related
to acquisitions are excluded from the amortization base until it is determined that proved reserves exist or until such time that impairment
has occurred. We capitalize interest on unproved properties that are excluded from the amortization base. The costs of drilling non-
commercial exploratory wells are included in the amortization base immediately upon determination that such wells are non-commercial.
Under the full cost method, sales of oil and natural gas properties are accounted for as adjustments to capitalized costs with no gain or loss
recognized unless an adjustment would significantly alter the relationship between capitalized costs and the value of proved reserves.
The computation of our DD&A rate includes estimates of reserves which requires significant judgment and is subject to change at each
assessment. The determination of when proved reserves exist for our unproved properties requires judgment, which can affect our DD&A
rate. Also, estimates of our capitalized ARO and estimates of future development costs require significant judgment. Actual results may be
significantly different from such estimates, which would affect the timing of when these expenses would be recognized as DD&A. See Oil
and Natural Gas Reserve Quantities and Asset Retirement Obligations below for more information.
Impairment of Oil and Natural Gas Properties
Under the full cost method, our capitalized costs are limited to a ceiling based on the present value of future net revenues from proved
reserves, computed using a discount factor of 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas
properties not being amortized less the related tax effects. Any costs in excess of the ceiling are recognized as a non-cash “Write-down of
oil and natural gas properties” on the Consolidated Statements of Operations and an increase to “Accumulated depreciation, depletion and
amortization” on the Consolidated Balance Sheets. The expense may not be reversed in future periods, even though higher oil, NGL and
natural gas prices may subsequently increase the ceiling. We perform this ceiling test calculation each quarter. In accordance with SEC
rules and regulations, we utilize SEC pricing when performing the ceiling test. We also hold prices and costs constant over the life of the
reserves, even though actual prices and costs of oil and natural gas are often volatile and may change from period to period. We did not
have any ceiling test impairments in 2023, 2022 or 2021.
57
Table of Contents
Oil and Natural Gas Reserve Quantities
Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of DD&A and impairment
assessment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of oil, NGL and natural gas
which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs
under existing economic and operating conditions. Our proved reserve information included in this Form 10-K was estimated by our
independent petroleum consultant, NSAI, in accordance with generally accepted petroleum engineering and evaluation principles and
definitions and guidelines established by the SEC. The accuracy of our reserve estimates is a function of:
● the quality and quantity of available data and the engineering and geological interpretation of that data;
● estimates regarding the amount and timing of future operating costs, severance taxes, development costs and workovers, all of
which may vary considerably from actual results;
● the accuracy of various mandated economic assumptions, such as the future prices of oil and natural gas; and
● the judgments of the persons preparing the estimates.
Because these estimates depend on many assumptions, any or all of which may differ substantially from actual results, reserve
estimates may be different from the quantities of oil and natural gas that are ultimately recovered.
Asset Retirement Obligations
We have obligations associated with the retirement of our oil and natural gas wells and related infrastructure. We have obligations to
plug and abandon all wells, remove our platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and
natural gas production operations. Estimating the future restoration and removal cost requires us to make estimates and judgments because
the removal obligations may be many years in the future and contracts and regulations often have vague descriptions of what constitutes
removal. We accrue a liability with respect to these obligations based on our estimate of the timing and amount to replace, remove or retire
the associated assets.
In estimating the liability associated with our asset retirement obligations, we utilize several assumptions, including a credit-adjusted
risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected
inflation rate. Revisions to these estimates impact the value of our abandonment liability, our oil and natural gas property balance and our
DD&A rates. After initial recording, the liability is increased for the passage of time, with the increase being reflected as “Accretion
expense” in the Consolidated Statements of Operations. If we incur an amount different from the amount accrued for decommissioning
obligations, we recognize the difference as an adjustment to our oil and natural gas properties.
Income Taxes
Our provision for income taxes includes U.S. state and federal taxes. We record our federal income taxes in accordance with
accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax
consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets
and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences
and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is
recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it
is more likely than not that the related tax benefits will not be realized.
We apply significant judgment in evaluating tax positions and estimating our provision for income taxes. During the ordinary course of
business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these
future tax consequences could differ significantly from our estimates, which could impact the Company’s financial position, results of
operations and cash flows. We record adjustments to reflect actual taxes paid in the period that we complete our tax returns.
58
Table of Contents
We account for uncertainty in income taxes recognized in the consolidated financial statements in accordance with GAAP by
prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative
guidance for accounting for uncertainty in income taxes requires that we recognize the financial statement benefit of a tax position only
after determining that the relevant tax authority would more likely than not sustain the position following an audit. When applicable, we
recognize interest and penalties related to uncertain tax positions in income tax expense. The final settlement of these tax positions may
occur several years after the tax return is filed and may result in significant adjustments depending on the outcome of these settlements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
In the normal course of business, we are exposed to certain market risks that are inherent to the business of exploration and
development of oil and natural gas. We may enter into derivative contracts to manage or reduce market risk, but we do not enter into
derivative contracts for speculative purposes.
We do not designate our derivative contracts as hedges for accounting purposes. Accordingly, the changes in the fair value of these
derivative contracts are recognized currently in earnings.
Commodity Price Risk
Our major market risk exposure is the fluctuation of prices for oil, NGL and natural gas. These fluctuations have a direct impact on our
revenues, earnings and cash flow. For example, assuming a 10% decline in our average realized oil, NGL and natural gas sales prices in
2023 and assuming no other items had changed, our revenue would have decreased by approximately $52.4 million in 2023. This amount
would be representative of the effect on operating cash flows under these price change assumptions.
We have attempted to mitigate commodity price risk and stabilize cash flows associated with our forecasted sales of natural gas
production through the use of swaps, costless collars, purchased calls, and purchased puts. Our derivatives will not mitigate all of the
commodity price risks of our forecasted sales of natural gas production and, as a result, we will be subject to commodity price risks on our
remaining forecasted production.
The following table summarizes the historical results of our hedging activities:
Year Ended December 31,
2022
2023
Oil ($/Bbl):
Average realized sales price, before the effects of derivative settlements
Effects of realized commodity derivatives
Average realized sales price, including realized commodity derivatives
Natural Gas ($/Mcf)
Average realized sales price, before the effects of derivative settlements
Effects of realized commodity derivatives
Average realized sales price, including realized commodity derivatives
$
$
$
$
75.52
$
—
$
75.52
2.93
(0.11)
2.82
$
$
93.59
(12.35)
81.24
7.23
0.65
7.88
During 2023, our average realized natural gas price after the effect of derivatives decreased 64.2% during 2023 to $2.82 per Mcf from
$7.88 per Mcf during 2022.
Interest Rate Risk
As of December 31, 2023, our interest rate risk exposure is mitigated as of result of fixed interest rates on all our long-term debt
outstanding. Should we ever have amounts outstanding under our Credit Agreement, we would be subject to some interest rate risk
exposure, as our Credit Agreement has a variable interest rate which is primarily impacted by the rates for the Secured Overnight Financing
Rate, and the current margin is 6.0% per annum. We do not have any derivative contracts related to interest rates as of December 31, 2023.
59
Table of Contents
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
W&T OFFSHORE, INC. AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Management’s Report on Internal Control over Financial Reporting
Reports of Independent Registered Public Accounting Firm (PCAOB ID 0042)
Consolidated Financial Statements:
Page
61
62
66
66
Consolidated Balance Sheets as of December 31, 2023 and 2022
Consolidated Statements of Operations for the years ended December 31, 2023, 2022 and 2021
67
Consolidated Statements of Changes in Shareholders’ (Deficit) Equity for the years ended December 31, 2023, 2022 and 2021 68
69
Consolidated Statements of Cash Flows for the years ended December 31, 2023, 2022 and 2021
70
Notes to Consolidated Financial Statements
60
Table of Contents
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is
defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control over financial reporting is a process designed to provide
reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external
purposes in accordance with accounting principles generally accepted in the United States (GAAP). Our internal control over financial
reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and
fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in
accordance with authorizations of management and our directors; and (iii) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the consolidated financial
statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections
of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or procedures may deteriorate. Accordingly, even effective internal control
over financial reporting can only provide reasonable assurance of achieving their control objectives.
Under the supervision and with the participation of our management, including our principal executive officer and principal financial
officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control –
Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework).
Based on our evaluation, management concluded that our internal control over financial reporting was effective as of
December 31, 2023 in providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles. The effectiveness of our internal control over
financial reporting as of December 31, 2023 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as
stated in their report, which is included herein.
61
Table of Contents
Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of W&T Offshore, Inc. and subsidiaries
Opinion on Internal Control over Financial Reporting
We have audited W&T Offshore, Inc. and subsidiaries’ (the “Company”) internal control over financial reporting as of December 31, 2023,
based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (2013 framework) (the COSO criteria). In our opinion, W&T Offshore, Inc. and subsidiaries maintained, in all
material respects, effective internal control over financial reporting as of December 31, 2023, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the
consolidated balance sheets of W&T Offshore, Inc. and subsidiaries as of December 31, 2023 and 2022, the related consolidated statements
of operations, changes in shareholders’ (deficit) equity and cash flows for each of the three years in the period ended December 31, 2023,
and the related notes and our report dated March 6, 2024 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over
Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our
audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in
accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and
the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness
exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such
other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting
principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide
reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally
accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations
of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of
any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Houston, Texas
March 6, 2024
62
Table of Contents
Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of W&T Offshore, Inc. and subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of W&T Offshore, Inc. and subsidiaries (the Company) as of December 31,
2023 and 2022, the related consolidated statements of operations, changes in shareholders’ (deficit) equity and cash flows for each of the
three years in the period ended December 31, 2023, and the related notes (collectively referred to as the “consolidated financial
statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the
Company at December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended
December 31, 2023, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the
Company's internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control-Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated
March 6, 2024 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the
Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be
independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the
Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our
audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or
fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the
amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant
estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits
provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were
communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the
financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit
matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating
the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they
relate.
63
Table of Contents
Description of the Matter
How we Addressed the Matter in our
Audit
Depreciation, Depletion and Amortization (“DD&A”) of Oil and Natural Gas Properties
At December 31, 2023, the net book value of the Company’s oil and natural gas properties
was $718 million, and depreciation, depletion and amortization (“DD&A”) expense was
$113 million for the year then ended. As discussed in Note 1 to the consolidated financial
statements, the Company follows the full-cost method of accounting for its oil and natural
gas properties. Under this method, oil and natural gas properties included in the amortization
base are amortized using the units-of-production method based on proved oil and natural gas
reserves, as estimated by independent petroleum engineers. Proved oil and natural gas
reserves are prepared using standard geological and engineering methods generally
recognized in the petroleum industry based on evaluations of estimated in-place hydrocarbon
volumes using financial and non-financial inputs. Judgment is required by the independent
petroleum engineers in interpreting the data used to estimate reserves. Estimating proved
reserves also requires the selection of inputs, including historical production, oil and natural
gas price assumptions, and future operating and capital costs assumptions, among others.
Because of the complexity involved in estimating proved oil and natural gas reserves,
management used independent petroleum engineers to prepare the oil and natural gas reserve
estimates as of December 31, 2023.
Auditing the Company’s DD&A expense calculation is especially complex because of the
use of the work of the independent petroleum engineers and the evaluation of the inputs
described above used by the engineers in estimating proved oil and natural gas reserves.
We obtained an understanding, evaluated the design and tested the operating effectiveness of
the Company’s controls that address the risks of material misstatement relating to the
calculation of DD&A expense. This included management’s controls over the completeness
and accuracy of the financial data provided to the engineers for use in estimating proved oil
and natural gas reserves.
Our audit procedures included, among others, evaluating the professional qualifications and
objectivity of the independent petroleum engineers used to prepare the oil and natural gas
reserve estimates. On a sample basis, we tested the completeness and accuracy of the
financial data and inputs described above used by the engineers in estimating proved oil and
natural gas reserves by agreeing them to source documentation, where available, and
assessing the inputs for reasonableness based on review of corroborative evidence and
consideration of any contrary evidence. Additionally, we performed analytic and lookback
procedures on select inputs into the oil and gas reserve estimate as well as on the outputs.
Finally, we tested that the DD&A expense calculations are based on the appropriate proved
oil and natural gas reserve balances from the Company’s reserve report.
Description of the Matter
Accounting for Asset Retirement Obligation
At December 31, 2023, the asset retirement obligation (ARO) balance totaled $499 million.
As further described in Notes 1 and 8 to the consolidated financial statements, the Company
records a liability for ARO in the period in which it is incurred, and a reasonable estimate can
be made. The estimation of the ARO requires significant judgment given the magnitude of
the expected retirement costs and higher estimation uncertainty related to the timing of
settlements and settlement amounts.
64
Table of Contents
How we Addressed the Matter in our
Audit
Auditing the Company’s ARO is complex and required us to use significant judgment
because of the estimation required by management in determining and measuring the
expected cash outflows. In particular, the estimate was sensitive to significant subjective
assumptions such as retirement cost estimates.
We obtained an understanding, evaluated the design, and tested the operating effectiveness of
the Company’s internal controls over its ARO estimation process, including management’s
review of the significant assumptions that have a material effect on the determination of the
obligations. We also tested management’s controls over the completeness and accuracy of
financial data used in the valuation.
Our audit procedures included, among others, assessing the significant assumptions and
inputs used in the valuation, such as retirement cost estimates and timing of settlement
assumptions. For example, we evaluated retirement cost estimates by comparing the
Company’s estimates to recent offshore activities and costs. Additionally, we compared
assumptions for the timing of settlements to production forecasts.
/s/ Ernst & Young, LLP
We have served as the Company’s auditor since 2000.
Houston, Texas
March 6, 2024
65
Table of Contents
W&T Offshore, Inc.
Consolidated Balance Sheets
(In thousands)
Assets
Current assets:
Cash and cash equivalents
Restricted cash
Accounts receivable:
Oil and natural gas sales
Joint interest, net
Other
Prepaid expenses and other current assets (Note 16)
Total current assets
Oil and natural gas properties and other, net (Note 1)
Restricted deposits for asset retirement obligations
Deferred income taxes
Other assets (Note 16)
Total assets
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable
Accrued liabilities (Note 16)
Undistributed oil and natural gas proceeds
Advances from joint interest partners
Income tax payable
Current portion of asset retirement obligation (Note 8)
Current portion of long-term debt, net (Note 2)
Total current liabilities
Asset retirement obligations (Note 8)
Long-term debt, net (Note 2)
Deferred income taxes
Other liabilities (Note 16)
Commitments and contingencies (Notes 17 and 19)
Shareholders’ equity:
Preferred stock, $0.00001 par value; 20,000 shares authorized; none issued at December 31, 2023 and
December 31, 2022
Common stock, $0.00001 par value; 400,000 shares authorized; 149,450 issued and 146,581 outstanding at
December 31, 2023; 149,002 issued and 146,133 outstanding at December 31, 2022
Additional paid-in capital
Retained deficit
Treasury stock, at cost; 2,869 shares
Total shareholders’ equity
Total liabilities and shareholders’ equity
December 31,
2023
2022
173,338
4,417
$
$
$
52,080
15,480
2,218
17,447
264,980
749,056
22,272
38,774
38,923
1,114,005
78,857
31,879
42,134
2,962
99
31,553
29,368
216,852
467,262
361,236
51
19,369
18,043
461,357
4,417
66,146
14,000
—
24,343
570,263
735,215
21,483
57,280
47,549
1,431,790
65,158
74,041
41,934
3,181
412
25,359
582,249
792,334
441,071
111,188
72
59,134
20,357
—
—
1
586,014
(530,656)
(24,167)
31,192
1,114,005
$
1
576,588
(544,788)
(24,167)
7,634
1,431,790
$
$
$
$
See accompanying Notes to Consolidated Financial Statements.
66
Table of Contents
Revenues:
Oil
NGLs
Natural gas
Other
Total revenues
Operating expenses:
Lease operating expenses
Gathering, transportation and production taxes
Depreciation, depletion, and amortization
Asset retirement obligations accretion
General and administrative expenses
Total operating expenses
Operating income
Interest expense, net
Derivative (gain) loss, net
Other expense (income), net
Income (loss) before income taxes
Income tax expense
Net income (loss)
Net income (loss) per common share:
Basic
Diluted
Weighted average common shares outstanding:
Basic
Diluted
W&T Offshore, Inc.
Consolidated Statements of Operations
(In thousands, except per share amounts)
$
$
$
Year Ended December 31,
2022
2021
2023
$
$
$
381,389
32,446
110,158
8,663
532,656
257,676
26,250
114,677
29,018
75,541
503,162
29,494
44,689
(54,759)
5,621
33,943
18,345
15,598
0.11
0.11
146,483
148,302
$
$
$
524,274
56,964
323,831
15,928
920,997
224,414
35,128
107,122
26,508
73,747
466,919
454,078
69,441
85,533
14,295
284,809
53,660
231,149
1.61
1.59
143,143
145,090
329,557
44,343
173,749
10,361
558,010
174,582
27,919
90,522
22,925
52,400
368,348
189,662
70,049
175,313
(6,165)
(49,535)
(8,057)
(41,478)
(0.29)
(0.29)
142,271
142,271
See accompanying Notes to Consolidated Financial Statements.
67
Table of Contents
Balances at December 31, 2020
Share-based compensation
Shares withheld related to net
settlement of equity awards
Share-based compensation
common stock issuances
Net loss
Balances at December 31, 2021
Share-based compensation
Shares withheld related to net
settlement of equity awards
Share-based compensation
common stock issuances
Net proceeds from issuance of
common stock
Net income
Balances at December 31, 2022
Cash dividends
Share-based compensation
Shares withheld related to net
settlement of equity awards
Share-based compensation
common stock issuances
Net income
Balances at December 31, 2023
W&T Offshore, Inc.
Consolidated Statements of Changes in Shareholders’ (Deficit) Equity
(In thousands)
Common Stock
Value
Shares
142,305
$
—
Additional
Paid-In
Capital
Retained
Deficit
1
$
—
550,339
3,364
$
(734,459)
—
Treasury Stock
Shares
2,869
$
—
Value
(24,167)
$
—
Total
Shareholders’
(Deficit)
Equity
(208,286)
3,364
—
558
—
142,863
—
—
299
2,971
—
146,133
—
—
—
(780)
—
—
—
(780)
—
—
1
—
—
—
552,923
7,922
—
(41,478)
(775,937)
—
—
—
—
—
2,869
(24,167)
—
—
—
(715)
—
—
—
1
—
—
—
16,458
—
576,588
—
10,383
—
—
—
231,149
(544,788)
(1,466)
—
—
—
—
—
—
—
2,869
—
—
—
—
(24,167)
—
—
—
(41,478)
(247,180)
7,922
(715)
—
16,458
231,149
7,634
(1,466)
10,383
—
—
(957)
—
—
—
(957)
448
—
$
146,581
—
—
$
1
—
—
$
586,014
—
15,598
(530,656)
—
—
$
2,869
—
—
$
(24,167)
—
15,598
31,192
See accompanying Notes to Consolidated Financial Statements.
68
Table of Contents
W&T Offshore, Inc.
Consolidated Statements of Cash Flows
(In thousands)
Operating activities:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Year Ended December 31,
2022
2023
2021
$
15,598
$
231,149
$
(41,478)
Depreciation, depletion, amortization and accretion
Share-based compensation
Amortization and write off of debt issuance costs
Derivative (gain) loss
Derivative cash payments, net
Derivative cash premium payments
Deferred income taxes
Changes in operating assets and liabilities:
Oil and natural gas receivables
Joint interest receivables
Prepaid expenses and other current assets
Accounts payable, accrued liabilities and other
Cash advances from JV partners
Income taxes
Asset retirement obligation settlements
Net cash provided by operating activities
Investing activities:
Investment in oil and natural gas properties and equipment
Changes in operating assets and liabilities associated with investing activities
Acquisition of property interests
Purchase of corporate aircraft (Note 18)
Purchases of furniture, fixtures and other
Net cash used in investing activities
Financing activities:
Repayment of 9.75% Senior Second Lien Notes due 2023
Repayment of Term Loan
Repayment of TVPX Loan
Repayment of Credit Facility
Proceeds from issuance of 11.75% Senior Second Lien Notes due 2026
Proceeds from issuance of Term Loan
Debt issuance costs
Net proceeds from issuance of common stock
Payment of dividends
Other
Net cash (used in) provided by financing activities
Change in cash, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash, beginning of year
Cash, cash equivalents and restricted cash, end of year
143,695
10,383
6,980
(54,759)
(8,932)
—
18,485
14,066
(1,480)
(2,712)
10,722
(219)
(2,531)
(33,970)
115,326
(41,278)
(535)
(27,384)
(8,983)
(3,428)
(81,608)
(552,460)
(33,741)
(733)
—
275,000
—
(7,380)
—
(1,466)
(957)
(321,737)
133,630
7,922
7,551
85,533
(41,880)
(46,111)
45,184
(11,227)
(4,255)
31,906
(12,034)
(11,892)
279
(76,225)
339,530
(41,632)
(1,894)
(51,474)
—
(80)
(95,080)
—
(42,959)
—
—
—
—
(1,675)
16,458
—
(716)
(28,892)
(288,019)
465,774
177,755
$
215,558
250,216
465,774
$
$
113,447
3,364
6,555
175,313
(81,298)
(40,484)
(8,189)
(16,089)
1,095
(5,103)
46,099
7,765
(20)
(27,309)
133,668
(32,062)
5,277
(661)
—
2
(27,444)
—
(24,142)
—
(80,000)
—
215,000
(9,810)
—
—
(782)
100,266
206,490
43,726
250,216
See accompanying Notes to Consolidated Financial Statements.
69
Table of Contents
W&T Offshore, Inc.
Notes to Consolidated Financial Statements
NOTE 1 — BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations
W&T Offshore, Inc. (with subsidiaries referred to herein as the “Company”) is an independent oil, NGL and natural gas producer with
substantially all of its operations offshore in the Gulf of Mexico. The Company is active in the exploration, development and acquisition of
oil and natural gas properties. Interests in fields, leases, structures and equipment are primarily owned by the Company and its 100%
owned subsidiaries, W & T Energy VI, LLC, Aquasition LLC (“A-I LLC”), and Aquasition II, LLC (“A-II LLC”), and through a
proportionately consolidated interest in Monza Energy LLC (“Monza”). The Company operates in one reportable segment.
Basis of Presentation
The consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries and the proportionally
consolidated interest in Monza. All significant intercompany accounts and transactions have been eliminated.
The accompanying consolidated financial statements have been prepared in accordance with U.S. GAAP and pursuant to the rules and
regulations of the SEC for annual financial information.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect
the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, the
reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves.
The Company bases its estimates and judgments on historical experience and on various other assumptions and information that are
believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived
with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information
is obtained and as our operating environment changes. While the Company believes that the estimates and assumptions used in the
preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.
Cash Equivalents
The Company considers all highly liquid investments purchased with original or remaining maturities of three months or less at the
date of purchase to be cash equivalents.
Restricted Cash
The Company maintains funds related to collateralized letters of credit (see Note 2 — Debt).
Revenue Recognition
The Company records revenues from the sale of oil, NGLs and natural gas based on quantities of production sold to purchasers under
short-term contracts (less than twelve months) at market prices when delivery to the customer has occurred, title has transferred, prices are
fixed and determinable and collection is reasonably assured. Revenue from the sale of oil, NGLs and natural gas is recognized when
performance obligations under the terms of the respective contracts are satisfied; this generally occurs with the delivery of oil, NGLs and
natural gas to the customer. Each unit of product represents a separate performance obligation; therefore, future volumes are wholly
unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
70
Table of Contents
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
The Company recognizes revenue for all oil, NGL and natural gas sold to purchasers regardless of whether the sales are proportionate
to the Company’s ownership interest in the property. The Company does not record imbalance receivables for those properties in which the
Company has taken less than its ownership share of production. As of December 31, 2023 and 2022, $3.7 million and $3.5 million,
respectively, are reported in Undistributed oil and natural gas proceeds in the Consolidated Balance Sheets related to natural gas
imbalances.
Concentration of Credit Risk
The Company’s customers consist primarily of major oil and natural gas companies, well-established oil and pipeline companies and
independent oil and gas producers and suppliers. The majority of the Company’s production is sold to customers under short-term contracts
at market-based prices. The Company attempts to minimize credit risk exposure to purchasers, joint interest owners, derivative
counterparties and other third-party entities through formal credit policies, monitoring procedures, and letters of credit or guarantees when
considered necessary.
In 2023, two customers accounted for approximately 41% and 13%, respectively, of the Company’s receipts from sales of oil, NGL
and natural gas. In 2022, two customers accounted for approximately 31% and 13%, respectively, of the Company’s receipts from sales of
oil, NGL and natural gas. In 2021, three customers accounted for 34%, 14% and 11%, respectively, of the Company’s receipts from sales of
oil, NGL and natural gas. The loss of any of the customers above is not expected to result in a material adverse effect on the Company’s
ability to market future oil and natural gas production as replacement customers could be obtained in a relatively short period of time on
terms, conditions and pricing substantially similar to those currently existing.
Accounts Receivable and Allowance for Credit Losses
Accounts receivable are recorded at historical cost, net of an allowance for credit losses, to reflect the net amounts to be collected.
Receivables consist of sales of production to customers and joint interest billings. At each reporting period, a loss methodology is used to
determine the recoverability of material receivables using historical data, current market conditions and forecasts of future economic
conditions to determine expected collectability.
The following table describes the balance and changes to the allowance for credit losses (in thousands):
Allowance for credit losses, beginning of period
Additional provisions for the year
Uncollectible accounts written off or collected
Allowance for credit losses, end of period
Oil and Natural Gas Properties and Other, Net
Year Ended December 31,
2022
2021
2023
$
$
12,062
123
(1,055)
11,130
$
$
10,046
3,085
(1,069)
12,062
$
$
9,123
2,192
(1,269)
10,046
The following table provides the components of Oil and natural gas properties and other, net (in thousands):
Oil and natural gas properties and related equipment
Furniture, fixtures and other
Total property and equipment
Less: Accumulated depreciation, depletion, amortization and impairment
Oil and natural gas properties and other, net
71
December 31,
2023
8,919,403
43,434
8,962,837
(8,213,781)
749,056
$
$
2022
8,813,404
20,915
8,834,319
(8,099,104)
735,215
$
$
Table of Contents
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
Oil and natural gas properties and equipment are recorded at cost using the full cost method. Under this method, all costs associated
with the acquisition, exploration, development and abandonment of oil and natural gas properties are capitalized. Acquisition costs include
costs incurred to purchase, lease or otherwise acquire properties. Exploration costs include costs of drilling exploratory wells and external
geological and geophysical costs, which mainly consist of seismic costs. Development costs include the cost of drilling development wells
and costs of completions, platforms, facilities and pipelines. Costs associated with production, certain geological and geophysical costs and
general and administrative costs are expensed in the period incurred.
Oil and natural gas properties included in the amortization base are amortized using the units-of-production method based on
production and estimates of proved reserve quantities. In addition to costs associated with evaluated properties and capitalized asset
retirement obligations, the amortization base includes estimated future development costs to be incurred in developing proved reserves as
well as estimated plugging and abandonment costs, net of salvage value, related to developing proved reserves. Future development costs
related to proved reserves are not recorded as liabilities on the balance sheet but are part of the calculation of depletion expense.
Oil and natural gas properties and equipment will include costs of unproved properties when applicable. The cost of unproved
properties related to significant acquisitions are excluded from the amortization base until the Company has made an evaluation that
impairment has occurred. As of December 31, 2023 and 2022, the Company had no unproved properties. The costs of drilling exploratory
dry holes are included in the amortization base immediately upon determination that such wells are non-commercial.
Sales of proved and unproved oil and natural gas properties, whether or not being amortized currently, are accounted for as
adjustments of capitalized costs with no gain or loss recognized unless such adjustments would significantly alter the relationship between
capitalized costs and proved reserves of oil and natural gas.
Furniture, fixtures and non-oil and natural gas property and equipment are depreciated using the straight-line method based on the
estimated useful lives of the respective assets, generally ranging from three to seven years. Leasehold improvements are amortized over the
shorter of their economic lives or the lease term. Repairs and maintenance costs are expensed in the period incurred.
Impairment of Oil and Natural Gas Properties and Other, Net
Under the full-cost method of accounting, the Company’s capitalized costs are limited to a quarterly ceiling test which determines a
limit on the book value of oil and natural gas properties. If the net capitalized cost of oil and natural gas properties (including capitalized
ARO) net of related deferred income taxes exceeds the ceiling test limit, the excess is charged to expense on a pre-tax basis and separately
disclosed. Any such write downs are not recoverable or reversible in future periods.
The ceiling test limit is calculated as: (i) the present value of estimated future net revenues from proved reserves, less estimated future
development costs, discounted at 10%; (ii) plus the cost of unproved oil and natural gas properties not being amortized; (iii) plus the lower
of cost or estimated fair value of unproved oil and natural gas properties included in the amortization base; and (iv) less related income tax
effects. Estimated future net revenues used in the ceiling test for each period are based on current prices for each product, defined by the
SEC as the unweighted average of first-day-of-the-month commodity prices over the prior twelve months for that period. All prices are
adjusted by field for quality, transportation fees, energy content and regional price differentials.
The Company did not record a ceiling test write-down during 2023, 2022 or 2021. If average oil and natural gas prices decrease below
average pricing during 2024, the Company could incur ceiling test write-downs in future periods.
Other property is reviewed for possible impairment whenever events or changes in circumstances indicate that estimated future net
operating cash flows directly related to the asset or asset group including disposal value is less than the carrying amount of the asset or
asset group. Impairment is measured as the excess of the carrying amount of the impaired asset or asset group over its fair value.
72
Table of Contents
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
Oil and Natural Gas Reserve Estimates
The Company utilizes SEC pricing when estimating quantities of proved reserves and the standardized measure of discounted future
cash flows. Proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are
scheduled to be drilled within five years, with some limited exceptions allowed. Refer to Note 20 – Supplemental Oil and Gas
Disclosures for additional information.
Asset Retirement Obligations
The Company has obligations to plug and abandon well bores, remove platforms, pipelines, facilities and equipment and restore the
land or seabed at the end of oil and natural gas production operations. The Company records a separate liability for the present value of an
asset retirement obligation (“ARO”) based on the estimated timing and amount to replace, remove or retire the associated assets, with an
offsetting increase to oil and natural gas property costs.
In estimating the liability associated with its ARO, the Company utilizes several assumptions, including a credit-adjusted risk-free
interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation
rate. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations
considerations, which can substantially affect estimates of these future costs from period to period.
After initial recording, the liability is increased for the passage of time, with the increase being reflected as Accretion expense on the
Consolidated Statements of Operations. If the Company incurs an amount different from the amount accrued for asset retirement
obligations, the Company recognizes the difference as an adjustment to proved properties.
Contingent Decommissioning Obligations
Certain counterparties in past divestiture transactions or third parties in existing leases that have filed for bankruptcy protection or
undergone associated reorganizations may not be able to perform required abandonment obligations. The Company may be held jointly and
severally liable for the decommissioning of various facilities and related wells. The Company accrues losses associated with
decommissioning obligations when such losses are probable and reasonably estimable. When there is a range of possible outcomes, the
amount accrued is the most likely outcome within the range. If no single outcome within the range is more likely than the others, the
minimum amount in the range is accrued. These accruals may be adjusted as additional information becomes available. In addition, when
decommissioning obligations are reasonably possible, the Company discloses an estimate for a possible loss or range of loss (or a statement
that such an estimate cannot be reasonably made). See Note 19 — Contingencies for additional information.
Derivative Financial Instruments
The Company uses commodity price derivative instruments to manage exposure to commodity price risk from sales of oil and natural
gas. The Company does not enter into derivative instruments for speculative trading purposes.
Derivative instruments are recorded on the balance sheet as an asset or a liability at fair value. The Company does not designate
derivatives instruments as hedging instruments, therefore, all changes in fair value are recognized in Derivative (gain) loss on the
Consolidated Statement of Operations. See Note 4 – Derivative Financial Instruments for additional information.
Fair Value of Financial Instruments
Fair value information is included in the notes to the Consolidated Financial Statements when the fair value of the financial
instruments is different from the book value or when it is required by U.S. GAAP. The carrying amount of cash and cash equivalents,
restricted cash, accounts receivable, accounts payable and accrued liabilities approximates fair value due to the short-term, highly liquid
nature of these instruments. See Note 3 – Fair Value Measurements for additional information.
73
Table of Contents
Income Taxes
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
The Company’s provision for income taxes includes U.S. state and federal taxes. Income taxes are recorded in accordance with
accounting for income taxes under U.S. GAAP which results in the recognition of deferred tax assets and liabilities determined by applying
tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and
their reported amounts in the financial statements. The effects of changes in tax rates and laws on deferred tax balances are recognized in
the period in which the new legislation is enacted. A valuation allowance is established on deferred tax assets when it is more likely than
not that some portion or all of the related tax benefits will not be realized.
During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is
uncertain. Such uncertain tax positions are recognized in the Consolidated Financial Statements when it is determined that the relevant tax
authority would more likely than not sustain the position following an audit. Any interest and penalties related to uncertain tax positions are
recorded in Income tax expense. See Note 14 – Income Taxes for additional information.
Debt Issuance Costs
Debt issuance costs associated with the Credit Agreement are amortized using the straight-line method over the scheduled maturity of
the debt. The unamortized debt issue costs associated with the Credit Agreement are reported within Prepaid expenses and other assets in
the Consolidated Balance Sheets.
Debt issuance costs associated with the Company’s other long-term debt are amortized using the effective interest method over the
scheduled maturity of the debt. The unamortized debt issuance costs associated with the current debt instruments are reported as a
reduction to the carrying value of Current portion of long-term debt, net in the Consolidated Balance Sheet. Unamortized debt issuance
costs associated with the long-term portion of debt instruments is reported as a reduction of the carrying value of Long-term debt, net in the
Consolidated Balance Sheets.
Share-Based Compensation
Compensation cost for share-based payments to employees and non-employee directors is based on the fair value of the equity
instrument on the date of grant and is recognized over the period during which the recipient is required to provide service in exchange for
the award. The fair value for equity instruments subject to only time or to Company performance measures was determined using the
closing price of the Company’s common stock at the date of grant. The fair value for equity instruments subject to market-based
performance measures was determined using a Monte Carlo valuation model with estimates made as of the grant date. Share-based
compensation expense is recognized over the period during which the recipient is required to provide service in exchange for the award.
Estimates are made for forfeitures during the vesting period, resulting in the recognition of compensation cost only for those awards that
are expected to vest, and estimated forfeitures are adjusted to actual forfeitures when the equity instrument vests. See Note 12 – Share-
Based Compensation for additional information.
Earnings Per Share
Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average
number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available
to common stockholders by the weighted average number of diluted common shares outstanding, which includes unvested restricted stock
awards, restricted stock units and performance stock units when the effect is dilutive.
74
Table of Contents
Accounting Standards to be Adopted
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
In December 2022, the Financial Accounting Standards Board issued Accounting Standards Update No. 2023-09, Improvements to
Income Tax Disclosures (“ASU 2023-09”) to enhance transparency of income tax disclosures. ASU 2023-09 requires specified categories in
the annual rate reconciliation that meet quantitative thresholds and further disaggregation of income taxes paid by jurisdictional categories
(federal (national), state and foreign). ASU 2023-09 is effective January 1, 2025 and should be applied prospectively, with retrospective
application being permitted. The Company is currently assessing the impact of ASU 2023-09; however, it is not expected to have a material
impact on the Company’s consolidated financial statements.
No other new accounting pronouncements issued or effective during 2023 have had or are expected to have a material impact on the
Company’s consolidated financial statements.
NOTE 2 — DEBT
The components of debt are presented in the following tables (in thousands):
Term Loan:
Principal
Unamortized debt issuance costs
Total
Credit Agreement borrowings
11.75% Senior Second Lien Notes due 2026:
Principal
Unamortized debt issuance costs
Total
TVPX Loan:
Principal
Unamortized discount
Unamortized debt issuance costs
Total
9.75% Senior Second Lien Notes due 2023:
Principal
Unamortized debt issuance costs
Total
Total debt, net
Less current portion, net
Long-term debt, net
Current Portion of Long-Term Debt, Net
December 31,
2023
2022
$
$
114,159
(3,052)
111,107
147,899
(4,592)
143,307
—
275,000
(5,090)
269,910
11,025
(1,294)
(144)
9,587
—
—
—
—
—
—
—
—
—
—
—
390,604
(29,368)
361,236
$
$
552,460
(2,330)
550,130
693,437
(582,249)
111,188
As of December 31, 2023, the current portion of long-term debt of $29.4 million represented principal payments due within one year
on the TVPX Loan and Term Loan (defined below), net of current unamortized debt issuance costs.
75
Table of Contents
Maturities of Long-Term Debt
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
The maturities of the Company’s principal amounts of long-term debt are as follows (in millions):
2024
2025
2026
2027
2028
Thereafter
Total
Term Loan
$
$
31.2
28.7
309.3
22.8
8.2
—
400.2
On May 19, 2021, A-I LLC and A-II LLC (collectively, the “Subsidiary Borrowers”), both indirect wholly owned subsidiaries of the
Company, entered into a credit agreement (the “Subsidiary Credit Agreement”) providing for a $215.0 million term loan (the “Term
Loan”).
At that time, in exchange for the net cash proceeds received by the Subsidiary Borrowers from the Term Loan, the Company assigned
to (a) A-I LLC all of its interests in certain oil and gas leasehold interests and associated wells and units located in State of Alabama waters
and U.S. federal waters in the offshore Gulf of Mexico, Mobile Bay region (such assets, the “Mobile Bay Properties”) and (b) A-II LLC its
interest in certain gathering and processing assets located (i) in State of Alabama waters and U.S. federal waters in the offshore Gulf of
Mexico, Mobile Bay region and (ii) onshore near Mobile, Alabama, including offshore gathering pipelines, an onshore oil treating and
sweetening facility, an onshore gathering pipeline, and associated assets (such assets, the “Midstream Assets”).
The Term Loan requires quarterly amortization payments and bears interest at a fixed rate of 7.0% per annum. The Term Loan matures
on May 19, 2028. The Subsidiary Credit Agreement also requires the Company to enter into certain natural gas swaps and put derivative
instruments (see Note 4 – Derivative Financial Instruments).
The Term Loan is non-recourse to the Company and any subsidiaries other than the Subsidiary Borrowers and the subsidiary that owns
the equity in the Subsidiary Borrowers (the “Subsidiary Parent”), and is secured by the first lien security interests in the equity of the
Subsidiary Borrowers and a first lien mortgage security interest and mortgages on certain assets of the Subsidiary Borrowers (the Mobile
Bay Properties, defined below). See Note 5 – Subsidiary Borrowers for additional information.
Credit Agreement
On November 2, 2021, the Company entered into the Ninth Amendment to the Sixth Amended and Restated Credit Agreement, which
established a short-term $100.0 million first priority lien secured revolving facility with borrowings limited to a borrowing base of $50.0
million (the “Credit Agreement”) provided by Calculus Lending, LLC (“Calculus”), a company affiliated with and controlled by the
Company’s CEO, as sole lender under the facility. Additionally, as of November 2, 2021, the Company cash collateralized each of the
outstanding letters of credit in the aggregate amount of $4.4 million. Alter Domus (US) LLC was appointed to replace Toronto Dominion
(Texas) LLC as administrative agent under the Credit Agreement.
On November 7, 2022, the Company entered into the Eleventh Amendment to the Credit Agreement, which extended the maturity date
and Calculus’ commitment to January 3, 2024, and shifted the rate at which outstanding borrowings will accrue interest to a SOFR-based
rate.
The Company has since entered into a series of amendments to extend the maturity date on the Credit Agreement, with the most recent
being the Fifteenth Amendment to the Credit Agreement, dated as of February 28, 2024, to extend the maturity date from February 29,
2024, to March 28, 2024.
76
Table of Contents
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
A committee of the independent members of the board of directors reviewed and approved each of these amendments given the CEO’s
affiliation with Calculus. See Note 18 – Related Parties for additional information.
As a result of the amendments noted above and related assignments and agreements the primary terms and covenants associated with
the Credit Agreement as of December 31, 2023 are as follows:
● $100.0 million first priority lien secured revolving credit facility, with borrowings limited to a borrowing base of $50.0 million;
● Outstanding borrowings accrue interest at SOFR plus 6.0% per annum and the commitment fee for the unused portion of available
borrowing capacity is 3.0% per annum;
● The Company’s ratio of First Lien Debt (as such term is defined in the Credit Agreement) outstanding under the Credit Agreement
on the last day of the most recent quarter to EBITDAX (as such term is defined in the Credit Agreement) for the
trailing four quarters must not be greater than 2.50 to 1.00;
● The Company’s ratio of Total Proved PV-10 to First Lien Debt (as such terms are defined in the Credit Agreement) as of the last day
of any fiscal quarter must be equal to or greater than 2.00 to 1.00;
● The ratio of the Company and its restricted subsidiaries’ consolidated current assets to consolidated current liabilities (subject in
each case to certain exceptions and adjustments as set forth in the Credit Agreement) at the last day of any fiscal quarter must be
greater than or equal to 1.00 to 1.00;
● As of the last day of any fiscal quarter, the Company and its restricted subsidiaries on a consolidated basis must pass a “Stress Test”
to determine whether certain future net revenues from the Company’s and its restricted subsidiaries’ and certain joint ventures’ oil
and gas properties included in the collateral are sufficient to satisfy the aggregate first lien indebtedness under the Credit Agreement
assuming the Borrowing Base is 100% funded or fully utilized; and
● Certain related party transactions are required to meet certain arm’s length criteria; except in each case as specifically permitted or
excluded from the covenant under the Credit Agreement.
Availability under the Credit Agreement is subject to redetermination of the borrowing base that may be requested at the discretion of
either the lender or the Company in accordance with the Credit Agreement. Any redetermination by the lender to change the borrowing
base will result in a similar change in the availability under the Credit Agreement. The borrowing base was reconfirmed at $50.0 million in
October 2023. The Credit Agreement is secured by a first priority lien on substantially all of the Company’s and its guarantor subsidiaries’
assets, excluding those assets of the Subsidiary Borrowers.
As of December 31, 2023, there were no borrowings outstanding under the Credit Agreement and no borrowings had been incurred
under the Credit Agreement during 2023.
11.75% Senior Second Lien Notes due 2026
On January 27, 2023, the Company issued at par $275.0 million in aggregate principal amount of its 11.75% Senior Second Lien Notes
(the “11.75% Notes”) under an indenture dated January 27, 2023 (the “Indenture”). The 11.75% Notes mature on February 1, 2026 and
interest is payable in arrears on February 1 and August 1.
The 11.75% Notes are secured by second-priority liens on the same collateral that is secured under the Credit Agreement, which does
not include the Mobile Bay Properties and the related Midstream Assets. The estimated annual effective interest rate on the 11.75% Notes
is 12.6%, which includes amortization of debt issuance costs.
Prior to August 1, 2024, the Company may redeem all or any portion of the 11.75% Notes at a redemption price equal to 100% of the
principal amount of the notes outstanding plus accrued and unpaid interest, if any, to the
77
Table of Contents
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
redemption date, plus the “Applicable Premium” (as defined in the Indenture). In addition, prior to August 1, 2024, the Company may, at its
option, on one or more occasions redeem up to 35% of the aggregate original principal amount of the 11.75% Notes in an amount not
greater than the net cash proceeds from certain equity offerings at a redemption price of 111.75% of the principal amount of the outstanding
plus accrued and unpaid interest, if any, to the redemption date.
On and after August 1, 2024, the Company may redeem the 11.75% Notes, in whole or in part, at redemption prices (expressed as
percentages of the principal amount thereof) equal to 105.875% for the 12-month period beginning August 1, 2024, and 100.000% on
August 1, 2025 and thereafter, plus accrued and unpaid interest, if any, to the redemption date. The 11.75% Notes are guaranteed by the
Guarantors.
The 11.75% Notes contain covenants that limit or prohibit the Company’s ability and the ability of certain of its subsidiaries to: (i)
make investments; (ii) incur additional indebtedness or issue certain types of preferred stock; (iii) create certain liens; (iv) sell assets; (v)
enter into agreements that restrict dividends or other payments from the Company’s subsidiaries to the Company; (vi) consolidate, merge or
transfer all or substantially all of the assets of the Company; (vii) engage in transactions with affiliates; (viii) pay dividends or make other
distributions on capital stock or subordinated indebtedness; and (ix) create subsidiaries that would not be restricted by the covenants of the
Indenture. These covenants are subject to important exceptions and qualifications set forth in the Indenture. In addition, most of the above-
described covenants will terminate if both S&P Global Ratings, a division of S&P Global Inc., and Moody’s Investors Service, Inc. assign
the 11.75% Notes an investment grade rating and no default exists with respect to the 11.75% Notes.
TVPX Loan
On May 15, 2023, the Company acquired a corporate aircraft from a company affiliated with and controlled by the
Company’s Chairman, Chief Executive Officer (“CEO”) and President, Tracy W. Krohn. The terms of the transactions were reviewed and
approved by the Audit Committee of the Company’s board of directors. See Note 18 – Related Parties.
The purchase price of the aircraft was $19.1 million, which was paid using $9.0 million of the Company’s cash on hand and through the
assumption of an approximately $11.8 million amortizing loan (the “TVPX Loan”), not in its individual capacity but as owner trustee of the
trust which holds title to the aircraft, a wholly owned indirect subsidiary of the Company, as the borrower.
The TVPX Loan bears a fixed interest rate of 2.49% per annum for a term of 41 months and requires monthly amortization payments of
$91.7 thousand plus accrued interest, and a balloon payment of $8.0 million at the end of the loan term. The TVPX Loan is guaranteed by
the Company on an unsecured basis. At the date of assumption, the Company determined that the fair market value of the TVPX Loan was
$10.1 million using current market rates.
The aircraft was purchased as part of a series of transactions pursuant to which the Company restructured the compensation for its
Named Executive Officers. Prior to the Company’s purchase of the aircraft, the Company used the aircraft for business purposes, and the
CEO also used the aircraft for personal purposes. Both the Company’s use for business purposes and the CEO’s use for personal purposes
were paid for by the Company pursuant to the CEO’s prior employment agreement. In connection with the Company’s efforts to reduce
overall executive compensation, including perquisite compensation Mr. Krohn was receiving for personal use of the aircraft, on April 20,
2023, the Company entered into an amendment to the employment agreement with the CEO which requires that the Company be
reimbursed for personal use of the aircraft in accordance with the Company’s aircraft use policy.
Redemption of 9.75% Senior Second Lien Notes due 2023
On February 8, 2023, the Company redeemed all of the $552.5 million of aggregate principal outstanding of the 9.75% Senior Second
Lien Notes (the “9.75% Notes”) at a redemption price of 100.0%, plus accrued and unpaid interest to the redemption date. The Company
used the net proceeds from the issuance of the 11.75% Notes and cash on hand to fund the redemption.
78
Table of Contents
Covenants
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
As of December 31, 2023 and for all presented measurement periods, the Company was in compliance with all applicable covenants of
the Credit Agreement and the Indenture.
NOTE 3 — FAIR VALUE MEASUREMENTS
Fair value is defined as the price the Company would receive to sell an asset or pay to transfer a liability in an orderly transaction
between market participants at the measurement date. The fair value of an asset should reflect its highest and best use by market
participants, whether using an in-use or an in-exchange valuation premise. The fair value of a liability should reflect the risk of
nonperformance, which includes, among other things, the Company’s credit risk.
Valuation techniques are generally classified into three categories: the market approach; the income approach; and the cost approach.
The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the
characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or
liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within
the following hierarchy:
● Level 1 – quoted prices in active markets for identical assets or liabilities.
● Level 2 – inputs other than quoted prices that are observable for an asset or liability. These include: quoted prices for similar
assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs
other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated
by observable market data by correlation or other means (market-corroborated inputs).
● Level 3 – unobservable inputs that reflect the Company’s expectations about the assumptions that market participants would use
in measuring the fair value of an asset or liability.
Derivative Financial Instruments
The Company measures the fair value of derivative financial instruments by applying the income approach, using models with inputs
that are classified within Level 2 of the valuation hierarchy. The inputs used for the fair value measurement of derivative financial
instruments are the exercise price, the expiration date, the settlement date, notional quantities, the implied volatility, the discount curve with
spreads and published commodity future prices. Derivative financial instruments are reported in the Consolidated Balance Sheets using fair
value. See Note 4 – Derivative Financial Instruments for additional information.
The following table presents the fair value of the Company’s derivative financial instruments (in thousands):
Assets:
Derivative instruments - current
Derivative instruments - long-term
Liabilities:
Derivative instruments - current
Derivative instruments - long-term
Debt Instruments
79
December 31,
2023
2022
$
1,180
10,068
$
6,267
2,756
4,954
23,236
46,595
43,061
Table of Contents
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
The fair values of the TVPX Loan and the Term Loan were measured using a discounted cash flows model and current market rates.
The fair value of the 11.75% Notes and 9.75% Notes were measured using quoted prices, although the market is not a highly liquid market.
The fair value of debt was classified as Level 2 within the valuation hierarchy. See Note 2 – Debt for additional information.
The following table presents the net value and fair value of the Company’s debt (in thousands):
TVPX Loan
Term Loan
11.75% Notes
9.75% Notes
Total
December 31, 2023
December 31, 2022
Net Value
Fair Value
Net Value
Fair Value
$
$
$
9,587
111,107
269,910
—
$
390,604
$
10,156
108,467
283,443
—
$
402,066
— $
143,307
—
550,130
693,437
$
—
139,056
—
544,902
683,958
NOTE 4 — DERIVATIVE FINANCIAL INSTRUMENTS
The Company’s market risk exposure relates primarily to commodity prices. The Company attempts to mitigate a portion of its
commodity price risk and stabilize cash flows associated with sales of oil and natural gas production through the use of oil and natural gas
swaps, costless collars, sold calls and purchased puts. The Company is exposed to credit loss in the event of nonperformance by the
derivative counterparties; however, the Company currently anticipates that the derivative counterparties will be able to fulfill their
contractual obligations. The Company is not required to provide additional collateral to the derivative counterparties and does not require
collateral from the derivative counterparties.
The Company has elected not to designate commodity derivative contracts for hedge accounting. Accordingly, commodity derivatives
are recorded on the Consolidated Balance Sheets at fair value with settlements of such contracts, and changes in the unrealized fair value,
recorded as Derivative (gain) loss on the Consolidated Statements of Operations in each period presented. The cash flows of all commodity
derivative contracts are included in Net cash provided by operating activities on the Consolidated Statements of Cash Flows.
The Company’s natural gas contracts are based off the Henry Hub price which is quoted off NYMEX.
The following table reflects the contracted volumes and weighted average prices under the terms of the Company’s open natural gas
derivative contracts as of December 31, 2023:
Period
Jan 2024 - Dec 2024
Jan 2025 - Mar 2025
Jan 2024 - Dec 2024 (1)
Jan 2025 - Mar 2025 (1)
Apr 2025 - Dec 2025 (1)
Jan 2026 - Dec 2026 (1)
Jan 2027 - Dec 2027 (1)
Jan 2028 - Apr 2028 (1)
(1)
Instrument
Type
calls
calls
swaps
swaps
puts
puts
puts
puts
Average
Daily
Total
Volumes Volumes
65,000
62,000
65,576
63,333
62,183
55,895
52,607
49,725
23,790,000
5,580,000
24,000,000
5,700,000
17,100,000
20,400,000
19,200,000
6,000,000
Weighted
Weighted
Weighted
Strike Price Put Price Call Price
6.13
5.50
—
—
—
—
—
—
— $
— $
— $
— $
$
$
$
$
— $
— $
$
$
— $
— $
— $
— $
2.27
2.35
2.37
2.42
$
$
$
$
$
$
$
$
2.46
2.72
These contracts were entered into by the Company’s wholly owned subsidiary, A-I LLC.
80
Table of Contents
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
The fair value of the Company’s derivative financial instruments amounts was recorded in the Consolidated Balance Sheets as follows
(in thousands):
Prepaid expenses and other current assets
Other assets
Accrued liabilities
Other liabilities
$
December 31,
2023
2022
$
1,180
10,068
6,267
2,756
4,954
23,236
46,595
43,061
Although the Company has master netting arrangements with its counterparties, the amounts recorded on the Consolidated Balance
Sheets are on a gross basis.
Changes in the fair value and settlements of contracts are recorded on the Consolidated Statements of Operations as Derivative (gain)
loss. The impact of commodity derivative contracts on the Consolidated Statements of Operations was as follows (in thousands):
Realized loss
Unrealized (gain) loss
Derivative (gain) loss, net
NOTE 5 — SUBSIDIARY BORROWERS
$
2023
Year Ended December 31,
2022
$
4,087
(58,846)
(54,759)
$
125,089
(39,556)
85,533
2021
95,187
80,126
175,313
The Subsidiary Borrowers used the net proceeds of the Term Loan (see Note 2 – Debt) to (i) fund the acquisition of the Mobile Bay
Properties and the Midstream Assets from the Company and (ii) pay fees, commissions and expenses in connection with the transactions
contemplated by the Subsidiary Credit Agreement and the other related loan documents, including to enter into certain swap and put
derivative contracts described in more detail under Note 4 – Derivative Financial Instruments, of this Annual Report.
As part of the transaction, the Subsidiary Borrowers entered into a management services agreement (the “Services Agreement”) with
the Company, pursuant to which the Company will provide (a) certain operational and management services for the Mobile Bay Properties
and the Midstream Assets and (b) certain corporate, general and administrative services for the Subsidiary Borrowers (collectively in this
capacity, the “Services Recipient”). Under the Services Agreement, the Company will indemnify the Services Recipient with respect to
claims, losses or liabilities incurred by the Services Agreement Parties that relate to personal injury or death or property damage of the
Company, in each case, arising out of performance of the Services Agreement, except to the extent of the gross negligence or willful
misconduct of the Services Recipient. The Services Recipient will indemnify the Company with respect to claims, losses or liabilities
incurred by the Company that relate to personal injury or death of the Services Recipient or property damage of the Services Recipient, in
each case, arising out of performance of the Services Agreement, except to the extent of the gross negligence or willful misconduct of the
Company. The Services Agreement will terminate upon the earlier of (a) termination of the Subsidiary Credit Agreement and payment and
satisfaction of all obligations thereunder or (b) the exercise of certain remedies by the secured parties under the Subsidiary Credit
Agreement and the realization by such secured parties upon any of the collateral under the Subsidiary Credit Agreement.
The Subsidiary Borrowers are wholly-owned subsidiaries of the Company; however, the assets of the Subsidiary Borrowers are not
available to satisfy the debt or contractual obligations of any other entities, including debt securities or other contractual obligations of the
Company, and the Subsidiary Borrowers do not bear any liability for the indebtedness or other contractual obligations of any other entities,
and vice versa.
During 2023, the Subsidiary Borrowers did not pay any cash distributions to the Company. During 2022, the Subsidiary Borrowers
paid cash distributions of $30.2 million to the Company.
81
Table of Contents
Consolidation and Carrying Amounts
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
The following table presents the amounts recorded by the Company on the Consolidated Balance Sheets related to the consolidation of
the Subsidiary Borrowers and the Subsidiary Parent (in thousands):
Assets:
Cash and cash equivalents
Receivables:
Oil and natural gas sales
Joint interest, net
Prepaid expenses and other assets
Oil and natural gas properties and other, net
Other assets
Liabilities:
Accounts payable
Accrued liabilities
Undistributed oil and natural gas proceeds
Current portion of long-term debt, net
Asset retirement obligations
Long-term debt, net
Other liabilities
December 31,
2023
2022
$
600
$
21,764
19,171
(33,151)
612
287,313
8,097
4,473
7,152
4,359
28,872
67,771
82,317
6,749
37,344
(5,760)
417
280,649
8,473
27,387
45,102
7,930
32,119
61,138
111,188
47,398
The following table presents the amounts recorded by the Company in the Consolidated Statement of Operations related to the
consolidation of the operations of the Subsidiary Borrowers and the Subsidiary Parent (in thousands):
Total revenues
Total operating expenses
Interest expense, net
Derivative (gain) loss
$
Year Ended December 31,
2022
2023
$
100,877
91,920
10,400
(71,724)
268,573
73,990
14,721
141,736
NOTE 6 — JOINT VENTURE DRILLING PROGRAM
During 2018, the Company and other members formed and funded Monza, which jointly participates with the Company in the
exploration, drilling and development of certain drilling projects (the “Joint Venture Drilling Program”) in the Gulf of Mexico. The total
commitments by all members, including the Company’s commitment to fund its retained interest in Monza projects held outside of Monza,
were $361.4 million. The Company contributed 88.94% of its working interest in certain identified undeveloped drilling projects to Monza
and retained 11.06% of its working interest. The Joint Venture Drilling Program is structured so that the Company initially receives an
aggregate of 30.0% of the revenues less expenses, through both the Company’s direct ownership of its working interest in the projects and
the Company’s indirect interest through its interest in Monza, for contributing 20.0% of the estimated total well costs plus associated leases
and providing access to available infrastructure at agreed-upon rates. Any exceptions to this structure are approved by the Monza board of
directors.
The members of Monza are third-party investors, the Company and an entity owned and controlled by the Company’s CEO. The entity
affiliated with the Company’s CEO invested as a minority investor on the same terms and conditions as the third-party investors. Its
investment is limited to 4.5% of total invested capital within Monza and it made a capital commitment to Monza of $14.5 million.
82
Table of Contents
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
Monza is an entity separate from any other entity with its own separate creditors who will be entitled, upon its liquidation, to be
satisfied out of Monza’s assets prior to any value in Monza becoming available to holders of its equity. The assets of Monza are not
available to pay creditors of the Company and its affiliates.
As of December 31, 2023, ten wells have been completed since the inception of the Joint Venture Drilling Program, and the Company
is the operator for eight of these wells completed.
Since inception through December 31, 2023, members of Monza have made partner capital contributions, including the Company’s
contributions of working interest in the drilling projects, to Monza totaling $302.4 million and received cash distributions totaling
$214.9 million. Since inception through December 31, 2023, the Company has made total capital contributions, including the contributions
of working interest in the drilling projects, to Monza totaling $68.2 million and received cash distributions totaling $46.4 million.
Consolidation and Carrying Amounts
Monza is considered a variable interest entity that is proportionally consolidated. Through December 31, 2023, there have been
no events or changes that would cause a redetermination of the variable interest status. The Company does not fully consolidate Monza
because the Company is not considered the primary beneficiary of Monza.
The following table presents the amounts recorded by the Company on the Consolidated Balance Sheets related to the consolidation of
the proportional interest in Monza’s operations (in thousands):
Working capital
Oil and natural gas properties and other, net
Asset retirement obligations
Other assets
$
December 31,
2023
2022
$
1,159
31,805
593
11,694
2,515
37,260
467
11,571
As required, the Company may call on Monza to provide cash to fund its portion of certain Joint Venture Drilling Program projects in
advance of capital expenditure spending. As of December 31, 2023 and 2022, the unused advances were $2.7 million and $2.9 million,
respectively, which are included in Advances from joint interest parties in the Consolidated Balance Sheets.
The following table presents the amounts recorded by the Company in the Consolidated Statement of Operations related to the
consolidation of the proportional interest in Monza’s operations (in thousands):
Total revenues
Total operating expenses
Interest income
NOTE 7 — ACQUISITIONS
Year Ended December 31,
2022
2023
$
$
13,086
9,436
199
28,803
13,523
42
On September 20, 2023, the Company entered into a purchase and sale agreement to acquire working interests in certain oil and natural
gas producing assets in the central and eastern shelf region of the Gulf of Mexico for $32.0 million, subject to normal and customary post-
effective date adjustments (including net operating cash flow attributable to the properties from the effective date of June 1, 2023 to the
close date). The transaction closed on September 20, 2023 for $27.4 million and was funded with cash on hand. The Company also
assumed the related AROs associated with these assets.
83
Table of Contents
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
On January 5, 2022, the Company entered into a purchase and sale agreement with ANKOR E&P Holdings Corporation and KOA
Energy LP to acquire their interests in and operatorship of certain oil and natural gas producing properties in federal shallow waters in the
Gulf of Mexico at Ship Shoal 230, South Marsh Island 27/Vermilion 191, and South Marsh Island 73 fields for $47.0 million. The
transaction closed on February 1, 2022, and after normal and customary post-effective date adjustments (including net operating cash flow
attributable to the properties from the effective date of July 1, 2021 to the close date), cash consideration of $34.0 million was paid to the
sellers. The transaction was funded using cash on hand. The Company also assumed the related AROs associated with these assets.
Additionally, on April 1, 2022, the Company entered into a purchase and sale agreement with a private seller to acquire the remaining
working interests in certain oil and natural gas producing properties in federal shallow waters of the Gulf of Mexico at the Ship Shoal 230,
South Marsh Island 27/Vermilion 191, and South Marsh Island 73 fields. The transaction had an effective date and closing date of April 1,
2022. After normal and customary post-effective date adjustments, cash consideration of $17.5 million was paid to the seller.
The Company determined that the assets acquired did not meet the definition of a business; therefore, these transactions were
accounted for as asset acquisitions. An acquisition qualifying as an asset acquisition requires, among other items, that the cost of the assets
acquired and liabilities assumed to be recognized on the Consolidated Balance Sheet by allocating the asset cost on a relative fair value
basis. The fair value measurements of the oil and natural gas properties acquired and asset retirement obligations assumed were derived
utilizing an income approach and based, in part, on significant inputs not observable in the market. These inputs represent Level 3
measurements in the fair value hierarchy and include, but are not limited to, estimates of reserves, future operating and development costs,
future commodity prices, estimated future cash flows and appropriate discount rates. These inputs required judgments and estimates by the
Company’s management at the time of the valuation. Transaction costs incurred on an asset acquisition are capitalized as a component of
the assets acquired.
The amounts recorded on the Consolidated Balance Sheet for the purchase price allocation and liabilities assumed related to the
acquisitions described above are presented in the following tables (in thousands):
Oil and natural gas properties and other, net
Asset retirement obligations
Allocated purchase price
Oil and natural gas properties and other, net
Restricted deposits for asset retirement obligations
Asset retirement obligations
Allocated purchase price
Oil and natural gas properties and other, net
Restricted deposits for asset retirement obligations
Asset retirement obligations
Allocated purchase price
NOTE 8 — ASSET RETIREMENT OBLIGATIONS
September
2023
43,736
(16,352)
27,384
February
2022
54,299
6,196
(26,493)
34,002
April
2022
22,632
1,549
(6,709)
17,472
$
$
$
$
$
$
Asset retirement obligations associated with the retirement and decommissioning of tangible long-lived assets are required to be
recognized as a liability in the period in which a legal obligation is incurred and becomes determinable,
84
Table of Contents
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
with an offsetting increase in the carrying amount of the associated asset. The cost of the tangible asset, including the initially recognized
ARO, is depleted such that the cost of the ARO is recognized over the useful life of the asset. The fair value of the ARO is measured using
expected cash outflows associated with the ARO, discounted at the Company’s credit-adjusted risk-free rate when the liability is initially
recorded. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.
The following changes in liability are included in the Consolidated Balance Sheet in current and long-term liabilities, and the changes
in that liability were as follows (in thousands):
Asset retirement obligations, beginning of period
Liabilities settled
Accretion expense
Liabilities acquired
Liabilities incurred
Revisions of estimated liabilities
Asset retirement obligations, end of period
Less: Current portion
Long-term
NOTE 9 — RESTRICTED DEPOSITS FOR ARO
Year Ended December 31,
2022
2023
466,430
(33,970)
29,018
16,352
129
20,856
498,815
(31,553)
467,262
$
$
424,495
(76,225)
26,508
33,202
138
58,312
466,430
(25,359)
441,071
$
$
Restricted deposits for ARO consist of funds escrowed for collateral related to the future plugging and abandonment obligations of
certain oil and natural gas properties. These deposits relate to the following fields (in thousands):
December 31,
2023
2022
Main Pass 283/Viosca Knoll 734 (1)
South Marsh Island 73 (2)
Other
(1)
13,684
7,753
46
In connection with the acquisition of these fields, the Company received funds from the previous operator to cover future asset retirement obligations for those fields.
The Company is not obligated to contribute additional amounts to these escrowed accounts.
13,887
7,756
629
$
$
(2)
In connection with the acquisitions completed in 2022, the Company received funds from the previous owners to cover future asset retirement obligations. The Company
is not obligated to contribute additional amounts to this escrowed account. See Note 7 - Acquisitions for additional information.
NOTE 10 — STOCKHOLDERS’ EQUITY
At-the-Market Equity Offering
In March 2022, the Company filed a prospectus supplement related to the issuance and sale of up to $100.0 million of shares of
common stock under the Company’s at-the-market equity agreement (the “ATM agreement”). The designated sales agent is entitled to a
placement fee of up to 3.0% of the gross sales price per share sold.
The Company did not sell any shares of common stock in connection with the ATM agreement during 2023. During 2022, the
Company sold an aggregate of 2,971,413 shares for an average price of $5.72 per share in connection with the ATM Offering and received
proceeds, net of commissions and expenses, of $16.5 million.
85
Table of Contents
Cash Dividends
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
On November 8, 2023, the Company announced that its board of directors approved the implementation of a quarterly cash dividend
payable to holders of its common stock. The initial cash dividend of $0.01 per share of common stock, or $1.5 million, was paid on
December 22, 2023, to shareholders of record at the close of business on November 28, 2023.
NOTE 11 — LEASES
The Company has operating leases consisting of an office lease, a hangar lease, a land lease and various pipeline right-of-way
contracts. For these contracts, a right-of-use (“ROU”) asset and lease liability was established based on the Company’s assumptions of the
term and incremental borrowing rates. At inception, contracts are reviewed to determine whether the agreement contains a lease. To the
extent an arrangement is determined to include a lease, it is classified as either an operating or a finance lease, which dictates the pattern of
expense recognition in the income statement.
The term of the office lease extends to February 2032 and has the option to extend, at the Company’s discretion, for up to an
additional ten years. The term of the hangar lease extends to February 2025 and has the option to renew, at the Company’s discretion, for an
additional two years. However, the Company is not reasonably certain that it will exercise any of the options to extend these leases and as
such, they have not been included in the remaining lease terms. The term of each pipeline right-of-way contract is ten years with various
effective dates, and each has an option to extend, at the Company’s discretion, for up to another ten years. It is expected renewals beyond
ten years can be obtained as renewals were granted to the previous lessees. The land lease has an option to renew every five
years extending to 2085. The expected term of the rights-of way and land leases was estimated to approximate the life of the related
reserves. The expected term of the rights-of way and land leases was estimated to approximate the life of the related reserves at the
inception of the lease.
The amounts disclosed herein primarily represent costs associated with properties operated by the Company that are presented on a
gross basis and do not reflect the Company’s net proportionate share of such amounts. A portion of these costs have been or will be billed to
other working interest owners where applicable. The Company’s share of these costs is included in oil and natural gas properties, lease
operating expense or general and administrative expense, as applicable.
The components of lease costs were as follows (in thousands):
Operating lease costs, excluding short-term leases
Short-term lease cost (1)
Variable lease cost (2)
Total lease cost
2023
December 31,
2022
$
$
1,670
58
765
2,493
$
$
1,579
2,957
647
5,183
$
$
2021
1,743
5,926
—
7,669
(1)
Short-term lease costs are reported at gross amounts and primarily represent costs incurred for drilling rigs, most of which are short-term contracts not recognized as a
right-of-use asset and lease liability on the balance sheet. The majority of such costs are recorded within “Oil and natural gas properties, net” in the consolidated balance
sheet.
(2) Variable lease costs primarily represent differences between minimum lease payment obligations and actual operating charges incurred by the Company related to long-
term operating leases.
86
Table of Contents
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
The present value of the fixed lease payments recorded as the Company’s ROU assets and operating lease liabilities, adjusted for initial
direct costs and incentives, are as follows (in thousands):
ROU assets ‒ Other assets
Lease liability:
Accrued liabilities
Other liabilities
Total lease liability
December 31,
2023
10,515
1,455
10,803
12,258
$
$
$
2022
10,364
1,628
10,527
12,155
$
$
$
The table below presents the weighted average remaining lease term and discount rate related to leases (in thousands):
Weighted average remaining lease term:
Weighted average discount rate:
2023
12.1 years
December 31,
2022
13.1 years
2021
14.1 years
10.3 %
10.1 %
10.1 %
The table below presents the supplemental cash flow information related to leases (in thousands):
Operating cash outflow from operating leases
Right-of-use assets obtained in exchange for new operating lease liabilities
$
$
1,713
559
$
$
1,224
$
— $
Undiscounted future minimum payments as of December 31, 2023 are as follows (in thousands):
2023
December 31,
2022
2024
2025
2026
2027
2028
Thereafter
Total lease payments
Less: imputed interest
Total
$
$
2021
425
—
2,156
1,601
1,625
1,658
1,712
12,888
21,640
(9,382)
12,258
NOTE 12 — SHARE-BASED COMPENSATION
On June 16, 2023, the 2023 Incentive Compensation Plan (the “2023 Plan”) was approved by the Company’s shareholders. The
Company will no longer grant awards pursuant to the W&T Offshore, Inc. Amended and Restated Compensation Plan, as amended from
time to time, (the “Prior Incentive Plan”) or the 2004 Directors Compensation Plan of W&T Offshore, Inc., as amended from time to time
(the “Prior Director Plan”). The 2023 Plan covers the Company’s eligible employees, non-employee directors and consultants and includes
both cash and share-based compensation awards. The 2023 Plan grants the Compensation Committee of the board of directors
administrative authority over all participants and grants the CEO with authority over the administration of awards granted to participants
that are not subject to section 16 of the Exchange Act (as applicable, the “Compensation Committee”). Any awards granted prior to the
effective date of the 2023 Plan are considered to have been granted under the applicable Prior Plan.
87
Table of Contents
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
Pursuant to the terms of the 2023 Plan, the Compensation Committee establishes the vesting or performance criteria applicable to the
award and may use a single measure or combination of business measures as described in the 2023 Plan. Also, individual goals may be
established by the Compensation Committee. Performance awards may be granted in the form of stock options, stock appreciation rights,
restricted stock (“RSAs”), restricted stock units (“RSUs”), bonus stock, dividend equivalents, or other awards related to stock, and awards
may be paid in cash, stock, or any combination of cash and stock, as determined by the Compensation Committee. The performance awards
granted under the 2023 Plan can be measured over a performance period of up to 10 years and annual incentive awards (a type of
performance award) will generally be paid within 90 days following the applicable year end.
The Company has the option following vesting to settle RSUs and PSUs by either the issuance of common stock, cash or a
combination thereof based on the fair market value of the common stock on the date of vesting. During 2023, 2022 and 2021, only shares
of common stock were used to settle all vested RSUs and PSUs. The Company expects to settle RSUs and PSUs that vest in the future
using shares of common stock.
As of December 31, 2023, the maximum number of shares of common stock available for issuance under the 2023 Plan is 10.0 million
shares and 9.5 million shares remain available for grant. Shares subject to awards granted under the 2023 Plan that are subsequently
canceled, forfeited or otherwise terminated without delivery of shares are available for future grant under the 2023 Plan. The Company’s
policy is to issue new shares when RSAs are granted and RSUs and PSUs are vested.
Restricted Stock Units
During 2023, the Company granted RSUs to employees and non-employee directors under both the 2023 Plan and the Prior Incentive
Plan. RSUs granted to employees are a long-term compensation component, subject to service conditions, and vest ratably over an
approximate three-year period. The RSUs granted to non-employee directors under the 2023 Plan vest one year from the date of the grant
or on the date of the Company’s annual shareholder meeting, subject to certain conditions.
Compensation cost for share-based payments to employees is recognized ratably over the period during which the recipient is required
to provide service in exchange for the award. Compensation cost is based on the fair value of the equity instrument on the date of grant
using the Company’s closing price on the grant date. Forfeitures are estimated during the vesting period, resulting in the recognition of
compensation cost only for those awards that are expected to actually vest. Estimated forfeitures are adjusted to actual forfeitures when the
award vests. All RSUs awarded are subject to forfeiture until vested and cannot be sold, transferred or otherwise disposed of during the
restricted period.
A summary of activity related to RSUs is as follows:
Nonvested, beginning of period
Granted
Vested
Forfeited
Nonvested, end of period
Weighted
Average
Grant Date
Fair Value
per Unit
5.76
4.06
5.62
5.50
4.52
$
Restricted
Stock Units
1,221,461
1,813,522
(492,453)
(134,334)
2,408,196
The grant date fair value of RSUs granted during 2023, 2022 and 2021 was $7.4 million, $6.1 million and $3.3 million, respectively.
The fair value of the RSUs that vested during 2023, 2022 and 2021 was $2.5 million, $1.9 million and $2.4 million, respectively, based on
the closing price of the Company’s common stock on the vesting date.
As of December 31, 2023, there was $4.7 million of total unrecognized compensation costs related to unvested RSUs which is
expected to be recognized over a weighted average period of 2.1 years.
88
Table of Contents
Performance Share Units
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
During 2023, the Company granted PSUs to employees under both the 2023 Plan and the Prior Incentive Plan. PSUs are a long-term
compensation component granted to certain employees. The PSUs are RSU awards granted subject to performance criteria. The
performance criteria relates to the evaluation of the Company’s total shareholder return (“TSR”) ranking against peer companies’ TSR over
the applicable performance period and subject to service conditions through the vesting date. TSR is determined based on the change in the
entity’s stock price plus dividends and distributions for the applicable performance period.
PSUs granted to employees in 2023 and 2022 are subject to an approximate three-year performance period and service conditions
through the vesting date. The performance periods for the 2023 PSU grants and the 2022 PSU grants end on December 31, 2025 and
December 31, 2024, respectively. PSUs granted in 2021 were subject to an approximate one-year performance period which ended on
December 31, 2021. Subsequent to the performance period, the PSUs were subject to service-based criteria until the PSUs vested on
September 29, 2023.
Compensation cost for share-based payments to employees is recognized ratably over the period during which the recipient is required
to provide service in exchange for the award. Compensation cost is based on the fair value of the equity instrument on the date of grant. All
PSUs awarded are subject to forfeiture until vested and cannot be sold, transferred or otherwise disposed of during the restricted period.
The grant date fair value of the PSUs was determined through the use of the Monte Carlo simulation method. This method requires the use
of subjective assumptions such as the price and the expected volatility of the Company’s stock and its self-determined Peer Group
companies’ stock, risk free rate of return and cross-correlations between the Company and its Peer Group companies. Expected volatilities
for the Company’s and each peer company utilized in the model are estimated using a historical period consistent with the awards’
remaining performance period as of the grant date. The risk-free interest rate is based on the yield on U.S. Treasury Constant Maturity for a
term consistent with the remaining performance period. The valuation model assumes dividends, if any, are immediately reinvested.
The following table summarizes the assumptions used to calculate the grant date fair value of the PSUs granted during 2023:
Expected term for performance period (in years)
Expected volatility
Risk-free interest rate
A summary of activity related to PSUs is as follows:
Nonvested, beginning of period
Granted
Vested
Forfeited
Nonvested, end of period
2.6
76.1 %
4.2 %
Weighted
Average
Grant Date
Fair Value
per Unit
9.78
4.85
5.78
9.76
7.38
Performance
Share Units
1,502,239
1,293,113
(151,812)
(244,821)
2,398,719
$
The grant date fair value of PSUs granted during 2023, 2022 and 2021 was $6.3 million, $14.2 million and $2.2 million, respectively.
The fair value of the PSUs that vested during 2023 and 2022 was $0.7 million and $0.1 million, respectively, based on the closing price of
the Company’s common stock on the vesting date. No PSUs vested during 2021.
As of December 31, 2023, there was $8.7 million of total unrecognized compensation costs related to unvested PSUs which is
expected to be recognized over a weighted average period of 1.5 years.
89
Table of Contents
Restricted Stock
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
Under the Prior Director Plan, the Company granted RSAs to its non-employee directors in 2022 and 2021 as a component of their
compensation arrangement. Vesting occurs upon completion of the one-year vesting period. The holders of RSAs generally have the same
rights as a shareholder of the Company with respect to such shares, including the right to vote and receive dividends or other distributions
paid with respect to the shares. RSAs are subject to forfeiture until vested and cannot be sold, transferred or otherwise disposed of during
the restriction period.
A summary of activity related to RSAs is as follows:
Nonvested, beginning of period
Granted
Vested
Nonvested, end of period
Weighted
Average
Grant Date
Fair Value
per Share
4.95
—
4.95
—
Restricted
Shares
$
42,426
—
(42,426)
—
The grant date fair value of RSAs granted during both 2022 and 2021 was $0.2 million and $0.2 million, respectively. The fair value of
the RSAs that vested during 2023, 2022 and 2021 was $0.2 million, $0.4 million and $0.5 million, respectively, based on the closing price
of the Company’s common stock on the vesting date.
Share-Based Compensation Expense
The following table presents the compensation expenses included in General and administrative expenses in the Consolidated
Statements of Operations (in thousands):
Restricted stock units
Performance share units
Restricted shares
Total
NOTE 13 — EMPLOYEE BENEFIT PLAN
2023
Year Ended December 31,
2022
2021
$
$
4,477
5,836
70
10,383
$
$
4,192
3,504
226
7,922
$
$
2,579
412
373
3,364
The Company maintains a defined contribution benefit plan (the “401(k) Plan”) in compliance with Section 401(k) of the Internal
Revenue Code (“IRC”), which covers those employees who meet the 401(k) Plan’s eligibility requirements. During 2023, 2022 and 2021
the time periods where matching occurred, the Company’s matching contribution was 100% of each participant’s contribution up to a
maximum of 6% of the participant’s eligible compensation, subject to limitations imposed by the IRC. The 401(k) Plan provides 100%
vesting in Company match contributions on a pro rata basis over five years of service (20% per year). Expenses relating to the 401(k) Plan
were $2.9 million, $2.4 million, and $2.0 million for 2023, 2022 and 2021, respectively.
90
Table of Contents
NOTE 14 — INCOME TAXES
Income Tax Expense (Benefit)
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
Components of income tax expense (benefit) were as follows (in thousands):
Current
Deferred
Total income tax expense (benefit)
Reconciliation
Year Ended December 31,
2022
2023
2021
$
$
(140)
18,485
18,345
$
$
8,476
45,184
53,660
$
$
132
(8,189)
(8,057)
The Company’s income tax expense (benefit) for 2023, 2022 and 2021 resulted in effective tax rates of 54.0%, 18.8% and (16.3)%,
respectively. The reconciliation of income taxes computed at the U.S. federal statutory tax rate of 21% to these effective tax rates is as
follows (in thousands):
Income tax expense (benefit) at the federal statutory rate
Compensation adjustments
State income taxes
Valuation allowance
Other
Total income tax expense (benefit)
Year Ended December 31,
2022
2023
2021
$
$
7,128
1,752
1,143
8,125
197
18,345
$
$
59,810
599
2,418
(9,117)
(50)
53,660
$
$
(10,402)
559
(330)
1,863
253
(8,057)
91
Table of Contents
Deferred Tax Assets and Liabilities
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for
financial reporting purposes and the amounts used for income tax purposes. Significant components of the Company’s deferred tax assets
and liabilities were as follows (in thousands):
Deferred tax assets:
Derivatives
Asset retirement obligations
Contingent asset retirement obligations
Right of use liability
Federal net operating losses
State net operating losses
Interest expense limitation carryover
Share-based compensation
Other
Total deferred tax asset
Valuation allowance
Total deferred tax asset after valuation allowance
Deferred tax liabilities:
Property and equipment
Investment in non-consolidated entity
Other
Total deferred tax liabilities
Net deferred tax asset
Valuation Allowance
December 31,
2023
2022
$
$
8,532
109,111
3,952
2,895
6,211
5,941
17,501
2,262
4,266
160,671
(23,202)
137,469
92,707
2,993
3,046
98,746
25,969
103,910
4,540
2,964
281
5,691
9,620
1,546
5,513
160,034
(15,311)
144,723
80,616
3,951
2,948
87,515
38,723
$
57,208
$
$
$
Changes to the Company’s valuation allowance are as follows (in thousands):
Balance at beginning of period
Additions to valuation allowance
Reductions to valuation allowance
Balance at end of period
Year Ended December 31,
2022
2023
2021
$
$
(15,311)
(7,891)
$
—
$
(23,202)
(24,359)
—
9,048
(15,311)
$
$
(22,361)
(1,998)
—
(24,359)
Deferred tax assets are recorded related to net operating losses and temporary differences between the book and tax basis of assets and
liabilities expected to produce tax deductions in future periods. The realization of these assets depends on recognition of sufficient future
taxable income in specific tax jurisdictions in which those temporary differences or net operating losses are deductible. In assessing the
need for a valuation allowance on the Company’s deferred tax assets, the Company considers whether it is more likely than not that some
portion or all of them will not be realized.
The Company assesses available positive and negative evidence regarding its ability to realize its deferred tax assets including
reversing temporary differences and projections of future taxable income during the periods in which those temporary differences become
deductible, as well as negative evidence such as historical losses. Assumptions about the Company’s future taxable income are consistent
with the plans and estimates used to manage the Company’s business. The Company showed positive income in 2023 and continues to
project similar results into the future. Based on this, the Company concluded that there is enough positive evidence to outweigh any
negative evidence although any changes in
92
Table of Contents
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
forecasted taxable income could have a material impact on this analysis. The portion of the valuation allowance remaining relates to state
net operating losses and the disallowed interest limitation carryover under IRC section 163(j).
Net Operating Loss and Interest Expense Limitation Carryover
The table below presents the details of the Company’s net operating loss and interest expense limitation carryover as of
December 31, 2023 (in thousands):
Federal net operating loss
State net operating loss
Interest expense limitation carryover
Years Open to Examination
$
Amount
29,578
100,903
79,914
Expiration
Year
N/A
2026-2042
N/A
As of December 31, 2023, the tax years 2020 through 2023 remain open to examination by the federal and state tax jurisdictions where
the Company conducts its business.
NOTE 15 — EARNINGS PER SHARE
The following table presents the calculation of basic and diluted earnings per common share (in thousands, except per share amounts):
Net income (loss)
Weighted average common shares outstanding - basic
Dilutive effect of securities
Weighted average common shares outstanding - diluted
Earnings per common share:
Basic
Diluted
Shares excluded due to being anti-dilutive
$
$
$
2023
Year Ended December 31,
2022
2021
15,598
$
231,149
$
(41,478)
146,483
1,819
148,302
143,143
1,947
145,090
$
$
0.11
0.11
—
$
$
1.61
1.59
—
142,271
—
142,271
(0.29)
(0.29)
1,370
NOTE 16 — OTHER SUPPLEMENTAL INFORMATION
Consolidated Balance Sheet Details
Prepaid expenses and other current assets consisted of the following (in thousands):
Derivatives (1)
Insurance/bond premiums
Prepaid deposits related to royalties
Prepayments to vendors
Prepayments to joint interest partners
Current portion of debt issuance costs
Other
Prepaid expenses and other current assets
93
December 31,
2023
2022
1,180
6,631
7,872
1,492
117
81
74
17,447
$
$
4,954
6,046
9,139
1,767
1,717
687
33
24,343
$
$
Table of Contents
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
(1)
Includes closed contracts which have not yet settled and the current portion of open contracts.
Other assets consisted of the following (in thousands):
Operating lease right-of-use assets
Investment in White Cap, LLC
Proportional consolidation of Monza
Derivatives (1)
Other
Total other assets
(1)
Includes open contracts.
Accrued liabilities consisted of the following (in thousands):
Accrued interest
Accrued salaries/payroll taxes/benefits
Operating lease liabilities
Derivatives (1)
Other
Total accrued liabilities
(1)
Includes closed contracts which have not yet settled.
Other liabilities consisted of the following (in thousands):
Dispute related to royalty deductions
Derivatives
Operating lease liabilities
Other
Total other liabilities
Consolidated Statement of Operations Information
December 31,
2023
2022
10,515
2,182
11,694
10,068
4,464
38,923
$
$
10,364
2,453
9,321
23,236
2,175
47,549
December 31,
2023
2022
13,479
9,473
1,455
6,267
1,205
31,879
$
$
8,967
15,097
1,628
46,595
1,754
74,041
December 31,
2023
2022
5,250
2,756
10,803
560
19,369
$
$
4,937
43,061
10,527
609
59,134
$
$
$
$
$
$
Under the Consolidated Appropriations Act of 2021, the Company recognized a $2.2 million and $2.1 million employee retention
credit during 2023 and 2021. These amounts are included as a credit to General and administrative expenses in the Condensed
Consolidated Statement of Operations. No such credit was received during 2022.
During 2023 and 2022, Other expense (income), net primarily consisted of additional expenses for net abandonment obligations
pertaining to a number of legacy Gulf of Mexico properties. During 2021, Other expense (income), net primarily consisted of income
related to the release restrictions on the Black Elk Escrow fund, partially offset by expenses related to the amortization of the brokerage fee
paid in connection with the Joint Venture Drilling Program, offset by contingent decommissioning obligation.
94
Table of Contents
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
Consolidated Statement of Cash Flows Information
Supplemental cash flows and noncash transactions were as follows (in thousands):
Cash and cash equivalents
Restricted cash
Cash, cash equivalents and restricted cash
Supplemental cash flows information:
Cash paid for interest
Cash paid for income taxes
Non-cash investing activities:
Accruals of property and equipment
ARO - additions, dispositions and revisions, net
NOTE 17 — COMMITMENTS
$
Year Ended December 31,
2022
2023
$
173,338
4,417
177,755
$
461,357
4,417
465,774
2021
245,799
4,417
250,216
42,132
2,392
7,165
37,337
71,126
8,198
6,636
91,652
64,805
152
9,464
36,175
Pursuant to the 2010 Purchase and Sale Agreement with Total E&P, the Company may fulfill security requirements related to ARO for
certain properties through securing surety bonds, through making payments to an escrow account under a formula pursuant to the
agreement, or a combination thereof, until certain prescribed thresholds are met. As of December 31, 2023, the Company had surety bonds
related to the agreement totaling $103.0 million and had $0.4 million in escrow. There is no further escalation of the threshold after 2023.
Pursuant to the 2010 Purchase and Sale Agreement with Shell Offshore Inc. related to ARO for certain properties, the Company has
surety bonds that are subject to re-appraisal by either party. As of December 31, 2023, neither party had requested a re-appraisal to be
made. The current security requirement of $64.0 million could be increased up to $94.0 million depending on certain conditions and
circumstances.
Pursuant to the 2019 Purchase and Sale Agreement with Exxon related to ARO for certain properties, the Company was required to
obtain $36.3 million of surety bonds as of December 31, 2023. This amount increases on June 1 of the following years to $44.0 million -
2024; $48.3 million - 2025; $53.2 million - 2026; $58.5 million - 2027, and future increases in increments ranging $5.9 million to
$10.4 million per year until the total amount reaches $114.0 million in 2034. The Company may request a redetermination with Exxon
every two years by providing certain documentation as provided in the purchase agreement. The Company is required to maintain this
scheduled level of bonds until the properties are fully plugged, abandoned, and restored in accordance with applicable laws and regulations.
Pursuant to the 2019 Purchase and Sale Agreement with Conoco related to ARO for certain properties, the Company was required to
obtain $49.0 million of surety bonds and is required to maintain this level of bonds until the properties are fully plugged, abandoned, and
restored in accordance with applicable laws and regulations.
The Company also has surety bonds primarily related to decommissioning obligations. Total expenses related to these surety bonds,
inclusive of the surety bonds in connection with the agreements described above, were $7.4 million, $8.3 million and $6.0 million during
2023, 2022 and 2021, respectively. Future surety bonds costs may change due to a number of factors, including changes and interpretations
of regulations by the BOEM, rates being charged in the market place and when obligations are completed.
In conjunction with the purchase of an interest in the Heidelberg field, the Company assumed contracts with certain pipeline
companies that contain minimum quantities obligations that extend through 2028. The Company recognized expenses of $1.0 million, $1.6
million and $2.1 million for the difference between the quantities shipped and the minimum obligations during 2023, 2022 and 2021,
respectively.
95
Table of Contents
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
The Company entered into a drilling contract during 2023. The contract is to begin in February 2025 and terminate in October 2025.
The Company expects the total obligation under the contract to be approximately $9.9 million.
NOTE 18 — RELATED PARTIES
The Company has entered into transactions with related parties either controlled by the Company’s CEO or in which he has an
ownership interest.
On May 15, 2023, the Company acquired a corporate aircraft from a company affiliated with and controlled by the Company’s CEO.
The purchase price of the aircraft was $19.1 million, which was paid using $9.0 million of cash on hand and through the assumption of the
TVPX Loan (see Note 2 – Debt). The terms of this transaction were reviewed and approved by the Audit Committee of the Company’s
board of directors.
The aircraft was purchased as part of a series of transactions pursuant to which the Company restructured the compensation for its
Named Executive Officers. In connection with the Company’s efforts to reduce overall executive compensation, including perquisite
compensation the CEO was receiving for personal use of the aircraft, the Company entered into an amendment to the employment
agreement with the CEO in April 2023. This amendment requires that the Company be reimbursed for personal use of the aircraft in
accordance with the Company’s aircraft use policy.
Prior to the Company’s purchase of the aircraft, the Company used this aircraft for business purposes, and the CEO also used the
aircraft for personal purposes. Both the Company’s use of the aircraft for business purposes and the CEO’s unlimited use for personal
purposes were paid for by the Company pursuant to the CEO’s prior employment agreement. Airplane services transactions were
approximately $0.2 million, $1.7 million and $0.6 million for the each of the years ended 2023, 2022 and 2021, respectively.
An entity owned by the Company’s CEO has ownership interests in certain wells in which the Company does not have an ownership
interest. These wells are covered under the Company’s insurance policy. The entity reimburses the Company for its proportionate share of
insurance premiums related to these wells and, when insurance proceeds are collected related to damage, those costs are disbursed as
applicable. In addition, the entity reimburses the Company for certain administrative costs incurred during the year. Reimbursements from
such company totaled $0.4 million, $0.2 million and $0.2 million during 2023, 2022 and 2021, respectively, and are included on the
Company’s Consolidated Statements of Operations as a reduction to general and administrative expenses.
A company that provides marine transportation and logistics services to the Company employs the spouse of the Company’s CEO. The
rates charged for these marine and transportation services were generally either equal to or below rates charged by non-related, third-party
companies and/or otherwise determined to be of the best value to the Company. Payments to such company totaled $16.5 million,
$20.0 million and $12.0 million during 2023, 2022 and 2021, respectively. The spouse received commissions partially based on services
rendered to the Company which were approximately $0.1 million in each of 2023, 2022 and 2021.
An entity controlled by the Company’s CEO was a holder of the Company’s 9.75% Notes in the principal amount of $8.0 million. The
9.75% Notes were redeemed in February 2023.
An entity controlled by the Company’s CEO purchased $21.0 million in aggregate principal amount of the 11.75% Notes on the same
terms as the other lenders.
96
Table of Contents
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
An entity indirectly owned and controlled by the Company’s CEO is the sole lender under the Credit Agreement (see Note 2 – Debt).
In relation to the execution of amendments to the Credit Agreement, the Company paid arrangement and extension fees of approximately
$1.1 million and $0.8 million in 2022 and 2021, respectively, and paid legal fees on behalf of the entity of approximately $0.1 million and
$0.2 million in 2022 and 2021, respectively. No arrangements fees or legal fees were paid in 2023. In addition, during 2023, 2022 and
2021, the entity earned commitment fees of $1.5 million, $1.5 million and $1.0 million, respectively, equal to 3.0% of the unused
borrowing base lending commitment.
See Note 6 – Joint Venture Drilling Program for information on related party transactions concerning Monza.
NOTE 19 — CONTINGENCIES
Appeal with ONRR
In 2009, the Company recognized allowable reductions of cash payments for royalties owed to the ONRR for transportation of their
deepwater production through subsea pipeline systems owned by the Company. In 2010, the ONRR audited calculations and support
related to this usage fee, and ONRR notified the Company that they had disallowed approximately $4.7 million of the reductions taken. The
Company disagrees with the position taken by the ONRR and filed an appeal with the ONRR. The Company was required to post a surety
bond in order to appeal the Interior Board of Land Appeals decision. As of December 31, 2023, the value of the surety bond posted is $8.9
million.
The Company has continued to pursue its legal rights, and, at present, the case is in front of the U.S. District Court for the Eastern
District of Louisiana where both parties have filed cross-motions for summary judgment and opposition briefs. The Company has filed a
Reply in support of its Motion for Summary Judgment and the government has in turn filed its Reply brief. With briefing now completed,
the Company is waiting for the district court’s ruling on the merits.
ONRR Audit of Historical Refund Claims
On September 18, 2023, the Company received notification from the ONRR regarding results of an audit performed on W&T’s
historical refund claims taken on various properties for alleged royalties owed to the ONRR. The Company’s review and the ONRR appeal
process are ongoing, and the Company does not believe any accrual is necessary at this time.
Civil Penalties Assessment
In January 2021, the Company executed a Settlement Agreement with BSEE which resolved nine pending civil penalties issued by
BSEE. The civil penalties pertained to INCs issued by BSEE alleging regulatory non-compliance at separate offshore locations on various
dates between July 2012 and January 2018. Under the Settlement Agreement, the Company agreed to pay a total of $0.7 million in three
annual installments. The final installment was paid in February 2023.
Contingent Decommissioning Obligations
The Company may be subject to retained liabilities with respect to certain divested property interests by operation of law. Certain
counterparties in past divestiture transactions or third parties in existing leases that have filed for bankruptcy protection or undergone
associated reorganizations may not be able to perform required abandonment obligations. Due to operation of law, the Company may be
required to assume decommissioning obligations for those interests. The Company may be held jointly and severally liable for the
decommissioning of various facilities and related wells. The Company no longer owns these assets, nor are they related to current
operations.
During 2023, the Company incurred $8.5 million in costs related to these decommissioning obligations and recorded an additional $6.2
million of anticipated decommissioning obligations. As of December 31, 2023, the remaining loss contingency recorded related to the
anticipated decommissioning obligations is $18.0 million.
97
Table of Contents
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
Although it is reasonably possible that the Company could receive state or federal decommissioning orders in the future or be notified
of defaulting third parties in existing leases, the Company cannot predict with certainty, if, how or when such orders or notices will be
resolved or estimate a possible loss or range of loss that may result from such orders. However, the Company could incur judgments, enter
into settlements or revise the Company’s opinion regarding the outcome of certain notices or matters, and such developments could have a
material adverse effect on the Company’s results of operations in the period in which the amounts are accrued and the Company’s cash
flows in the period in which the amounts are paid. To the extent that the Company does incur costs associated with these properties future
periods, the Company intends to seek contribution from other parties that owned an interest in the facilities.
Other Claims
In the ordinary course of business, the Company is a party to various pending or threatened claims and complaints seeking damages or
other remedies concerning commercial operations and other matters in the ordinary course of its business. In addition, claims or
contingencies may arise related to matters occurring prior to the Company’s acquisition of properties or related to matters occurring
subsequent to the Company’s sale of properties. In certain cases, the Company has indemnified the sellers of properties acquired and, in
other cases, the Company has indemnified the buyers of properties sold. The Company is also subject to federal and state administrative
proceedings conducted in the ordinary course of business including matters related to alleged royalty underpayments on certain federal-
owned properties. Although the Company can give no assurance about the outcome of pending legal and federal or state administrative
proceedings and the effect such an outcome may have, the Company believes that any ultimate liability resulting from the outcome of such
proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on the consolidated
financial position, results of operations or liquidity of the Company.
NOTE 20 — SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)
Capitalized Costs
Net capitalized costs related to oil, NGLs and natural gas producing activities are as follows (in thousands):
Proved oil and natural gas properties and equipment
Accumulated depreciation, depletion and amortization
Net capitalized costs related to producing activities
$
$
Year Ended December 31,
2022
8,813,404
(8,088,271)
725,133
$
$
$
$
2023
8,919,403
(8,200,968)
718,435
2021
8,636,408
(7,981,271)
655,137
Depreciation, depletion and amortization ($/Boe)
8.85
7.32
6.50
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
The following costs were incurred in oil, NGLs and natural gas property acquisition, exploration, and development activities (in
thousands):
Acquisition of proved oil and natural gas properties (1)
Exploration costs (2)
Development costs (3)
Total
Year Ended December 31,
2022
2023
2021
$
$
43,736
12,250
54,022
110,008
$
$
78,565
24,498
77,282
180,345
$
$
2,197
18,444
47,218
67,859
(1)
Includes capitalized ARO of $16.4 million and $33.2 million during 2023 and 2022, respectively. There was no capitalized ARO related to acquisitions during 2021.
98
Table of Contents
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
(2)
(3)
Includes seismic costs of $2.8 million, $5.6 million, and $0.1 million incurred during 2023, 2022 and 2021, respectively. Includes geological and geophysical costs
charged to expense of $4.8 million, $5.5 million, and $5.7 million during 2023, 2022 and 2021, respectively.
Includes net additions from capitalized ARO of $21.0 million, $55.6 million, and $36.2 million during 2023, 2022 and 2021, respectively. These adjustments for ARO are
associated with liabilities incurred and revisions of estimates.
Oil and Natural Gas Reserve Information
There are numerous uncertainties in estimating quantities of proved reserves and in providing the future rates of production and timing
of development expenditures. The following reserve information represents estimates only and are inherently imprecise. Reserve estimates
were prepared based on the interpretation of various data by the Company’s independent reservoir engineers, including production data and
geological and geophysical data of the Company’s existing wells.
All of the Company’s reserves are located in the United States with all located in state and federal waters in the Gulf of Mexico. In
addition to other criteria, estimated reserves are assessed for economic viability based on the unweighted average of first-day-of-the-month
commodity prices over the period January through December for the year in accordance with definitions and guidelines set forth by the
SEC. The prices used do not purport, nor should it be interpreted, to present the current market prices related to estimated oil and natural
gas reserves.
The following sets forth changes in estimated quantities of net proved oil, NGLs and natural gas reserves:
Proved reserves as of December 31, 2020
Revisions of previous estimates
Purchase of minerals in place
Production
Proved reserves as of December 31, 2021
Revisions of previous estimates
Purchase of minerals in place
Production
Proved reserves as of December 31, 2022
Revisions of previous estimates
Extensions and discoveries
Purchase of minerals in place
Production
Proved reserves as of December 31, 2023
Year-end proved developed reserves:
2023
2022
2021
Year-end proved undeveloped reserves:
2023
2022
2021
Oil
(MMBbls)
NGLs
(MMBbls)
Natural Gas
(Bcf)
MMBoe
32.2
10.0
—
(5.0)
37.2
4.5
4.5
(5.6)
40.6
—
—
1.4
(5.0)
37.0
27.4
31.1
27.6
9.6
9.5
9.6
17.4
3.1
—
(1.4)
19.1
1.2
0.2
(1.6)
18.9
(4.0)
—
0.2
(1.4)
13.7
12.7
17.6
17.8
1.0
1.3
1.3
569.3
83.0
0.1
(44.8)
607.6
64.3
7.5
(44.8)
634.6
(168.8)
—
5.8
(37.6)
434.0
379.4
576.0
549.2
54.6
58.6
58.4
144.4
27.1
—
(13.9)
157.6
16.3
6.0
(14.6)
165.3
(32.2)
—
2.6
(12.7)
123.0
103.3
144.8
137.0
19.7
20.5
20.6
During 2023, decreases in revisions of previous estimates were primarily due to SEC price revisions for all proved reserves. Proved
reserves were also added through the acquisition of properties in September 2023.
During 2022, increases in revisions of previous estimates were primarily due to upward revisions to the Brazos A133 field combined
with increases due to SEC price revisions for all proved reserves. Proved reserves were also added
99
Table of Contents
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
through the acquisitions of properties acquired from ANKOR and subsequent working interest acquisition in the same properties from a
private seller.
During 2021, increases in revisions of previous estimates were primarily due to upward revisions to the Garden Banks 783 (Magnolia)
field combined with increases due to SEC price revisions for all proved reserves.
The Company believes that it will be able to develop all but 3.1 MMBoe (approximately 16%) of the total 19.7 MMBoe classified as
PUDs at December 31, 2023 within five years from the date such PUDs were initially recorded. The lone exceptions are at the Mississippi
Canyon 243 field (“Matterhorn”), Ship Shoal 349 and Viosca Knoll 823 (“Virgo”) where future development drilling has been planned as
sidetracks of existing wellbores due to conductor slot limitations and rig availability. Three sidetrack PUD locations, one each at
Matterhorn, Ship Shoal 349 and Virgo, will be delayed until an existing well is depleted and available to sidetrack. The Company also plans
to recomplete and convert an existing producer at Matterhorn to water injection for improved recovery following depletion of existing well.
Based on the latest reserve report, these PUD locations are expected to be developed in 2025 and 2035.
Standardized Measure of Discounted Future Net Cash Flows
The following presents the standardized measure of discounted future net cash flows related to the Company’s proved oil, NGLs and
natural gas reserves together with changes therein (in millions):
Future cash inflows
Future costs:
Production
Development and abandonment
Income taxes
Future net cash inflows
10% annual discount factor
Standardized measure of discounted future net cash flows
Year Ended December 31,
2022
2023
2021
$
4,282.3
$
8,856.0
$
5,178.0
(2,007.6)
(1,052.3)
(210.3)
1,012.1
(328.9)
683.2
$
(2,895.0)
(990.0)
(1,006.0)
3,965.0
(1,702.0)
2,263.0
$
(2,062.0)
(976.0)
(359.0)
1,781.0
(625.0)
1,156.0
$
Future cash inflows represent expected revenues from production of period-end quantities of proved reserve computed using SEC
pricing for the periods presented. All prices are adjusted by field for quality, transportation fees, energy content and regional price
differentials. Due to the lack of a benchmark price for NGLs, a ratio is computed for each field of the NGLs realized price compared to the
oil realized price. Then, this ratio is applied to the oil price using SEC guidance. The average base commodity prices used to determine the
standardized measure are as follows:
Oil ($/Bbl)
NGLs ($/Bbl)
Natural gas ($/Mcf)
2023
December 31,
2022
$
$
74.79
24.08
2.74
$
91.50
41.92
6.85
2021
65.25
26.83
3.68
Future production, development and abandonment costs and production rates and timing were based on the best information available
to the Company. Estimated future net cash flows, net of future income taxes, have been discounted to their present values based on the
prescribed annual discount rate of 10%.
The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair market
value of the Company’s oil, NGLs and natural gas reserves. Actual prices realized, costs incurred, and production quantities and timing
may vary significantly from those used.
100
Table of Contents
W&T Offshore, Inc.
Notes to Consolidated Financial Statements (continued)
The change in the standardized measure of discounted future net cash flows relating to the Company’s proved oil, NGLs and natural
gas reserves is as follows (in millions):
Standardized measure, beginning of year
Sales and transfers of oil, NGL and natural gas produced, net of production costs
Net changes in prices and production costs
Net change in future development costs
Revisions of quantity estimates
Acquisition of reserves in place
Accretion of discount
Net change in income taxes
Changes in timing and other
Standardized measure, end of year
$
$
NOTE 21 — SUBSEQUENT EVENTS
$
$
Year Ended December 31,
2022
1,156.0
(672.7)
1,368.6
(15.2)
249.1
225.2
138.1
(369.3)
183.2
2,263.0
2023
2,263.0
(240.1)
(1,241.4)
(22.0)
(828.8)
72.0
285.7
443.1
(48.3)
683.2
$
$
2021
493.7
(370.4)
980.9
(24.7)
289.6
0.3
44.0
(181.8)
(75.6)
1,156.0
On December 13, 2023, the Company entered into a purchase and sale agreement to acquire rights, titles and interest in and to certain
leases, wells and personal property in the central shelf region of the Gulf of Mexico, among other assets, for a gross purchase price of $72.0
million, subject to customary purchase price adjustments. The transaction closed on January 16, 2024 for $76.9 million (including closing
fees and other transaction costs) and was funded using cash on hand. The Company also assumed the related AROs associated with these
assets. The Company is in the process of completing the preliminary purchase price allocation of the assets acquired and the liabilities
assumed.
On January 26, 2024, the Company entered into a Fourteenth Amendment to the Credit Agreement to extend the maturity date of the
Credit Agreement to February 29, 2024.
On February 28, 2024, the Company entered into a Fifteenth Amendment to the Credit Agreement to extend the maturity date of the
Credit Agreement to March 28, 2024.
On March 5, 2024, the board of directors approved a first quarter dividend of $0.01 per share. The Company expects to pay the
dividend on March 25, 2024, to stockholders of record as of the close of business on March 18, 2024.
101
Table of Contents
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
In accordance with Exchange Act Rules 13a-15 and 15d-15, our management, with the participation of our President and Chief
Executive Officer and our Executive Vice President and Chief Financial Officer, supervised and participated in our evaluation of our
disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2023. Our
disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in
reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive
officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed,
summarized and reported within the time periods specified in the rules and forms of the SEC. However, a control system, no matter how
well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. The
design of a control system must reflect the fact that there are resource constraints, and the benefit of controls must be considered relative to
their costs. Consequently, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any,
within our company have been detected. Based upon that evaluation, our principal executive officer and principal financial officer
concluded that our disclosure controls and procedures were effective as of December 31, 2023 at the reasonable assurance level.
Management’s Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule
13a-15(f) under the Exchange Act. Management conducted an evaluation and assessment of the effectiveness of our internal control over
financial reporting as of December 31, 2023, based on the criteria set forth in Internal Control – Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based on this assessment, management has
concluded that our internal control over financial reporting was effective as of December 31, 2023.
The effectiveness of our internal control over financial reporting as of December 31, 2023 has been audited by Ernst & Young LLP, an
independent registered public accounting firm, as stated in their report which appears herein.
Attestation Report of the Registered Public Accounting Firm
Ernst & Young LLP, the independent registered public accounting firm that audited our consolidated financial statements included in
this Form 10-K, has issued an attestation report on the effectiveness of internal control over financial reporting as of December 31, 2023
which is included under Part II, Item 8. Financial Statements and Supplementary Data, in this Form 10-K.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that
materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
During the three months ended December 31, 2023, none of our directors or “officers” (as such term is defined in Rule 16(a)-1(f)
under the Exchange Act) adopted or terminated a “Rule 10b5-1 trading agreement” or “non-Rule 10b5-1 trading arrangement” (each as
defined in Item 408(a) and (c) of Regulation S-K).
102
Table of Contents
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this item is incorporated by reference from 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.
Our board of directors has adopted a Code of Business Conduct and Ethics applicable to all officers, directors and employees, which is
available on our website (www.wtoffshore.com) under “Investors.” We intend to satisfy the disclosure requirement under Item 5.05 of Form
8-K regarding amendment to, or waiver from, a provision of our Code of Business Conduct and Ethics by posting such information on the
website address and location specified above.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is incorporated by reference from 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.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
STOCKHOLDER MATTERS
The information required by this item is incorporated by reference from 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.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by this item is incorporated by reference from 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.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this item is incorporated by reference from 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.
103
Table of Contents
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
PART IV
(a) Documents filed as a part of this Form 10-K:
1. Financial Statements
See “Index to Consolidated Financial Statements” in Part II, Item 8 of this Form 10-K.
2. Financial Statement Schedules
All schedules are omitted because they are not applicable, not required or the required information is included in the
consolidated financial statements or related notes.
3. Exhibits
Exhibit
Number
Description
3.1
3.2
4.1†
4.2
4.3
Second Amended and Restated Articles of Incorporation of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.1
of the Company’s Quarterly Report on Form 10-Q, filed August 2, 2023)
Fourth Amended and Restated Bylaws of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.1 of the Company’s
Current Report on Form 8-K, filed April 26, 2023)
Indenture, dated as of January 27, 2023, by and among W&T Offshore, Inc., the guarantors party thereto and Wilmington
Trust, National Association, as trustee (including form of 11.75% Senior Second Lien Notes due 2026) (Incorporated by
reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K, filed on January 30, 2023)
Form of 11.750% Senior Second Lien Note due 2026 (included in Exhibit 4.1 hereto)
First Supplemental Indenture, dated as of May 25, 2023, among Falcon Aero Holdings LLC, Falcon Aero Holdco LLC,
W&T Offshore, Inc., the other Guarantors party thereto and Wilmington Trust, National Association, as trustee
(Incorporated by reference to Exhibit 4.1 of the Company’s Quarterly Report on Form 10-Q, filed August 2, 2023)
4.4
Description of Securities Registered Under Section 12 of the Securities Exchange Act of 1934, as amended (Incorporated
by reference to Exhibit 4.3 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2019)
10.1+
2004 Directors Compensation Plan of W&T Offshore, Inc. (Incorporated by reference to Exhibit 10.11 of the Company’s
Registration Statement on Form S-1, filed May 3, 2004)
10.2+
First Amendment to the 2004 Directors Compensation Plan of W&T Offshore, Inc. (Incorporated by reference to Appendix
A of the Company’s Definitive Proxy Statement, filed March 26, 2020)
10.3+
10.4+
W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (Incorporated by reference from Appendix A to
the Company’s Definitive Proxy Statement on Schedule 14A, filed April 2, 2010)
First Amendment to W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (Incorporated by reference
to Appendix A to the Company’s Definitive Proxy Statement on Schedule 14A filed April 3, 2013)
104
Table of Contents
10.5+
10.6+
10.7+
10.8+
10.9+
10.10+
10.11
10.12
10.13
10.14
Second Amendment to W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (Incorporated by
reference to Appendix B to the Company’s Definitive Proxy Statement on Schedule 14A filed April 3, 2013)
Third Amendment to W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (Incorporated by reference
to Appendix B to the Company’s Definitive Proxy Statement on Schedule 14A filed March 24, 2016)
Fourth Amendment to W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (Incorporated by reference
to Appendix A to the Company’s Definitive Proxy Statement on Schedule 14A filed March 24, 2017)
Employment Agreement between W&T Offshore, Inc. and Tracy W. Krohn dated as of November 1, 2010 (Incorporated by
reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed on November 5, 2010)
Amended and Restated Employment Agreement between W&T Offshore, Inc. and Tracy W. Krohn (Incorporated by
reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed on April 26, 2023)
Form of Indemnification Agreement by and between W&T Offshore, Inc. and each of its directors and certain of its officers
(Incorporated by reference to Exhibit 10.3 of the Company’s Quarterly Report on Form 10-Q, filed August 8, 2022)
Intercreditor Agreement, dated May 11, 2015, by and among W&T Offshore, Inc. Toronto Dominion (Texas) LLC, as
priority lien agent, Morgan Stanley Senior Funding, Inc. as second lien collateral trustee, and the various agents and lenders
party thereto (Incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K, filed May 14,
2015)
First Amendment to Intercreditor Agreement, dated as of October 18, 2018, by and among Toronto Dominion (Texas) LLC,
as Original Priority Lien Agent, Morgan Stanley Senior Funding, Inc., as Original Second Lien Collateral Trustee,
Wilmington Trust, National Association, as Original Second Lien Trustee, Wilmington Trust, National Association, as
Second Lien Trustee, Wilmington Trust, National Association, as Second Lien Collateral Trustee, Cortland Capital Market
Services LLC, as Priority Lien Agent, Wilmington Trust, National Association as Third Lien Collateral Trustee and
Wilmington Trust, National Association as Third Lien Trustee (Incorporated by reference to Exhibit 10.1 of the Company’s
Current Report on Form 8-K, filed on October 24, 2018)
Priority Confirmation Joinder, dated as of January 27, 2023, to the Intercreditor Agreement, as amended, by and between
Alter Domus (US) LLC, as Priority Lien Agent for the Priority Lien Secured Parties and Wilmington Trust, National
Association, as Second Lien Collateral Trustee for the Second Lien Secured Parties (Incorporated by reference to
Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed on January 30, 2023)
Sixth Amended and Restated Credit Agreement, dated as of October 18, 2018, by and among W&T Offshore, Inc., Toronto
Dominion (Texas) LLC, as agent and the various agents and lenders party thereto (Incorporated by reference to Exhibit
10.3 of the Company’s Current Report on Form 8-K, filed on October 24, 2018)
105
Table of Contents
10.15
10.16
10.17
10.18
10.19
10.20
10.21
10.22
10.23
10.24
10.25
First Amendment to Sixth Amended and Restated Credit Agreement, dated November 27, 2019, by and among W&T
Offshore, Inc., Toronto Dominion (Texas) LLC, as agent and the various agents and lenders party thereto (Incorporated by
reference to Exhibit 10.14 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2019, filed on
March 5, 2020)
Second Amendment and Consent to Sixth Amended and Restated Credit Agreement, dated February 24, 2020, by and
among W&T Offshore, Inc., Toronto Dominion (Texas) LLC, as agent and the various agents and lenders party thereto
(Incorporated by reference to Exhibit 10.15 of the Company’s Annual Report on Form 10-K for the year ended December
31, 2019, filed on March 5, 2020)
Third Amendment and Waiver to Sixth Amended and Restated Credit Agreement, dated June 17, 2020, by and among W&T
Offshore, Inc., Toronto Dominion (Texas) LLC, as agent and the various agents and lenders party thereto (Incorporated by
reference to Exhibit 10.1 of the Company’s Quarterly report on Form 10-Q, filed on June 23, 2020)
Fourth Amendment to Sixth Amended and Restated Credit Agreement, dated July 24, 2020, by and among W&T Offshore,
Inc., Toronto Dominion (Texas) LLC, as agent and the various agents and lenders party thereto (Incorporated by reference
to exhibit 10.19 of the Company’s Current Annual Report on Form 10-K for the year ended December 31, 2020, filed on
March 4, 2021)
Waiver, Consent to Second Amendment to Intercreditor Agreement and Fifth Amendment to Sixth Amended and Restated
Credit Agreement, dated January 6, 2021, by and among W&T Offshore, Inc., Toronto Dominion (Texas) LLC, as agent
and the various agents and lenders party thereto (Incorporated by reference to exhibit 10.1 of the Company’s Current
Report on Form 8-K, filed on January 12, 2021)
Waiver, Consent and Sixth Amendment to Sixth Amended and Restated Credit Agreement, dated May 19, 2021, by and
among W&T Offshore, Inc., the guarantor subsidiaries party thereto, the lenders party thereto, the issuers of letters of credit
party thereto and Toronto Dominion (Texas) LLC, individually and as agent (Incorporated by reference to exhibit 10.1 of
the Company’s Current Report on Form 8-K, filed on May 25, 2021)
Waiver and Seventh Amendment to Sixth Amended and Restated Credit Agreement, dated June 30, 2021 by and among
W&T Offshore, Inc., the guarantor subsidiaries party thereto, the lenders party thereto, the issuers of letters of credit party
thereto and Toronto Dominion (Texas) LLC, individually and as agent (Incorporated by reference to Exhibit 10.2 of the
Company’s Quarterly Report on Form 10-Q, filed on August 4, 2021)
Eighth Amendment to the Sixth Amended and Restated Credit Agreement and Master Assignment, Registration and
Appointment Agreement, dated effective as of November 2, 2021 (Incorporated by reference to Exhibit 10.1 of the
Company’s Quarterly Report on Form 10-Q, filed on November 3, 2021)
Ninth Amendment to the Sixth Amended and Restated Credit Agreement dated effective as of November 2, 2021
(Incorporated by reference Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q, filed on November 3, 2021)
Tenth Amendment to the Sixth Amended and Restated Credit Agreement dated effective as of March 8, 2022 (Incorporated
by reference Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q, filed on May 4, 2022)
Eleventh Amendment to the Sixth Amended and Restated Credit Agreement dated effective as of November 8, 2022
(Incorporated by reference Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q, filed on November 9, 2022)
106
Table of Contents
10.26†
Twelfth Amendment to the Sixth Amended and Restated Credit Agreement dated as of May 15, 2023 (Incorporated by
reference Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed on May 19, 2023)
10.27
10.28
10.29
10.30
10.31
10.32
10.33+
10.34+
10.35+
10.36+
10.37+
10.38+
Thirteenth Amendment to the Sixth Amended and Restated Credit Agreement dated effective as of December 29, 2023
(Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed January 2, 2024)
Fourteenth Amendment to the Sixth Amended and Restated Credit Agreement dated effective as of January 26, 2024
(Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed January 26, 2024)
Fifteenth Amendment to the Sixth Amended and Restated Credit Agreement dated as of February 28, 2024 (Incorporated by
reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed March 1, 2024)
Credit Agreement, dated May 19, 2021, by and among Aquasition LLC, as Borrower, Aquasition II LLC, as Co-Borrower,
and Munich Re Reserve Risk Financing, as the lenders party thereto (Incorporated by reference to Exhibit 10.3 of the
Company’s Quarterly Report on Form 10-Q, filed on August 8, 2021)
Purchase and Sale Agreement, dated December 13, 2023, by and among W&T Offshore, Inc., as buyer, and Cox Oil
Offshore, L.L.C., Energy XXI GOM, LLC, EPL Oil & Gas, LLC, MLCJR LLC, Cox Operating L.L.C., Energy XXI Gulf
Coast, LLC and M21K, LLC, as sellers (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on
Form 8-K, filed December 15, 2023)
Management Services Agreement, dated May 19, 2021, by and among Aquasition LLC, Aquasition II LLC, and W&T
Offshore, Inc. (Incorporated by reference to Exhibit 10.4 of the Company’s Quarterly Report on Form 10-Q, filed on
August 8, 2021)
W&T Offshore, Inc. 2023 Incentive Compensation Plan (Incorporated by reference to Exhibit 10.1 of the Company’s
Current Report on Form 8-K, filed June 20, 2023)
W&T Offshore, Inc. Change in Control Severance Plan (Incorporated by reference to Exhibit 10.2 of the Company’s
Current Report on Form 8-K, filed June 20, 2023)
Form of Restricted Stock Unit Agreement (Service-based Vesting), pursuant to the W&T Offshore, Inc. Amended and
Restated Incentive Compensation Plan (Incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on
Form 10-Q, filed August 8, 2022)
Form of Restricted Stock Unit Agreement (Performance Vesting), pursuant to the W&T Offshore, Inc. Amended and
Restated Incentive Compensation Plan (Incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on
Form 10-Q, filed August 8, 2022)
Form of Restricted Stock Unit Agreement (Service-based Vesting), pursuant to the W&T Offshore, Inc. Amended and
Restated Incentive Compensation Plan (Incorporated by reference to Exhibit 10.3 of the Company’s Quarterly Report on
Form 10-Q, filed August 2, 2023)
Form of Restricted Stock Unit Agreement (Performance Vesting), pursuant to the W&T Offshore, Inc. Amended and
Restated Incentive Compensation Plan (Incorporated by reference to Exhibit 10.4 of the Company’s Quarterly Report on
Form 10-Q, filed August 2, 2023)
107
Table of Contents
10.39+
10.40+
10.41+
Form of Restricted Stock Unit Grant Notice (Performance Vesting), pursuant to the W&T Offshore, Inc. 2023 Incentive
Compensation Plan (Incorporated by reference to Exhibit 10.3 of the Company’s Quarterly Report on Form 10-Q, filed
November 8, 2023)
Form of Restricted Stock Unit Grant Notice (Service-based Vesting), pursuant to the W&T Offshore, Inc. 2023 Incentive
Compensation Plan (Incorporated by reference to Exhibit 10.4 of the Company’s Quarterly Report on Form 10-Q, filed
November 8, 2023)
Form of Non-Employee Director Restricted Stock Unit Grant Notice, pursuant to the W&T Offshore, Inc. 2023 Incentive
Compensation Plan (Incorporated by reference to Exhibit 10.5 of the Company’s Quarterly Report on Form 10-Q, filed
November 8, 2023)
10.42+
Form of 2023 Executive Annual Incentive Award Agreement (Incorporated by reference to Exhibit 10.5 of the Company’s
Quarterly Report on Form 10-Q, filed August 2, 2023)
21.1*
Subsidiaries of the Registrant
23.1*
Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm
23.2*
Consent of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers and Geologists
31.1*
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer
31.2*
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer
32.1**
Certification of Chief Executive Officer and Chief Financial Officer of W&T Offshore, Inc. pursuant to 18 U.S.C. § 1350
97.1*
W&T Offshore, Inc, Clawback Policy, dated December 1, 2023
99.1**
Report of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers and Geologists
101.INS*
Inline XBRL Instance Document
101.SCH*
Inline XBRL Schema Document
101.CAL*
Inline XBRL Calculation Linkbase Document
101.DEF*
Inline XBRL Definition Linkbase Document
101.LAB*
Inline XBRL Label Linkbase Document
101.PRE*
Inline XBRL Presentation Linkbase Document
104*
Cover Page Interactive Data File (formatted as Inline XBLE and contained in Exhibit 101)
+ Management Contract or Compensatory Plan or Arrangement.
Filed herewith.
*
** Furnished herewith.
† Certain schedules and similar attachments to this agreement have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The
Company hereby undertakes to furnish a supplemental copy to each some omitted schedule or similar attachment to the SEC upon
request.
108
Table of Contents
ITEM 16. FORM 10-K SUMMARY
None.
109
Table of Contents
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Form
10-K to be signed on its behalf by the undersigned, thereunto duly authorized, on March 6, 2024.
SIGNATURES
W&T OFFSHORE, INC.
By:
/S/ SAMEER PARASNIS
Sameer Parasnis
Executive Vice President and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this Form 10-K has been signed below by the following persons
on behalf of the registrant and in the capacities indicated on March 6, 2024.
/S/ TRACY W. KROHN
Tracy W. Krohn
Chairman, Chief Executive Officer, President and Director
(Principal Executive Officer)
/S/ SAMEER PARASNIS
Sameer Parasnis
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
/S/ BART P. HARTMAN III
Bart P. Hartman III
Vice President and Chief Accounting Officer
(Principal Accounting Officer)
/S/ VIRGINIA BOULET
Virginia Boulet
/S/ DANIEL O. CONWILL IV
Daniel O. Conwill IV
/S/ B. FRANK STANLEY
B. Frank Stanley
DR. NANCY CHANG
/S/ DR. NANCY CHANG
Dr. Nancy Chang
Director
Director
Director
Director
110
The subsidiaries of W&T Offshore, Inc. are listed below.
SUBSIDIARIES OF W&T OFFSHORE, INC.
Name
Aquasition Energy LLC
Aquasition LLC
Aquasition II LLC
Aquasition III LLC
Aquasition IV LLC
Aquasition V LLC
Falcon Aero Holdco LLC
Falcon Aero Holdings LLC
Green Hell LLC
Seaquester LLC
Seaquestration LLC
W & T Energy VI, LLC
W & T Energy VII, LLC
White Shoal Pipeline Corporation
Exhibit 21.1
Percent
Owned
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
100.0%
73.4%
State of
Organization
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Exhibit 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in the following Registration Statements:
(1)
Registration Statement (Form S-3 No. 333-260248) of W&T Offshore, Inc.,
(2)
Registration Statement (Form S-3 No. 333-214168) of W&T Offshore, Inc.,
(3)
Registration Statement (Form S-8 No. 333-219747) pertaining to the W&T Offshore, Inc. Amended and Restated Incentive Compensation
Plan, as amended, and
(4)
Registration Statement (Form S-8 No. 333-272794) pertaining to the W&T Offshore, Inc. 2023 Incentive Compensation Plan
of our reports dated March 6, 2024, with respect to the consolidated financial statements of W&T Offshore, Inc. and subsidiaries, and the
effectiveness of internal control over financial reporting of W&T Offshore, Inc. and subsidiaries included in this Annual Report (Form 10-
K) for the year ended December 31, 2023.
/s/ ERNST & YOUNG LLP
Houston, Texas
March 6, 2024
Exhibit 23.2
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
As independent consultants, Netherland, Sewell & Associates, Inc. hereby consents to the incorporation by reference in the Annual Report on Form
10-K of W&T Offshore, Inc. to be filed on or about March 6, 2024, of information from our reserves report with respect to the reserves of W&T Offshore,
Inc. dated January 24, 2024, and entitled "Estimates of Reserves and Future Revenue to the W&T Offshore, Inc. Interest in Certain Oil and Gas Properties
Located in State Waters Offshore Alabama, Louisiana, and Texas, and in the Gulf of Mexico as of December 31, 2023", and to the use of our reports on
reserves and the incorporation of the reports on reserves for the years ended 2018, 2019, 2020, 2021 and 2022. We further consent to the incorporation by
reference of information contained in our report dated January 24, 2024, in the Registration Statements (Form S-3 Nos. 333-260248 and 333-214168) of
W&T Offshore, Inc., in the Registration Statement (Form S-8 No. 333-219747) pertaining to the W&T Offshore, Inc. Amended and Restated Incentive
Compensation Plan and in the Registration Statement (Form S-8 No. 333-272794) pertaining to the W&T Offshore, Inc. 2023 Incentive Compensation
Plan. We also consent to W&T Offshore, Inc.'s use of the phrase "independent petroleum consultant" as referencing Netherland, Sewell & Associates, Inc.
NETHERLAND, SEWELL & ASSOCIATES, INC.
By:/s/ Eric J. Stevens, P.E.
Eric J. Stevens, P.E.
President and Chief Operating Officer
Dallas, Texas
March 6, 2024
Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients.
The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the
parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original
document, the original document shall control and supersede the digital document.
Exhibit 31.1
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
PURSUANT TO RULE 13a – 14(a) AND 15d – 14(a)
OF §302 OF THE SARBANES-OXLEY ACT OF 2002
I, Tracy W. Krohn, certify that:
1.
I have reviewed this Annual Report on Form 10-K of W&T Offshore, Inc. (the “registrant”);
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-
15(f)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by
others within those entities, particularly during the period in which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for
external purposes in accordance with generally accepted accounting principles;
c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most
recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably
likely to materially affect, the registrant’s internal control over financial reporting.
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to
the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal
control over financial reporting.
Date: March 6, 2024
/s/ Tracy W. Krohn
Tracy W. Krohn
Chairman, Chief Executive Officer, President and Director
(Principal Executive Officer)
Exhibit 31.2
CERTIFICATION OF CHIEF FINANCIAL OFFICER
PURSUANT TO RULE 13a – 14(a) AND 15d – 14(a)
OF §302 OF THE SARBANES-OXLEY ACT OF 2002
I, Sameer Parasnis, certify that:
1.
I have reviewed this Annual Report on Form 10-K of W&T Offshore, Inc. (the “registrant”);
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-
15(f)) for the registrant and have:
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by
others within those entities, particularly during the period in which this report is being prepared;
b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for
external purposes in accordance with generally accepted accounting principles;
c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most
recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably
likely to materially affect, the registrant’s internal control over financial reporting.
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to
the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal
control over financial reporting.
Date: March 6, 2024
/s/ Sameer Parasnis
Sameer Parasnis
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER
PURSUANT TO 18 U.S.C. § 1350, AS ADOPTED
PURSUANT TO §906 OF THE SARBANES-OXLEY ACT OF 2002
Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, each of the undersigned officers of
W&T Offshore, Inc. (the “Company”), hereby certifies, to the best of his knowledge, that the Company’s Annual Report on Form 10-K for the year
ended December 31, 2023 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and that
the information contained in such Annual Report fairly presents, in all material respects, the financial condition and results of operations of the
Company.
Exhibit 32.1
Date: March 6, 2024
Date: March 6, 2024
/s/ Tracy W. Krohn
Tracy W. Krohn
Chairman, Chief Executive Officer, President and Director
(Principal Executive Officer)
/s/ Sameer Parasnis
Sameer Parasnis
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
Exhibit 97.1
W&T OFFSHORE, INC.
CLAWBACK POLICY
Purpose
The Board of Directors (the “Board”) of W&T Offshore, Inc. (the “Company”) has adopted this policy
which provides for the recoupment of certain executive compensation in the event of a required accounting
restatement of the Company’s financial statements due to material noncompliance with financial reporting
requirements under the U.S. federal securities laws (which shall exclude any restatement caused by a change in
applicable accounting rules or interpretations), or an error or mistake in the calculation of a performance metric
or goal that was the basis of the payment of incentive-based compensation (as defined below) (the “Policy”).
This Policy is designed to comply with Section 10D of the Securities Exchange Act of 1934, as amended (the
“Exchange Act”), the rules promulgated thereunder, and the listing standards of the national securities exchange
on which the Company’s securities are listed.
Administration
This Policy shall be administered by the Compensation Committee of the Board (the “Committee”). Any
determinations made by the Committee shall be final and binding on all affected individuals. The Committee is
authorized to interpret and construe this Policy. It is intended that this Policy be interpreted in a manner that is
consistent with the requirements of Section 10D of the Exchange Act and the applicable rules or standards
adopted by the Securities and Exchange Commission or any national securities exchange on which the
Company’s securities are listed. The Committee may require that any employment or service agreement, equity
award agreement, or similar agreement or arrangement entered into on or after the Effective Date (as defined
below) shall, as a condition to the grant of any benefit thereunder, require a Subject Executive (as defined
below) to agree to the terms of this Policy.
Subject Executives; Recoupment; Accounting Restatement
The Committee shall, as to (i) any current or former executive officer (as determined by the Committee
in accordance with Section 10D of the Exchange Act, the rules promulgated thereunder, and the listing
standards of the national securities exchange on which the Company’s securities are listed) and (ii) such other
senior executives/employees who may from time to time be deemed subject to this Policy by the Committee (all
individuals identified in clause (i) or (ii) a “Subject Executive”), cause the Company to require the
reimbursement by the Subject Executive of all or a portion of any incentive-based compensation paid or
awarded to the Subject Executive up to the amounts specified below where: (a) the Company is required to
prepare an accounting restatement of its financial statements due to the Company’s material noncompliance
with any financial reporting requirement under the securities laws, including any required accounting
restatement to correct an error in previously issued financial statements that is material to the previously issued
financial statements, or that would result in a material misstatement if the error were corrected in the current
period or left uncorrected in the current period (each an “Accounting Restatement”), (b) the payment to the
Subject Executive was predicated upon the achievement of certain financial results that were subsequently the
subject of the Accounting Restatement or the
miscalculation and (c) the amount received by the Subject Executive exceeded the amount that otherwise would
have been received had it been determined based on the Accounting Restatement (the “Overpayment”).
For incentive-based compensation based on stock price or total shareholder return, where the amount of
erroneously awarded compensation is not subject to mathematical recalculation directly from the information in
the Accounting Restatement, the amount must be based on a reasonable estimate of the effect of the Accounting
Restatement on the stock price or total shareholder return upon which the incentive-based compensation was
received; and the Company must maintain documentation of the determination of that reasonable estimate and
provide such documentation to the exchange on which the Company’s securities are listed.
The Committee will require reimbursement or forfeiture of the Overpayment received by any Subject
Executive during the three (3) completed fiscal years immediately preceding the date on which the Company is
required to prepare an Accounting Restatement and any transition period (that results from a change in the
Company’s fiscal year) within or immediately following those three (3) completed fiscal years.
In no event shall the Company be required to award Subject Executives an additional payment if the
restated or accurate financial results would have resulted in a higher incentive-based compensation payment.
Incentive-Based Compensation
“Incentive-based compensation” covered by this Policy and the related amount that is subject to being
clawed back by the Company means any compensation that is granted, earned, or vested based wholly or in part
upon the attainment of financial reporting measures. The incentive-based compensation covered by this Policy
and the related amount that will be subject to being clawed back by the Company includes, but is not limited to:
●
Bonus. This Policy applies to an annual bonus (including any cash-settled or equity settled annual
incentive award, the settlement of which is or was contingent solely or in part upon achievement of one
or more performance objectives as contemplated by W&T Offshore, Inc’s incentive compensation plan,
as amended or restated from time to time, or any similar plan (the “Plan”)), paid with respect to a year to
which the Accounting Restatement or miscalculation applies, except that this Policy is not applicable to
any annual bonus paid solely based on satisfaction of subjective standards, such as demonstrating
leadership, and/or completion of a specified employment period or paid with respect to performance for
a fiscal year preceding the three (3) completed fiscal years immediately prior to the fiscal year in which
the Committee determines that an Accounting Restatement or new calculation is required. The amount
subject to being clawed back will be the incremental amount, without regard to any taxes paid, that the
Board determines was paid in excess of the amount that would have been paid had the financial
statements been in material compliance with the financial reporting requirements under U.S. federal
securities laws or all calculations had been correct.
2
● Restricted Stock Units and other Equity Awards. This Policy applies to the number of shares of
Company common stock issued in settlement of Restricted Stock Unit (“RSU”) awards and other share-
settled Awards (as defined in the Plan) granted pursuant to the Plan, the settlement of which is or was
contingent in whole or in part upon achievement of one or more performance objectives as contemplated
by the Plan and whose final day of the applicable performance period occurs in a year to which the
Accounting Restatement or miscalculation applies, except that this Policy is not applicable to any RSU
awards or other Plan awards whose final day of the applicable performance period occurs in a fiscal year
preceding the three (3) completed fiscal years immediately prior to the fiscal year in which the
Committee determines that an Accounting Restatement or new calculation is required. The number of
shares subject to being clawed back will be the total shares without regard to any taxes paid that the
Board determines were issued in excess of the number of shares that would have been issued had the
financial statements been in material compliance with the financial reporting requirements under U.S.
federal securities laws or all calculations had been correct. If any shares to be clawed back have been
sold, then the proceeds of such sale, net of brokers’ commissions, may be clawed back.
● Sale Proceeds. This Policy applies to proceeds from the sale of shares acquired through the Plan that
were granted or vested solely or in part on satisfying one or more financial reporting measure
performance objectives as contemplated by the Plan. Compensation that would not be considered
incentive-based compensation includes, but is not limited to: (i) salaries; (ii) bonuses paid solely on
satisfying subjective standards, such as demonstrating leadership, and/or completion of a specified
employment period; (iii) non-equity incentive plan awards earned solely on satisfying strategic or
operational measures; (iv) wholly time-based equity awards; and (v) discretionary bonuses or other
compensation that is not paid from a bonus pool that is determined by satisfying one or more financial
reporting measures as contemplated by the Plan.
Incentive-based compensation is deemed received in the Company’s fiscal period during which the
financial reporting measure specified in the incentive-based compensation award is attained, even if the
payment or grant of the incentive-based compensation occurs after the end of that period.
Method of Recoupment
The Committee shall have sole discretion in determining the form, amount and timing of the recoupment
of any Overpayment, subject to applicable stock exchange rules and law. Any right of recoupment under this
Policy is in addition to, and not in lieu of, any other remedies or rights of recoupment that may be available to
the Company pursuant to the terms of any similar policy in any employment agreement, equity award
agreement, or similar agreement and any other legal remedies available to the Company, including:
● requiring reimbursement of cash incentive-based compensation previously paid;
● seeking recovery of any gain realized on the vesting, exercise, settlement, sale, transfer, or other
disposition of any equity-based awards granted as incentive based compensation;
3
● offsetting the recouped amount from any compensation otherwise owed by the Company to the Subject
Executive;
● cancelling outstanding vested or unvested equity awards; and/or
● taking any other remedial and recovery action permitted by law, as determined by the Committee.
In lieu of requiring a claw back of amounts in accordance with the above bullet points, the Committee
may claw back unvested equity awards, as determined by the Committee.
Impracticability
The Committee shall recover any Overpayment in accordance with this Policy except to the extent that
the Committee determines such recovery would be impracticable because:
● direct expenses paid to a third party to assist in enforcing the policy would exceed the amount to be
recovered;
● recovery would violate home country law where that law was adopted prior to November 28, 2022; or
● recovery would likely cause an otherwise tax-qualified retirement plan, under which benefits are broadly
available to employees of the Company, to fail to meet the requirements of 26 U.S.C. 401(a)(13) or 26
U.S.C. 411(a) and regulations thereunder.
No Indemnification
The Company shall not indemnify any Subject Executive against the loss of any incorrectly awarded
incentive-based compensation.
Each Subject Executive’s acceptance of incentive-based compensation shall constitute his or her
agreement (i) to be bound by this Policy and (ii) to not seek indemnification or contribution from the Company
for any amounts clawed back.
Before the Committee determines to seek recovery pursuant to this Policy, it shall provide to the Subject
Executive written notice and the opportunity to be heard at a meeting of the Board of Directors of the Company.
Effective Date
This Policy shall be effective as of December 1, 2023 (the “Effective Date”) and shall apply to
Incentive-based compensation (including Incentive-based compensation granted pursuant to arrangements
existing prior to the Effective Date). Notwithstanding the foregoing, this Policy shall only apply to Incentive-
based compensation received (as determined pursuant to this Policy) on or after October 2, 2023.
4
Amendment or Termination
The Board may amend this Policy from time to time in its discretion. The Board may terminate this
Policy at any time.
5
Exhibit 99.1
EXECUTIVE CHAIRMAN
C.H. (SCOTT) REES III
DANNY D. SIMMONS
CHIEF EXECUTIVE OFFICER
RICHARD B. TALLEY, JR.
PRESIDENT & COO
ERIC J. STEVENS
EXECUTIVE COMMITTEE
ROBERT C. BARG
P. SCOTT FROST
JOHN G. HATTNER
JOSEPH J. SPELLMAN
January 24, 2024
Mr. Matthew W. McFarland
W&T Offshore, Inc.
5718 Westheimer Road, Suite 700
Houston, Texas 77057
Dear Mr. McFarland:
In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2023, to the W&T Offshore, Inc.
(W&T) interest in certain oil and gas properties located in state waters offshore Alabama, Louisiana, and Texas and in federal waters in the Gulf of
Mexico. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report
constitute all of the proved reserves owned by W&T. The estimates in this report have been prepared in accordance with the definitions and
regulations of the U.S. Securities and Exchange Commission (SEC) and conform to the FASB Accounting Standards Codification Topic 932,
Extractive Activities—Oil and Gas, except that future income taxes are excluded and, as requested, abandonment costs have not been included in
our estimates of future net revenue. Definitions are presented immediately following this letter. This report has been prepared for W&T's use in
filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such
purpose.
For fields included in the Monza Joint Venture (Monza JV), the net reserves and future net revenue to the W&T interest have been estimated
incorporating the terms of the Monza JV using the proportional consolidation method. W&T entered into the Monza JV on February 23, 2018.
Under the proportional consolidation method, W&T's interest share of revenues, expenses, investments, and liabilities includes both W&T's direct
interest in the properties and W&T's interest share of the Monza JV.
We estimate the net reserves and future net revenue to the W&T interest in these properties, as of December 31, 2023, to be:
Category
Proved Developed Producing
Proved Developed Non-Producing
Proved Undeveloped
Total Proved
Totals may not add because of rounding.
Oil
(MBBL)
22,202.4
5,167.7
9,575.5
36,945.7
Net Reserves
NGL
(MBBL)
10,051.9
2,664.1
1,008.7
13,724.7
Gas
(MMCF)
299,361.8
80,058.5
54,566.9
433,987.1
Future Net Revenue(1) (M$)
Total
1,026,883.0
388,956.5
305,403.2
1,721,242.7
Present Worth
at 10%
750,118.1
204,058.5
126,719.7
1,080,896.3
(1) Future net revenue does not include estimated abandonment costs.
The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels
(MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature
and pressure bases.
Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. As
requested, probable and possible reserves that exist for these properties have not been included. Estimates of proved undeveloped reserves
have been included for three proved locations that are scheduled to be drilled more than five years beyond the original booking dates because of
limitations with conductor slot availability. These locations have been included based on W&T’s declared intent to drill these wells. The estimates
of reserves and future revenue included herein have not been adjusted for risk. This report does not
2100 ROSS AVENUE, SUITE 2200 • DALLAS, TEXAS 75201 • PH: 214-
969-5401 • FAX: 214-969-5411
1301 MCKINNEY STREET, SUITE 3200 • HOUSTON, TEXAS 77010 • PH: 713-654-4950 • FAX: 713-654-4951
info@nsai-petro.com
netherlandsewell.com
include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been
estimated.
Gross revenue is W&T's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after
deductions for W&T's share of state production taxes, ad valorem taxes, capital costs, and operating expenses but before consideration of any
income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to
indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be
construed as being the fair market value of the properties.
Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the
period January through December 2023. For oil and NGL volumes, the average West Texas Intermediate spot price of $78.21 per barrel is
adjusted by field for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $2.637 per
MMBTU is adjusted by field for energy content, transportation fees, and market differentials. All prices are held constant throughout the lives of the
properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $74.79 per barrel of oil,
$24.08 per barrel of NGL, and $2.739 per MCF of gas.
Operating costs used in this report are based on operating expense records of W&T. For the nonoperated properties, these costs include the per-
well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field
levels. As requested, operating costs for the operated properties are limited to direct lease- and field-level costs and W&T's estimate of the portion
of its headquarters general and administrative overhead expenses necessary to operate the properties. Economic projections are included to
account for the fees associated with W&T's oil transportation contracts for Green Canyon 859 Field; the minimum transportation obligation
extends beyond the economic life of the field. For all other areas, we have made no specific investigation of any firm transportation contracts that
may be in place and our estimates of future revenue include the effects of such contracts only to the extent that the associated fees are accounted
for in the historical field- and lease-level accounting statements. Operating costs have been divided into field-level costs, per-well costs, and per-
unit-of-production costs and are not escalated for inflation. As requested, the field-level costs are allocated by month among the proved reserves
categories.
Capital costs used in this report were provided by W&T and are based on authorizations for expenditure (AFEs) prepared for internal approval
and, if applicable, external interest owner approval. If an AFE was not available, W&T provided cost estimates based on recent activity similar in
scope to the proposed project. Capital costs are included as required for workovers, new development wells, and production equipment. Based on
our understanding of W&T's future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard
these estimated capital costs to be reasonable. Capital costs are not escalated for inflation. As requested, our estimates do not include any
salvage value for the lease and well equipment or the cost of abandoning the properties.
For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or
condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do
not include any costs due to such possible liability.
We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the W&T interest.
Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are
based on W&T receiving its net revenue interest share of estimated future gross production after field usage and shrinkage.
The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil
and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible;
probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates
of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance.
In addition to the primary economic assumptions discussed herein, our estimates are based
on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to
us by W&T, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would
impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual
performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated
amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs
incurred in recovering such reserves may vary from assumptions made while preparing this report.
For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, petrophysical data,
seismic data, well test data, production data, bottomhole pressure data, historical price and cost information, and property ownership interests.
The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the
Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers
(SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis,
volumetric analysis, analogy, and reservoir modeling, that we considered to be appropriate and necessary to categorize and estimate reserves in
accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation
of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.
The data used in our estimates were obtained from W&T, public data sources, and the nonconfidential files of Netherland, Sewell & Associates,
Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or
independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates
presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards.
Gregory S. Cohen, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since
2013 and has over 14 years of prior industry experience. Ruurdjan (Rudi) de Zoeten, a Licensed Professional Geoscientist in the State of Texas,
has been practicing consulting petroleum geoscience at NSAI since 2008 and has over 18 years of prior industry experience. We are independent
petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a
contingent basis.
Sincerely,
NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-2699
By:
/s/ Richard B. Talley, Jr.
Richard B. Talley, Jr., P.E.
Chief Executive Officer
By:
/s/ Gregory S. Cohen
Gregory S. Cohen, P.E. 117412
Vice President
By:
/s/ Ruurdjan (Rudi) de Zoeten
Ruurdjan (Rudi) de Zoeten, P.G. 3179
Vice President
Date Signed: January 24, 2024
Date Signed: January 24, 2024
GSC:ARS
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is
supplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the
FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure
Interpretations.
(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to
purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees,
recording fees, legal costs, and other costs incurred in acquiring properties.
(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions
(depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of
interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support
proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:
(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
(ii) Same environment of deposition;
(iii) Similar geological structure; and
(iv) Same drive mechanism.
Instruction to paragraph (a) (2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.
(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity
greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state
it usually contains sulfur, metals, and other non-hydrocarbons.
(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but
that, when produced, is in the liquid phase at surface pressure and temperature.
(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from
the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.
(6) Developed oil and gas reserves. Developed oil and gas reserves are 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.
Supplemental definitions from the 2018 Petroleum Resources Management System:
Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective
date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion
intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or
pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from
zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access
these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing
the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities
and other costs of development activities, are costs incurred to:
(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific
development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent
necessary in developing the proved reserves.
(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of
well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
Definitions - Page 1 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices,
and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
(iv) Provide improved recovery systems.
(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible.
As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a
group of several fields and associated facilities with a common ownership may constitute a development project.
(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that
exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at
the terminal point of oil and gas producing activities as defined in paragraph (a) (16) of this section.
(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative
production as of that date.
(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to
have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells.
Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after
acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and
facilities and other costs of exploration activities, are:
(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and
other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as
geological and geophysical or "G&G" costs.
(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title
defense, and the maintenance of land and lease records.
(iii) Dry hole contributions and bottom hole contributions.
(iv) Costs of drilling and equipping exploratory wells.
(v) Costs of drilling exploratory-type stratigraphic test wells.
(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of
oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a
stratigraphic test well as those items are defined in this section.
(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.
(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural
feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious
strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated
as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized
geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.
(16) Oil and gas producing activities.
(i) Oil and gas producing activities include:
(A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and
original locations;
(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas
from such properties;
(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the
acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
(1) Lifting the oil and gas to the surface; and
(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
Definitions - Page 2 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable
natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such
extraction.
Instruction 1 to paragraph (a) (16) (i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet
valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal
point for the production function as:
a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a
b.
marine terminal; and
In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a
purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery,
a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.
Instruction 2 to paragraph (a) (16) (i): For purposes of this paragraph (a) (16), the term saleable hydrocarbons means hydrocarbons that are
saleable in the state in which the hydrocarbons are delivered.
(ii) Oil and gas producing activities do not include:
(A) Transporting, refining, or marketing oil and gas;
(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does
not have the legal right to produce or a revenue interest in such production;
(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and
gas can be extracted; or
(D) Production of geothermal steam.
(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved
plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total
quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of
available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to
define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than
the recovery quantities assumed for probable reserves.
(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical
and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in
successful similar projects.
(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the
same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other
geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in
communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than
the proved area if these areas are in communication with the proved reservoir.
(vi) Pursuant to paragraph (a) (22) (iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the
potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir
above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the
reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir
fluid properties and pressure gradient interpretations.
(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which,
together with proved reserves, are as likely as not to be recovered.
(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated
proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities
recovered will equal or exceed the proved plus probable reserves estimates.
Definitions - Page 3 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available
data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty
criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in
communication with the proved reservoir.
(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the
hydrocarbons in place than assumed for proved reserves.
(iv) See also guidelines in paragraphs (a) (17) (iv) and (a) (17) (vi) of this section.
(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could
reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes
and their associated probabilities of occurrence.
(20) Production costs.
(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs
of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They
become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:
(A) Costs of labor to operate the wells and related equipment and facilities.
(B) Repairs and maintenance.
(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
(E) Severance taxes.
(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining,
and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their
depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation,
depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part
of the cost of oil and gas produced along with production (lifting) costs identified above.
(21) Proved area. The part of a property to which proved reserves have been specifically attributed.
(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and 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.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and
(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain
economically producible oil or gas on the basis of available geoscience and engineering data.
(ii)
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in
a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with
reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an
associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience,
engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid
injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the
operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes
the reasonable certainty of the engineering analysis on which the project or program was based; and
Definitions - Page 4 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price
shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an
unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by
contractual arrangements, excluding escalations based upon future conditions.
(23) Proved properties. Properties with proved reserves.
(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be
recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed
the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased
availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery
(EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field
tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in
an analogous formation.
(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as
of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable
expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or
related substances to market, and all permits and financing required to implement the project.
Note to paragraph (a) (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those
reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a
known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may
contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be
disclosed as of the end of the year:
a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in
the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph
932-235-50-7).
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting
purposes.
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are
disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:
a. Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-
end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in
existence at year-end.
b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing
and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing
economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production
costs.
c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with
consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves,
less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and
allowances relating to the entity's proved oil and gas reserves.
d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax
expenses from future cash inflows.
Definitions - Page 5 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows
relating to proved oil and gas reserves.
f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.
(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by
impermeable rock or water barriers and is individual and separate from other reservoirs.
(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may
be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and
undiscovered accumulations.
(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells
include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-
situ combustion.
(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic
condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes
tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory
type" if not drilled in a known area or "development type" if drilled in a known area.
(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from
new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of
production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility
at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they
are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):
Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or
environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods,
this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer
time period, and any extension beyond five years should be the exception, and not the rule.
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may
extend past five years include, but are not limited to, the following:
● The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum
number of wells necessary to maintain the lease generally would not constitute significant development activities);
● The company's historical record at completing development of comparable long-term projects;
● The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;
●
The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its
development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves
typically would not be appropriate); and
● The extent to which delays in development are caused by external factors related to the physical operating environment (for example,
restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting
resources to develop properties with higher priority).
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in
the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable
technology establishing reasonable certainty.
(32) Unproved properties. Properties with no proved reserves.
Definitions - Page 6 of 6