W&T Offshore, Inc. Annual Report 2021

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FY2021 Annual Report · W&T Offshore, Inc.

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2021 Annual Report

Our Team Drives
Our Success
**PRINTER
PLEASE
CREATE
SPINE

W&T Offshore, Inc.

5718 Westheimer Rd, Suite 700

Houston, TX 77057-5745

wtoffshore.com

W&T Offshore, Inc. NYSE: WTI

A strong
team is the
foundation on
which great
companies
are built.

Board of Directors

Tracy W. Krohn

Founder, Chairman,

Chief Executive Officer

and President

Virginia Boulet

Presiding Director

Daniel O. Conwill IV

B. Frank Stanley

Director

Executive Officers

Tracy W. Krohn

Founder, Chairman,

Janet Yang

William J. Williford

Stephen L. Schroeder

Shahid A. Ghauri

Executive Vice President

Senior Vice President and

Vice President, General

Chief Executive Officer

and Chief Financial

and Chief Operating

Chief Technical Officer

Counsel and Corporate

and President

Officer

Secretary

Corporate Office

W&T Offshore, Inc.

5718 Westheimer Road, Suite 700

Houston, TX 77057-5745

Tel 713.626.8525

www.wtoffshore.com

Registrar & Transfer Agent

Communication concerning the transfer of

shares, lost certificates, duplicate mailings

Annual Meeting

or change of address notifications should be

directed to the transfer agent.

Computershare Investor

Services, L.L.C.

33 North LaSalle Street

Suite 1100

Chicago, IL 60602

Tel 312.588.4992

us.computershare.com

Independent Auditors

Ernst & Young LLP, Houston, TX

Independent Petroleum Consultants

Netherland, Sewell & Associates, Inc.

2100 Ross Avenue

Suite 2200

Dallas, TX 75201

In light of public health concerns

regarding the coronavirus outbreak and in

consideration of medical and governmental

recommendations limiting the number of

persons that may gather at public events,

the Annual Meeting of Shareholders will

be held in a virtual meeting format only

at www.virtualshareholdermeeting.com/

WTI2022 on May 3, 2022 at 8:00 a.m.,

Central Daylight Time.

Form 10-K & Quarterly Reports /

Investor Contact

A copy of the W&T Offshore, Inc. Form

10-K for the year ended December 31, 2021

and quarterly Form 10-Q reports filed with

the Securities and Exchange Commission,

are available from the Company. Requests

for investor-related information should

be directed to Investor Relations at the

Company’s corporate office or on the

Internet at www.wtoffshore.com. E-mail:

investorrelations@wtoffshore.com. The

W&T Offshore, Inc. Form 10-K and quarterly

Form 10-Q reports are also available on our

Web site at www.wtoffshore.com. The most

recent certifications by the Chief Executive

Officer and Chief Financial Officer pursuant

to Section 301 of the Sarbanes-Oxley Act of

2002 are filed as exhibits to the Form 10-K.

Tracy W. Krohn, W&T’s Chief Executive

Officer, has also filed with the New York

Stock Exchange the most recent Annual

CEO Certification as required by Section

303A.12(a) of the New York Stock Exchange

Listed Company Manual.

2021 Annual Report

Since W&T’s founding nearly 40 years ago, our people have always been our most valuable asset.

Through multiple commodity cycles over those many years, our culture, principles, values, and

ultimately our success have been guided by our people. We are collectively focused on cash flow

generation, operational excellence, corporate responsibility, and strengthening our financial position.

We are excited for the future and look forward to sustainably growing the Company.

WHO WE ARE

Founded in 1983, W&T Offshore, Inc. (W&T) is an

independent oil and natural gas producer with offshore

operations across all water depths in the Gulf of Mexico

(GOM). For almost four decades, we have grown through a

combination of attractive property acquisitions, methodical

integration and exploitation of those acquisitions, and

successful development and exploratory drilling on our

legacy fields.

A majority of our daily production is derived from wells we

operate. As of December 31, 2021, we own working interests

in 144 offshore structures, 103 of which are located in

fields that we operate. We have ownership interests in 178

productive wells, 142 of which we operate.

At year-end, we have working interests in 43 producing

fields. These fields are in both federal and state waters and

our leases cover approximately 606,000 gross acres, of

which 411,000 acres are on the GOM shelf in less than 500

feet of water, 187,000 acres are in deepwater in 500 feet

of water or greater, and 8,000 acres are in Alabama state

waters. Approximately 80% of our average daily production

is in shallow water while the balance is in deepwater.

W&T became a public company in 2005 and trades on the

NYSE under the symbol “WTI”.

W&T Offshore, Inc. NYSE: WTI

To my fellow
Shareholders,

These past two years have been truly extraordinary

with everything from a global COVID-19 pandemic,

to multiple years of active tropical storms in the Gulf

of Mexico, to dramatic swings in oil and gas pricing.

Through it all, we have persevered by remaining focused

and committed to the core values that have guided our

success for the past four decades: maximizing cash

flow generation, operating efficiently, and striving to

constantly improve the profitability of our assets at any

commodity price. These are the operating principles

we have focused on to build value for our shareholders,

while developing and producing oil and gas resources in

a safe and environmentally responsible manner. These

core values have provided the foundation for W&T to

profitably grow over the years through a combination of

accretive property acquisitions, methodical integration

and exploitation of those acquisitions, and successful

development and exploratory drilling on our legacy

fields, all while generating strong free cash flow to fund

our growth. Our most valuable asset, our people, have

done an excellent job adapting to the changing market

conditions while maintaining the highest levels of safety

and operational excellence. W&T finished 2021 on a

particularly strong note, and we will carry this momentum

into 2022 and beyond.

We are in a much stronger position today compared to

a year ago, both operationally and financially. In every

quarter of 2021, we produced positive free cash flow. We

maintained strong levels of production at 38,100 barrels

of oil equivalent per day in 2021, with about 47% being

liquids. In 2021, we took several steps to enhance our

liquidity, lower our net debt, and improve our financial

flexibility for the future. Our net debt is down $97 million

since year-end 2020 and $202 million since year-end

2019, while our liquidity improved by 70% year-over-year

to $296 million at year-end 2021. Much of this improved

“We are focused on building value for
our shareholders, while developing and
producing oil and gas assets in a safe and
environmentally responsible manner.”

financial flexibility is the result of the Munich Re transaction we did in May

of 2021. You may recall that in 2019 we paid approximately $170 million for

our Mobile Bay Area producing assets and related gas treatment facilities,

which was a great price then and looks even better now. We transferred

those assets to a wholly-owned special purpose vehicle in return for net

cash proceeds from a $215 million first-lien non-recourse 7-year term loan to

the SPVs at a very attractive fixed interest rate of 7%. When the debt is paid

off, we will continue to own 100% of these assets. This allowed us to fully

pay off our revolving credit facility and added substantial liquidity through

additional cash on the balance sheet, enabling us to move quickly when

opportunities arise. While the lender required hedging for this financing,

we also utilized call options in our hedging strategy to maintain a lot of the

upside on natural gas prices, which turned out to be beneficial for us as

natural gas prices have increased substantially since early 2021.

In November 2021, we restructured our credit facility to provide us additional

financial flexibility. We established a $100 million first priority lien secured

revolving facility with a borrowing base of $50 million with Calculus Lending.

While we currently have no borrowings on the facility, it provides us access

to additional capital at attractive terms.

In February 2022, W&T closed an accretive acquisition for just over

$30 million. Having cash on our balance sheet allowed W&T to close

the transaction quickly. We estimated at the time of the acquisition that

these assets had proved reserves of approximately 5.5 million barrels of

oil equivalent (“MMBoe”) (69% oil) and 2P reserves of approximately 7.6

MMBoe. This accretive acquisition consists of over 50 gross producing

wells, all of which W&T will operate, at Ship Shoal 230, South Marsh

Island/Vermilion 191, and South Marsh Island 73. These assets provide a

solid base of proved reserves and produce strong free cash flow. These

properties are very complementary to our existing assets and there are a

number of opportunities, both near-term and long-term, that will allow us

2021 Annual Report

157.6

Proved Reserves (MMBoe)

38.1

Average Production (MBoe/d)

$558.0

Total Revenue ($mm)

$133.7

Cash Flow from Operations ($mm)

323

Employees

W&T Offshore, Inc. NYSE: WTI

The map above shows the Company’s
shelf and deepwater leases in the Gulf
of Mexico. The assets circled are those
that were acquired in the ANKOR
acquisition in February 2022.

to maximize the value of these assets. Acquisitions continue

to be a core pillar of how we create value here at W&T and

this is a great example of what we look for when we are

evaluating an acquisition.

We’ve always talked about our ability to generate free cash

flow from our stable, long-life asset base and its importance

to our long-term sustainability. That is particularly evident in

our outstanding year-end reserve results. Proved reserves at

year-end 2021 increased 9% to 157.6 MMBoe compared to

2020. While improved SEC pricing certainly contributed to the

increase, we also had positive performance revisions of over

5 MMBoe. The positive performance revision is a testament

to our reserve base, as it demonstrates our ability to maintain

and even grow our reserves without acquisitions or without

bringing online any new wells. Our solid 2P reserves are a

major contributor to this result. The Company’s reserve life

index lengthened to 11.3 years, up from 9.4 years at the end

of 2020. About 36% of year-end 2021 proved reserves were

liquids with the balance being natural gas.

2021 Annual Report

In addition to increasing reserves, we also saw a dramatic

and enhance our ESG program over time. We are constantly

increase in the present value of our proved reserves

looking at ways to be a better steward to the environment

discounted at 10% (“PV-10”). The PV-10 value of W&T’s SEC

and the communities in which we operate. In February 2021,

proved reserves at year-end 2021 was $1.6 billion, an increase

we consolidated the two Mobile Bay treating facilities into

of 119% from year-end 2020. This was driven by improved

just one plant, the OTF facility. This consolidation allowed us

pricing with an average realized crude oil price of $65.25 per

to reduce our emissions, water usage, electricity usage, and

barrel and an average realized natural gas price of $3.68 per

operating costs without adversely impacting our workforce

Mcf. Using NYMEX strip prices as of March 2, 2022, the PV-

in the area.

10 value of our year-end reserves increases to $2.0 billion.

In closing, I want to thank my management team and all of

Looking ahead to 2022, under the strengthening commodity

our employees for their continued hard work and dedication,

pricing conditions, we are forecasting strong free cash flow

as well as our Board for their guidance and support. We are

generation, and we will continue to evaluate additional

projecting significant cash flow generation in 2022. We are

accretive acquisitions while systematically paying down

increasing our capital spending in 2022 to evaluate attractive

debt. We are excited to integrate our newest acquisition of

organic drilling opportunities. We are well positioned with

complementary assets that closed in February 2022. We

a meaningful cash position and strong liquidity in the

are also bringing online the Cota well in the first quarter

strong current pricing environment, which presents many

of 2022, which we drilled in early 2021 and encountered

opportunities for W&T. The Gulf of Mexico has a long history

approximately 100 feet of net oil pay. We see a lot of

of prolific production, and we are constantly assessing the

opportunities in 2022 to expand our organic drilling

vast pool of assets it possesses for accretive acquisitions

program and expect to spend between $70 and $90 million

that meet our criteria and that are within our focus area. Our

in capital this year, excluding acquisitions, with a major part

management team’s 34% stake in W&T’s equity ensures

of that going to the drilling of a development deepwater

that management’s interests are highly aligned with those

well. We also have capital allocated for facilities, leasehold,

of our shareholders. I am excited about the opportunities in

seismic, recompletions and other expenditures associated

front of us to add value to the business and look forward to a

with future drilling.

successful 2022 and beyond.

Environmental stewardship, sound corporate governance,

and contributing positively to our employees and the

communities where we work and operate are cornerstones

of our culture. We believe that all employees have a

responsibility to ensure that we operate with the highest

standards related to ESG and we have empowered our

management to allocate resources and tools necessary to

create a working environment focused on accomplishing

our ESG objectives. Last year we achieved a meaningful

milestone by issuing our inaugural ESG report. It is a great

foundation to build upon and we will continue to develop

Tracy W. Krohn
Founder, Chairman, Chief Executive Officer and President

W&T Offshore, Inc. NYSE: WTI

Financial Highlights

Year Ending December 31,

Income Statement (000s)

Total Revenues

Operating Income

Net Income

Cash-Flow Statement (000s)

Cash Provided by Operating Activities

Capex (oil and natural gas properties) excl acquisitions

Capex (acquisition of oil and natural gas properties)

Balance Sheet (000s)

Cash and Cash Equivalents

Total Assets

Long-Term Debt

Operating Data

Net Sales:

Oil (MMBbls)

NGLs (MMBbls)

Natural Gas (Bcf)

Total Oil Equivalent (MMBoe)

Average Daily Sales (MBoe/d)

Averaged Realized Sales Price:

Oil ($/Bbl)

NGLs ($/Bbl)

Natural Gas ($/Mcf)

Oil Equivalent ($/Boe)

Proved Reserves

Oil (MMBbls)

NGLs (MMBbls)

Natural Gas (Bcf)

Total Oil Equivalent (MMBoe)

Total Proved Developed (MMBoe)

Proved Undeveloped (MMBoe)

2021

558,010

189,662

(41,478)

133,668

26,785

661

245,799

1,193,207

687,938

5.0

1.5

44.8

13.9

38.1

65.94

30.59

3.88

39.36

37.2

19.1

607.6

157.6

137.0

20.6

2020

346,634

801

37,790

108,509

44,167

2,919

43,726

940,582

625,286

5.6

1.7

48.4

15.4

42.0

38.45

11.26

2.05

21.76

32.2

17.4

569.3

144.4

132.2

12.2

2019

534,896

118,536

74,086

232,227

125,706

188,019

32,433

1,003,719

719,533

6.7

1.3

41.3

14.8

40.6

59.89

17.60

2.57

35.63

37.8

24.5

571.1

157.4

133.8

23.6

Proved Developed Reserves as a % of Proved Reserves

87%

92%

85%

Revenues
($ in millions)

Cash Provided by
Operating Activities
($ in millions)

Production
(MBoe/d)

Proved Reserves
(MMBoe)

$534.9

$558.0

$232.2

$346.6

$133.7

$108.5

40.6

42.0

38.1

157.4

157.6

144.4

2019

2020

2021

2019

2020

2021

2019

2020
2019

2021

2019

2020

2021

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

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2021

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)

72-1121985
(I.R.S. Employer Identification Number)

5718 Westheimer Road, Suite 700 Houston, Texas
(Address of principal executive offices)

77057-5745
(Zip Code)

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

Title of each class
Common Stock, par value $0.00001

Securities registered pursuant to section 12(b) of the Act:
Trading Symbol(s)
WTI

Name of each exchange on which registered
New York Stock Exchange

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☑
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☑
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the

preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past
90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every interactive data file required to be submitted pursuant to Rule 405 of Regulation

S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging

growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of
the Exchange Act.

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. ☑

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 $453,247,467 based on the closing sale price of $4.85 per

share as reported by the New York Stock Exchange on June 30, 2021.

The number of shares of the registrant’s common stock outstanding on February 28, 2022 was 143,012,124.

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.

W&T OFFSHORE, INC.
TABLE OF CONTENTS

Cautionary Statements Regarding Forward-Looking Statements
Glossary of Oil and Natural Gas Terms

PART I
Item 1.
Item 1A.
Item 1B.
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
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

Page

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112

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 and Section 21E of the Securities Exchange Act of 1934. All statements, other
than statements of historical fact included in this report, 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 involve risks, uncertainties and assumptions. 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.

All statements, other than statements of historical fact included in this report are statements that could be deemed

forward-looking statements, such as those statements that address activities, events or developments that we expect,
believe or anticipate will or may occur in the future.

These 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. 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 Securities and Exchange Commission (“SEC”). 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.

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of terms commonly used in the oil and natural gas industry that may

be used in this Annual Report on Form 10-K.

Acquisitions. Refers to acquisitions, mergers or exercise of preferential rights of purchase.

Bbl. One stock tank barrel or 42 U.S. gallons liquid volume.

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

Bcfe. One billion cubic feet equivalent, determined using an energy-equivalent ratio of six Mcf of natural gas to one

barrel of crude oil, condensate or natural gas liquids.

Boe. Barrel of oil equivalent.

Boe/d. Barrel of oil equivalent per day.

BOEM. Bureau of Ocean Energy Management. The agency is responsible for managing development of the nation’s

offshore resources in an environmentally and economically responsible way.

BSEE. Bureau of Safety and Environmental Enforcement. The agency is responsible for enforcement of safety and

environmental regulations.

Conventional shelf well. A well drilled in water depths less than 500 feet.

Deep shelf well. A well drilled on the outer continental shelf to subsurface depths greater than 15,000 feet and water

depths of less than 500 feet.

Deepwater. Water depths greater than 500 feet in the Gulf of Mexico.

Deterministic estimate. Refers to a method of estimation whereby a single value for each parameter in the reserves

calculation is used in the reserves estimation procedure.

Developed reserves. Oil and natural gas 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.

Development project. A project 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.

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 field or 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.

iii

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 and/or stratigraphic condition.

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.

Mcfe. One thousand cubic feet equivalent, determined using the energy-equivalent ratio of six Mcf of natural gas to

one barrel of crude oil or other hydrocarbon.

Mcfe/d. One thousand cubic feet equivalent per day.

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.

MMcfe. One million cubic feet equivalent, determined using an energy-equivalent ratio of six Mcf of natural gas to

one barrel of crude oil condensate or natural gas liquids.

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. Also, referred to as the Henry Hub Index.

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 assumed the functions of the former Minerals Revenue

Management Program, which had been renamed to the Bureau of Ocean Energy Management, Regulation and
Enforcement.

Probabilistic estimate. Refers to a method of estimation whereby the full range of values that could reasonably
occur for each unknown parameter in the reserves estimation procedure is used to generate a full range of possible
outcomes and their associated probabilities of occurrence.

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

Proved properties. Properties with proved reserves.

Proved reserves. 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—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. As used in this definition, “existing economic conditions” include prices and costs at which economic
production 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. The SEC provides a complete definition of proved reserves in
Rule 4-10(a)(22) of Regulation S-X.

PV-10. A term used in the industry that is not a defined term in generally accepted accounting principles. We define

PV-10 as the present value of estimated future net revenues of estimated proved reserves as calculated by our
independent petroleum consultant using a discount rate of 10%. This amount includes projected revenues, estimated
production costs and estimated future development costs. PV-10 excludes cash flows for asset retirement obligations,
general and administrative expenses, derivatives, debt service and income taxes.

Reasonable certainty. When deterministic methods are used, reasonable certainty means a high degree of confidence

that the quantities of hydrocarbons will be recovered. When probabilistic methods are used, reasonable certainty means
at least a 90% probability that the quantities of hydrocarbons 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, engineering, and economic data are made to estimated ultimate recovery with time,
reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.

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

has been previously completed.

Reliable technology. 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.

Reserves. Estimated remaining quantities of oil, natural 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 the oil, natural gas or related substances to market, and all permits and
financing required to implement the project.

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.

Sub-salt. A geological layer lying below the salt layer.

Undeveloped reserves. Oil and natural gas 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.
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 production at greater distances. 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. 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, or by other evidence using reliable technology establishing reasonable certainty.

Unproved properties. Properties with no proved reserves.

WTI. West Texas Intermediate grade crude oil. A light crude oil produced in the United States with an American

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

Item 1. Business

PART I

W&T Offshore, Inc. is an independent oil and natural gas producer, active in the exploration, development and
acquisition of oil and natural gas properties in the Gulf of Mexico. 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. We currently hold working interests in
43 offshore producing fields in federal and state waters. Our acreage, well, production and reserves information is
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”), as described in more detail in
Financial Statements and Supplementary Data – Note 5 – Joint Venture Drilling Program under Part II, Item 8 in this
Form 10-K.

We have developed significant technical expertise in finding and developing properties in the Gulf of Mexico with
production rates which provide the best opportunity to achieve a rapid return on our invested capital. We have leveraged
our experience in the conventional shelf to develop higher impact capital projects in the Gulf of Mexico in both the
deepwater and the deep shelf. We have acquired rights to explore and develop new prospects and existing oil and natural
gas properties in both the deepwater and the deep shelf, while at the same time continuing our focus on the conventional
shelf. Our drilling efforts in recent years have included the deepwater of the Gulf of Mexico.

Business Strategy

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

• 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; and

• Continuing to manage our balance sheet in a prudent manner and continuing our track record of financial

flexibility in any commodity price environment.

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

Market Trends

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

While the current outlook for commodity prices is favorable and our operations are no longer significantly impacted

by confinement restrictions, the risk of disruption to our operations continues as the emergence of a new variant of
COVID-19 could adversely impact our operations, or commodity prices could significantly decline from current levels.
The ongoing COVID-19 outbreak continues to evolve and, during the fourth quarter of 2021, a new variant emerged, the
Omicron variant. It is difficult to assess if it will cause meaningful disruptions in economic activity across the world and
if there will be any significant impacts in demand for energy.

The recent invasion of parts of Ukraine by Russia, and the impact of world sanctions against Russia and the

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

Our margins in 2021 decreased from 2020 primarily due to realized derivative gains in 2020 compared to realized
derivative losses in 2021, partially offset by higher average realized commodity prices in 2021 compared to 2020. We
measure margins using net (loss) income before net interest expense; income tax (benefit) expense; depreciation,
depletion, amortization and accretion; unrealized commodity derivative gain or loss; amortization of derivative
premiums; bad debt reserve; gain on debt transaction; release of restricted funds; litigation; and other (“Adjusted
EBITDA”) as a percent of revenue, which is a not a financial measurement under generally accepted accounting
principles (“GAAP”).

Our total production decreased 9.6% in 2021 from the prior year. Our proved reserves increased by 13.2 million

barrels of oil equivalent (“MMBoe”) in 2021, primarily due to the significant increase in commodity prices in 2021 as
compared to 2020.

We continually monitor current and forecasted commodity prices to assess what changes, if any, should be made to

our 2022 plans. See Management’s Discussion and Analysis of Financial Condition and Results of Operations –
Liquidity and Capital Resources under Part II, Item 7 in this Form 10-K for additional information.

Competition

The oil and natural gas industry is highly competitive. We also face increasing indirect competition from alternative

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

Oil and Natural Gas Marketing and Delivery Commitments

We sell our crude oil, NGLs and natural gas to third-party customers. We are not dependent upon, or contractually
limited to, any one customer or small group of customers. However, in 2021, approximately 34% of our revenues were
received from BP Products North America, 14% from Chevron-Texaco and 11% from Williams Field Services, with no
other customer comprising greater than 10% of our 2021 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, as replacement
customers could be obtained in a relatively short period of time on terms, conditions, and pricing substantially similar to
those currently existing. We do not have any agreements which obligate us to deliver a fixed volume of physical
products to customers.

Compliance with Government Regulations

Various aspects of our oil and natural gas operations are subject to extensive and continually changing regulations

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

The Federal Energy Regulatory Commission (“FERC”) regulates the transportation and sale for resale of natural gas

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

The Federal Trade Commission (“FTC”), the FERC and the Commodity Futures Trading Commission (“CFTC”)

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

These departments and agencies have substantial enforcement authority and the ability to grant and suspend

operations, and to levy substantial penalties for non-compliance. Failure to comply with such regulations, as interpreted
and enforced, could have a material adverse effect on our business, results of operations and financial condition.

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

President Biden has made tackling climate change, including the restriction or elimination of future greenhouse
gases (“GHGs”), a priority in his administration. The Biden Administration has already adopted several executive orders
and is expected to pursue additional orders and pursue legislation, regulations or other regulatory initiatives in support of
this regulatory agenda. Notably, President Biden issued an executive order in January 2021 suspending new leasing
activities for oil and gas exploration and production on federal lands and offshore waters pending review and
reconsideration of federal oil and gas permitting and leasing practices. The suspension of these federal leasing activities
prompted legal action by several states against the Biden Administration, resulting in issuance of a nationwide
preliminary injunction by a federal district court in June 2021, effectively halting implementation of the leasing
suspension. Subsequent federal litigation, however has impeded the most recent federal oil and gas lease sale in the Gulf
of Mexico requiring the DOI to conduct a new environmental analysis that takes into consideration such climate effects
before holding another sale. In November 2021, the DOI released its report on federal oil and gas leasing and permitting
practices. The report includes recommendations in respect to offshore sector, including adjusting royalty rates to ensure
that the full value of the tracts being leased are captured, strengthening financial assurance coverage amounts that are
required by operators, establishing a “fitness to operate” criteria that companies would need to meet in respect of safety,
environmental and financial responsibilities in order to operate on the OCS. Several of the report recommendations
require action by the Congress and cannot be implemented unilaterally by the Biden Administration. We continue to
conduct our operations on our existing leases in the OCS; however, uncertainty on future Biden Administration actions
with regard to offshore oil and gas activities on the OCS together with the issuance of any future executive orders or
adoption and implementation of laws, rules or initiatives that further restrict, delay or result in cancellation of existing oil
and gas activities on the OCS could have a material adverse effect on our business and operations.

Decommissioning and financial assurance requirements. The BOEM requires that lessees demonstrate financial
strength and reliability according to its regulations and provide acceptable financial assurances to assure satisfaction of
lease obligations, including decommissioning activities on the OCS. In 2016, the BOEM under the Obama
Administration issued Notice to Lessees and Operators 2016-N01 (the “2016 NTL”) to clarify the procedures and
guidelines that BOEM Regional Directors use to determine if and when additional financial assurances may be required
for OCS leases, rights of way (“ROWs”) and rights of use and easement (“RUEs”). The 2016 NTL was not fully
implemented as the BOEM under the Trump Administration rescinded the 2016 NTL in 2020. In October 2020, BOEM
published jointly with BSEE a proposed rule that sought to clarify and provide greater transparency to decommissioning
and related financial assurance requirements imposed on record title owners and operating rights owners of interests in
federal OCS leases and RUE and ROW grant holders conducting operations on the federal OCS.

Consistent with the November 2021 DOI leasing report recommendations and in response to President Biden’s
January 2021 executive order, the Biden Administration could pursue more stringent decommissioning and financial
assurance requirements that could increase our operating costs. In the federal government’s most recent list of potential
regulatory actions for 2022, the BSEE lists its plans to propose rules finalizing the policies and procedures concerning
compliance with OCS oil and gas decommissioning obligations originally proposed under the Trump Administration. In
addition, BOEM lists its plans to propose a new rule in respect of financial assurance. The BOEM has the authority to
issue liability orders in the future, including if it determines there is a substantial risk of nonperformance of the interest
holder’s decommissioning liabilities. See Risk Factors under Part I, Item 1A, Management’s Discussion and Analysis of
Financial Condition and Results of Operations in Part II, Item 7 and Financial Statements and Supplementary Data
under Part II, Item 8 in this Form 10-K for more discussion on decommissioning and financial assurance requirements.

Reporting of decommissioning expenditures. Under applicable BSEE regulations, lessees operating on the OCS and
conducting decommissioning activities are required to submit summaries of actual expenditures for decommissioning of
subject wells, platforms, and other facilities. The BSEE has reported that it uses this summary information to better
estimate future decommissioning costs, and the BOEM typically relies upon the BSEE’s estimates to set the amount of
required bonds or other forms of financial security in order to minimize the government’s perceived risk of potential
decommissioning liability.

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

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

In 2007, the FERC issued rules (“Order 704”) requiring that any market participant, including a producer such as us,

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

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

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 crude oil,

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

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

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

Hurricanes in the Gulf of Mexico can have a significant impact on oil and gas operations on the OCS. The effects

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

Compliance with Environmental Regulations

General. We are subject to complex and stringent federal, state and local environmental laws. These laws, among

other things, govern the issuance of permits to conduct exploration, drilling and 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. 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. Certain environmental laws, such as the federal Oil Pollution Act of 1990, as amended (“OPA”) impose strict joint
and several liability for environmental contamination, such as may arise in the event of an accidental spill on the OCS,
rendering a person liable for environmental damage and cleanup costs without regard to negligence or fault on the part of
such person. The regulatory burden on the oil and gas industry increases our cost of doing business and consequently
affects our profitability. The cost of remediation, reclamation and decommissioning, including abandonment of wells,
platforms and other facilities in the Gulf of Mexico is significant. These costs are considered a normal, recurring cost of
our on-going operations. Our competitors are subject to the same laws and regulations.

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

The federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976
(“RCRA”), regulates the generation, transportation, storage, treatment and disposal of non-hazardous and hazardous
wastes and can require cleanup of hazardous waste disposal sites. RCRA currently excludes drilling fluids, produced
waters and certain other wastes associated with the exploration, development or production of oil and natural gas from
regulation as “hazardous waste”, and the disposal of such oil and natural gas exploration, development and production
wastes is regulated under less onerous non-hazardous waste requirements, usually under state law.

Standards have been developed under RCRA and/or state laws for worker protection from exposure to Naturally

Occurring Radioactive Materials (“NORM”), treatment, storage, and disposal of NORM and NORM waste, and
management of NORM-contaminated piping valves, containers and tanks. Historically, we have not incurred any
material expenditures in connection with our compliance with the existing RCRA and applicable state laws related to
NORM waste.

Air Emissions and Climate Change. Air emissions from our operations are subject to the federal Clean Air Act, as

amended (“CAA”), and comparable state and local requirements. We may be required to incur certain capital
expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating
permits and approvals for air emissions. For example, in 2015, the EPA issued a final rule under the CAA lowering the
National Ambient Air Quality Standard (“NAAQS”) for ground level ozone from 75 to 70 parts per billion. Since that
time, the EPA issued area designations with respect to ground-level ozone and, in December 2020, published notice of a
final action to retain the 2015 ozone NAAQS without revision on a going-forward basis. However, several groups have
filed litigation over this December 2020 final action, and the Biden Administration has announced plans to reconsider
the December 2020 final action in favor of a more stringent ground-level ozone NAAQS.

The threat of climate change continues to attract considerable public, governmental and scientific attention in the
United States and in foreign countries. As a result, numerous proposals have been made at the international, national,
regional and state levels of government to monitor and limit existing emissions of GHG as well as to restrict or eliminate
such future emissions. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG
reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. In the United
States, no comprehensive climate change legislation has been implemented at the federal level. Under the Biden
Administration, however, the EPA has adopted regulations under the existing CAA that, among other things, impose
preconstruction and operating permit requirements on certain large stationary sources, require the monitoring and annual
reporting of GHG emissions from certain petroleum and natural gas system sources, and implement New Source
Performance Standards directing the reduction of methane from certain new, modified or reconstructed facilities in the
oil and natural gas sector. Compliance with these rules or other similar rules implemented in the future could result in
increased compliance costs on our operations. In November 2021, the EPA also issued a proposed rule that would more
stringently regulate methane emissions from crude oil and natural gas sources. The EPA plans to issue a supplemental
proposal enhancing this proposed rulemaking in 2022 with the goal of issuing a final rule by the end of 2022.
Additionally, state implementation of revised air emission standards could result in stricter permitting requirements,
delaying, limiting or prohibiting our ability to obtain such permits and result in increased expenditures for pollution
control equipment, the costs of which could be significant.

At the international level, there exists 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,” to which President Biden recommitted the Unites States, thereby requiring the United States to determine
its emissions reduction goals every five years after 2020. The international community also gathered in Glasgow in
November 2021 at the 26th Conference of the Parties (“COP26”), at which the United States and European Union jointly
announced the launch of a Global Methane Pledge, an initiative which over 100 counties joined, committing to a
collective goal of reducing global methane emissions by at least 30 percent from 2020 levels by 2030, including “all
feasible reductions” in the energy sector. The impacts of these orders, pledges, agreements and any legislation or
regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26, or other
international conventions cannot be predicted at this time.

Governmental, scientific and public concern over the threat of climate change arising from GHG emissions has
resulted in increasing federal political risk regarding climate change. Litigation risks are also 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.

Additionally, our access to capital may be impacted by climate change policies. 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 that favor “clean” power sources, such as wind and solar, making those sources more
attractive, and some of them may elect not to provide funding for fossil fuel energy companies. Many of the largest U.S.
banks have made “net zero” carbon emission commitments and have announced that they will be assessing financed
emissions across their portfolios and are taking steps to quantify and reduce those emissions. These and other
developments in the financial sector could lead to some lenders and investors restricting 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. Additionally, there is the possibility that financial institutions will be pressured or
required to adopt policies that limit funding for fossil fuel energy companies.

The OCSLA authorized the DOI to regulate activities authorized by the BOEM in the Central and Western Gulf of

Mexico. The EPA has air quality jurisdiction over all other parts of the OCS. Under the OCSLA, DOI is limited to
regulating offshore emissions of criteria and their precursor – pollutants to the extent they significantly affect the air
quality of any state. BSEE conducts field inspections of emission sources installed on offshore platforms that have the
potential to emit regulated air pollutants. The agency also reviews BOEM-mandated monitoring and reporting of air
emission sources for compliance with approved plan emission limits. BSEE may initiate 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 (“INC”) or recommending further enforcement action against potential violators.

Water Discharges. The primary federal law for oil spill liability is the OPA which amends and augments oil spill

provisions of the federal Water Pollution Control Act (the “Clean Water Act”). OPA imposes certain duties and
liabilities on “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or
threatening United States waters, including the OCS or adjoining shorelines. A liable “responsible party” includes the
owner or operator of an onshore facility, vessel or pipeline that is a source of an oil discharge or that poses the
substantial threat of discharge or, in the case of offshore facilities, the lessee or permittee of the area in which a
discharging facility is located. OPA assigns joint and several, strict liability, without regard to fault, to each liable party
for all containment and oil removal costs and a variety of public and private damages including, but not limited to, the
costs of responding to oil and natural resource release related damages and economic damages suffered by persons
adversely affected by an oil spill. Although defenses exist to the liability imposed by OPA, they are limited. In
January 2018, the BOEM raised OPA’s damages liability cap to $137.7 million; however, a party cannot take advantage
of liability limits if the spill was caused by gross negligence or willful misconduct, resulted from violation of a federal
safety, construction or operating regulation, or if the party failed to report a spill or cooperate fully in the cleanup. OPA
requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial
responsibility to cover costs that could be incurred in responding to an oil spill, and to prepare and submit for approval
oil spill response plans. These oil spill response plans must detail the action to be taken in the event of a spill; identify
contracted spill response equipment, materials, and trained personnel; and identify the time necessary to deploy these
resources in the event of a spill. In addition, OPA currently requires a minimum financial responsibility demonstration of
between $35.0 million and $150.0 million for companies operating on the OCS. We are currently required to
demonstrate, on an annual basis, that we have ready access to $35.0 million that can be used to respond to an oil spill
from our facilities on the OCS.

The Clean Water Act and comparable state laws impose restrictions and strict controls regarding the monitoring and

discharge of pollutants, including produced waters and other natural gas wastes, into federal and state waters. The
discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the
EPA or an analogous state agency. The EPA has also adopted regulations requiring certain onshore oil and natural gas
exploration and production facilities to obtain individual permits or coverage under general permits for storm water
discharges. The treatment of wastewater or developing and implementing storm water pollution prevention plans, as well
as for monitoring and sampling the storm water runoff from our onshore gas processing plant have compliance costs.
Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge
of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure
plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil. Our Board of
Directors reviews our Clean Water Act compliance metrics on a quarterly basis.

Marine Protected Areas and Endangered and Threatened Species. Executive Order 13158, issued in May 2000,
directs federal agencies to safeguard existing Marine Protected Areas (“MPAs”) in the United States and establish new
MPAs. The order requires federal agencies to avoid harm to MPAs to the extent permitted by law and to the maximum
extent practicable. It also directs the EPA to propose new regulations under the Clean Water Act to ensure appropriate
levels of protection for the marine environment. In addition, Federal Lease Stipulations include regulations regarding the
taking of lives of protected marine species (sea turtles, marine mammals, Gulf sturgeon and other listed marine species).

Certain flora and fauna that have been officially classified as “threatened” or “endangered” are protected by the
federal Endangered Species Act, as amended (“ESA”). This law prohibits any activities that could “take” a protected
plant or animal or reduce or degrade its habitat area. The U.S. Fish and Wildlife Service (“USFWS”) under former
President Trump issued a final rule in January 2021, which notably clarifies that criminal liability under the Migratory
Bird Treaty Act (“MBTA”) will apply only to actions “directed at” migratory birds, its nests, or its eggs; however, in
October 2021, the USFWS under the Biden Administration revoked the Trump Administration’s rule on incidental take
and published an advanced notice of proposed rulemaking to codify a general prohibition on incidental take while
establishing a process to regulate or permit exceptions to such a prohibition. Additionally, the USFWS may make
determinations on the listing of species as threatened or endangered under the ESA and litigation with respect to the
listing or non-listing of certain species may result in more fulsome protections for non-protected or lesser-protected
species. We conduct operations on leases in areas where certain species that are listed as threatened or endangered are
known to exist and where other species that potentially could be listed as threatened or endangered under the ESA may
exist.

Other federal statutes that provide protection to animal and plant species and which may apply to our operations

include, but are not necessarily limited to, the National Environmental Policy Act, the Coastal Zone Management Act,
the Emergency Planning and Community Right-to-Know Act, the Marine Mammal Protection Act, the Marine
Protection, Research and Sanctuaries Act, the Fish and Wildlife Coordination Act, the Magnuson-Stevens Fishery
Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. These
laws and related implementing regulations may require the acquisition of a permit or other authorization before
construction or drilling commences and may limit or prohibit construction, drilling and other activities on certain lands
lying within wilderness or wetlands. These and other protected areas may require certain mitigation measures to avoid
harm to wildlife, and such laws and regulations may impose substantial liabilities for pollution resulting from our
operations.

The leases and permits required for our various operations are subject to revocation, modification and renewal by
issuing authorities. Moreover, applicable leasing and permitting programs may be subject to legislative, regulatory or
executive actions to delay or suspend the issuance of leases and permits.

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 delays the installation of
production facilities, thereby delaying production and sales of our oil and natural gas.

Inflation. Although inflation in the United States has been relatively low in recent years, it rose significantly in the
second half of 2021. This is believed to be the result of the economic impact from the COVID-19 pandemic, including
the global supply chain disruptions, among other factors. For 2021, our realized prices for crude oil increased 71.5%,
NGLs increased 171.6% and natural gas increased 89.0% from 2020. Historically, our operating costs have moved
directionally with the price of crude oil, NGLs and natural gas, as these commodities affect the demand for these goods
and services, but the timing of such increases and decreases may lag behind changes in commodity prices. However,
global, industry-wide supply chain disruptions caused by the COVID-19 pandemic have also resulted in shortages in
labor, materials and services which have resulted in inflationary cost increases for labor, materials and services and
could continue to cause costs to increase as well as scarcity of certain products and raw materials. We are experiencing
some inflationary pressure for certain costs, including employees and vendors, although such cost increases did not
materially impact our 2021 financial condition or results of operations, and we currently do not expect them to materially
impact our 2022 financial results or operations. However, to the extent elevated inflation remains, we may experience
further cost increases for our operations, including natural gas purchases and oilfield services and equipment as
increasing oil, natural gas and NGL prices increase drilling activity in our areas of operations, as well as increased labor
costs. An increase in oil, natural gas and NGL prices may cause the costs of materials and services to rise. We cannot
predict any future trends in the rate of inflation and a significant increase in inflation, to the extent we are unable to
recover higher costs through higher commodity prices and revenues, would negatively impact our business, financial
condition and results of operation.

Human Capital Resources

People are our most valuable asset, and we strive to provide a work environment that attracts and retains the top
talent in the industry, reflects our core values and demonstrates our core values to the communities in which we operate.

As of December 31, 2021, our personnel base consisted of 323 of our employees and over 330 individuals who are

employees of third parties that provide skilled labor in support of our field operations. This combined
workforce conducts our business in Texas, Alabama 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 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 focus on certain measures and objectives when managing our workforce that are material in
understanding our business, which are summarized below:

Health and Safety. Our highest priorities are the safety of all personnel and protection of the environment. To drive

a culture of personnel safety in our operations, we operate under a comprehensive Safety and Environmental
Management System (“SEMS”). Our 2021 total recordable incident rate (“TRIR”) for employees was 0.32, which is far
below the industry average for the Gulf of Mexico of 1.01. Our Health, Safety and Environmental (“HS&E”) group is
comprised of a Vice President, and Environmental, Safety and Regulatory Managers and 9 staff personnel. The
Department 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.

As a company identified by the Federal Government as essential to the critical infrastructure of the United States,

we have continuously operated during the COVID-19 pandemic. To provide our personnel with a physically safer work
environment and mitigate the risks associated with the transmission of COVID-19, we implement policies requiring
mandatory face masks and social distancing in all work environments, conduct daily temperature screening at all
locations and COVID-19 testing for field project crews.

Recruitment 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. Global, industry-wide supply
chain disruptions caused by the COVID-19 pandemic have resulted in shortages in labor, which have resulted in
inflationary cost increases for labor and could continue to cause costs to increase. If these conditions continue, it could
result in increased wages to retain existing employees and impact what we offer prospective employees in the future in
order to remain competitive.

Diversity and Inclusion. 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 policies and practices support diversity of thought, perspective, sexual orientation, gender, gender identity and
expression, race, ethnicity, culture and professional experience. From recent graduates to experienced hires, we seek to
attract and develop top talent to continue building a unique blend of cultures, backgrounds, skills and beliefs that mirrors
the world we live in. The tables below present, by category of employee, the gender and ethnicity composition of our
employees as of December 31, 2021:

Category
Exec/Sr. Manager
Mid-Level Manager
Professionals
All Other

US Ethnicity
Asian
Black/African American
Hispanic/Latino
Native American
Two or more races
White

Female Male
20 %
21 %
48 %
12 %

80 %
79 %
52 %
88 %

Exec/ Sr. Mid-Level
Manager Manager

40 %
20 %
—
—
—
40 %

Professionals All Other
1 %
11 %
5 %
20 %
6 %
9 %
1 %
—
1 %
—
86 %
60 %

9 %
6 %
2 %
—
—
83 %

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, 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.

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

Crude oil, natural gas and NGL prices can fluctuate widely due to a number of factors that are beyond our control.
Depressed oil, natural gas or NGL prices adversely affects 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 crude 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:

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changes in global supply and demand for crude oil, NGLs and natural gas;
events that impact global market demand (e.g. the reduced demand experienced during the COVID-19
pandemic);
the actions of the Organization of Petroleum Exporting Countries (“OPEC”) and other major oil producing
countries (“OPEC Plus”);
the price and quantity of imports of foreign crude 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 recent invasion of parts of
Ukraine by Russia);
domestic and foreign governmental regulations and taxes;
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 crude oil, NGLs and natural gas inventories;
adverse weather conditions;
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 GHG;
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.

If crude oil, NGLs 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 crude oil, NGLs and natural gas prices may reduce our estimates of the proved reserve volumes that
may be economically recovered, which would reduce the total volumes and future value of our proved reserves. 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 crude oil, NGL and natural gas pricing. While we have not
recorded an impairment of our oil and gas properties during the year-ended December 31, 2021, 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 10 – 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 crude oil and natural gas price volatility, they may also limit future income if crude oil and natural gas prices
were to rise substantially over the price established by such positions. In addition, such transactions may expose us to the
risk of financial loss in certain circumstances, including instances in which 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.

We depend upon third-party pipelines that provide delivery options from our facilities. Because we do not own or

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

A portion of our oil and natural gas is processed for sale on platforms owned by third parties with no economic
interest in our wells and no other processing facilities would be available to process such oil and natural gas without
significant investment by us. In addition, third-party platforms could be damaged or destroyed by hurricanes which
could reduce or eliminate our ability to market our production. As of December 31, 2021, four fields, accounting for
approximately 0.3 MMBoe (or 2.5%) of our 2021 production, are tied back to separate, third-party owned platforms.
There can be no assurance that the owners of such platforms will continue to process our oil and natural gas production.

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.
We have, in the past, been required to shut in wells when hurricanes have caused or threatened damage to pipelines,
gathering stations, and production facilities. In addition, certain third-party pipelines have submitted requests in the past
to increase the fees they charge us to use these pipelines. These increased fees, if approved, could adversely impact our
revenues or increase our operating costs, either of which would adversely impact our operating profits, cash flows and
reserves.

Operating Risks

Relatively short production periods for our Gulf of Mexico properties based on proved reserves subject us to high
reserve replacement needs and require significant capital expenditures to replace our proved reserves at a 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 27.3% of our total proved
reserves as of December 31, 2021 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, and
we may not be able to develop, find or acquire additional proved reserves in sufficient quantities to sustain our current
production levels or to grow production beyond current levels. 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.

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

We are and could be exposed to uninsured losses in the future. We currently carry multiple layers of insurance

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

Currently OPA requires owners and operators of offshore oil production facilities to have ready access to between
$35.0 million and $150.0 million, which amount is based on a worst case oil spill discharge volume demonstration that
can be used to cover costs that could be incurred in responding to an oil spill at our facilities on the OCS. We are
currently required to demonstrate that we have ready access to $35.0 million. If OPA is amended to increase the
minimum level of financial responsibility, we may experience difficulty in providing financial assurances sufficient to
comply with this requirement.

For some risks, we have not obtained insurance as we believe the cost of available insurance is excessive relative to

the risks presented. We reevaluate the purchase of insurance, policy limits and terms annually. Future insurance
coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some
forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically
acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider
reasonable, and we may elect to maintain minimal or no insurance coverage. The occurrence of a significant event not
fully insured or indemnified against losses could have a material adverse effect on our financial condition and results of
operations. See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity
and Capital Resources – Insurance Coverage under Part II, Item 7 in this Form 10-K for additional information on
insurance coverage.

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.

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

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

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

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

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.

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

Because a majority of our properties could experience the same conditions at the same time, these conditions could

have a greater impact on our results of operations than they might have on other operators who have properties over a
wider geographic area.

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

In the past, hurricanes in the Gulf of Mexico have caused catastrophic losses and property damage. Well control
insurance coverage becomes limited from time to time and the cost of such coverage becomes both more costly and
more volatile. In the past, we have been able to renew our policies each annual period, but our coverage has varied
depending on the premiums charged, our assessment of the risks and our ability to absorb a portion of the risks. The
insurance market may further change dramatically in the future due to hurricane damage, major oil spills or other events.

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

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

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical
data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these
interpretations or assumptions could materially affect the estimated quantities and the calculation of the present value of
our reserves at December 31, 2021.

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

Actual future production, crude oil and natural gas prices, revenues, taxes, development expenditures, operating

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

You should not assume that the standardized measure or the present value of future net revenues from our proved oil

and natural gas reserves is the current market value of our estimated oil and natural gas reserves. In accordance with
SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the 12-month
unweighted first-day-of-the-month average price for each product and costs in effect on the date of the estimate. Actual
future prices and costs may differ materially from those used in the present value estimate.

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

A prospect is an area in which we own an interest, could acquire an interest or have operating rights, and have what

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

The COVID-19 pandemic has affected, and may continue to materially adversely affect, our industry, business,
financial condition or results of operations.

The COVID-19 pandemic and related economic repercussions have created significant volatility, uncertainty, and
turmoil in the oil and gas industry. The COVID-19 outbreak and the responsive actions to limit the spread of the virus
significantly reduced global economic activity in 2020 and 2021, resulting in a decline in the demand for oil, natural gas,
and other commodities. As COVID-19 vaccines have been more widely distributed, global economic activity is
improving and commodity prices are currently above pre-pandemic levels. However, the energy markets remain subject
to heightened levels of volatility and uncertainty as responses to COVID-19 and COVID-19 variants continue to evolve.
Disruptions in global demand for oil and natural gas caused by the COVID 19 pandemic may continue to affect us,
constraining our ability to store and move production to downstream markets, or affecting future decisions to delay or
curtail development activity or temporarily shut-in production which could further reduce cash flow. We will continue to
monitor the effects of the pandemic on energy markets in the future.

The extent of the impact of the COVID-19 pandemic and any other future pandemic on our business will depend on
the nature, spread and duration of the disease, the responsive actions to contain its spread or address its effects, its effect
on the demand for oil and natural gas, the timing and severity of the related consequences on commodity prices and the
economy more generally, including any recession resulting from the pandemic, among other things. Any extended
period of depressed commodity prices or general economic disruption as a result of the pandemic would adversely affect
our business, financial conditions and results of operations. In addition, the COVID-19 pandemic has heightened the
other risks and uncertainties described in this report.

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

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

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.

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, 2021, we had Senior Second Lien Notes and a term loan of certain of our subsidiaries that is
non-recourse to the Company (the “Term Loan”). We have no borrowings outstanding on our revolving credit facility
under our Credit Agreement, which lending commitment and final maturity is set to expire on January 3, 2023. The
Senior Second Lien Notes mature on November 1, 2023.

Our leverage and debt service obligations could:

•

increase our vulnerability to general adverse economic and industry conditions, including reduced demand
during the COVID-19 pandemic;
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.

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

and results of operations. If new debt is added to our current debt levels, the related risks that we face could intensify.
Additionally, availability of borrowings and letters of credit under our Credit Agreement is determined by establishment
of a borrowing base, which is periodically redetermined in lender’s sole discretion based on our lenders’ review of crude
oil, NGLs and natural gas prices, our proved reserves and other criteria. Lower crude oil, NGLs and natural gas prices in
the future would also adversely affect our cash flow and could result in reductions in our borrowing base and sources of
alternate credit and affect our ability to satisfy the covenants and ratios required by the Credit Agreement and Indenture.

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, 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;
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•
•
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•
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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 our 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.

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 Second Lien Senior Notes are secured by various liens on our oil, natural gas

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

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

We may 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 and Regulatory Risks

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

President Biden has made addressing the threat of climate change from GHG emissions a priority under his

Administration. Regulatory agencies under the Biden Administration have issued proposed rulemakings, and may issue new or
amended rulemakings in support of President Biden’s regulatory and political agenda, which include reducing dependence on,
and use of, fossil fuels and curtailment of hydraulic fracturing on federal lands. Our operations in the Gulf of Mexico require
permits from federal and state governmental agencies in order to perform drilling and completion activities and conduct other
regulated activities and the Biden Administration may continue pursuing actions that delay or refuse approval of new leases for
hydrocarbon exploration and development on federal lands and waters or delay or fail to grant approvals required for
development of existing leases on such lands and waters. See Part I, Item 1, Business – Compliance with Governmental
Regulations for more discussion on orders and regulatory initiatives impacting the oil and natural gas industry pursued under
the Biden Administration. To the extent that our operations in federal waters are restricted, delayed for varying lengths of time
or cancelled, such developments could have a material adverse effect on our results of operations, our ability to replace
reserves and the ability to implement our business strategy.

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

The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations and
provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities
on the OCS. As of the filing date of this Form 10-K, we are in compliance with our financial assurance obligations to the
BOEM and have no outstanding BOEM orders, requests or financial assurance obligations. The BOEM under the
Obama and Trump Administrations had sought to implement varying levels of stringent and costly standards under the
existing federal financial assurance requirements, either through issuance and implementation of NTL #2016-N01 as was
the case under the Obama Administration, or proposing rulemaking to revise the decommissioning and related financial
assurance regulations as was the case under the Trump Administration. However, BOEM under the Biden
Administration is expected to propose new financial assurance requirements that, if adopted as proposed, could increase
our operating costs. See Part I, Item 1, Business – Compliance with Governmental Regulations for more discussion on
financial assurance regulatory initiatives impacting the oil and natural gas industry that may be pursued under the Biden
Administration. Additionally, 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 such future orders, the BOEM could commence enforcement proceedings or take other remedial action,
including assessing civil penalties, suspending operations or production, or initiating procedures to cancel leases, which,
if upheld, would have a material adverse effect on our business, properties, results of operations and financial condition.

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

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

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

In January 2021, President Biden suspended new oil and natural gas leases on federal lands and waters, including

the OCS pending review and reconsideration of federal oil and gas leasing and permitting practices. While this
suspension was challenged and enjoined in June 2021 by a federal district court, the Biden Administration is appealing
the court decision. Additionally, regulatory agencies under the Biden Administration may issue new or amended
rulemakings regarding deep water leasing, permitting or drilling that could result in more stringent or costly restrictions,
delays or cancellations to our operations as well as those of similarly situated offshore energy companies on the OCS.
The BSEE and the BOEM have over the past decade, primarily under the Obama Administration, imposed more
stringent permitting procedures and regulatory safety and performance requirements with respect to new wells drilled in
federal deepwater. While actions by BSEE or BOEM under the former Trump Administration sought to mitigate or
delay certain of those more rigorous standards, the Biden Administration could reconsider rules and regulatory initiatives
implemented under the Trump Administration and replace them with new, more stringent requirements and also provide
more rigorous enforcement of existing regulatory requirements. Compliance with any added or more stringent Biden
Administration regulatory requirements or enforcement initiatives and existing environmental and spill regulations,
together with uncertainties or inconsistencies in decisions and rulings by governmental agencies and delays in the
processing and approval of drilling permits and exploration, development, oil spill response and decommissioning plans
and possible additional regulatory initiatives could result in difficult and more costly actions and adversely affect or
delay new drilling and ongoing development efforts. Moreover, governmental agencies under the Biden Administration
are expected to continue to evaluate aspects of safety and operational performance in the United States Gulf of Mexico
that could result in new, more restrictive requirements.

These regulatory actions, or any new rules, regulations, or legal or enforcement initiatives or controls that impose

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

Our estimates of future ARO may vary significantly from period to period and are especially significant because our
operations are concentrated in the Gulf of Mexico.

We are required to record a liability for the present value of our ARO to plug and abandon inactive non-producing
wells, to remove inactive or damaged platforms, and inactive or damaged facilities and equipment, collectively referred
to as “idle iron,” and to restore the land or seabed at the end of oil and natural gas production operations. 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.

Moreover, BSEE under the Biden Administration could also reconsider its current NTL on idle iron removal or
existing idle iron-related regulations and establish new, more stringent decommissioning requirements on an expedited
basis. Estimating future restoration and removal costs in the Gulf of Mexico is especially difficult because most of the
removal obligations may be many years in the future, regulatory requirements are subject to change or such requirements
may be interpreted more restrictively, and asset removal technologies are constantly evolving, which may result in
additional or increased costs. As a result, we may make significant increases or decreases to our estimated ARO in future
periods. For example, because we operate in the Gulf of Mexico, platforms, facilities and equipment are subject to
damage or destruction as a result of hurricanes. The estimated cost to plug and abandon a well or dismantle a platform
can change dramatically if the host platform, from which the work was anticipated to be performed, is damaged or
toppled rather than structurally intact. Accordingly, our estimate of future ARO will differ dramatically from our
recorded estimate if we have a damaged platform.

Any additional requirements under BOEM’s formerly issued NTL #2016-N01, if it were re-issued and fully
implemented, or in the event BOEM under the Biden Administration were to issue new, more stringent financial
assurance guidance or requirements, would increase our operating costs and reduce the availability of surety bonds due
to the increased demands for such bonds in a low-price commodity environment. In addition, increased demand for
salvage contractors and equipment could result in increased costs for decommissioning activities, including plugging and
abandonment operations. These items have, and may further, increase our costs and impact our liquidity adversely.

In addition, the U.S. Government imposes strict joint and several liability under the OCSLA on the various lessees of a
federal oil and gas lease for lease obligations, including decommissioning activities, which means that any single co-lessee
may be liable to the U.S. Government for the full amount of all of the multiple lessees’ obligations under the lease. In
certain circumstances, we also could be liable for accrued decommissioning liabilities on federal oil and gas leases that we
previously owned and assigned to an unrelated third party should the assignee to whom we assigned the leases or any future
assignee of those leases is unable to perform its decommissioning obligations (including payment of costs incurred by
unrelated parties in decommissioning such lease facilities). For example, we have in the past received a demand for
payment of decommissioning costs related to accrued liabilities for property interests that were sold several years prior.
These indirect obligations would affect our costs, operating profits and cash flows negatively and could be material.

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

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

Our operations could be significantly delayed or curtailed, and our cost of operations could significantly increase as a

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

We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. It is

also possible that a portion of our oil and natural gas properties could be subject to eminent domain proceedings or other
government takings for which we may not be adequately compensated. See Business – Compliance with Government
Regulations under Part I, Item 1 in this Form 10-K for a more detailed explanation of regulations impacting our business.

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

Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the

release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and
regulations require the acquisition of a permit or other approval before drilling or other regulated activity commences;
restrict the types, quantities and concentration of substances that can be released into the environment in connection with
drilling and production activities; limit or prohibit exploration or drilling activities on certain lands lying within wilderness,
wetlands, MPAs and other protected areas or that may affect certain wildlife, including marine species and endangered and
threatened species; and impose substantial liabilities for pollution resulting from our operations.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal
penalties; loss of our leases; incurrence of investigatory, remedial or corrective obligations; and the imposition of injunctive
relief, which could prohibit, limit or restrict our operations in a particular area.

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

New laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or

increased governmental enforcement could significantly increase our capital expenditures and operating costs or could
result in delays, limitations or cancelations to our exploration and production activities, which could have an adverse effect
on our financial condition, results of operations, or cash flows. See Business – Compliance with Environmental
Regulations under Part I, Item 1 in this Form 10-K for a more detailed description of our environmental, marine species,
and endangered and threatened species regulations.

The threat of climate change could result in increased costs and reduced demand for the oil and natural gas we produce,
which could have a material adverse effect on our business, results of operations, financial condition and cash flows.

The threat of climate change continues to attract considerable attention in the United States and foreign countries. As a
result, 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. As a
result, our operations are subject to a series of 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 – Compliance with
Environmental Regulations” for more discussion on the threat of climate and restriction of GHG emissions. The adoption
and implementation of any international, federal, regional or state legislation, executive actions, regulations 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. 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 climate change, increasing
societal expectations on companies to address climate change, and potential customer use of substitutes to energy
commodities may result in increased costs, reduced demand for oil and natural gas we produce, resulting in reduced profits,
increased investigations and litigation, and negative impacts on our stock price and access to capital markets. Moreover, the
increased competitiveness of alternative energy sources (such as wind, solar geothermal, tidal and biofuels) could reduce
demand for the oil and natural gas we produce, which would lead to a reduction in our revenues. Finally, 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.

Increasing attention to Environmental, Social and Governance (“ESG”) matters may impact our business.

Increasing attention to climate change, societal expectations for companies to address climate change, investor and
societal expectations regarding voluntary ESG disclosures, and consumer demand for alternative forms of energy 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 and environmental conservation, for example, may result in demand shifts
from oil and natural gas products and bias against companies operating in the sector. 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 asserted damage, or to other mitigating factors.

We have established a managerial ESG Task Force composed of cross-functional management-level employees in

Operations, HSE&R, Legal, Human Resources, Investor Relations, 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 Board of Directors. Throughout 2021, we
undertook several initiatives to improve our ESG performance. From an environmental perspective, we consolidated the gas
processing operations for our Mobile Bay assets which lowered our greenhouse gas emissions related to the operation of
those assets. On the social front, we instituted a company-wide diversity training program and tied completion of that
program to our short-term compensation for the year. Relating to governance, we continued to assess the various competing
ESG frameworks; executive management and the Board are evaluating the appropriate oversight and management policies
and procedures that would allow us to continue to strengthen our ESG performance. 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.

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.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Our producing fields are located in federal and state waters in the Gulf of Mexico in water depths ranging from less
than 10 feet up to 7,300 feet. The reservoirs in our offshore fields are generally characterized as having high porosity and
permeability, with higher initial production rates relative to other domestic reservoirs. As of December 31, 2021, two of
our fields located in the conventional shelf accounted for approximately 71.6% our proved reserves on an energy
equivalent basis. The following table provides information for these fields:

Proved Reserves as of December 31, 2021

Mobile Bay Properties
Ship Shoal 349 (Mahogany)

Oil (MMBbls)
0.2
13.9

(MMBbls)
14.8
1.1

NGLs

Percent of
Total
Company
Natural Gas Equivalent Proved
(MMBoe) Reserves
58.8 %
12.8 %

(Bcf)
466.1
31.6

92.7
20.2

Oil

The Mobile Bay Properties and Ship Shoal 349 (Mahogany) 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. Following are descriptions of these areas of operations:

Mobile Bay Properties

The Mobile Bay Properties (including the Fairway field) consist of interests located off the coast of Alabama, in
state coastal and federal Gulf of Mexico waters approximately 70 miles south of Mobile, Alabama. During 2021, we
consolidated the Fairway field into the Mobile Bay Properties in conjunction with the Mobile Bay Transaction as
described in Financial Statements and Supplementary Data – Note 4 - Mobile Bay Transaction under Part II, Item 8 in
this Form 10-K. The field area includes 17 Alabama state water lease blocks and four Federal OCS lease blocks.
These properties include seven major platforms and 21 flowing wells, in up to 50 feet of water.

We acquired our initial 64.3% working interest, along with operatorship, in the Fairway Field and associated
Yellowhammer gas processing plant, from Shell Offshore, Inc. in August 2011 and acquired the remaining working
interest of 35.7% in September 2014. In August 2019, we acquired varied operated working interests in the other Mobile
Bay Properties ranging from 25% to 100% in nine producing fields from Exxon (effective January 1, 2019), and we
became the operator of the fields in December 2019. During September 2019 to December 2019, transitioning activities
occurred to transfer operatorship of the Mobile Bay Properties from Exxon to W&T. During 2020, we completed the
purchase of the remaining interest in two federal Mobile Bay fields from Chevron U.S.A. Inc. Cumulative field
production for the combined Mobile Bay and Fairway properties through 2021 is approximately 843.9 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, 2021, 56 Norphlet wells have been drilled on the Mobile Bay Properties, 45 of
which were successful and 27 of which are currently producing.

As we did not acquire the majority of the Mobile Bay Properties until the end of August 2019, the results of

operations were not included within our Consolidated Results of Operations until September 1, 2019. Given the limited
history of the full combined Mobile Bay Properties and Fairway field, production volumes, realized prices received and
production costs are not presented for 2019.

The following table presents our produced oil, NGLs and natural gas volumes (net to our interests) from the Mobile

Bay Properties over the past two 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,

2021

2020

29
998
32,940
6,516

27.49 $
30.84
3.92
24.68

9
1,167
34,793
6,975

38.52
10.34
2.08
12.18

7.34 $

5.60

(1)

Includes lease operating expenses and gathering and transportation 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. Phillips Petroleum Company discovered the field in 1993. We initially acquired a
25% working interest in the field from BP Amoco in 1999. In 2003, we acquired an additional 34% working interest
through a transaction with ConocoPhillips that increased our working interest to approximately 59%, and we became the
operator of the field in December 2004. In early 2008, we acquired the remaining working interest from Apache
Corporation (“Apache”) and we now own a 100% working interest in this field except for an interest in one well
owned by the Joint Venture Drilling Program. Cumulative field production through 2021 is approximately 59.3 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, 2021, 31 wells have been drilled and 26 were successful. Since acquiring an interest and subsequently
taking over as operator, we have directly participated in drilling 17 wells with a 100% success rate. During 2018, one
well was completed which had been drilled to target depth during 2017, and in addition, two wells were drilled and
completed during 2018. During 2019, one well was drilled, completed and producing in 2019, and significant workover
activities were done to increase production. There has been no additional 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:

Year Ended December 31,
2020

2021

2019

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)

1,667
88
2,565
2,182

1,939
148
3,015
2,590

2,444
154
3,955
3,257

65.27 $
36.85
4.00
56.05

36.69 $
14.46
1.92
30.54

58.27
21.96
2.53
47.84

6.60 $

4.98 $

4.77

(1)

Includes lease operating expenses and gathering and transportation costs.

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, 2021, 2020 and 2019 are summarized below:

Classification of Proved Reserves (1)
December 31, 2021

Proved developed producing
Proved developed non-producing

Total proved developed

Proved undeveloped

Total proved
December 31, 2020

Proved developed producing
Proved developed non-producing

Total proved developed

Proved undeveloped

Total proved
December 31, 2019

Proved developed producing
Proved developed non-producing

Total proved developed

Proved undeveloped

Total proved

Oil
(MMBbls)

NGLs
(MMBbls)

% of
Natural
Total
Gas (Bcf) MMBoe(2) Proved

PV-10
(In millions)

20.8
6.8
27.6
9.6
37.2

19.4
4.6
24.0
8.2
32.2

24.0
4.0
28.0
9.8
37.8

16.4
1.4
17.8
1.3
19.1

15.6
0.9
16.5
0.9
17.4

20.2
1.5
21.7
2.8
24.5

507.9
41.3
549.2
58.4
607.6

510.4
39.8
550.2
19.1
569.3

469.2
35.7
504.9
66.2
571.1

121.9
15.1
137.0
20.6
157.6

120.1
12.1
132.2
12.2
144.4

122.3
11.5
133.8
23.6
157.4

77 % $
10 %
87 %
13 %
100 % $

1,185.3
222.9
1,408.2
213.7
1,621.9

83 % $
8 %
91 %
9 %
100 % $

573.0
73.7
646.7
94.2
740.9

78 % $
7 %
85 %
15 %
100 % $

992.0
95.0
1,087.0
215.5
1,302.5

(1)

In accordance with guidelines established by the SEC, our estimated proved reserves as of December 31, 2021
were determined to be economically producible under existing economic conditions, which requires the use of
the 12-month average commodity price for each product, calculated as the unweighted arithmetic average of the
first-day-of-the-month price for the year end December 31, 2021. Applying this methodology, the West Texas
Intermediate (“WTI”) average spot price of $66.55 per barrel and the Henry Hub natural gas average spot price
of $3.60 per million British Thermal Unit were utilized as the referenced price and after adjusting for quality,
transportation, fees, energy content and regional price differentials, the average adjusted product prices were
$65.25 per barrel for oil, $26.83 per barrel for NGLs and $3.68 per Mcf for natural gas. In determining the
estimated realized price for NGLs, a ratio was computed for each field of the NGLs realized price compared to
the crude oil realized price. Then, this ratio was applied to the crude 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 escalations.

(2) The conversions to barrels of oil equivalent were determined using the energy equivalence ratio of six Mcf of
natural gas to one barrel of crude oil, condensate or NGLs. Totals may not compute due to rounding. The
energy-equivalent ratio does not assume price equivalency, and the energy-equivalent price for oil and NGLs
may differ significantly.

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.

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):

Present value of estimated future net revenues (PV-10)
Present value of estimated ARO, discounted at 10%
PV-10 after ARO
Future income taxes, discounted at 10%
Standardized measure

Changes in Proved Reserves

2021
$ 1,621.9 $
(241.1)
1,380.8
(224.8)
$ 1,156.0 $

2019

December 31,
2020
740.9 $ 1,302.5
(184.9)
(204.2)
1,117.6
536.7
(130.7)
(43.0)
986.9
493.7 $

The following table discloses our estimated changes in proved reserves during the year ended December 31, 2021:

Proved reserves at December 31, 2020
Reserves additions (reductions):

Revisions(1)
Extensions and discoveries
Purchases of minerals in place
Production

Net reserve additions (reductions)

Total proved reserves at December 31, 2021

MMBoe

144.4

27.1
—
—
(13.9)
13.2
157.6

(1) Net revisions of 27.1 MMBoe are primarily attributable to higher commodity prices.

See Development of Proved Undeveloped Reserves below for a table reconciling the change in proved undeveloped

reserves during 2021. See Financial Statements and Supplementary Data– Note 19 – 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, 2021 are calculated based
upon SEC mandated 2021 unweighted average first-day-of-the-month crude 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 2021 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.

Development of Proved Undeveloped Reserves

Our PUDs were estimated by NSAI, our independent petroleum consultant. Future development costs associated

with our PUDs at December 31, 2021 were estimated at $358.3 million.

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

Proved undeveloped reserves, beginning of year

Transfers to proved developed reserves
Revisions of previous estimates
Extensions and discoveries
Purchase of minerals in place
Sales of minerals in place

Proved undeveloped reserves, end of year

Activity related to PUD in 2021:

2021

December 31,
2020

12.2

23.6

—
8.4
—
—
—
20.6

—
(11.4)
—
—
—
12.2

2019

17.0

(0.5)
7.1
—
—
—
23.6

• Net PUD upward revisions of 8.4 MMBoe were primarily due to price revisions at our Ship Shoal 028 and

Mahogany fields.

Activity related to PUDs in 2020:

• Net PUD downward revisions of 11.4 MMBoe were primarily due to price revisions at our Ship Shoal 028 and

Mahogany fields.

Activity related to PUDs in 2019:

• Successfully drilled and converted two locations and 0.5 MMBoe from PUD to proved developed with total

capital expenditures of $27.1 million during 2019.

• Net PUD revisions of 7.1 MMboe were primarily at our Ship Shoal 028 and our Mahogany fields.

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

Year Scheduled for Development
2022
2023
2024
2025
2026

Total

Percentage of
PUD Reserves
Number of PUD Scheduled to be

Locations

Developed

1
3
1
2
4
11

14 %
28 %
3 %
20 %
35 %
100 %

We believe that we will be able to develop all but 2.5 MMBoe (approximately 12%) of the total 20.6 MMBoe
classified as PUDs at December 31, 2021, within five years from the date such PUDs were initially recorded. The lone
exceptions are at the Mississippi Canyon 243 field (“Matterhorn”) and Viosca Knoll 823 (“Virgo”) deepwater fields
where future development drilling has been planned as sidetracks of existing wellbores due to conductor slot limitations
and rig availability. Two sidetrack PUD locations, one each at Matterhorn 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 2023 and 2024.

Qualifications of Technical Persons and Internal Controls over Reserves Estimation Process

Our estimated proved reserve information as of December 31, 2021 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 16 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.

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. 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 crude 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. We convert barrels to Mcfe using
an energy-equivalent ratio of six Mcf to one barrel of oil, condensate or NGLs. This energy-equivalent ratio does not
assume price equivalency, and the energy-equivalent prices for crude oil, NGLs and natural gas may differ substantially.

Acreage

The following table summarizes our leasehold at December 31, 2021. Deepwater refers to acreage in over 500 feet

of water:

Shelf
Deepwater
Alabama State Waters
Total

Developed Acreage
Net

Undeveloped Acreage
Gross

Net

Gross
348,421 272,205 62,604 57,342 411,025 329,547
77,367
153,449
5,147
8,041
509,911 339,171 95,998 72,890 605,909 412,061

61,819 33,394 15,548 186,843
8,041
5,147

Gross

—

Net

Total Acreage

Approximately 82% 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.

Regarding the undeveloped leasehold, of the total 72,890 net undeveloped acres none could expire in 2022;

25,395 net acres (35%) could expire in 2023; 24,662 net acres (34%) could expire in 2024; 11,313 net acres (15%) could
expire in 2025; and 11,520 net acres (16%) could expire in 2025 and beyond. In making decisions regarding drilling and
operations activity for 2022 and beyond, we give consideration to undeveloped leasehold that may expire in the near
term in order that we might retain the opportunity to extend such acreage.

Our net acreage decreased 93,815 net acres (19%) from December 31, 2020 due to lease expirations and

relinquishments.

Drilling Activity

The table below is based on the SEC’s criteria of completion or abandonment to determine wells drilled.

Development and Exploration Drilling

The following table summarizes our development and exploration offshore wells completed over the past

three years:

Year Ended December 31,
2019

2020

2021

Development Wells Completed:

Gross wells
Net wells

Exploration Wells Completed:

Gross wells
Net wells

—
—

3.0
1.6

—
—

3.0
0.8

Our success rates related to our development and exploration wells was 100% in 2019, with all wells drilled and

completed being productive and none were non-commercial (dry holes).

Drilling Activity

During 2020, we drilled one well, which we completed in March 2022. During 2021, we participated in the drilling

of an exploration well which we do not expect to complete.

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.

Productive Wells

The following presents our ownership interest at December 31, 2021 in our productive oil and natural gas wells. A
net well represents our fractional working interest of a gross well in which we own less than all of the working interest:

Operated
Non-operated

Total offshore wells

Oil Wells (1)

Gross Net

Gas Wells (2)
Gross Net

Total Wells

Gross Net

75.0
33.0
108.0

66.0
5.0
71.0

67.0
3.0
70.0

59.0
0.5
59.5

142.0
36.0
178.0

125.0
5.5
130.5

(1)

(2)

Includes eight gross (5.8 net) oil wells with multiple completions.

Includes two gross (1.6 net) gas wells with multiple completions.

Production

For the years 2021, 2020 and 2019, our net daily production averaged 38,117 Boe, 42,046 Boe, and 40,634 Boe,
respectively. Production decreased in 2021 from 2020 primarily due to temporary shut-in and deferral of as much as
approximately 80% of the Company’s production in preparation for, and as a result of, the effects of Hurricane Ida as
well as other well maintenance events throughout the year. 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.

The following presents historical information about our produced oil, NGLs and natural gas volumes from all of our

producing fields over the past three years:

Year Ended December 31,
2019

2020

2021

Net Sales:

Oil (MBbls)
NGLs (MBbls)
Natural gas (MMcf)
Total oil equivalent (MBoe)

Item 3. Legal Proceedings

4,998
1,450

5,629
1,696

6,675
1,271
44,790 48,384 41,310
13,913 15,389 14,831

Appeal with ONRR. In 2009, we recognized allowable reductions of cash payments for royalties owed to the ONRR

for transportation of their deepwater production through our subsea pipeline systems. In 2010, the ONRR audited
our calculations and support related to this usage fee, and we were notified that the ONRR had disallowed approximately
$4.7 million of the reductions taken. We recorded a reduction to other revenue in 2010 to reflect this disallowance with
the offset to a liability reserve; however, we disagree with the position taken by the ONRR. We filed an appeal with the
ONRR, which was denied in May 2014. On June 17, 2014, we filed an appeal with the Interior Board of Land Appeals
(“IBLA”) under the DOI. On January 27, 2017, the IBLA affirmed the decision of the ONRR requiring W&T to pay
approximately $4.7 million in additional royalties. We filed a motion for reconsideration of the IBLA decision on
March 27, 2017. Based on a statutory deadline, we filed an appeal of the IBLA decision on July 25, 2017 in the U.S.
District Court for the Eastern District of Louisiana. We were required to post a bond in the amount of $7.2 million and
cash collateral of $6.9 million in order to appeal the IBLA decision. On December 4, 2018, the IBLA denied our motion
for reconsideration. On February 4, 2019, we filed our first amended complaint, and the government has filed its Answer
in the Administrative Record. On July 9, 2019, we filed an Objection to the Administrative Record and Motion to
Supplement the Administrative Record, asking the court to order the government to file a complete privilege log with the
record. Following a hearing on July 31, 2019, the Court ordered the government to file a complete privilege log. In an
Order dated December 18, 2019, the court ordered the government to produce certain contracts subject to a protective
order and to produce the remaining documents in dispute to the court for in camera review. Ultimately, the court upheld
the government’s assertion of privilege and the parties commenced briefing on the merits. At this point, both parties
have filed cross-motions for summary judgment and opposition briefs. W&T 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, we are
waiting for the district court’s ruling on the merits. In January 2020, the cash collateral in the amount of $6.9 million
securing the appeal bond in this matter was released to us. In compliance with the ONRR’s request for W&T to increase
the surety posted in the appeal, the penal sum of the bond posted is currently $8.5 million.

Monetary Sanctions by Government Authorities (Civil Penalty Assessments). In January 2021, we 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, with the proposed civil penalty amounts totaling $7.7 million. Under the
Settlement Agreement, W&T will pay a total of $720,000 in three annual installments. The first installment was paid in
March 2021. In addition, W&T committed to implement a Safety Improvement Plan with various deliverables due over a
period ending in 2022. In September 2021, we paid $40,200 related to an INC issued in 2018. Additionally, in
September 2021, we were notified of a new proposed civil penalty assessment for $46,000 for an INC that occurred at
one of our properties in 2018, which we subsequently paid in January 2022.

Other Claims. We are a party to various pending or threatened claims and complaints seeking damages or other
remedies concerning our commercial operations and other matters in the ordinary course of our business. In addition,
claims or contingencies may arise related to matters occurring prior to our acquisition of properties or related to matters
occurring subsequent to our sale of properties. In certain cases, we have indemnified the sellers of properties we have
acquired, and in other cases, we have indemnified the buyers of properties we have sold. We are 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 we can give no assurance about the outcome of
pending legal and federal or state administrative proceedings and the effect such an outcome may have on us, we believe
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 our consolidated financial position, results of operations
or liquidity.

See Financial Statements and Supplementary Data – Note 18 – Contingencies under Part II, Item 8 in this

Form 10-K for additional information on the matters described above.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

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, 2022,

there were 185 registered holders of our common stock.

Dividends

During 2021 and 2020, no dividends were paid as dividend payments have been suspended. Our Board of Directors

decides the timing and amounts of any dividends for the Company. Dividends are subject to periodic review of the
Company’s performance, which includes the current economic environment and applicable debt agreement restrictions.
See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital
Resources under Part II, Item 7 and Financial Statements and Supplementary Data – Note 2 –Debt under Part II, Item 8
in this Form 10-K for more information regarding covenants related to dividends in our debt agreements.

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.

Comparison of Cumulative Total Return

$250

$200

$150

$100

$50

12/31/2016

12/31/2017

12/31/2018

12/31/2019

12/31/2020

12/31/2021

W&T Offshore

S&P Oil & Gas Exploration & Production Index

S&P 500

Securities Authorized for Issuance under Equity Compensation Plans

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. For descriptions of the plans
and additional information, see Financial Statements and Supplementary Data – Note 11 –Share-Based Awards and
Cash-Based Awards under Part II, Item 8 in this Form 10-K.

Issuer Purchases of Equity Securities

For the year 2021, we did not purchase any of our equity securities.

The following table sets forth information about restricted stock units (“RSUs”) during the quarter ended

December 31, 2021:

Period
October 1, 2021 – October 31, 2021
November 1, 2021 - November 30, 2021
December 1, 2021 – December 31, 2021 (1)

Total
Number of
Restricted
Stock Units
Delivered

N/A
N/A
235,855

Average
Price per
Restricted
Stock Unit

N/A
N/A
3.31

Purchased as

Total
Number of
Shares

Part of
Publicly
Announced
Plans or
Programs

N/A
N/A
N/A

Maximum
Number (or)
Approximate

Dollar
Value of
Shares that
May Yet be
Purchased
Under the
Plans or
Programs
N/A
N/A
N/A

(1) RSUs delivered by employees during December 2021 to satisfy tax withholding obligations on the vesting of

RSU.

Sales of Unregistered Equity Securities

We did not have any sales of unregistered equity securities during the fiscal year ended December 31, 2021 that we

have not previously reported on a Quarterly Report on Form 10-Q or a Current Report on Form 8-K.

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, Items 1 and 2 Business and Properties; Item 1A Risk Factors; and Item 7A Quantitative
and Qualitative Disclosures About Market Risk and with Part II, Item 8 Financial Statements and Supplementary Data
in this Annual Report. The following discussion and analysis includes forward-looking statements that reflect our plans,
estimates and beliefs. Our actual results could differ materially from those anticipated in these forward-looking
statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed
below and elsewhere in this Annual Report, particularly in Part I, Item 1A Risk Factors.

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

Overview

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

Business Strategy

Our goal is to pursue high rate of return projects and develop oil and natural gas resources that allow us to grow our

production, reserves and cash flow in a capital efficient manner, thus enhancing the value of our assets. We intend to
execute the following elements of our business strategy in order to achieve this goal:

• 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; and

• Continuing to manage our balance sheet in a prudent manner and continuing our track record of financial

flexibility in any commodity price environment.

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

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

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

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

Hurricanes and Severe Weather. During the third quarter of 2021, our production from the U.S Gulf of Mexico was

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

Known Trends and Uncertainties

Volatility in Oil, NGL and Natural Gas Prices. Historically, the markets for oil and natural gas has been volatile.

Our realized sales prices received for our crude oil, NGLs and natural gas production are affected by many factors
outside of our control, including changes in market supply and demand, which are impacted by weather conditions,
pipeline capacity constraints, inventory storage levels, domestic production activities and political issues, and
international geopolitical and economic events. As a result, we cannot accurately predict future commodity prices and,
therefore, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have
on our drilling program, production volumes or revenues.

While the current outlook for commodity prices is favorable and our operations are no longer significantly impacted

The recent invasion of parts of Ukraine by Russia, and the impact of world sanctions against Russia and the

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

Prolonged period of weak commodity prices may create uncertainties in our financial condition and results of

operations. Such uncertainties may include:

•
•
•
•
•

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.

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

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

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

Hurricane and Severe Weather Events. Since our operations are in the Gulf of Mexico, we are particularly vulnerable

to the effects of hurricanes on production. We normally obtain insurance to reduce, but not totally mitigate, our financial
exposure risk; however, affordable insurance coverage for property damage to our facilities for hurricanes is not assured.
See Liquidity and Capital Resources – Insurance Coverage under this Item 7 in this Form 10-K for additional information.
Significant hurricane impacts could include reductions and/or deferrals of future oil and natural gas production and
revenues, increased lease operating expense for evacuations and repairs and possible acceleration of plugging and
abandonment costs.

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

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

Surety Bond Collateral. Some of the sureties that provide us surety bonds used for supplemental financial assurance

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

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

Results of Operations

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

Revenues

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs. Our oil,

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

Oil
NGLs
Natural gas
Other

Year Ended December 31,

2021

2020

59.1 %
7.9 %
31.1 %
1.9 %

62.4 %
5.5 %
28.7 %
3.4 %

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

Revenues:

Oil
NGLs
Natural gas
Other

Total revenues

Production Volumes:

Oil (MBbls)
NGLs (MBbls)
Natural gas (MMcf)
Total oil equivalent (MBoe)

Year Ended December 31,
2021
2020
(In thousands, except realized sales price data)

Change

329,557
44,343
173,749
10,361
558,010

216,419
19,101
99,300
11,814
346,634

113,138
25,242
74,449
(1,453)
211,376

4,998
1,450
44,790
13,913

5,629
1,696
48,384
15,389

(631)
(246)
(3,594)
(1,476)

Average daily equivalent sales (Boe/day)

38,118

42,046

(3,928)

Average realized sales prices:

Oil ($/Bbl)
NGLs ($/Bbl)
Natural gas ($/Mcf)
Oil equivalent ($/Boe)
Oil equivalent ($/Boe), including realized commodity derivatives

65.94
30.59
3.88
39.36
32.52

38.45
11.26
2.05
21.76
24.70

27.49
19.33
1.83
17.60
7.82

Changes in average sales prices and sales volumes caused the following changes to our oil, NGL and natural gas

revenues between the years ended December 31, 2021 and 2020 (in thousands):

Oil
NGLs
Natural gas

Price
137,392
28,017
81,826
247,235

Volume

(24,254)
(2,775)
(7,377)
(34,406)

Total
113,138
25,242
74,449
212,829

Realized Prices on the Sale of Oil, NGLs and Natural Gas. Our average realized crude oil sales price differs from

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

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

The actual prices we realize from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result

of quality and location differentials. Currently, the sales points of our gas production are generally within close
proximity to the Henry Hub which creates a minimal differential in the prices we receive for our production versus
average Henry Hub prices.

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

Operating Expenses

The following table presents information regarding costs and expenses and selected average costs and expenses per

Boe sold for the periods presented and corresponding changes:

Operating expenses:

Lease operating expenses
Production taxes
Gathering and transportation
Depreciation, depletion, amortization and accretion
Ceiling test write-down of oil and natural gas properties
General and administrative expenses

Total operating expenses

Average per Boe ($/Boe):
Lease operating expenses
Gathering and transportation

Production costs

Production taxes
DD&A
G&A expenses

Operating costs

Year Ended December 31,
2020
2021
(In thousands, except per Boe data)

Change

174,582
10,074
17,845
113,447
—
52,400
368,348

12.55
1.28
13.83
0.72
8.15
3.77
26.47

162,857
4,918
16,029
120,284
—
41,745
345,833

10.58
1.04
11.62
0.32
7.82
2.71
22.47

11,725
5,156
1,816
(6,837)
—
10,655
22,515

1.97
0.24
2.21
0.40
0.33
1.06
4.00

Lease operating expenses. Lease operating expenses include the expense of operating and maintaining our wells,

platforms and other infrastructure primarily in the Gulf of Mexico. These operating costs are comprised of several
components, including direct or base lease operating expenses, insurance premiums, workover costs, facilities repairs
and maintenance expenses, and hurricane repair expenses. Our lease operating costs, which depend in part on the type of
commodity produced, the level of workover activity and the geographical location of the properties, increased
$11.7 million to $174.6 million in 2021 compared to $162.9 million in 2020. On a per Boe basis, lease operating
expenses increased to $12.55 per Boe during 2021 compared to $10.58 per Boe during 2020. On a component basis, base
lease operating expenses increased $5.0 million, workover expenses increased $1.8 million, facilities maintenance
expenses increased $4.9 million, and hurricane repairs increased $1.0 million. These increases were partially offset by
decrease of $1.0 million in insurance premiums.

Expenses for direct labor, materials and supplies, rental and third party costs comprise the most significant portion

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

Workovers and facilities maintenance expenses consist of costs associated with major remedial operations on
completed wells to restore, maintain or improve the well’s production. Since these remedial operations are not regularly
scheduled, workover and maintenance expense are not necessarily comparable from period to period.

Production taxes. Production taxes consist of severance taxes levied by the Alabama Department of Revenue and
the Texas Department of Revenue on production of oil and natural gas from land or water bottoms within the boundaries
of each state, respectively. Production taxes were $10.1 million in 2021, an increase of $5.2 million as compared to
2020, primarily due to the increase in realized natural gas prices, partially offset by decreased natural gas production
volumes.

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

Depreciation, depletion, amortization and accretion. Depreciation, depletion and amortization expense is the
expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas reserves. We use the full
cost method of accounting for oil and natural gas activities. See Part II, Item 8. Financial Statements and Supplementary
data — Note 1 — Summary of Significant Accounting Policies for further discussion. Accretion expense is the expensing
of the changes in value of our asset retirement obligations as a result of the passage of time over the estimated productive
life of the related assets as the discounted liabilities are accreted to their expected settlement values. DD&A, which
includes accretion for ARO, increased to $8.15 per Boe in 2021 from $7.82 per Boe in 2020. On a nominal basis, DD&A
decreased to $113.4 million in 2021 from $120.3 million in 2020. The rate per Boe increased year-over-year mostly as a
result of increases in the future development costs included in the depreciable base compared to the relatively smaller
increase in proved reserves over the comparable prior year period.

General and administrative expenses (“G&A”). G&A expense generally consists of costs incurred for overhead,

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

Other Income and Expense

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

corresponding changes:

Other income and expenses:

Derivative loss (gain)
Interest expense, net
Gain on debt transactions
Other (income) expense, net
Income tax (benefit) expense

Year Ended December 31,
2020
2021
(In thousands)

Change

175,313
70,049
—
(6,165)
(8,057)

(23,808)
61,463
(47,469)
2,978
(30,153)

199,121
8,586
47,469
(9,143)
22,096

Derivative loss (gain). We utilize commodity derivative instruments to reduce our exposure to fluctuations in the

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

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

Interest expense, net. We finance a portion of our working capital requirements, capital expenditures and

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

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

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

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

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

The Company assesses available positive and negative evidence regarding our ability to realize our deferred tax

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

Liquidity and Capital Resources

Liquidity Overview

Our primary uses of cash are for capital expenditures, working capital, debt service and for general corporate
purposes. We fund capital expenditures and strategic property acquisitions to allow us to replace our oil and natural gas
reserves, repay outstanding borrowings, make related interest payments and satisfy our AROs. We have funded such
activities in the past with cash on hand, net cash provided by operating activities, sales of property, securities offerings
and bank borrowings.

The primary sources of our liquidity are cash from operating activities and borrowings under our Credit Agreement.

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

We believe that we will have adequate liquidity from cash flow from operations to fund our capital expenditure
plans for 2022, fund our ARO spending for 2022 and fulfill our various other obligations. Availability under our Credit
Agreement as of December 31, 2021 was $50.0 million. Our preliminary capital expenditure budget for 2022 has been
established in the range of $70.0 million to $90.0 million, which includes our share of the Joint Venture Drilling
Program, and excludes acquisitions. In our view of the outlook for 2022, we believe this level of capital expenditure will
enhance our liquidity capacity throughout 2022 and beyond while providing liquidity to make strategic acquisitions. At
current pricing levels, we expect our cash flows to cover our liquidity requirements and we expect additional financing
sources to be available if needed. If our liquidity becomes stressed from significant reductions in realized prices, we
have flexibility in our capital expenditure budget to reduce investments. We strive to maintain flexibility in our capital
expenditure projects and if prices improve, we may increase our investments. Beyond 2022, while we expect to continue
to have adequate liquidity from cash flow from operations to fulfill our future obligations, we continue to evaluate
financing and refinancing alternatives on a strategic basis.

Sources and Uses of Cash

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

Operating activities
Investing activities
Financing activities

Year Ended December 31,
2020
2021
(In thousands)

Change

133,668
(27,444)
100,266

108,509 $
(47,616)
(49,600)

25,159
20,172
149,866

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

Other items affecting operating cash flows for 2021 were: ARO settlements of $27.3 million, which increased from

$3.3 million in 2020; cash advances from joint venture partners of $7.8 million during 2021 compared to $2.0 million
during 2020; derivative cash payments, net, were $81.3 million in 2021 compared to derivative cash receipts, net, of
$45.2 million in 2020; and derivative premiums of $40.5 million were paid in 2021.

Investing activities. Net cash used in investing activities during 2021 and 2020 was $27.4 million and

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

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

Joint Venture Drilling Program. To provide additional financial flexibility, we created the Joint Venture Drilling

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

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

Crude 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

Year Ended December 31,
2020
2021

65.94
(10.44)
55.50

3.88
(0.96)
2.92

38.45
6.48
44.93

2.05
(0.05)
2.00

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

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

effect.

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

Employee Retention Credit. Under the Consolidated Appropriations Act, 2021 passed by the United States Congress

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

Capital Expenditures

Our preliminary capital expenditure budget for 2022 has been established in the range of $70.0 million to

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

The level of our investment in oil and natural gas properties changes from time to time depending on numerous
factors including the prices of crude oil, NGLs and natural gas; acquisition opportunities; liquidity and financing options;
and the results of our exploration and development activities. The following table presents our investments in oil and gas
properties and equipment for exploration, development, acquisitions and other leasehold costs:

Exploration (1)
Development (1)
Acquisitions of interests (2)
Seismic and other

Investments in oil and gas property/equipment – accrual basis

Year Ended December 31,
2020
2021

(In thousands)

18,273
9,478
661
4,311
32,723

1,837
11,109
2,919
4,686
20,551

(1) Reported geographically in the subsequent table.
(2) Various working interest acquisitions in 2020 and 2021 including the purchase of additional working interest at

the Magnolia field the Mobile Bay Properties during 2020.

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

Conventional shelf (1)
Deepwater

Exploration and development capital expenditures – accrual basis

Year Ended December 31,
2020
2021

(In thousands)

7,872
19,879
27,751

10,247
2,699
12,946

(1)

Includes exploration and development capital expenditures in Alabama state waters.

The capital expenditures reported in the above two tables are included within Oil and natural gas properties and

other, net on the Consolidated Balance Sheets. The capital expenditures reported within the Investing section of the
Consolidated Statements of Cash Flows include adjustments for payments related to capital expenditures.

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

Offshore – gross wells drilled:

Conventional shelf
Deepwater
Wells operated by W&T

2021

Completed
2020

2019

—
—
—

3
3
5

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

See Properties – Drilling Activity under Part I, Item 2 of this Form 10-K for a breakdown of exploration and

development wells and additional drilling activity information.

See Properties – Development of Proved Undeveloped Reserves under Part I, Item 2 of this Form 10-K for a

discussion on activity related to proved undeveloped reserves.

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

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

Asset retirement obligations. Annually, we review and revise our ARO estimates. Our ARO at

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

Debt

We are actively monitoring the debt capital markets, and we intend to seek financings with longer tenors and market

based covenants to continue to provide working and potential acquisition capital as well as provide funding for
refinancing of some or all of our Second Lien Notes. The terms of such financings, which may replace or augment our
Credit Agreement and refinance some or all of our Second Lien Notes, may vary significantly from those under the
Credit Agreement and our Second Lien Notes.

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

Term Loan. As of December 31, 2021, we had $190.9 million of Term Loan principal outstanding. The Term Loan

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

Credit Agreement. As of December 31, 2021, we had no borrowings outstanding under the Credit Agreement.

During the year ended December 31, 2021, we repaid $80.0 million of borrowings.

On November 2, 2021, the Company entered into two amendments to the Credit Agreement which effectively

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

Senior Second Lien Notes. As of December 31, 2021, we had $552.5 million principal outstanding of Senior Second

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

Debt Covenants. The Term Loan, Credit Agreement, and Senior Second Lien Notes contain financial covenants

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

The Subsidiary Borrowers

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

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

Below is consolidating balance sheet information reflecting the elimination of the accounts of our Unrestricted

Subsidiaries from our Consolidated Balance Sheet as of December 31, 2021 (in thousands):

Consolidated
Balance Sheet

Eliminations of
Unrestricted
Subsidiaries

Consolidated
Balance Sheet of
restricted
subsidiaries

245,799
4,417

(38,937)
—

206,862
4,417

54,919
9,745
64,664
43,379
358,259
665,252
16,019
102,505
51,172
1,193,207

82,481
36,243
56,419
106,140
42,960
133
324,376

700,359
(12,421)
687,938
368,076
59,884
113
1
552,923
(775,937)
(24,167)
(247,180)
1,193,207

(34,420)
10,856
(23,564)
(356)
(62,857)
(272,747)
—
—
19,903
(315,701)

(29,678)
(3,144)
—
(29,937)
(42,960)
—
(105,719)

(147,899)
7,546
(140,353)
(54,515)
(42,615)
—
—
—
27,501
—
27,501
(315,701)

20,499
20,601
41,100
43,023
295,402
392,505
16,019
102,505
71,075
877,506

52,803
33,099
56,419
76,203
—
133
218,657

552,460
(4,875)
547,585
313,561
17,269
113
1
552,923
(748,436)
(24,167)
(219,679)
877,506

Assets

Current assets:

Cash and cash equivalents
Restricted cash
Receivables:

Oil and natural gas sales
Joint interest, net

Total receivables

Prepaid expenses and other 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’ Deficit

Current liabilities:

Accounts payable
Undistributed oil and natural gas proceeds
Asset retirement obligations
Accrued liabilities
Current portion of long-term debt
Income tax payable

Total current liabilities

Long-term debt

Principal
Unamortized debt issuance costs

Long-term debt, net

Asset retirement obligations, less current portion
Other liabilities
Deferred income taxes

Common stock
Additional paid-in capital
Retained deficit
Treasury stock, at cost

Total shareholders’ deficit

Total liabilities and shareholders’ deficit

Below is Consolidating Statement of Operations information reflecting the elimination of the accounts of our
Unrestricted Subsidiaries from our Consolidated Statement of Operations for the year ended December 31, 2021 (in
thousands):

Revenues:

Oil
NGLs
Natural gas
Other

Total revenues
Operating expenses:

Lease operating expenses
Production taxes
Gathering and transportation
Depreciation, depletion, amortization and accretion
General and administrative expenses

Total operating expenses
Operating (loss) income

Interest expense, net
Derivative loss (gain)
Gain on debt transactions
Other expense, net

(Loss) income before income taxes

Income tax benefit

Net (loss) income

Consolidated

Eliminations of
Unrestricted
Subsidiaries

Consolidated
restricted
subsidiaries

329,557 $
44,343
173,749
10,361
558,010

174,582
10,074
17,845
113,447
52,400
368,348
189,662

(463) $

(21,438)
(92,863)
(4,786)
(119,550)

(26,507)
(6,620)
(2,539)
3,579
(647)
(32,735)
(86,814)

70,049
175,313
—
(6,165)
(49,535)
(8,057)
(41,478) $

(9,782)
(104,533)
—
—
27,501
—
27,501 $

329,094
22,905
80,886
5,575
438,460

148,075
3,454
15,306
117,026
51,753
335,613
102,848

60,267
70,780
—
(6,165)
(22,034)
(8,057)
(13,977)

The following table presents our produced oil, NGLs and natural gas volumes (net to our interests) from the Mobile

Bay Properties for the period from May 19, 2021 through December 31, 2021:

Production Volumes:

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)

For the period from
May 19, 2021 to
December 21, 2021

13
603
20,417
4,019

35.64
35.55
4.55
28.56

7.23

(1)

Includes lease operating expenses and gathering and transportation costs.

Reserves information is for the Mobile Bay properties is described in more detail under Part I Item 2, Properties, in

this Form 10-K.

Insurance Coverage

We currently carry multiple layers of insurance coverage in our Energy Package (defined as certain insurance

policies relating to our oil and gas properties which include named windstorm coverage) covering our operating
activities, with higher limits of coverage for higher valued properties and wells. The current policy is effective for
one year beginning June 1, 2021 and limits for well control range from $30.0 million to $500.0 million depending on the
risk profile and contractual requirements. With respect to coverage for named windstorms, we have a $162.5 million
aggregate limit covering all of our higher valued properties, and $150.0 million for all other properties subject to a
retention of $17.5 million on the conventional shelf properties and $12.5 million on the deepwater properties. Included
within the $162.5 million aggregate limit is TLO coverage on our Mahogany platform, which has no retention. The
operational and named windstorm coverages are effective for one year beginning June 1, 2021. Coverage for pollution
causing a negative environmental impact is provided under the well control and other sections within the policy.

Our general and excess liability policies are effective for one year beginning May 1, 2021 and provide for $300.0
million of coverage for bodily injury and property damage liability, including coverage for liability claims resulting from
seepage, pollution or contamination. With respect to the Oil Spill Financial Responsibility requirement under the OPA of
1990, we are required to evidence $35.0 million of financial responsibility to the BSEE and we have insurance coverage
of such amount. We do not carry business interruption insurance.

The premiums for the above policies including brokerage fees were $9.7 million for the May/June 2021 policy

renewals compared to $10.9 million for the expiring policies. The change in our premiums effective with the
May/June 2020 renewal was primarily attributable to negotiations.

Contractual Obligations

At December 31, 2021, we did not have any financing leases. The following table summarizes our significant

contractual obligations by maturity as of December 31, 2021 (in millions):

Payments Due by Period as of December 31, 2021

Long-term debt – principal
Long-term debt – interest (1)
Operating leases
Asset retirement obligations (2)
Other liabilities and commitments (3)
Total

One to
Three
Years

Less than
One Year

Three to More Than
Five Years Five Years
31.0
53.0 $
1.7
8.4
15.9
3.1
202.6
82.4
51.3
12.1
$ 1,416.4 $ 176.1 $ 778.8 $ 159.0 $ 302.5

43.0 $ 616.3 $
66.5
1.1
56.4
9.1

Total
743.3 $
138.0
23.8
424.5
86.8

61.4
3.7
83.1
14.3

(1)

Interest payments were calculated through the stated maturity date of the related debt:
(a) Interest payments for the Credit Agreement were calculated using the interest rate applied to our outstanding
balance as of December 31, 2021 and assumes no change in this interest rate in future periods. In addition, a
commitment fee of 3.0% was applied on the available balance as of December 31, 2021 and fees related to
letters of credit were estimated at the rate incurred on December 31, 2021.
(b) Interest payments on the Senior Second Lien Notes were calculated per the terms of the notes;
(c) Interest payments on the Term Loan were calculated at the 7% interest rate set forth in the Term Loan.

(2) ARO in the above table is presented on a discounted basis, consistent with the amounts reported on the

Consolidated Balance Sheet as of December 31, 2021 and are estimates of future payments. Actual payments
and the timing of the payments may be significantly different than our estimates. All other amounts in the above
table are presented on an undiscounted basis.

(3) 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, 2021, we had approximately $401.8 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. Included are estimates of minimum quantities obligations for certain pipeline contracts
which were assumed in conjunction with the purchase of an interest in the Heidelberg field. The above table
excludes 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, operating costs and 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
16 – Commitments under Part II, Item 8 in this 10-K for additional information.

Seasonality and Inflation

The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies,
suppliers and others associated with the industry puts extreme pressure on the economic stability and pricing structure
within the industry. Typically, as prices for oil and natural gas increase, so do associated costs. Material changes in
prices impact the current revenue stream, estimates of future reserves, borrowing base calculations of bank loans and the
value of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural
gas companies and their ability to raise capital, borrow money and retain personnel. We anticipate business costs will
vary in accordance with commodity prices for oil and natural gas, and the associated increase or decrease in demand for
services related to production and exploration. See Risk Factors – Crude oil, natural gas and NGL prices can fluctuate
widely due to a number of factors that are beyond our control. Depressed oil, natural gas or NGL prices adversely
affects 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 under Part I, Item 1A in this Form 10-K and Item 1 Business – Seasonality and Inflation, under Part I,
Item 1 in this form 10-K for additional information.

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 in the United States. 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.

Revenue Recognition. Revenues are recorded from the sale of oil, natural gas and NGLs 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. This
typically occurs when production has been delivered to a pipeline.

Revenues are recorded based on the actual sales volumes sold to purchasers. An imbalance receivable or payable is

recorded only to the extent the imbalance is in excess of its share of remaining proved developed reserves in an
underlying property. Our imbalances are recorded gross on our Consolidated Balance Sheets.

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, the Company’s 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 Company’s Consolidated Balance Sheets. The expense may not be reversed in future
periods, even though higher oil, natural gas and NGL prices may subsequently increase the ceiling. The Company
performs this ceiling test calculation each quarter. In accordance with the SEC rules and regulations, the Company
utilizes SEC Pricing when performing the ceiling test. The Company also holds 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 2021, 2020 or 2019.

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 crude oil, natural gas and natural gas liquids 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 crude oil 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.

Asset retirement obligations. The Company has obligations associated with the retirement of its 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. The Company accrues a liability with respect to these obligations based on its estimate of the timing and
amount to replace, remove or retire the associated assets.

In estimating the liability associated with its asset retirement obligations, 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. 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 the Company incurs an amount different from the amount accrued for
decommissioning obligations, the Company recognizes the difference as an adjustment to proved 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 our 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 our financial position, results of operations and cash flows. We record adjustments to reflect actual taxes
paid in the period we complete our tax returns.

We account for uncertainty in income taxes recognized in the 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

We are exposed to market risks arising from fluctuating prices of crude oil, NGLs, natural gas and interest rates as

discussed below. We have utilized derivative contracts to reduce the risk of fluctuations in commodity prices and expect
to use these instruments in the future. While derivative contracts are intended to reduce the effects of volatile oil prices,
they may also limit income from favorable price movements. For additional details about our derivative contracts, refer
to Financial Statements and Supplementary Data – Note 10 – Derivative Financial Instruments under Part II, Item 8 in
this Form 10-K.

Commodity price risk. Oil, NGL, and natural gas prices can fluctuate significantly and have a direct impact on our
revenues, earnings and cash flow. For example, assuming a 10% decline in our average realized oil, NGLs and natural
gas sales prices in 2021 and assuming no other items had changed, our revenue would have decreased by approximately
$65 million in 2021. If costs and expenses of operating our properties had increased by 10% in 2021, our income before
income tax would have decreased by approximately $24 million in 2021. These amounts would be representative of the
effect on operating cash flows under these price and cost change assumptions.

We have attempted to mitigate commodity price risk and stabilize cash flows associated with our forecasted sales of

oil and natural gas production through the use of swaps, costless collars, purchased calls, and purchased puts. These
contracts will impact our earnings as the fair value of these derivatives changes. Our derivatives will not mitigate all of
the commodity price risks of our forecasted sales of oil and natural gas production and, as a result, we will be subject to
commodity price risks on our remaining forecasted production. During year ended December 31, 2021, our average
realized oil price after the effect of derivatives increased 23.5% to $55.50 per Bbl from $44.93 per Bbl during the year-
ended December 31, 2020. Our average natural gas price realizations after the effect of derivatives increased 46.0%
during the year ended December 31, 2021 to $2.92 per Mcf from $2.00 per Mcf during the year-ended December 31,
2020.

Interest rate risk. As of December 31, 2021, we had no debt outstanding on our Credit Agreement. The Credit
Agreement has a variable interest rate which is primarily impacted by the rates for the London Interbank Offered Rate
and the current margin is 6.0% per annum. We did not have any derivative contracts related to interest rates as of
December 31, 2021.

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
Report of Independent Registered Public Accounting Firm (PCAOB ID 0042)
Report of Independent Registered Public Accounting Firm (PCAOB ID 0042)
Consolidated Financial Statements:

Consolidated Balance Sheets as of December 31, 2021 and 2020
Consolidated Statements of Operations for the years ended December 31, 2021, 2020 and 2019
Consolidated Statements of Changes in Shareholders’ Deficit for the years ended December 31, 2021,
2020 and 2019
Consolidated Statements of Cash Flows for the years ended December 31, 2021, 2020 and 2019
Notes to Consolidated Financial Statements

Page
60
61
63

65
66

67
68
69

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, 2021 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, 2021 has been audited by Ernst &
Young LLP, an independent registered public accounting firm, as stated in their report, which is included herein.

Report of Independent Registered Public Accounting Firm

The Shareholders and 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, 2021, 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, 2021, 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, 2021 and
2020, the related consolidated statements of operations, changes in shareholders’ deficit, and cash flows for each of the
three years in the period ended December 31, 2021, and the related notes and our report dated March 9, 2022 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 9, 2022

Report of Independent Registered Public Accounting Firm

The Shareholders and 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, 2021 and 2020, the related consolidated statements of operations, changes in shareholders’ deficit,
and cash flows for each of the three years in the period ended December 31, 2021, 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, 2021 and 2020, and the results of
its operations and its cash flows for each of the three years in the period ended December 31, 2021, 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, 2021, 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 9, 2022 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.

Description of the
Matter

Depreciation, Depletion and Amortization (“DD&A”) of Oil and Natural Gas Properties

At December 31, 2021, the net book value of the Company’s oil and natural gas properties was $665
million, and depreciation, depletion and amortization (“DD&A”) expense was $90 million for the
year then ended. As discussed in Note 1, under the full-cost method of accounting, DD&A is recorded
based on the units-of-production method. Capitalized acquisition, exploration, development, and
abandonment costs are amortized on the basis of total proved reserves, as estimated by independent
petroleum engineers. Proved oil and natural gas reserves are estimated quantities of oil and natural
gas which geological and engineering data demonstrate with reasonable certainty to be commercially
recoverable in future years from known reservoirs under existing economic and operating conditions.
Significant judgment is required by the independent petroleum engineers in evaluating geological

and engineering data used to estimate oil and natural gas reserves. Estimating reserves also requires
the selection of inputs, including oil and natural gas price assumptions, future operating and capital
costs assumptions and tax rates by jurisdiction, among others. Because of the complexity involved
in estimating oil and natural gas reserves, management used independent petroleum engineers to
prepare the oil and natural gas reserve estimates as of December 31, 2021.

Auditing the Company’s DD&A calculation is especially complex because of the use of the work of
the independent petroleum engineers and the evaluation of management’s determination of the inputs
described above used by the engineers in estimating proved oil and natural gas reserves.

How we Addressed
the Matter in our
Audit

We obtained an understanding, evaluated the design and tested the operating effectiveness of the
Company’s controls over its process to calculate DD&A, including 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. In addition, in assessing whether we can use the work of the independent petroleum
engineers we evaluated 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 and we identified and evaluated corroborative and contrary evidence. We also
tested the mathematical accuracy of the DD&A calculations, including comparing the proved oil and
natural gas reserve amounts used to the Company’s reserve report.

Accounting for Asset Retirement Obligation

At December 31, 2021, the asset retirement obligation (ARO) balance totaled $424 million. As
further described in Notes 1 and 7, the Company records a liability for ARO in the period in which
it is incurred. 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.

Auditing the Company’s ARO is complex and highly judgmental because of the significant
estimation required by management in determining the obligation. In particular, the estimate was
sensitive to significant subjective assumptions such as retirement cost estimates and the estimated
timing of settlements, which are both affected by expectations about future market and economic
conditions.

Description of the
Matter

How we Addressed
the Matter in our
Audit

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.

To test the ARO, 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.

We have served as the Company’s auditor since 2000.

/s/ Ernst & Young LLP

Houston, Texas
March 9, 2022

W&T OFFSHORE, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands)

Assets
Current assets:

Cash and cash equivalents
Restricted cash
Receivables:

Oil and natural gas sales
Joint interest, net

Total receivables

Prepaid expenses and other assets (Note 1)

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 1)

Total assets

Liabilities and Shareholders’ Deficit
Current liabilities:

Accounts payable
Undistributed oil and natural gas proceeds
Advances from joint interest partners
Asset retirement obligations
Accrued liabilities (Note 1)
Current portion of long-term debt
Income tax payable

Total current liabilities

Long-term debt (Note 2)

Principal
Unamortized debt issuance costs

Long-term debt, net

Asset retirement obligations, less current portion
Other liabilities (Note 1)
Deferred income taxes
Commitments and contingencies (Note 18)
Shareholders’ deficit:

Preferred stock, $0.00001 par value; 20,000 shares authorized; none issued at
December 31, 2021 and December 31, 2020
Common stock, $0.00001 par value; 200,000 shares authorized; 145,732 issued and 142,863
outstanding at December 31, 2021; 145,174 issued and 142,305 outstanding at
December 31, 2020
Additional paid-in capital
Retained deficit
Treasury stock, at cost; 2,869 shares at December 31, 2021 and December 31, 2020

Total shareholders’ deficit

Total liabilities and shareholders’ deficit

See accompanying notes.

December 31,

2021

2020

245,799
4,417

43,726
—

54,919
9,745
64,664
43,379
358,259

38,830
10,840
49,670
13,832
107,228

665,252

686,878

16,019
102,505
51,172
1,193,207

67,409
36,243
15,072
56,419
106,140
42,960
133
324,376

700,359
(12,421)
687,938

368,076
55,389
113
4,495

29,675
94,331
22,470
940,582

41,304
19,167
7,308
17,188
29,880
—
153
115,000

632,460
(7,174)
625,286

375,516
32,938
128
—

—

1
552,923
(775,937)
(24,167)
(247,180)
1,193,207

1
550,339
(734,459)
(24,167)
(208,286)
940,582

W&T OFFSHORE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands except per share data)

Year Ended December 31,
2020

2019

2021

Revenues:

Oil
NGLs
Natural gas
Other

Total revenues
Operating expenses:

Lease operating expenses
Production taxes
Gathering and transportation
Depreciation, depletion, and amortization
Asset retirement obligations accretion
General and administrative expenses

Total operating expenses
Operating income (loss)

Interest expense, net
Derivative loss (gain)
Gain on debt transactions
Other (income) expense, net

(Loss) income before income taxes

Income tax benefit

Net (loss) income

Net (loss) income per common share:

Basic
Diluted

Weighted average common shares outstanding

Basic
Diluted

$ 329,557 $ 216,419 $ 399,790
22,373
106,347
6,386
534,896

44,343
173,749
10,361
558,010

19,101
99,300
11,814
346,634

174,582
10,074
17,845
90,522
22,925
52,400
368,348
189,662

162,857
4,918
16,029
97,763
22,521
41,745
345,833
801

184,281
2,524
25,950
129,038
19,460
55,107
416,360
118,536

70,049
175,313
—
(6,165)
(49,535)
(8,057)
$ (41,478) $

61,463
(23,808)
(47,469)
2,978
7,637
(30,153)
37,790 $

59,569
59,887
—
188
(1,108)
(75,194)
74,086

(0.29) $
(0.29)

0.26 $
0.26

0.52
0.52

142,271
142,271

141,622
143,277

140,583
143,724

See accompanying notes.

W&T OFFSHORE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ DEFICIT
(In thousands)

Common Stock
Outstanding

Shares Value

Balances at December 31, 2018
Share-based compensation
Stock issued
RSUs surrendered for payroll taxes
Net income

Balances at December 31, 2019
Share-based compensation
Stock issued
RSUs surrendered for payroll taxes
Net income

Balances at December 31, 2020
Share-based compensation
Stock issued
RSUs surrendered for payroll taxes
Net income

Balances at December 31, 2021

140,644 $
—
1,025
—
—
141,669
—
636
—
—
142,305
—
558
—
—
142,863 $

Additional

Paid-In Retained

Capital Deficit
1 $ 545,705 $ (846,335)
—
3,690
—
—
—
(2,345)
74,086
—
(772,249)
547,050
—
3,959
—
—
—
(670)
37,790
—
(734,459)
550,339
—
3,364
—
—
—
(780)
(41,478)
—
1 $ 552,923 $ (775,937)

—
—
—
—
1
—
—
—
—
1
—
—
—
—

Treasury Stock
Shares Value

2,869 $ (24,167) $

Total
Shareholders’
Deficit
(324,796)
3,690
—
(2,345)
74,086
(249,365)
3,959
—
(670)
37,790
(208,286)
3,364
—
(780)
(41,478)
(247,180)

—
—
—
—
2,869
—
—
—
—
2,869
—
—
—
—

—
—
—
—
(24,167)
—
—
—
—
(24,167)
—
—
—
—

2,869 $ (24,167) $

See accompanying notes.

W&T OFFSHORE, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)

Operating activities:
Net (loss) income
Adjustments to reconcile net (loss) income to net cash provided by
operating activities:

Depreciation, depletion, amortization and accretion
Amortization of debt items and other items
Share-based compensation
Derivative loss (gain)
Derivative cash (payments) receipts, net
Derivative cash premium payments
Gain on debt transactions
Deferred income taxes

Changes in operating assets and liabilities:

Oil and natural gas receivables
Joint interest receivables
Prepaid expenses and other assets
Income tax
Asset retirement obligation settlements
Cash advances from JV partners
Accounts payable, accrued liabilities and other

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
Purchases of furniture, fixtures and other
Net cash used in investing activities

Financing activities:
Borrowings on credit facility
Repayments on credit facility
Purchase of Senior Second Lien Notes
Proceeds from Term Loan
Repayments on Term Loan
Debt issuance costs
Other

Net cash provided by (used in) financing activities

Increase in cash and cash equivalents
Cash and cash equivalents and restricted cash, beginning of period
Cash and cash equivalents and restricted cash, end of period

Year Ended December 31,
2020

2021

2019

(41,478) $

37,790 $

74,086

113,447
6,555
3,364
175,313
(81,298)
(40,484)
—
(8,189)

(16,089)
1,095
(5,103)
(20)
(27,309)
7,765
46,099
133,668

120,284
6,834
3,959
(23,808)
45,196
—
(47,469)
(30,287)

18,537
8,561
9,563
2,014
(3,339)
2,028
(41,354)
108,509

148,498
5,514
3,690
59,887
22,064
(8,123)
—
(64,102)

(9,563)
(4,766)
52,214
(9,346)
(11,443)
(15,347)
(11,036)
232,227

(32,062)

(17,632)

(137,816)

5,277
(661)
2
(27,444)

—
(80,000)
—
215,000
(24,142)
(9,810)
(782)
100,266
206,490
43,726

$ 250,216 $

(26,535)
(2,919)
(530)
(47,616)

12,110
(188,019)
(89)
(313,814)

25,000
(50,000)
(23,930)
—
—
—
(670)
(49,600)
11,293
32,433
43,726 $

150,000
(66,000)
—
—
—
(939)
(2,334)
80,727
(860)
33,293
32,433

See accompanying notes

1. Significant Accounting Policies

Operations

W&T Offshore, Inc. and subsidiaries, referred to herein as “W&T,” “we,” “us,” “our,” or the “Company”, is an
independent oil and natural gas producer with substantially all of its operations in the Gulf of Mexico. We are active in
the exploration, development and acquisition of oil and natural gas properties. Our interest in fields, leases, structures
and equipment are primarily owned by the parent company, W&T Offshore, Inc. (on a stand-alone basis, the “Parent
Company”) and our 100% owned subsidiaries, W & T Energy VI, LLC, Aquasition LLC, and Aquasition II, LLC, and
through our proportionately consolidated interest in Monza Energy, LLC (“Monza”), as described in more detail in
Note 4 – Mobile Bay Transaction.

Basis of Presentation

Our consolidated financial statements include the accounts of W&T Offshore, Inc. and its majority-owned
subsidiaries. Our interests in oil and gas joint ventures are proportionately consolidated. All significant intercompany
transactions and amounts have been eliminated for all years presented. Our consolidated financial statements have been
prepared in accordance with United States generally accepted accounting principles (“GAAP”) and the appropriate
rules and regulations of the Securities and Exchange Commission (“SEC”).

For presentation purposes, as of December 31, 2021, Derivative loss (gain) has been moved out of “Operating

income (loss)” on the Consolidated Statement of Operations. Such reclassification had no effect on our results of
operations, financial position or cash flows.

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. Actual results could differ from those estimates.

Accounting Standard Updates Effective January 1, 2021

Simplifying the Accounting for Income Taxes. In December 2019, the Financial Accounting Standards Board
("FASB") issued Accounting Standards Update ("ASU") No. 2019-12, Income Taxes (Topic 740): Simplifying the
Accounting for Income Taxes ("ASU 2019-12"). ASU 2019-12 simplifies the accounting for income taxes by removing
certain exceptions to the general principles in Topic 740 and by clarifying and amending existing guidance. ASU
2019-12 is effective for annual and interim financial statement periods beginning after December 15, 2020. Adoption of
the amendment did not have a material impact on our financial statements or disclosures.

Cash Equivalents

We consider 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

As of December 31, 2021, the Company cash collateralized each of the outstanding letters of credit in the aggregate

amount of approximately $4.4 million issued by certain commercial bank lenders under the Credit Agreement prior to
the Ninth Amendment. See Note 2 –Debt for additional information.

Revenue Recognition

We recognize revenue from the sale of crude oil, NGLs, and natural gas when our performance obligations are
satisfied. Our contracts with customers are primarily short-term (less than 12 months). Our responsibilities to deliver a
unit of crude oil, NGL, and natural gas under these contracts represent separate, distinct performance obligations. These
performance obligations are satisfied at the point in time control of each unit is transferred to the customer. Pricing is
primarily determined utilizing a particular pricing or market index, plus or minus adjustments reflecting quality or
location differentials.

We record oil and natural gas revenues based upon physical deliveries to our customers, which can be different from

our net revenue ownership interest in field production. These differences create imbalances that we recognize as a
liability only when the estimated remaining recoverable reserves of a property will not be sufficient to enable the under-
produced party to recoup its entitled share through production. We do not record receivables for those properties in
which we have taken less than our ownership share of production. At December 31, 2021 and 2020, $3.5 million and
$3.5 million, respectively, were included in current liabilities related to natural gas imbalances.

Concentration of Credit Risk

Our customers are primarily large integrated oil and natural gas companies and large commodity trading companies.

The majority of our production is sold utilizing month-to-month contracts that are based on bid prices. We attempt to
minimize our credit risk exposure to purchasers of our oil and natural gas, 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.

The following table identifies customers from whom we derived 10% or more of our receipts from sales of crude

oil, NGLs and natural gas:

Year Ended December 31,
2020

2019

2021

Customer

BP Products North America
Chevron - Texaco
Mercuria Energy America Inc.
Shell Trading (US) Co./ Shell Energy N.A.
Vitol Inc.
Williams Field Services

** Less than 10%

34 %
14 %
**
**
**
11 %

39 %
**
10 %
**
**
13 %

40 %
**
**
11 %
12 %
**

We believe that 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 replacement customers could be obtained in a relatively short period of
time on terms, conditions and pricing substantially similar to those currently existing.

Accounts Receivables and Allowance for Credit Losses

Our accounts receivables are recorded at their historical cost, less an allowance for credit losses. The carrying value

approximates fair value because of the short-term nature of such accounts. In addition to receivables from sales of our
production to our customers, we also have receivables from joint interest owners on properties we operate. In certain
arrangements, we have the ability to withhold future revenue disbursements to recover amounts due us from the joint
interest partners. A loss methodology is used to develop the allowance for credit losses on material receivables to
estimate the net amount to be collected. The loss methodology uses historical data, current market conditions and
forecasts of future economic conditions. 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

Prepaid expenses and other assets

2019

2021
9,123 $
2,192
(1,269)
$ 10,046 $

2020
9,898 $ 9,692
206
—
9,123 $ 9,898

417
(1,192)

Amounts recorded in Prepaid expenses and other assets on the Consolidated Balance Sheets are expected to be

realized within one year. The following table provides the primary components (in thousands):

Derivatives – current (1)
Unamortized insurance/bond premiums
Prepaid deposits related to royalties
Prepayment to vendors
Prepayments to joint interest partners
Debt issue costs
Other

Prepaid expenses and other assets

December 31,

2021
21,086 $

5,400
8,441
4,522
2,808
1,065
57
43,379 $

2020
2,752
4,717
4,473
1,429
402
—
59
13,832

(1)

Includes both open and closed contracts that have not yet settled and prepaid premiums paid for purchased put
and call options.

Oil and Natural Gas Properties and Other, Net

We use the full-cost method of accounting for oil and natural gas properties and equipment, which are recorded at

cost. 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 (“ARO”), 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
include costs of unproved properties. The cost of unproved properties related to significant acquisitions are excluded
from the amortization base until it is determined that proved reserves can be assigned to such properties or until such
time as we have made an evaluation that impairment has occurred. As of December 31, 2021 and 2020, there were no
unproved properties included in the Oil and natural gas properties and other, net balance. 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 five 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.

The following table provides the components of Oil and natural gas properties and other, net (in thousands):

December 31,

2021

2020

Oil and natural gas properties and equipment
Furniture, fixtures and other

Total property and equipment

Less: Accumulated depreciation, depletion, amortization and impairment

Oil and natural gas properties and other, net

Ceiling Test Write-Down

$ 8,636,408 $ 8,567,509
20,847
8,588,356
7,901,478
665,252 $ 686,878

20,844
8,657,252
7,992,000

Under the full-cost method of accounting, we are required to perform a “ceiling test” calculation quarterly, which
determines a limit on the book value of our 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.

We did not record a ceiling test write-down during 2021, 2020 or 2019. If average crude oil and natural gas prices

decrease below average pricing during 2021, we may incur ceiling test write-downs during 2022 or in future periods.

Asset Retirement Obligations

We are required to record a separate liability for the present value of our ARO, with an offsetting increase to the
related oil and natural gas properties on our balance sheet. We have significant obligations to plug and abandon well
bores, remove our platforms, pipelines, facilities and equipment and restore the land or seabed at the end of oil and
natural gas production operations. These obligations are primarily associated with plugging and abandoning wells,
removing pipelines, removing and disposing of offshore platforms and site cleanup. Estimating such costs requires us to
make judgments on both the costs and the timing of ARO. Asset removal technologies and costs are constantly
changing, as are regulatory, political, environmental, safety and public relations considerations, which can substantially
affect our estimates of these future costs from period to period. See Note 7 – Asset Retirement Obligations for additional
information.

Oil and Natural Gas Reserve Information

We use the unweighted average of first-day-of-the-month commodity prices over the preceding 12-month period

when estimating quantities of proved reserves. Similarly, the prices used to calculate the standardized measure of
discounted future cash flows and prices used in the ceiling test for impairment are the 12-month average commodity
prices. 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 19 –
Supplemental Oil and Gas Disclosures for additional information about our proved reserves.

Derivative Financial Instruments

We have exposure related to commodity prices and have used various derivative instruments to manage our
exposure to commodity price risk from sales of oil and natural gas. We do not enter into derivative instruments for
speculative trading purposes. We entered into commodity derivatives contracts during 2021, 2020 and 2019, and as of
December 31, 2021, we had open commodity derivative instruments. When we have outstanding borrowings on our
revolving bank credit facility, we may use various derivative financial instruments to manage our exposure to interest
rate risk from floating interest rates. During 2021, 2020 and 2019, we did not enter into any derivative instruments
related to interest rates.

Derivative instruments are recorded on the balance sheet as an asset or a liability at fair value. We have elected not

to designate our derivatives instruments as hedging instruments, therefore, all changes in fair value are recognized in
earnings. See Note 10 – Derivative Financial Instruments for additional information about our derivative financial
instruments.

Fair Value of Financial Instruments

We include fair value information in the notes to our consolidated financial statements when the fair value of our

financial instruments is different from the book value or it is required by applicable guidance. We believe that the book
value of our cash and cash equivalents, receivables, accounts payable and accrued liabilities materially approximates fair
value due to the short-term nature and the terms of these instruments. We believe that the book value of our restricted
deposits approximates fair value as deposits are in cash or short-term investments.

Income Taxes

We use the liability method of accounting for income taxes in accordance with the Income Taxes topic of the
Accounting Standard Codification. Under this method, deferred tax assets and liabilities are 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. In assessing the need for a
valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of
them will not be realized. We recognize uncertain tax positions in our financial statements when it is more likely than
not that we will sustain the benefit taken or expected to be taken. We classify interest and penalties related to uncertain
tax positions in income tax expense. See Note 13 – Income Taxes for additional information.

Other Assets (long-term)

The major categories recorded in Other assets are presented in the following table (in thousands):

Right-of-Use assets (Note 8)
Unamortized debt issuance costs
Investment in White Cap, LLC
Unamortized brokerage fee for Monza
Proportional consolidation of Monza's other assets (Note 5)
Derivatives (1)
Other

Total other assets (long-term)

December 31,

2021
10,602 $
—
2,533
—
2,511
34,435
1,091

51,172 $

2020
11,509
2,094
2,699
626
1,782
2,762
998
22,470

(1)

Includes open contracts and prepaid premiums paid for purchased put and call options

Accrued Liabilities

The major categories recorded in Accrued liabilities are presented in the following table (in thousands):

Accrued interest
Accrued salaries/payroll taxes/benefits
Litigation accruals
Lease liability
Derivatives (1)
Other

Total accrued liabilities

(1)

Includes both open and closed contracts.

Paycheck Protection Program (“PPP”)

December 31,

2021
10,154 $
9,617
646
1,115
81,456
3,152
106,140 $

2020
10,389
4,009
436
394
13,620
1,032
29,880

On April 15, 2020, the Company received $8.4 million under the U.S. Small Business Administration (“SBA”) PPP.

As there is no definitive guidance under U.S. GAAP, we have applied the guidance under IAS 20 and accounted for the
PPP as a government grant. Under IAS 20, a government grant is recognized when there is reasonable assurance that the
Company has complied with the provisions of the grant.

The Company submitted an application to the SBA on August 20, 2020, requesting that the PPP funds received be

applied to specific covered and non-covered payroll costs. On June 11, 2021, we received notification that the SBA
accepted our application and approved full forgiveness of our PPP.

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. Debt issuance costs associated with all other debt are deferred and amortized over the
scheduled maturity of the debt utilizing the effective interest method. Unamortized debt issuance costs associated with
our Credit Agreement is reported within Prepaid expenses and other assets and unamortized debt issuance costs
associated with our other debt instruments are reported as a reduction in Long-term debt, net in the Consolidated Balance
Sheets. See Note 2 –Debt for additional information.

Gain on Debt Transactions

During 2020, we acquired $72.5 million in principal of our outstanding Senior Second Lien Notes for $23.9 million
and recorded a non-cash gain on purchase of debt of $47.5 million. During 2018, the refinancing of our capital structure
resulted in a gain of $47.1 million as a result of writing off the carrying value adjustments related to the debt issued in
2016, partially offset by premiums paid to repurchase and retire, repay or redeem all of our prior debt instruments. See
Note 2 – Debt for additional information.

Other Liabilities (long-term)

The major categories recorded in Other liabilities are presented in the following table (in thousands):

Dispute related to royalty deductions
Derivatives
Lease liability (Note 8)
Black Elk escrow
Other

Total other liabilities (long-term)

Share-Based Compensation

December 31,

2021
5,177 $
37,989
11,227
—
996
55,389 $

2020
5,467
4,384
11,360
11,103
624
32,938

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. We
recognize share-based compensation expense on a straight line basis 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 estimated to vest and estimated
forfeitures are adjusted to actual forfeitures when the equity instrument vests. See Note 11 – Share-Based Awards and
Cash-Based Awards for additional information.

Employee Retention Credit.

Under the Consolidated Appropriations Act, 2021 passed by the United States Congress and signed by the President

on December 27, 2020, provisions of the Coronavirus Aid, Relief and Economic Security Act (“CARES Act”) were
extended and modified making the Company eligible for a refundable employee retention credit subject to meeting
certain criteria. The Company recognized a $2.1 million employee retention credit during the year ended
December 31, 2021 which is included as a credit to General and administrative expenses in the Consolidated Statement
of Operations.

Other Expense (Income), Net

For 2021, the amount primarily consists of other 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. For 2020, the amount primarily consists of expenses related to the amortization of the
brokerage fee paid in connection with the Joint Venture Drilling Program See Note 9 – Restricted Deposits for ARO for
additional information regarding the release of the Black Elk Escrow restrictions. For 2019, the amount consists
primarily of federal royalty obligation reductions claimed in the current year related to capital deductions from prior
periods, and partially offset by expenses related to the amortization of the brokerage fee paid in connection with the Joint
Venture Drilling Program.

Earnings Per Share

Unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents
(whether paid or unpaid) are participating securities and are included in the computation of earnings per share under the
two-class method when the effect is dilutive. See Note 14 – Earnings Per Share for additional information.

2. Debt

The components of our debt are presented in the following tables (in thousands):

Term Loan:
Principal
Unamortized debt issuance costs

Total Term Loan

Credit Agreement borrowings:

Senior Second Lien Notes:

Principal
Unamortized debt issuance costs
Total Senior Second Lien Notes

Less current portion

Total long-term debt, net

December 31,

2021

2020

190,859 $
(7,545)
183,314

—
—
—

—

80,000

552,460
(4,876)
547,584

552,460
(7,174)
545,286

(42,960)
687,938 $

—
625,286

Aggregate annual maturities of amounts recorded as of December 31, 2021 are as follows (in millions):

2022
2023
2024
2025
2026
Thereafter
Total

43.0
586.2
30.1
27.6
25.4
31.0
743.3

Current portion of Long-Term Debt

As of December 31, 2021, the current portion of long-term debt of $43.0 represented principal payments due within

one year of the Term Loan (defined below).

Term Loan (Subsidiary Credit Agreement)

On May 19, 2021, Aquasition LLC and Aquasition II LLC, both Delaware limited liability companies and indirect,
wholly-owned subsidiaries of W&T Offshore, Inc., entered into a credit agreement (the “Subsidiary Credit Agreement”)
providing for a term loan in an aggregate principal amount equal to $215.0 million (the “Term Loan”). The Term Loan
requires quarterly amortization payments commencing September 30, 2021. The Term Loan bears interest at a fixed rate
of 7% per annum and will mature on May 19, 2028. The Term Loan is non-recourse to the Company and any
subsidiaries other than the Subsidiary Borrowers and the subsidiary that owns the equity in the Subsidiary Borrowers,
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).

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 crude oil treating and sweetening facility, an
onshore gathering pipeline, and associated assets (such assets, the “Midstream Assets”). A portion of the proceeds to the
Company was used to repay the $48.0 million outstanding balance on its reserve-based lending facility under the Credit
Agreement (defined below), with the majority of the proceeds to W&T expected to be used for general corporate
purposes, including oil and gas acquisitions, development activities, and other opportunities to grow the Company’s
broader asset base. We refer to the transactions contemplated by the Subsidiary Credit Agreement, including the
assignment of the Mobile Bay Properties to A-I LLC and the assignment of the Midstream Assets to A-II LLC as the
“Mobile Bay Transaction”.

For information about Mobile Bay Transaction refer to Note 4 – Mobile Bay Transaction.

9.75% Senior Second Lien Notes Due 2023

On October 18, 2018, we issued $625.0 million of 9.75% Senior Second Lien Notes due 2023 (the “Senior Second

Lien Notes”), which were issued at par with an interest rate of 9.75% per annum that matures on November 1, 2023, and
are governed under the terms of the Indenture of the Senior Second Lien Notes (the “Indenture”), entered into by and
among the Company, the Guarantors, and Wilmington Trust, National Association, as trustee (the “Trustee”). The
estimated annual effective interest rate on the Senior Second Lien Notes was 10.3%, which includes debt issuance costs.
Interest on the Senior Second Lien Notes is payable in arrears on May 1 and November 1 of each year.

During the year ended December 31, 2020, we acquired $72.5 million in principal of our outstanding Senior Second

Lien Notes for $23.9 million and recorded a non-cash gain on purchase of debt of $47.5 million, which included a
reduction of $1.1 million related to the write-off of unamortized debt issuance costs.

As of November 1, 2020, we may redeem the Senior Second Lien Notes, in whole or in part, at redemption prices

(expressed as percentages of the principal amount thereof) equal to 104.875% for the 12-month period beginning
November 1, 2020, 102.438% for the 12-month period beginning November 1, 2021, and 100.0% on November 1, 2022
and thereafter, plus accrued and unpaid interest, if any, to the redemption date. The Senior Second Lien Notes are
guaranteed by W&T Energy VI and W & T Energy VII, LLC (together, the “Guarantor Subsidiaries”). If we experience
certain change of control events, we will be required to offer to repurchase the notes at 101.0% of the principal amount,
plus accrued and unpaid interest, if any, to the repurchase date.

The Senior Second Lien Notes are secured by a second-priority lien on all of our assets that are secured under the

Sixth Amended and Restated Credit Agreement (as amended, the “Credit Agreement”). The Senior Second Lien
Notes contain covenants that limit or prohibit our ability and the ability of certain of our 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 restricted 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 unrestricted subsidiaries that would not be restricted by the covenants of the Indenture.
These covenants are subject to 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 Senior Second Lien Notes an investment grade rating and no default exists with respect to the
Senior Second Lien Notes.

Credit Agreement

On November 2, 2021, the Company entered into the Eighth Amendment to the Credit Agreement (the “Eighth

Amendment”) which effectively terminated the Company’s reserve based lending relationship with commercial bank
lenders who have traditionally provided its secured revolving credit facility. The Company has not had any borrowings
under the Credit Agreement since the closing of the Mobile Bay Transaction in May 2021. As of November 2, 2021, the
Company has cash collateralized each of the outstanding letters of credit in the aggregate amount of approximately $4.4
million. Alter Domus (US) LLC was appointed to replace Toronto Dominion (Texas) LLC as administrative agent under
the Credit Agreement.

On November 2, 2021, the Company also entered into the Ninth Amendment to the Credit Agreement (the “Ninth

Amendment”), which establishes a short-term $100.0 million first priority lien secured revolving facility with
borrowings limited to a borrowing base of $50.0 million (the “Calculus Lending facility”) provided by Calculus
Lending, LLC, (“Calculus”) a company affiliated with, and controlled by W&T’s Chairman and Chief Executive
Officer, Tracy W. Krohn, as sole lender under the Calculus Lending facility. A committee of the independent members
of the Board of Directors reviewed and approved the amendments given the CEO’s affiliation with Calculus Lending,
LLC. As a result of the Eighth Amendment and Ninth Amendment and related assignments and agreements, the key
terms and covenants associated with the Calculus Lending facility under the Credit Agreement as of December 31, 2021
are as follows:

• The revised borrowing base is $50.0 million.

• The Calculus Lending facility commitment will expire and final maturity of any and all outstanding loans is

April 30, 2022. Outstanding borrowings will accrue interest at LIBOR plus 6.0% per annum. The commitment
fee for the unused portion of available borrowing amounts will be 3.0% per annum.

• The Company’s ratio of first lien debt outstanding under the Calculus Lending facility 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 on the last day of the fiscal quarter ending March 31, 2022 and on the last
day of each fiscal quarter thereafter.

• 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 commencing with the fiscal quarter ending March 31, 2022
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 Company and its
restricted subsidiaries’ 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 commencing with the fiscal quarter ending March 31, 2022, the

Company and its restricted subsidiaries on a consolidated basis must pass a “Stress Test” consisting of an
analysis conducted by the lender in good faith and in consultation with the Company based upon the latest
engineering report furnished to lender, which analysis is designed to determine whether the future net revenues
expected to accrue to the Company’s and its guarantor subsidiaries’ interest (and the interest of certain joint
ventures) in the oil and gas properties included in the properties used to determine the latest borrowing base
during half of the remaining expected economic lives of such properties are sufficient to satisfy the aggregate
first lien indebtedness of the Company and its restricted subsidiaries in accordance with the terms of such
indebtedness assuming the Calculus Lending facility is 100% funded or fully utilized.

• 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.

As consideration for its commitment as sole lender and consistent with customary non-commercial bank lending

practice, Calculus was paid certain market-based fees in connection with its commitment.

Availability under the Credit Agreement is subject to redetermination of our borrowing base that may be requested

at the discretion of either the lender or the Company. The borrowing base is calculated by our lender based on their
evaluation of our proved reserves and their own internal criteria. Any redetermination by our lender to change our
borrowing base will result in a similar change in the availability under the Credit Agreement. The Credit Agreement is
secured by a first priority lien on substantially all of our oil and natural gas properties and personal property, excluding
those assets of the Subsidiary Borrowers, which liens were released in the Mobile Bay Transaction (as described in
Note 4 – Mobile Bay Transaction). Subsequent to December 31, 2021, the Company entered into the Tenth Amendment
to Sixth Amended and Restated Credit Agreement and Extension Agreement, which extended the maturity date and
Lender commitment to January 3, 2023 (see Note 20 – Subsequent Events for additional information).

Borrowings outstanding under the Credit Agreement are reported in the table above. The estimated annual effective
interest rate on borrowings, exclusive of debt issuance costs, commitment fees and other fees was 3.2%. Separately, as of
December 31, 2021 and 2020, we had $4.4 million, outstanding in letters of credit which have been cash collateralized as
of December 31, 2021.

As of December 31, 2021 and for all presented measurement periods, we were in compliance with all applicable

covenants of the Credit Agreement and Senior Second Lien Notes.

For information about fair value measurements of our long term debt, refer to Note 3 – Fair Value Measurements.

3. Fair Value Measurements

Under GAAP, fair value is defined as the price that would be received to sell an asset or paid 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 our expectations about the assumptions that market participants

would use in measuring the fair value of an asset or liability.

Derivative Financial Instruments

As of December 31, 2021 and 2020, the carrying value of our open derivative contracts equaled the estimated fair
value. We measure the fair value of our open 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 our open 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. Our
open derivative financial instruments are reported in the Consolidated Balance Sheets using fair value. See Note 10 –
Derivative Financial Instruments, for additional information on our derivative financial instruments.

The following table presents the fair value of our open derivative financial instruments (in thousands):

Assets:
Derivative instruments - open contracts, current
Derivative instruments - open contracts, long-term

Liabilities:
Derivative instruments - open contracts, current
Derivative instruments - open contracts, long-term

Debt

December 31,

2021

2020

19,215 $
34,435

2,705
2,762

73,190
37,989

13,291
4,384

The fair value of the Term Loan was measured using a discounted cash flows model and current market rates. The

net value of our debt under the Credit Agreement approximates fair value because the interest rates are variable and
reflective of current market rates. The fair value of our Senior Second Lien Notes was measured using quoted prices,
although the market is not a highly liquid market. The fair value of our debt was classified as Level 2 within the
valuation hierarchy. See Note 2 – Debt for additional information on our debt.

The following table presents the net value and fair value of our long-term debt (in thousands):

December 31, 2021

December 31, 2020

Net Value Fair Value Net Value Fair Value

Liabilities:
Term Loan
Credit Agreement
Senior Second Lien Notes

Total

$ 183,314 $ 190,579 $

— $

—
547,584
730,898

—
527,715
718,294

80,000
545,286
625,286

—
80,000
393,352
473,352

4. Mobile Bay Transaction

On May 19, 2021, the Company’s wholly-owned special purpose vehicles, A-I LLC and A-II LLC or the Subsidiary
Borrowers, entered into the Subsidiary Credit Agreement providing for the Term Loan in an aggregate principal amount
equal to $215.0 million. Proceeds of the Term Loan were used by the Borrowers to (i) fund the acquisition of the Mobile
Bay Properties and the Midstream Assets from the Company and (ii) pay fees, commissions and expenses in connection
with the transactions contemplated by the Subsidiary Credit Agreement and the other related loan documents, including
to enter into certain swap and put derivative contracts described in more detail under Note 10 – Derivative Financial
Instruments, of this Annual Report.

As part of the Mobile Bay 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 i) the Mobile Bay Properties and ii) the Midstream Assets and (b) certain corporate, general
and administrative services for A-I LLC and A-II LLC (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 will not be available to satisfy the debt or contractual obligations of any entities other than the Subsidiary
Borrowers, including debt securities or other contractual obligations of W&T Offshore, Inc., and the Subsidiary
Borrowers do not bear any liability for the indebtedness or other contractual obligations of any entity other than the
Subsidiary Borrowers, and vice versa.

As of December 31, 2021, in the Consolidated Balance Sheet, we recorded $38.9 million in Cash and cash
equivalents, $272.7 million, in Oil and natural gas properties and other, net, $43.0 million in Current portion of long-
term debt, $54.5 million in Asset retirement obligations, and $140.4 million in Long-term debt, net related to the
consolidation of the Subsidiary Borrowers and the subsidiary that owns the equity of the Subsidiary Borrowers. For
2021, in the Consolidated Statement of Operations, we recorded $119.6 million in Total revenues, $32.7 million in
Operating costs and expenses, $104.5 million in Derivative loss, and $9.8 million in Interest expense, net related to the
consolidation of the operations of the Subsidiary Borrowers and the subsidiary that owns the equity of the Subsidiary
Borrowers.

5. Joint Venture Drilling Program

In March 2018, W&T and two other initial members formed and initially funded Monza, which jointly participates

with us in the exploration, drilling and development of certain drilling projects (the “Joint Venture Drilling Program”) in
the Gulf of Mexico. Subsequent to the initial closing, additional investors joined as members of Monza during 2018 and
total commitments by all members, including W&T’s commitment outside of Monza, were $361.4 million. W&T
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 we initially receive an aggregate
of 30.0% of the revenues less expenses, through both our direct ownership of our working interest in the projects and our
indirect interest through our 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. W&T is the operator for seven of the nine wells completed through December 31, 2021.

The members of Monza are made up of third-party investors, W&T and an entity owned and controlled by

Mr. Tracy W. Krohn, our Chairman and Chief Executive Officer. The Krohn entity invested as a minority investor on the
same terms and conditions as the third-party investors, and its investment is limited to 4.5% of total invested capital
within Monza. The entity affiliated with Mr. Krohn has made a capital commitment to Monza of $14.5 million.

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.

Through December 31, 2021, nine wells have been completed of which five were producing as of
December 31, 2021. W&T is the operator for seven of the nine wells completed through December 31, 2021.

Through December 31, 2021, members of Monza made partner capital contributions, including our contributions of

working interest in the drilling projects, to Monza totaling $302.4 million and received cash distributions totaling
$90.1 million. Our net contribution to Monza, reduced by distributions received, as of December 31, 2021 was
$49.0 million. W&T is obligated to fund certain cost overruns to the extent they occur, subject to certain exceptions, for
the Joint Venture Drilling Program wells above budgeted and contingency amounts, of which the total exposure cannot
be estimated at this time.

Consolidation and Carrying Amounts

Our interest in Monza is considered to be a variable interest that we account for using proportional consolidation.
Through December 31, 2021, there have been no events or changes that would cause a redetermination of the variable
interest status. We do not fully consolidate Monza because we are not considered the primary beneficiary. As of
December 31, 2021, in the Consolidated Balance Sheet, we recorded $3.5 million, net, in Oil and natural gas properties
and other, net, $2.5 million in Other assets, $0.3 million in ARO and $4.6 million, net, increase in working capital in
connection with our proportional interest in Monza’s assets and liabilities. As of December 31, 2020, in the Consolidated
Balance Sheet, we recorded $9.9 million, net, in Oil and natural gas properties and other, net, $1.8 million in Other
assets, $0.2 million in ARO and $1.3 million, net, increase in working capital in connection with our proportional
interest in Monza’s assets and liabilities. Additionally, during 2021 and 2020, we called on Monza to provide cash to
fund its portion of certain Joint Venture Drilling Program projects in advance of capital expenditure spending, and the
unused balances as of December 31, 2021 and 2020 were $14.8 million and $7.3 million, respectively, which
are included in the Consolidated Balance Sheet in Advances from joint interest partners. For 2021, in the Consolidated
Statement of Operations, we recorded $12.7 million in Total revenues, $10.0 million in Operating costs and expenses,
and $2.1 million in Derivative loss in connection with our proportional interest in Monza’s operations. For 2020, in the
Consolidated Statement of Operations, we recorded $8.4 million in Total revenues, $11.4 million in Operating costs and
expenses, and $0.8 million in Derivative loss in connection with our proportional interest in Monza’s operations.

6. Acquisitions and Divestitures

Mobile Bay Properties

In August 2019, we completed the purchase of Exxon Mobil Corporation's ('Exxon') interests in and operatorship of

oil and gas producing properties in the eastern region of the Gulf of Mexico offshore Alabama and related onshore and
offshore facilities and pipelines, (the 'Mobile Bay Properties'). After taking into account customary closing adjustments
and an effective date of January 1, 2019, cash consideration paid by us was $169.8 million which includes expenses
related to the acquisition. We also assumed the related ARO and certain other obligations associated with these assets.
The acquisition was funded from cash on hand and borrowings of $150.0 million under the Credit Agreement, which
were previously undrawn. We determined that the assets acquired did not meet the definition of a business; therefore, the
transaction was accounted for as an asset acquisition. The following table presents the purchase price allocation (in
thousands):

Oil and natural gas properties and other, net - at cost:
Other assets

Current liabilities
Asset retirement obligations
Other liabilities

2019

$ 192,373
4,838

1,559
21,684
4,132

During 2020, we completed the purchase of the remaining interest in two federal Mobile Bay fields from Chevron

U.S.A. Inc. ('Chevron'). After taking into account customary closing adjustments and an effective date of January 1,
2020, cash consideration paid by us was $2.2 million which includes expenses related to the acquisition.

Magnolia Field

In December 2019, we completed the purchase of ConocoPhillips Company's ('Conoco') interests in and

operatorship of oil and gas producing properties at Garden Banks blocks 783 and 784 (the 'Magnolia Field'). After taking
into account customary closing adjustments and an effective date of October 1, 2019, cash consideration was $15.9
million which includes cash expenses related to the acquisition. We also assumed the related ARO. The acquisition was
funded from cash on hand. We determined that the assets acquired did not meet the definition of a business; therefore,
the transaction was accounted for as an asset acquisition. The following table presents the purchase price allocation (in
thousands):

Oil and natural gas properties and other, net - at cost:

Asset retirement obligations

2019
23,791

7,842

During 2020, we completed the purchase of the remaining interest in the Magnolia field from Marubeni Oil & Gas
(USA) ('Marubeni'). After taking into account customary closing adjustments and an effective date of October 1, 2019,
cash consideration paid by us was $1.5 million which includes expenses related to the acquisition.

7. Asset Retirement Obligations

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,
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 our 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 table is a reconciliation of our ARO (in thousands):

Asset retirement obligations, beginning of period
Liabilities settled
Accretion of discount
Liabilities incurred and assumed through acquisition
Revisions of estimated liabilities (1)
Asset retirement obligations, end of period
Less current portion

Long-term

Year Ended December 31,

2021

2020

$ 392,704 $ 355,594
(3,339)
22,521
4,860
13,068
392,704
(17,188)
$ 368,076 $ 375,516

(27,309)
22,925
454
35,721
424,495
(56,419)

(1) Revisions in 2021 and 2020 were due to changes in scope, weather impact, revisions to actual expenses versus

estimates and revisions related to non-operated properties.

8. Leases

Our lease contracts consist of office leases, 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 our assumptions of the term, inflation
rates 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. All of these lease contracts
are operating leases.

During 2020, we terminated the existing office lease and executed a new lease on separate office space. The term of

the previous office lease ended in December 2020. The term of the new office lease extends to February 2032 and
has the option to renew for up to another 10 years. During 2019, various pipeline rights-of-way contracts and a land
lease were acquired, assumed, renewed or otherwise entered into, primarily in conjunction with acquiring the Mobile
Bay Properties. The term of each pipeline right-of-way contract is 10 years with various effective dates, and each has an
option to renew for up to another ten years. It is expected renewals beyond 10 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. We recorded
ROU assets and lease liabilities using a discount rate of 9.75% for the office lease and 10.75% for the other leases due to
their longer expected term.

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. The Company’s share of these costs is included in
property and equipment, lease operating expense or general and administrative expense, as applicable. The components
of lease costs were as follows (in thousands):

Operating lease cost, excluding short-term leases
Short-term lease cost (1)

Total lease cost

December 31,

2021
1,743 $
5,926
7,669 $

2020
3,060
1,633
4,693

(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 were recorded within Oil and natural gas properties and other, net, on the
Consolidated Balance Sheet.

The present value of the fixed lease payments recorded as the Company’s right-of-use asset and liability, adjusted

for initial direct costs and incentives are as follows (in thousands):

ROU assets

Lease liability:
Accrued liabilities
Other liabilities

Total lease liability

December 31,

2021

2020

$ 10,602 $ 11,509

1,115 $

394
11,360
$ 12,342 $ 11,754

11,227

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:

December 31,

2021
14.1 years

2020
14.8 years

10.1 %

10.2 %

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

December 31,

2021

425 $

2020
1,825

— $

5,142

Undiscounted future minimum payments as of December 31, 2021 are as follows (in thousands):

2022
2023
2024
2025
2026
Thereafter

Total lease payments
Present value adjustment

Total

9. Restricted Deposits for ARO

1,134
1,625
2,023
1,512
1,542
15,919
23,755
(11,413)
12,342

Restricted deposits as of December 31, 2021 and 2020 consisted of funds escrowed for collateral related to the

future plugging and abandonment obligations of certain oil and natural gas properties.

Pursuant to the Purchase and Sale Agreement with Total E&P USA Inc. (“Total E&P”), security for future plugging

and abandonment of certain oil and natural gas properties is required either through surety bonds or payments to an
escrow account or a combination thereof. Monthly payments are made to an escrow account and these funds are returned
to us once verification is made that the security amount requirements have been met. See Note 16 - Commitments for
potential future security requirements.

During the year ended December 31, 2020, W&T received $13.9 million of cash as a restricted deposit to be used
exclusively for payment of certain asset retirement obligations related to properties sold by W&T to Black Elk Energy
Offshore Operations, LLC (“Black Elk”) in October 2009 in connection with the liquidation of Black Elk under
Chapter 11 of the U.S. Bankruptcy Code. The cash was retained in an escrow account and recorded within Restricted
Deposits for asset retirement obligations on the Consolidated Balance Sheet as of December 31, 2020. As of
December 31, 2020, $11.1 million was recorded in Other liabilities as our estimate of the additional asset retirement
obligations to be funded from the restricted deposit account. On December 29, 2021, the United States Bankruptcy Court
for the Southern District of Texas sent the Company notice that we are able to retain the remaining funds and that those
funds were no longer subject to any restrictions, effectively releasing the cash from escrow. Accordingly, we removed
the remaining liability of $11.1 million and transferred the related cash previously retained in escrow to cash. We
recorded the $11.1 million in Other (income) expense during the year ended December 31, 2021.

10. Derivative Financial Instruments

During 2021, 2020 and 2019, we entered into commodity contracts for crude oil and natural gas which related to a
portion of our expected production for the time frames covered by the contracts. The crude oil contracts were based on
West Texas Intermediate (“WTI”) crude oil prices as quoted off the New York Mercantile Exchange (“NYMEX”). The
natural gas contracts are based on Henry Hub natural gas prices as quoted off the NYMEX. The open contracts as of
December 31, 2021 are presented in the following tables:

Period
Crude Oil - WTI (NYMEX)

Jan 2022 - Nov 2022
Jan 2022 - Nov 2022

Average
Daily

Total

Instrument
Type

Volumes

(Bbls)(1)
2,525
2,428

Volumes
(Bbls)(1)
843,256 $
811,096 $

swaps
collars

Weighted
Strike Price

($/Bbls)(1)

Weighted
Put Price
($/Bbls)(1)

Weighted
Call Price

49.99 $
$
—

— $
$

41.71

($/Bbls)(1)
—
58.91

Natural Gas - Henry Hub (NYMEX)

($/MMbtu)(2)

Jan 2022 - Dec 2022
Jan 2023 - Dec 2023
Jan 2024 - Dec 2024
Jan 2025 - Mar 2025
Jan 2022 - Dec 2022
Jan 2022 - Nov 2022
Jan 2022 - Dec 2022 (3)
Jan 2023 - Dec 2023 (3)
Jan 2024 - Dec 2024 (3)
Jan 2025 - Mar 2025 (3)
Apr 2025 - Dec 2025 (3)
Jan 2026 - Dec 2026 (3)
Jan 2027 - Dec 2027 (3)
Jan 2028 - Apr 2028 (3)

(MMbtu)(2)
116,853
70,000
65,000
62,000
47,370
17,160
78,904
72,329
65,574
63,333
62,182
55,890
52,603
49,587

calls
calls
calls
calls
collars
swaps
swaps
swaps
swaps
swaps
puts
puts
puts
puts

(MMbtu)(2)
42,651,402 $
25,550,000 $
23,790,000 $
5,580,000 $
17,290,000 $
5,731,485 $
28,800,000 $
26,400,000 $
24,000,000 $
5,700,000 $
17,100,000 $
20,400,000 $
19,200,000 $
6,000,000 $

— $
— $
— $
— $
— $
2.60 $
2.69 $
2.48 $
2.46 $
2.72 $
— $
— $
— $
— $

($/MMbtu)(2)
3.93
3.50
3.50
3.50
3.17
—
—
—
—
—
—
—
—
—

— $
— $
— $
— $
1.89 $
— $
— $
— $
— $
— $
2.27 $
2.35 $
2.37 $
2.50 $

(1) Bbls – Barrels
(2) MMbtu – Million British Thermal Units
(3) These contracts were entered into by the Company’s wholly owned subsidiary, A-I LLC, in conjunction with

the Mobile Bay Transaction (see Note 4 – Mobile Bay Transaction).

The following amounts were recorded in the Consolidated Balance Sheets in the categories presented and include

the fair value of open contracts as well as closed contracts that had not yet settled (in thousands):

Prepaid expenses and other current assets
Other assets (long-term)
Accrued liabilities
Other liabilities (long-term)

December 31,

2021
$ 21,086 $
34,435
81,456
37,989

2020
2,752
2,762
13,620
4,384

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 loss (gain). The impact of our commodity derivative contracts has on the Consolidated Statements of
Operations were as follows (in thousands):

Year Ended December 31,
2020

2021

2019

Realized loss (gain)
Unrealized loss (gain)
Derivative loss (gain)

$ 95,187 $ (33,415) $

80,126
175,313

9,607
(23,808)

884
59,003
59,887

Cash payments on commodity derivative contract settlements, net, are included within Net cash provided by

operating activities on the Consolidated Statements of Cash Flows and were as follows (in thousands):

Year Ended December 31,
2020

2021

2019

Derivative loss (gain)
Derivative cash (payments) receipts, net
Derivative cash premium payments

11. Share-Based Awards and Cash-Based Awards

Incentive Compensation Plan

$ 175,313 $ (23,808) $ 59,887
22,064
(8,123)

(81,298)
(40,484)

45,196
—

The W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan, and subsequent amendments, (the

“Plan”) was approved by our shareholders. The Plan covers the Company’s eligible employees and consultants and
includes both cash and share-based compensation awards. The 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”).

Pursuant to the terms of the 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 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, 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 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.

Restricted Stock Units

During 2021 and 2019, the Company granted RSUs under the Plan to certain of its employees. There were no RSUs

granted in 2020. RSUs are a long-term compensation component, granted to certain employees.

As of December 31, 2021, there were 9,852,351 shares of common stock available for issuance in satisfaction of
awards under the Plan. The shares available for issuance are reduced on a one-for-one basis when RSUs are settled in
shares of common stock, net of withholding tax through the withholding of shares. The Company has the option
following vesting to settle RSUs in stock or cash, or a combination of stock and cash. During 2021, 2020 and 2019, only
shares of common stock were used to settle all vested RSUs. The Company expects to settle RSUs that vest in the future
using shares of common stock.

RSUs currently outstanding relate to the 2021 grants. The 2021 RSUs granted are a long-term compensation
component, subject to service conditions, with one-third of the award vesting each year on January 1, 2022, 2023, and
2024, respectively. The 2019 grants were subject to predetermined performance criteria applied against the applicable
performance period and were also subject the satisfaction of the service conditions. Vesting of the outstanding 2019
RSUs occurred in December 2021. See the table below for anticipated vesting by year of outstanding RSU grants.

We recognize compensation cost for share-based payments to employees 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. The fair values for the RSUs granted during 2021 and 2019 were determined using the
Company’s closing price on the grant date. We are also required to estimate forfeitures, resulting in the recognition of
compensation cost only for those awards that are expected to actually vest. 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:

2021

Weighted
Average

2020

Weighted
Average

2019

Weighted
Average

Nonvested, beginning of period
Granted
Vested
Forfeited
Nonvested, end of period

Restricted Grant Date Fair Restricted Grant Date Fair
Stock Units Value Per Unit
Stock Units Value Per Unit
5.73
4.51
1,614,722 $
4.71
—
4.51
4.50
4.71

763,688 $
710,441
(731,095)
(44,569)
698,465 $

—
(787,203)
(63,831)
763,688 $

Grant Date Fair
Restricted
Stock Units Value Per Unit
3.90
3,355,917 $
4.51
994,698
2.76
6.90 (1,475,373)
3.37
5.80 (1,260,520)
5.73
4.51

1,614,722 $

RSUs fair value at grant date - During 2021 and 2019, the grant date fair value of RSUs granted was $3.3 million

and $4.5 million, respectively. There were no RSUs granted during 2020.

RSUs fair value at vested date - The fair value of the RSUs that vested during 2021, 2020 and 2019 was

$2.4 million, $2.0 million and $7.0 million, respectively, based on the Company’s closing price on the vesting date.

For the outstanding RSUs issued to the eligible employees as of December 31, 2021, vesting is expected to occur as

follows (subject to forfeitures):

2022
2023
2024

Total

Restricted

Shares
232,822
232,822
232,821
698,465

Performance Share Units (“PSUs”)

As of December 31, 2021, the Company granted PSUs under the plan to certain employees. There were no PSUs

granted in 2020 and 2019. 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 for the
applicable performance period (2021) and service-based criteria. TSR is determined based on the change in the entity’s
stock price plus dividends and distributions for the applicable performance period. Subsequent to the performance
period, the PSUs will continue to be subject to service-based criteria with vesting occurring on October 1, 2023.

A summary of activity related to PSUs is as follows:

Nonvested, beginning of period
Granted
Vested
Forfeited
Nonvested, end of period

2021

Weighted
Average

Performance Grant Date Fair
Share Units
Value Per Unit
—
$
—
5.56
393,073
—
—
5.57
(196,155)
5.55
196,918

We recognize compensation cost for share-based payments to employees 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 highly subjective assumptions. Our key
assumptions in the method include the price and the expected volatility of our stock and our self-determined Peer Group
companies’ stock, risk free rate of return and cross-correlations between the Company and our Peer Group companies.
The valuation model assumes dividends, if any, are immediately reinvested. The grant date fair value of the PSUs
granted as of December 31, 2021 is $1.9 million. The following table summarizes the assumptions used to calculate the
grant date fair value of the PSUs granted:

Remaining term for performance period (in years)
Expected volatility
Risk-free interest rate

Share-Based Awards: Restricted Stock

2021 Grant Date
June 28

0.5
67.9 %
0.1 %

Under the Directors Compensation Plan, shares of restricted stock (“Restricted Shares”) were issued in 2021,
2020 and 2019 to the Company’s non-employee directors as a component of their compensation arrangement. Vesting
occurs upon completion of the specified vesting period, which was three years for the 2019 grants and one year for the
2020 and 2021 grants. The holders of Restricted Shares 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. Restricted Shares are subject to forfeiture until vested and cannot be sold, transferred or otherwise disposed
of during the restriction period.

As of December 31, 2021, there were 410,742 shares of common stock available for issuance in satisfaction of
awards under the Directors Compensation Plan. Reductions in shares available are made when Restricted Shares are
granted.

A summary of activity related to Restricted Shares is as follows:

2021

2020

2019

Weighted
Average
Grant Date
Restricted Fair Value
Per Share

Nonvested, beginning of period
Granted
Vested
Nonvested, end of period

154,128 $
62,502
(146,404)

70,226 $

3.64
3.36
3.51
3.65

Shares
123,180 $
109,376
(78,428)
154,128 $

Weighted
Average
Grant Date
Fair Value
Per Share

Restricted

4.55
2.56
2.38
3.64

Shares
181,832 $
46,360
(105,012)
123,180 $

3.08
6.04
2.67
4.55

Subject to the satisfaction of service conditions, the Restricted Shares outstanding as of December 31, 2021 are

eligible to vest in 2022.

Restricted stock fair value at grant date - The grant date fair value of restricted stock granted during 2021, 2020 and
2019 was $0.2 million, $0.3 million and $0.3 million, respectively, based on the Company’s closing price on the date of
grant.

Restricted stock fair value at vested date - The fair value of the restricted stock that vested during 2021, 2020 and
2019 was $0.5 million, $0.2 million and $0.5 million, respectively, based on the Company’s closing price on the date of
vesting.

Share-Based Compensation

A summary of compensation expense under share-based payment arrangements is as follows (in thousands):

Restricted stock units
Performance share units
Restricted Shares

Total

Year Ended December 31,
2020
3,555 $
—
404
3,959 $

2021
2,579 $
412
373
3,364 $

2019
3,410
—
280
3,690

As of December 31, 2021, unrecognized share-based compensation expense related to our awards of RSUs and

Restricted Shares was $1.4 million and $0.1 million, respectively. Unrecognized compensation expense will be
recognized through November 2022 for our RSUs and April 2023 for our Restricted Shares.

Cash-based Incentive Compensation

Short-term Cash-Based Incentive Compensation

There are two components of the short-term cash-based incentive award granted during as of December 31, 2021.

• The first short-term, cash-based award granted in February 2021 was discretionary and subject only to

continued employment on the payment dates. The 2021 discretionary bonus award was paid in equal
installments on March 15, 2021 and April 15, 2021, to substantially all employees subject to employment on
those dates. Incentive compensation expense of $7.0 million was recognized as of December 31, 2021, related
to these awards.

• For the second short-term, cash-based award granted in June 2021, a portion of the Company performance-

based criteria and individual performance criteria were achieved. In addition, the Board of Directors approved a
discretionary amount. Incentive compensation expense of $6.5 million was recognized in 2021 related to these
cash-based awards. Payments are expected to be made in March 2022.

No cash-based incentive awards were granted in 2020. Cash-based incentive compensation expense recorded in

2020 related to the amortization of long-term cash awards granted in prior periods.

Long-term Cash-Based Incentive Compensation

The 2021 long-term, cash-based awards (“Cash Awards”) were granted in June 2021 and are subject to the same

performance-based criteria as the PSUs noted above. The Company’s TSR ranking against peer companies will be
evaluated for the performance period of 2021. Subsequent to the performance period, the Cash Awards will continue to
be subject to service-based criteria with vesting occurring on October 1, 2023.

These Cash Awards are accounted for as liability awards and are measured at fair value each reporting date through
the end of the performance period. We recognize compensation cost for long-term cash-based awards to employees over
the service period from June 28, 2021 through October 1, 2023. The reporting date fair value of the awards as of
December 31, 2021 was determined through the calculation of the total shareholder return of our stock against our self-
determined peer group companies’ stock, using the risk-free rate of return, and an appropriate discount rate. The fair
value of the awards as of December 31, 2021 is $1.0 million. As of December 31, 2021, unrecognized compensation
expense related to these awards was $0.8 million. The following table summarizes the assumptions used to calculate the
fair value of the outstanding long-term Cash Awards as of December 31, 2021:

Estimated performance achievement
Risk-free interest rate
Expected term for cash payment (in years)
Discount rate used to discount expected cash payment

50.8 %
0.7 %
1.8
12.5 %

Share-Based Awards and Cash-Based Awards Compensation Expense

A summary of compensation expense related to share-based awards and cash-based awards is as follows (in

thousands):

Year Ended December 31,
2020

2021

2019

Share-based compensation included in:
General and administrative expenses

Cash-based incentive compensation included in:

Lease operating expense (1)
General and administrative expenses (1)

Total charged to operating (loss) income

(1)

Includes adjustments of accruals to actual payments.

12. Employee Benefit Plan

$ 3,364 $ 3,959 $ 3,690

3,500
10,086

2,206
8,897
$ 16,950 $ 8,827 $ 14,793

849
4,019

We maintain 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 2021, 2020, and 2019 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). Our expenses relating to the 401(k) Plan were $2.0 million, $2.3 million,
and $2.0 million for 2021, 2020 and 2019, respectively.

13. Income Taxes

Income Tax (Benefit) Expense

Components of income tax (benefit) expense were as follows (in thousands):

Year Ended December 31,
2020

2019

2021

132 $

134 $ (11,092)
(64,102)
(30,287)
$ (8,057) $ (30,153) $ (75,194)

(8,189)

Current
Deferred

Total income tax (benefit) expense

Reconciliation

The reconciliation of income taxes computed at the U.S. federal statutory tax rate to our income tax (benefit)

expense is as follows (in thousands):

Income tax (benefit) expense at the federal statutory rate
Compensation adjustments
State income taxes
Uncertain tax position
Impact of U.S. legislative changes
Valuation allowance
Other

Total income tax (benefit) expense

2021
$ (10,402) $

2019

Year Ended December 31,
2020
1,604 $
1,373
75
—
(21,345)
(12,018)
158

(233)
971
(175)
(11,523)
—
(64,704)
470
(8,057) $ (30,153) $ (75,194)

559
(330)
—
—
1,863
253

Our effective tax rate for the years 2021, 2020 and 2019 differed from the applicable federal statutory rate of 21.0%
primarily due to the impact of the valuation allowance on our deferred tax assets, which is discussed below. As a result,
our effective tax rate for 2021 is 16.3% while our effective tax rates for the years 2020 and 2019 presented above are not
meaningful.

Deferred Tax Assets and Liabilities

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
our deferred tax assets and liabilities were as follows (in thousands):

Deferred tax liabilities:

Property and equipment
Derivatives
Investment in non-consolidated entity
Other

Total deferred tax liabilities

Deferred tax assets:

Derivatives
Asset retirement obligations
Federal net operating losses
State net operating losses
Interest expense limitation carryover
Share-based compensation
Valuation allowance
Other

Total deferred tax assets

Net deferred tax assets (liabilities)

December 31,

2021

2020

$ 55,170 $ 37,535
—
8,070
2,588
48,193

—
4,659
2,817
62,646

21,026
91,850
42,127
7,612
18,628
312
(24,359)
7,842
165,038

3,416
84,332
47,307
8,136
16,304
419
(22,361)
4,843
142,396
$ 102,392 $ 94,203

Income Taxes Receivable, Refunds and Payments

As of December 31, 2021 and 2020, we did not have any current income taxes receivable. During 2020 we received
a refund of $2.0 million which related to a net operating loss (“NOL”) carryback claim for the year 2017 that we carried
back to prior years. This carryback claim was made pursuant to IRC Section 172(f) (related to rules regarding “specified
liability losses”), which permits certain platform dismantlement, well abandonment and site clearance costs to be carried
back 10 years. During the years ending December 31, 2021 and 2020, we did not make any tax payments of significance.

Net Operating Loss and Interest Expense Limitation Carryover

The table below presents the details of our net operating loss and interest expense limitation carryover as of

December 31, 2021 (in thousands):

Federal net operating loss
State net operating loss
Interest expense limitation carryover

Valuation Allowance

Expiration Year
Amount
$ 200,605 earliest is 2037
2026-2040
N/A

133,481
85,451

During 2021, our valuation allowance increased $2.0 million primarily due to an increase in our disallowed interest

expense limitation carryover. During 2020, we recorded a decrease in the valuation allowance of $32.1 million;
resulting in an income tax benefit in 2020 primarily as a result of the enactment of the CARES Act on March 27, 2020
and the issuance by the United States Treasury Department (Treasury) of final and proposed regulations under Internal
Revenue Code (“IRC”) Section 163(j) on July 28, 2020 that provided additional guidance and clarification to the
business interest expense limitation. Deferred tax assets are recorded related to net operating losses and temporary
differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future periods.
The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in
which those temporary differences or net operating losses are deductible. In assessing the need for a valuation allowance
on our deferred tax assets, we consider whether it is more likely than not that some portion or all of them will not be
realized.

The Company assesses available positive and negative evidence regarding our ability to realize our deferred tax

assets including reversing temporary differences and projections of future taxable income during the periods in which
those temporary differences become deductible, as well as negative evidence such as historical losses. Although the
Company incurred a loss in 2021, we determined that these results were not indicative of future results and concluded
that the positive evidence outweighed the negative evidence. The portion of the valuation allowance remaining relates to
state net operating losses, charitable contributions carryover and the disallowed interest limitation carryover under IRC
section 163(j). As of December 31, 2021, the Company’s valuation allowance was $24.4 million.

Years open to examination

The tax years from 2018 through 2021 remain open to examination by the tax jurisdictions to which we are subject.

14. Earnings Per Share

The Company’s unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend
equivalents (whether paid or unpaid) are deemed participating securities and are included in the computation of earnings
per share under the two-class method when the effect is dilutive.

The following table presents the calculation of basic and diluted earnings per common share (in thousands, except

per share amounts):

Year Ended December 31,
2020

2021

2019

Net (loss) income
Less portion allocated to nonvested shares

Net (loss) income allocated to common shares

$ (41,478) $ 37,790 $ 74,086
1,371
$ (41,478) $ 37,353 $ 72,715

437

—

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 (weighted-
average)

142,271
—
142,271

141,622
1,655
143,277

140,583
3,141
143,724

$
$

(0.29) $
(0.29) $

0.26 $
0.26 $

0.52
0.52

1,370

—

15. Supplemental Cash Flow Information

The following table reflects our supplemental cash flow information (in thousands):

Year Ended December 31,
2020

2021

2019

$ 245,799 $ 43,726 $ 32,433
—
66,720
51
51,833
7,720

—
59,183
159
2,007
603

4,417
64,805
152
1
112

9,464
36,175

3,035
17,928

29,662
37,440

Supplemental cash items:
Cash and cash equivalents
Restricted cash and restricted cash equivalents
Cash paid for interest
Cash paid for income taxes
Cash refunds received for income taxes
Cash received for interest income

Non-cash investing activities:
Accruals of property and equipment
ARO - additions, dispositions and revisions, net

16. Commitments

Pursuant to the Purchase and Sale Agreement with Total E&P, we may fulfill security requirements related to ARO
for certain properties through securing surety bonds, or through making payments to an escrow account under a formula
pursuant to the agreement, or a combination thereof, until certain prescribed thresholds are met. Once the threshold is
met for that year, excess funds in the escrow account are returned to us. As of December 31, 2021, we had surety bonds
related to the agreement with Total E&P totaling $96.7 million and had no amounts in escrow. The threshold escalates to
$103.0 million for 2023 in $3.0 million per year increments.

Pursuant to the Purchase and Sale Agreement with Shell Offshore Inc. (“Shell”) related to ARO for certain

properties, we have surety bonds that are subject to re-appraisal by either party. As of December 31, 2021, neither party
had requested a re-appraisal to be made. The current security requirement of $64.0 million, which we have met, could be
increased up to $94.0 million depending on certain conditions and circumstances.

Pursuant to the Purchase and Sale Agreement with Exxon related to ARO for certain properties, we were required to
obtain $33.0 million of surety bonds as of December 31, 2021. This amount increases on June 1 of the following years to
$36.3 million - 2022; $40.0 million - 2023; $44.0 million - 2024; $48.3 million - 2025; $53.2 million - 2026, and future
increases in increments ranging $5.3 million to $10.4 million per year until the total amount reaches $114.0 million in
2034. We may request a redetermination with Exxon every two years by providing certain documentation as provided in
the purchase agreement. We are 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 Purchase and Sale Agreement with Conoco related to ARO for certain properties, we were required

to obtain $49.0 million of surety bonds and are required to maintain this level of bonds until the properties are fully
plugged, abandoned, and restored in accordance with applicable laws and regulations.

During 2021, 2020 and 2019, we had surety bonds primarily related to our decommissioning obligations or ARO.
Total expenses related to surety bonds, inclusive of the surety bonds in connection with the agreements described above,
were $6.0 million, $5.4 million, and $4.7 million during 2021, 2020 and 2019, respectively. The amount of future
commitments is dependent on rates charged in the market place and when asset retirements are completed. Estimated
future expenses related to surety bonds were based on current market prices and estimates of the timing of asset
retirements, of which some wells and structures are estimated to extend to 2065. Future payment estimates are (in
millions):

2022
2023
2024
2025
2026
Thereafter
Total

7.3
6.1
6.1
6.0
5.1
50.9
81.5

Future surety bond costs may change due to a number of factors, including changes and interpretations of

regulations by the BOEM.

In conjunction with the purchase of an interest in the Heidelberg field, we assumed contracts with certain pipeline

companies that contain minimum quantities obligations that extend to 2021. For 2021, 2020 and 2019 expense
recognized for the difference between the quantities shipped and the minimum obligations was $2.1 million, $4.5 million
and $4.5 million, respectively. As of December 31, 2021, the estimated future costs are (in millions):

2022
2023
2024
2025
2026
Thereafter
Total

1.8
1.2
0.9
0.6
0.4
0.4
5.3

As of December 31, 2021 we have drilling commitments of $2.9 million for 2022. We do not have any long-term

drilling rig commitments as of December 31, 2021.

See Note 8 – Leases for information on leases.

17. Related Parties

During 2021, 2020 and 2019, there were certain transactions between us and other companies our Chief Executive

Officer, Tracy W. Krohn (“CEO”) either controlled or in which he had an ownership interest. Our CEO owns an aircraft
that the Company used for business purposes and the CEO used for his personal matters pursuant to his employment
contract, and these costs were paid by the Company. Airplane services transactions were approximately $0.6 million,
$0.3 million and $1.2 million for the years 2021, 2020 and 2019 respectively.

Our CEO has ownership interests in certain wells operated by us (such ownership interests pre-date our initial public

offering). Revenues are disbursed and expenses are collected in accordance with ownership interest. Proportionate
insurance premiums were paid to us and proportionate collections of insurance reimbursements attributable to damage
on certain wells were disbursed.

A company that provides marine transportation and logistics services to W&T employs the spouse of our 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 $12.0 million, $14.4 million and $22.8 million in 2021, 2020 and 2019, respectively. The spouse
received commissions partially based on services rendered to W&T which were approximately $0.1 million in 2021,
2020 and 2019.

During 2018, an entity controlled by our CEO participated in the Senior Second Lien Note issuance for an $8.0

million principal commitment on the same terms as the other lenders.

During 2021, pursuant to the Ninth Amendment to the Sixth Amended and Restated Credit Agreement, Calculus, an

entity indirectly owned and controlled by our CEO, became the sole lender under our Credit Agreement. In relation to
the execution of the Ninth Amendment, the Company paid Calculus an arrangement fee of approximately $0.8 million
and paid legal fees on behalf of Calculus of approximately $0.2 million. See Note 2 – Debt for information on the
related party transaction concerning Calculus.

See Note 5 – Joint Venture Drilling Program for information on a related party transaction concerning Monza.

18. Contingencies

Appeal with ONRR

In 2009, we recognized allowable reductions of cash payments for royalties owed to the ONRR for transportation of

their deepwater production through our subsea pipeline systems. In 2010, the ONRR audited our calculations and
support related to this usage fee, and in 2010, we were notified that the ONRR had disallowed approximately $4.7
million of the reductions taken. We recorded a reduction to other revenue in 2010 to reflect this disallowance with the
offset to a liability reserve; however, we disagree with the position taken by the ONRR. We filed an appeal with the
ONRR, which was denied in May 2014. On June 17, 2014, we filed an appeal with the Interior Board of Land Appeals
(“IBLA”) under the DOI. On January 27, 2017, the IBLA affirmed the decision of the ONRR requiring W&T to pay
approximately $4.7 million in additional royalties. We filed a motion for reconsideration of the IBLA decision on
March 27, 2017. Based on a statutory deadline, we filed an appeal of the IBLA decision on July 25, 2017 in the U.S.
District Court for the Eastern District of Louisiana. We were required to post a bond in the amount of $7.2 million and
cash collateral of $6.9 million in order to appeal the IBLA decision. On December 4, 2018, the IBLA denied our motion
for reconsideration. On February 4, 2019, we filed our first amended complaint, and the government has filed its Answer
in the Administrative Record. On July 9, 2019, we filed an Objection to the Administrative Record and Motion to
Supplement the Administrative Record, asking the court to order the government to file a complete privilege log with the
record. Following a hearing on July 31, 2019, the Court ordered the government to file a complete privilege log. In an
Order dated December 18, 2019, the court ordered the government to produce certain contracts subject to a protective
order and to produce the remaining documents in dispute to the court for in camera review. Ultimately, the court upheld
the government’s assertion of privilege and the parties commenced briefing on the merits. At this point, both parties
have filed cross-motions for summary judgment and opposition briefs. W&T 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, we are
waiting for the district court’s ruling on the merits. In January 2020, the cash collateral in the amount of $6.9 million
securing the appeal bond in this matter was released to us. In compliance with the ONRR’s request for W&T to increase
the surety posted in the appeal, the sum of the bond posted is currently $8.2 million.

Royalties-In-Kind (“RIK”)

Under a program of the Minerals Management Service (“MMS”) (a Department of Interior (“DOI”) agency and
predecessor to the ONRR), royalties must be paid “in-kind” rather than in value from federal leases in the program. The
MMS added to the RIK program our lease at the East Cameron 373 field beginning in November 2001, where in
some months we over delivered volumes of natural gas and under delivered volumes of natural gas in other months for
royalties owed. The MMS elected to terminate receiving royalties in-kind in October 2008, causing the imbalance to
become fixed for accounting purposes. The MMS ordered us to pay an amount based on its interpretation of the program
and its calculations of amounts owed. We disagreed with MMS’s interpretations and calculations and filed an appeal
with the IBLA, of which the IBLA ruled in MMS’ favor. We filed an appeal with the District Court of the Western
District of Louisiana, who assigned the case to a magistrate to review and issue a ruling, and the District Court upheld
the magistrate’s ruling on May 29, 2018. We filed an appeal on July 24, 2018. Part of the ruling was in favor of our
position and part was in favor of MMS’ position. We appealed the ruling to the U.S. Fifth Circuit Court of Appeals and
the government filed a cross-appeal. The Fifth Circuit issued its ruling on December 23, 2019, holding that, while the
DOI has statutory authority to switch the method of royalty payment from volumes (“in-kind”) to cash (“in value”), the
“cashout” methodology that the DOI ordered W&T to implement was unenforceable because that methodology was a
“substantive rule” that the DOI adopted in violation of the Administrative Procedure Act. In addition, the Fifth Circuit
held that the DOI’s claim was unlawfully inflated because DOI improperly failed to give W&T credit for all royalty
volumes delivered. The Fifth Circuit remanded the case to the District Court to implement the court’s decision on
appeal. Based on the combination of (i) the DOI’s concessions concerning the scope of W&T’s liability (e.g., that W&T
is only liable for its working interest share of the royalty volumes at issue), and (ii) the Fifth Circuit’s ruling, we estimate
that the value of the DOI’s claim against W&T is no greater than $250,000 and have adjusted the liability reserve for this
matter as of December 31, 2021 to such amount.

Notices of Proposed Civil Penalty Assessment

In January 2021, we 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, with the proposed civil penalty amounts
totaling $7.7 million. Under the Settlement Agreement, W&T will pay a total of $720,000 in three annual installments.
The first installment was paid in March 2021. In addition, W&T committed to implement a Safety Improvement Plan
with various deliverables due over a period ending in 2022. In September 2021, we paid $40,200 related to an INC
issued in 2018. Additionally in September 2021, we were notified of a new proposed civil penalty assessment for
$46,000 for an INC that occurred at one of our properties in 2018, which we subsequently paid in January 2022.

Supplemental Bonding Requirements by the BOEM

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 the
filing date of this Form 10-K, the Company is in compliance with its financial assurance obligations to the BOEM and
has no outstanding BOEM orders related to assurance obligations. W&T and other offshore Gulf of Mexico producers
may in the ordinary course receive future demands for financial assurances from the BOEM as the BOEM continues to
reevaluate its requirements for financial assurances.

Surety Bond Issuers’ Collateral Requirements

The issuers of surety bonds in some cases have requested and received additional collateral related to surety bonds
for plugging and abandonment activities. We may be required to post collateral at any time pursuant to the terms of our
agreement with various sureties under our existing bonds, if they so demand at their discretion. We did not receive any
such collateral demands from surety bond providers during 2021 or 2020.

Retained Liabilities Related to Divested Property Interests

We may be subject to retained liabilities with respect to certain divested property interests by operation of law. For
example, recent historical declines in commodity prices created an environment where there is an increased risk that
owners and/or operators of interests purchased from us may no longer be able to satisfy plugging or abandonment
obligations that attach to those interests. In that event, due to operation of law, we may be required to assume plugging or
abandonment obligations for those interests. During the year ended December 31, 2021, as a result of the declaration of
bankruptcy by a third party that is the indirect successor in title to certain offshore interests that we previously divested,
we recorded a loss contingency accrual of $4.5 million related to the anticipated cost to decommission certain wells,
pipelines, and production facilities for which we may receive decommissioning orders from BSEE. We no longer own
these assets nor are they related to our current operations. We intend to seek contribution from other parties that owned an
interest in the facilities. Potential recoveries from other parties that previously owned an interest in these wells, pipelines,
and production facilities have not been recognized as of December 31, 2021.

Other Claims

We are a party to various pending or threatened claims and complaints seeking damages or other remedies
concerning our commercial operations and other matters in the ordinary course of our business. In addition, claims or
contingencies may arise related to matters occurring prior to our acquisition of properties or related to matters occurring
subsequent to our sale of properties. In certain cases, we have indemnified the sellers of properties we have acquired,
and in other cases, we have indemnified the buyers of properties we have sold. We are 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 we can give no assurance about the outcome of pending
legal and federal or state administrative proceedings and the effect such an outcome may have on us, we believe 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 our consolidated financial position, results of operations or
liquidity.

100

19. Supplemental Oil and Gas Disclosures—UNAUDITED

Geographic Area of Operation

All of our proved reserves are located within the United States in the Gulf of Mexico. Therefore, the following

disclosures about our costs incurred, results of operations and proved reserves are on a total-company basis.

Capitalized Costs

Net capitalized costs related to our oil, NGLs and natural gas producing activities are as follows (in millions):

Net capitalized costs:

Year Ended December 31,
2020

2021

2019

Proved oil and natural gas properties and equipment
Accumulated depreciation, depletion and amortization related to oil,
NGLs and natural gas activities

Net capitalized costs related to producing activities

655.1 $

676.6 $

(7,981.3)

(7,890.9)

(7,793.3)
738.9

$ 8,636.4 $ 8,567.5 $ 8,532.2

Costs Incurred In Oil and Gas Property Acquisition, Exploration and Development Activities

The following costs were incurred in oil and gas acquisition, exploration, and development activities (in millions):

Costs incurred: (1)

Proved properties acquisitions
Exploration (2)
Development

Total costs incurred in oil and gas property acquisition, exploration and
development activities

Year Ended December 31,
2020

2021

2019

2.2 $
47.3
18.4

8.1 $
7.4
23.6

223.8
30.6
114.5

67.9 $

39.1 $

368.9

(1)

(2)

Includes net additions from capitalized ARO of $36.2 million, $15.2 million, and $37.5 million during 2021,
2020, and 2019, respectively. These adjustments for ARO are associated with acquisitions, liabilities incurred,
divestitures and revisions of estimates.
Includes seismic costs of $0.1 million, $0.3 million, and $7.8 million incurred during 2021, 2020, and 2019,
respectively. Includes geological and geophysical costs charged to expense of $5.7 million, $4.5 million, and
$5.7 million during 2021, 2020, and 2019, respectively.

Depreciation, depletion, amortization and accretion expense

The following table presents our depreciation, depletion, amortization and accretion expense per barrel equivalent

(“Boe”) of products sold:

Year Ended December 31,
2020

2021

2019
10.01

Depreciation, depletion, amortization and accretion ($/Boe)

8.15 $

7.82 $

101

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 and may be subject to substantial revisions as additional information such as reservoir performance,
additional drilling, technological advancements and other factors become available. Decreases in the prices of oil, NGLs
and natural gas could have an adverse effect on the carrying value of our proved reserves, reserve volumes and our
revenues, profitability and cash flow. We are not the operator with respect to 25.3% of our proved developed non-
producing reserves as of December 31, 2021 so we may not be in a position to control the timing of all development
activities. We are the operator for substantially all of our proved undeveloped reserves as of December 31, 2021. In
prior years, we were not the operator of substantially all proved undeveloped reserves.

All of the reserves are located in the United States with all located in state and federal waters in the Gulf of Mexico.

The reserve estimates exclude insignificant royalties and interests owned by the Company due to the unavailability of
such information. 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 and the FASB. The prices used do not purport, nor
should it be interpreted, to present the current market prices related to our estimated oil and natural gas reserves. Actual
future prices and costs may differ materially from those used in determining our proved reserves for the periods
presented. The prices used are presented in the section below entitled “Standardized Measure of Discounted Future Net
Cash Flows”.

102

The following sets forth estimated quantities of our net proved, proved developed and proved undeveloped oil,

NGLs and natural gas reserves:

Total Energy Equivalent

Reserves (1)

Proved reserves as of December 31, 2018

Revisions of previous estimates (2)
Extensions and discoveries (3)
Purchase of minerals in place (4)
Production

Proved reserves as of December 31, 2019

Revisions of previous estimates (5)
Extensions and discoveries (6)
Purchase of minerals in place (7)
Production

Proved reserves as of December 31, 2020

Revisions of previous estimates (8)
Extensions and discoveries
Purchase of minerals in place (9)
Production

Proved reserves as of December 31, 2021

Year-end proved developed reserves:

2021
2020
2019

Year-end proved undeveloped reserves:

2021(10)
2020
2019

Natural Gas
Natural Gas Oil Equivalent Equivalent

Oil (MMBbls)
39.1
1.4
0.9
3.1
(6.7)
37.8
(0.9)
0.2
0.7
(5.6)
32.2
10.0
—
—
(5.0)
37.2

NGLs
(MMBbls)
9.8
(1.5)
0.1
17.4
(1.3)
24.5
(5.9)
—
0.5
(1.7)
17.4
3.1
—
—
(1.4)
19.1

(Bcf)
210.5
(16.9)
1.2
417.6
(41.3)
571.1
31.6
0.2
14.8
(48.4)
569.3
83.0
—
0.1
(44.8)
607.6

(MMBoe)

84.0
(3.0)
1.1
90.1
(14.8)
157.4
(1.4)
0.2
3.6
(15.4)
144.4
27.1
—
—
(13.9)
157.6

(Bcfe)
504.1
(18.2)
6.7
540.9
(89.0)
944.5
(8.8)
1.3
21.8
(92.3)
866.5
162.4
—
0.1
(83.5)
945.5

27.6
24.0
28.0

17.8
16.5
21.7

549.2
550.2
504.9

137.0
132.2
133.8

821.9
793.3
802.9

9.6
8.2
9.8

1.3
0.9
2.8

58.4
19.1
66.2

20.6
12.2
23.6

123.8
73.2
141.6

(1) The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy-
equivalent ratio of six Mcf of natural gas to one barrel of crude oil, condensate or NGLs (totals may not
compute due to rounding). The energy-equivalent ratio does not assume price equivalency, and the energy-
equivalent prices for crude oil, NGLs and natural gas may differ significantly.

(2)

Increases primarily related to upward revisions to our Ship Shoal 028 field and our Main Pass 108 field.
Decreases of 10.0 MMBoe were due to price revisions for all proved reserves, which include estimated price
revisions of the purchase of minerals in place from the date of purchase to December 31, 2019.

(3) Primarily related to extensions and discoveries of 0.9 MMBoe at our Mississippi Canyon 800 (Gladden) field.

(4) Primarily related to the Mobile Bay Properties and Magnolia acquisitions.

(5) Decreases of 27.7 MMBoe were due to price revisions for all proved reserves. increases of 26.2 MMBoe were

primarily related to technical revisions at our Mobile Bay and Fairway properties.

(6) Primarily related to the discovery at East Cameron 338 field.

(7) Primarily related to the Mobile Bay Properties and Mahogany working interest acquisitions.

103

(8)

Increases of 27.1 MMBoe were due to price revisions for all proved reserves.

(9) Primarily related to Main Pass working interest acquisitions.

(10) We believe that we will be able to develop all but 2.5 MMBoe (approximately 12%) of the total 20.6 MMBoe
classified as PUDs at December 31, 2021, within five years from the date such PUDs were initially recorded.
The lone exceptions are at the Mississippi Canyon 243 field (“Matterhorn”) and Viosca Knoll 823 (“Virgo”)
deepwater fields where future development drilling has been planned as sidetracks of existing wellbores due to
conductor slot limitations and rig availability. Two sidetrack PUD locations, one each at Matterhorn 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
existing well. Based on the latest reserve report, these PUD locations are expected to be developed in 2023 and
2024.

Standardized Measure of Discounted Future Net Cash Flows

The following presents the standardized measure of discounted future net cash flows related to our proved oil and
natural gas reserves together with changes therein. Future cash inflows represent expected revenues from production of
period-end quantities of proved reserves based on the unweighted average of first-day-of-the-month commodity prices
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 crude oil realized price. Then, this ratio is applied to the crude oil price using FASB/SEC
guidance. The average commodity prices weighted by field production and after adjustments related to the proved
reserves are as follows:

Oil ($/Bbl)
NGLs ($/Bbl)
Natural gas ($/Mcf)

2021
65.25 $
26.83
3.68

December 31,
2020
37.78 $
10.29
2.05

2019
58.11
18.72
2.63

Future production, development costs and ARO are based on costs in effect at the end of each of the

respective years with no escalations. Estimated future net cash flows, net of future income taxes, have been discounted to
their present values based on a 10% annual discount rate.

The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to
present the fair market value of our oil and natural gas reserves. These estimates reflect proved reserves only and ignore,
among other things, future changes in prices and costs, revenues that could result from probable reserves which could
become proved reserves in 2022 or later years and the risks inherent in reserve estimates. The standardized measure of
discounted future net cash flows relating to our proved oil and natural gas reserves is as follows (in millions):

Year Ended December 31,
2020

2021

2019

Standardized Measure of Discounted Future Net Cash Flows

Future cash inflows

Future costs:
Production
Development and abandonment
Income taxes

Future net cash inflows before 10% discount
10% annual discount factor
Total

104

$ 5,178.2 $ 2,561.2 $ 4,153.8

(2,061.7)
(976.5)
(359.0)
1,781.0
(625.0)
$ 1,156.0 $

(1,257.4)
(707.4)
(60.5)
535.9
(42.2)
493.7 $

(1,901.1)
(794.7)
(170.5)
1,287.5
(300.6)
986.9

The change in the standardized measure of discounted future net cash flows relating to our proved oil and natural

gas reserves is as follows (in millions):

Year Ended December 31,
2020

2021

2019

Changes in Standardized Measure

Standardized measure, beginning of year
Increases (decreases):

Sales and transfers of oil and gas produced, net of production
costs
Net changes in price, net of future production costs
Extensions and discoveries, net of future production and
development costs
Changes in estimated future development costs
Previously estimated development costs incurred
Revisions of quantity estimates
Accretion of discount
Net change in income taxes
Purchases of reserves in-place
Sales of reserves in-place
Changes in production rates due to timing and other

Net (decrease) increase

Standardized measure, end of year

493.7 $

986.9 $ 1,067.0

(370.5)
980.9

(168.6)
(503.7)

(315.8)
(376.4)

—
(25.4)
0.6
289.6
44.0
(181.8)
0.5
—
(75.6)
662.3

2.8
(15.9)
1.4
(65.2)
111.8
87.7
44.6
—
11.9
(493.2)

$ 1,156.0 $

493.7 $

27.0
(6.0)
19.3
116.4
107.4
62.9
298.3
—
(13.2)
(80.1)
986.9

20. Subsequent Events

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 working 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 approximately $30.2 million was paid to the sellers.

On March 8, 2022, the Company entered into the Tenth Amendment to Sixth Amended and Restated Credit Agreement

and Extension Agreement, which extended the maturity date and Lender commitment to January 3, 2023 for the short-term
$100.0 million first priority lien secured revolving facility with a borrowing base of $50.0 million provided by Lender to the
Borrower, subject to the satisfaction of customary closing conditions.

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

We have established disclosure controls and procedures designed to ensure that information required to be disclosed in our

reports filed or submitted under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within
the time periods specified by the SEC’s rules and forms and that any information relating to us is accumulated and
communicated to our management, including our Chief Executive Officer and Chief Financial Officer,as appropriate to allow
timely decisions regarding required disclosures. In designing and evaluating our disclosure controls and procedures, our
management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable
assurance of achieving desired control objectives. In reaching a reasonable level of assurance, our management necessarily was
required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

105

As required by Exchange Act Rule 13a-15(b), we performed an evaluation, under the supervision and with the
participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness
of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and
15d-15(e)) as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and
Chief Financial Officer have each concluded that as of December 31, 2021 our disclosure controls and procedures are
effective to ensure that information we are required to disclose in reports filed or submitted under the Securities
Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the
Securities and Exchange Commission’s rules and forms, and that our controls and procedures are designed to ensure that
information required to be disclosed by us in such reports is accumulated and communicated to our management,
including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding
required disclosure.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management’s assessment of the effectiveness of our internal control over financial reporting as of

December 31, 2021, is set forth in “Management’s Report on Internal Control over Financial Reporting” included under
Part II, Item 8 in this Form 10-K.

Attestation Report of the Registered Public Accounting Firm

The effectiveness of our internal control over financial reporting as of December 31, 2021, has been audited by
Ernst & Young LLP, an independent registered public accounting firm, as stated in their report, which is included under
Part II, Item 8 in this Form 10-K.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting that occurred during the quarterly period
ended December 31, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control
over financial reporting.

Item 9B. Other Information

On March 8, 2022, the Company entered into the Tenth Amendment to Sixth Amended and Restated Credit
Agreement and Extension Agreement, among (i) W&T Offshore, Inc., as Borrower, (ii) each Borrower guarantor
subsidiary, (iii) Calculus Lending, LLC, as Lender, and (iv) Alter Domus (US) LLC, as Administrative Agent for the
Lender, which extended the maturity date and Lender commitment to January 3, 2023 for the short-term $100.0 million
first priority lien secured revolving facility with a borrowing base of $50.0 million provided by Lender to the Borrower,
subject to the satisfaction of customary closing conditions. Calculus Lending, LLC is an affiliate of, and controlled by,
Tracy W. Krohn, current Chief Executive Officer and President of the Company. The terms of the Tenth Amendment
were approved by the Audit Committee of the Board of Directors of the Company.

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.

106

Item 10. Directors, Executive Officers and Corporate Governance

PART III

The information required by this item is incorporated by reference from our definitive proxy statement to be filed