W&T Offshore, Inc. Annual Report 2020

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FY2020 Annual Report · W&T Offshore, Inc.

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A Dedicated Team Responds
to Challenging Times
2020 Annual Report

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 more than 37 years, we have grown

through the right 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.

We currently own working interests in 146 offshore structures, 105

of which are located in fields that we operate. We have ownership

interests in 213 productive wells, 152 of which we operate.

Our working interests in 43 producing fields are in both federal and

state waters and our leases cover approximately 737,000 gross acres,

of which 527,000 acres are on the GOM shelf in less than 500 feet

of water, and the balance of 210,000 acres are in deepwater in 500

feet of water or greater. Approximately 74% 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”.

Inaugural W&T Environmental, Social and
Governance (“ESG”) Report

W&T is pleased to issue its 2020 inaugural ESG report concurrent with

this annual report. It can be found on our web site, www.wtoffshore.

com, under the “Corporate Responsibility” tab. In the creation of its

inaugural report, the Company consulted the Sustainability Accounting

Standards Board’s (“SASB”) Oil and Gas Exploration and Production

Sustainability Accounting Standard, the recommendations of the

Task Force on Climate-related Financial Disclosures (“TCFD”), and

other reporting guidance from industry frameworks and standards.

Management believes this report communicates W&T’s long-standing

commitment to operating with the highest regards toward ESG and

includes detailed discussion of W&T’s policies and key metrics for the

period 2018 through 2020.

Our long-held strategic vision
focused on generating free
cash ﬂ ow guided us through
2020, when we confronted an
international crude oil supply
and demand imbalance, a
global COVID-19 pandemic,
and a record-breaking eight
named storms that impacted
our production in the Gulf of
Mexico. Despite the personal
challenges every employee at
W&T faced last year, our team
met those adversities head-on
and we remained focused on
successfully executing our long-
term strategy. We generated
more free cash ﬂ ow in 2020 than
in 2019, and ended 2020 with a
stronger balance sheet with less
debt than the year before.

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To my fellow
shareholders

We founded W&T nearly 40 years ago, and from day one, we have been committed

to building value for our shareholders while developing and producing oil and gas

resources in a safe and environmentally responsible manner. We have proﬁ tably

grown W&T over the years through the right combination of attractive property

acquisitions, methodical integration and exploitation of those acquisitions, and

successful development and exploratory drilling on our legacy ﬁ elds, all while

generating strong free cash ﬂ ow to fund our growth. These core values have guided

our success and provided the foundation for W&T to grow into a leading operator

in the Gulf of Mexico, a generous partner to the communities where we operate, and

good stewards to the environment.

Despite the multiple challenges we faced last year, we generated higher free

cash ﬂ ow for the full year 2020, than we did in 2019. We adjusted quickly to the

changing environment early in 2020 by reducing our planned capital expenditures,

and substantially reducing our operating expenses by operational efﬁ ciencies and

temporarily shutting in some of our production due to the sharp decline in oil prices.

In 2020, our capital expenditures were limited to just $17.6 million. The lower decline

proﬁ le of our conventional asset base allows for reductions in capital expenditures to

align with changes in the pricing environment, without signiﬁ cantly impacting near-

term production levels.

In early 2020 when there was signiﬁ cant uncertainty in the energy market, we

judiciously utilized a portion of our 2020 free cash ﬂ ow to retire $72.5 million of

our senior notes for a total cost of $23.9 million, thereby saving over $7.1 million in

annualized interest and preserving long-term capital. From January 1, 2020 through

early March 2021, we reduced net debt by $135.3 million and have a stronger balance

sheet now than in 2019.

While our production increased year-over-year to 42,046

Boe/d primarily due to the full year impact of additional

production from the Mobile Bay and Magnolia acquisitions

in the prior year, 2020 production was negatively impacted

by the eight named storms that entered the GOM. In

addition, we experienced planned and unplanned downtime

at some of our facilities, and a combination of operated and

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“ We have experienced quite a number
of commodity price cycles through the
years and two keys to our continued
success have been our focus on
generating positive free cash ﬂ ow
and capitalizing on opportunities for
accretive acquisitions.”

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non-operated production that was temporarily

move will substantially reduce our costs. We

shut-in due to low oil prices, as well as

continue to control the costs that we can, while

expected natural decline.

focusing on improving margins.

Turning to costs, to combat the sharp downturn

Turning to our 2020 year-end reserve report,

in prices in the ﬁ rst half of 2020, we swiftly

W&T’s SEC proved reserves of 144.4 million

implemented several successful initiatives to

barrels of oil equivalent (“MMBoe”) were down

reduce our lease operating expenses (“LOE”).

only modestly from 2019. Upward revisions

We swapped out higher cost contract personnel

of 26.2 MMBoe in 2020 related to improved

with full time employees, reduced transportation

well performance and technical revisions,

costs by lowering the number of boats and

and 3.9 MMBoe from acquisitions and drilling,

helicopters needed through operational

were offset by 27.7 MMBoe of reductions due

efﬁ ciencies, cut workover and facilities costs

to lower average realized SEC commodity

through vendor and supplier costs reductions,

prices of $37.78 per barrel of oil and $2.05

and increased our focus on projects that

per thousand cubic feet of natural gas (“Mcf”),

maintain and optimize production. We did not

and 15.4 MMBoe of production. Our year-end

diminish our commitment to safety, operational

2020 proved reserves utilizing average realized

compliance or environmental protection with

NYMEX strip pricing of $44.43 per barrel of oil

any of these actions. As a result of these cost

and $2.66 per Mcf of natural gas as of December

saving initiatives, our full year 2020 LOE was

31, 2020 would have been 169.5 MMBoe.

down over $20 million from the prior year,

and down over $50 million from preliminary

forecasts for 2020 that included a full year of

LOE related to the Mobile Bay and Magnolia

acquisitions. Looking to build on these cost

reduction efforts, we recently completed the

consolidation of our two natural gas treatment

About 34% of year-end 2020 reserves were

liquids and the balance was natural gas. Our

reserve life ratio at year-end 2020, based on

year-end 2020 SEC proved reserves and 2020

production was 9.4 years. Based on NYMEX

strip pricing, it was 11.0 years.

facilities that serve the Mobile Bay area into a

The PV-10 value of W&T’s SEC proved reserves

single facility with more than enough capacity

at year-end 2020 was $741 million, down

for our current operations as well as production

about 43% from year end 2019. This was driven

from future natural gas drilling projects in the

by reduced average realized SEC pricing.

area. The consolidation of these facilities is

However, utilizing average realized NYMEX

expected to result in approximately $5 million

strip pricing as of December 31, 2020, the

per year in savings, beginning in 2021, and it

PV-10 would have been $1.1 billion. Pricing has

has the added beneﬁ t of reducing our carbon

continued to increase through the early part of

footprint by lowering our Scope 1 emissions.

2021 which should positively impact our 2021

We also made strides in lowering our G&A

year-end reserves and PV-10 value.

costs and in late 2020, we moved our

For the three-year period 2018 through

corporate headquarters in Houston only a few

2020, W&T’s all-in reserve replacement cost

miles down the road. Our new headquarters

was $4.62 per Boe. We believe that is a

has about the same amount of space but the

very competitive cost for any U.S. E&P, and

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reinforces the value of both the acquisitions we

In closing, I want to thank my management team

have completed and the drilling successes that

and all of our employees for their continued

we have achieved.

Looking ahead to 2021, while we have a

substantial inventory of drilling opportunities

with potentially high rates of return, we are

maximizing ﬁ nancial ﬂ exibility by moderating

the amount of free cash ﬂ ow that we allocate

to our drilling capital in 2021. The current

price environment should allow us to generate

meaningful free cash ﬂ ow which we can use

to further reduce debt or potentially fund

additional accretive acquisition opportunities.

Accordingly, our capital spending in 2021 is

hard work and dedication, as well as our Board

for their guidance and support. We persevered

and thrived through an extraordinarily difﬁ cult

year in 2020 for energy companies. We saw

oil prices and production impacted by the

global COVID-19 pandemic, supply and demand

imbalances and one of the most active tropical

storm seasons ever seen in the GOM. Our

success in 2020 was a testament to the efforts

of all of our employees who maintained their

commitment to W&T despite the personal issues

they all faced due to the pandemic.

currently expected to be in the range of $30

We have experienced quite a number of

to $60 million, and will be focused on lower-

commodity price cycles through the years and

risk, higher return projects. We have signiﬁ cant

two keys to our continued success have been

ﬂ exibility to adjust our spending up or down

our focus on generating positive free cash

at any time since we have no long-term rig

ﬂ ow, which we did in every quarter in 2020,

contracts or drilling obligations. Additionally, we

and capitalizing on opportunities for accretive

are forecasting 2021 spending of between $17 to

acquisitions. We have a premier portfolio of

$21 million on asset retirement obligations.

both shallow water and deepwater properties

At W&T our people are our most valuable

asset and every employee has a responsibility

to ensure that we operate with the highest

regards toward Environment, Safety and

Governance. Our Board has empowered

management to allocate resources and tools

necessary to add value to our stakeholders in

a sustainable manner while accomplishing our

ESG objectives. While ESG is an integral part of

our corporate culture, our strategy has always

been focused on operational excellence, safety

and generating free cash ﬂ ow, long before

these values became trendy in the energy

industry. I encourage our stakeholders to read

our inaugural ESG report that has been posted

to our web site that includes key metrics over

the past three years that are aligned with SASB

and TCFD standards and guidelines.

in the GOM with low decline rates and

signiﬁ cant upside. We have reduced a material

amount of our debt and we believe that we

are well positioned today to take advantage

of the improved commodity environment and

the many opportunities that 2021 may present

for W&T. With a 35% stake in W&T’s equity,

our management team’s interests are highly

aligned with those of our shareholders. This

alignment of interest ensures that we are truly

incentivized to maximize shareholder value and

mitigate risk.

Tracy W. Krohn
Founder, Chairman, Chief
Executive Ofﬁ cer and President

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Financial Highlights

Year Ending December 31,

Income Statement (000s)

Total Revenues

Operating Income

Net Income

Cash-Flow Statement (000s)

2020

2019

2018

$ 346,634

$ 534,896

$ 580,706

24,609

$ 58,649

$ 247,027

37,790

74,086

$ 248,827

Cash Provided by Operating Activities

$ 108,509

$ 232,227

$ 321,763

Capex (oil and natural gas properties) excl acquisitions

Capex (acquisition of oil and natural gas properties)

44,167

$ 125,706

2,919

188,019

106,191

16,782

Balance Sheet (000s)

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)

$ 940,582

$ 1,003,719

$ 848,866

$ 625,286

$ 719,533

$ 633,535

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

6.7

1.3

41.3

14.8

40.6

6.7

1.3

32.0

13.3

36.5

59.89

17.60

2.57

35.63

65.62

28.40

3.11

43.19

37.8

24.5

571.1

157.4

133.8

23.6

39.1

9.8

210.5

84.0

67.0

17.0

Proved Developed Reserves as a % of Proved Reserves

91 %

85 %

80 %

Revenue
($ in millions)

$580.7

$534.9

Cash Provided by
Operating Activities
($ in millions)

Production
(MBoe/d)

Proved Reserves
(MMBoe)

40.6

42.0

157.4

36.5

144.4

$346.6

$321.8

$232.2

$108.5

2018

2019

2020

2018

2019

2020

2018

2019

2020

2018

2019

2020

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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, 2020
or

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)

Securities registered pursuant to section 12(b) of the Act:

Title of each class
Common Stock, par value $0.00001

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 $213,418,732 based on the closing sale price

of $2.28 per share as reported by the New York Stock Exchange on June 30, 2020.

The number of shares of the registrant’s common stock outstanding on February 28, 2021 was 142,304,770.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s Proxy Statement relating to the Annual Meeting of Shareholders, to be filed within 120 days of the end of the fiscal year

covered by this report, are incorporated by reference into Part III of this Form 10-K.

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W&T OFFSHORE, INC.
TABLE OF CONTENTS

Glossary of Oil and Gas Terms

Item 1. Business

Item 1A. Risk Factors

Item 1B. Unresolved Staff Comments

Item 2. Properties

Item 3. Legal Proceedings

Executive Officers of the Registrant

Item 4. Mine Safety Disclosures

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity

Securities

Item 6. Selected Financial Data

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Item 8. Financial Statements and Supplementary Data

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

Item 9A. Controls and Procedures

Item 9B. Other Information

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Item 11. Executive Compensation

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Item 13. Certain Relationships and Related Transactions, and Director Independence

Item 14. Principal Accountant Fees and Services

PART IV

Item 15. Exhibits and Financial Statement Schedules

Signatures

Page
ii

102

103

104

108

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FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K (“Form 10-K”) contains forward-looking statements within the meaning of the

Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. 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 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.

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. Previously, this function was managed
by the Bureau of Ocean Energy Management, Regulation and Enforcement.

BSEE. Bureau of Safety and Environmental Enforcement. The agency is responsible for enforcement of safety and
environmental regulations. Previously, this function was managed by the Bureau of Ocean Energy Management,
Regulation and Enforcement.

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.

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.

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.

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. These are created during the processing of natural gas.

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.

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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.

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 subsidiary, W&T Energy VI, LLC, a Delaware limited
liability company and through our proportionately consolidated interest in Monza Energy, LLC (“Monza”), as described in
more detail in Financial Statements and Supplementary Data – Note 4 – 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 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 our plans.

Market Trends

COVID-19 Impacts on Economic Environment. Due to circumstances related to the outbreak of COVID-19, various

measures have been taken by federal, state and local governments to reduce the rate of spread of COVID-19. These
measures and other factors have resulted in a decrease of general economic activity and a corresponding decrease in global
and domestic energy demand impacting commodity pricing. In addition, actions by the Organization of Petroleum
Exporting Countries and other high oil exporting countries like Russia (“OPEC+”) negatively impacted crude oil prices
during early 2020. These rapid and unprecedented events pushed crude oil storage near capacity and drove prices down
significantly in the second quarter of 2020. These events were the primary cause of the significant supply-and-demand
imbalance for oil, significantly lowering oil pricing in 2020 compared to the prior year. Throughout the United States
during 2020, COVID-19 outbreaks continued and, in some areas, increased. Should these conditions continue in future
periods, they could constrain our ability to store and move production to downstream markets, delay or curtail development
activity or temporarily shut-in production, any or all of which could further reduce our cash flow.

Hurricanes Impact on our Production. Beginning in the second quarter of 2020 and extending through October 2020,
the Gulf of Mexico experienced numerous hurricanes and tropical storms that required us to shut-in production at times due
to their impact. We have since returned substantially all wells to production that were shut-in due to the hurricanes and
tropical storms, as have operators of properties in which we have an interest. While no major structural damage occurred,
we incurred $4.7 million in repairs costs during 2020 associated with repairs to our assets caused by storm events in
2020. See “Risk Factors” – “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.”

During 2020, average realized commodity prices decreased from those we experienced during 2019. Our margins in
2020 decreased from 2019 primarily due to lower average realized commodity prices, partially offset by lower operating
expenses as a result of our cost-cutting efforts in 2020. We measure margins using net income (loss) 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; litigation; and
other (“Adjusted EBITDA”) as a percent of revenue, which is a not a financial measurement under generally accepted
accounting principles (“GAAP”).

Our production increased 3.8% in 2020 from the prior year. Our proved reserves decreased by 13.0 million barrels of oil
equivalent ("MMBoe") in 2020, primarily due to the significant decline in commodity prices in 2020 as compared to 2019.
MMBoe was computed on an equivalency ratio as described above. During 2020, we drilled one well which we expect to
complete in 2021.

We continue to closely monitor current and forecasted commodity prices to assess what changes, if any, should be
made to our 2021 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 2020, approximately 39% of our revenues were
received from BP Products North America, 13% to Williams Field Services and 10% to Mercuria Energy America Inc.
Trading (US) Co., with no other customer comprising greater than 10% of our 2020 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
volumes of physical products to customers.

Compliance with Government Regulations

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

regulations as legislation affecting the oil and natural gas industry is under constant review for amendment or
expansion. Numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued,
rules and regulations binding upon the oil and natural gas industry and its individual members. The Bureau of Ocean
Energy Management (“BOEM”) 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 entered office in January 2021 and 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, the Acting Secretary of the U.S. Department of the
Interior issued an order on January 20, 2021, effective immediately, that suspends new oil and gas leases and drilling
permits on federal lands and offshore waters, including the OCS for a period of 60 days. Building on this suspension,
President Biden issued an executive order on January 27, 2021 that suspends 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. While these January 20, 2021 and January 27, 2021 orders do not apply to existing leases,
the January 27, 2021 order further directs applicable agencies to take measures to eliminate provision of subsidies to the
fossil fuel industry, although the term "subsidies" is not defined by the adminstration. We continue to conduct our
operations on our existing leases in the OCS; however, uncertainty on future Biden Administration actions with regards 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 (“NTL”) #2016-N01 (“NTL #2016-N01”) to clarify the procedures and guidelines
that BOEM Regional Directors use to determine if and when additional financial assurances may be required for OCS
leases, rights of way (“ROWs”) and rights of use and easement (“RUEs”). While NTL #2016-N01 became effective in
September 2016, it was not fully implemented as the BOEM under the Trump Administration first extended indefinitely in
2017 implementation of the NTL and subsequently rescinded the NTL in the latter half of 2020, instead electing to publish
in October 2020 a proposed rule that would amend the BOEM’s financial assurance requirements. The Biden
Administration is expected to review and reconsider actions made under the Trump Administration with respect to
provision of financial assurance, including the rescission of NTL #2016-N01 and publication of the October 2020 proposed
rulemaking. Any issuance by the Biden Administration of more stringent NTL guidance or rules relating to the provision
of additional financial assurance may have a material adverse effect on us and similarly situated offshore oil and gas
operators on the OCS. Moreover, 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.

Unbundling. The ONRR has publicly announced an “unbundling” initiative to revise the methodology employed by

producers in determining the appropriate allowances for transportation and processing costs that are permitted to be
deducted in determining royalties under Federal oil and gas leases. The ONRR’s initiative requires re-computing allowable
transportation and processing costs using revised guidance from the ONRR going back 84 months for every gas processing
plant utilized during that period.

Regulation and transportation of natural gas. Our sales of natural gas are affected by the availability, terms and cost
of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. The FERC
has undertaken various initiatives to increase competition within the natural gas industry. As a result of initiatives like
FERC Order No. 636, issued in 1992, the interstate natural gas transportation and marketing system allows non-pipeline
natural gas sellers, including producers, to effectively compete with interstate pipelines for sales to local distribution
companies and large industrial and commercial customers. The most significant provisions of Order No. 636 require that
interstate pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural
gas supplies. In many instances, the effect of Order No. 636 and related initiatives have been to substantially reduce or
eliminate the interstate pipelines’ traditional role as wholesalers of natural gas in favor of providing only storage and
transportation services. The rates for such storage and transportation services are subject to FERC ratemaking authority,
and FERC exercises its authority either by 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. Our sales of liquids, which include crude oil, condensate and NGLs are not
currently regulated and are transacted at market prices. In a number of instances, however, the ability to transport and sell
such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction. The
price we receive from the sale of crude oil and NGLs is affected by the cost of transporting those products to market.
Interstate transportation rates for crude oil, condensate, NGLs and other products are regulated by the FERC. In general,
interstate crude oil, condensate and NGL pipeline rates must be cost-based, although settlement rates agreed to by all
shippers are permitted and market based rates may be permitted in certain circumstances. The FERC has established an
indexing system for such transportation, which generally allows such pipelines to take an annual inflation-based rate
increase.

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

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

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.
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; 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 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, on December 31, 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 NAAQS may be subject to revision under the Biden Administration.

In the United States, no comprehensive climate change legislation has been implemented at the federal level, but

President Biden is expected to issue executive orders or pursue legislative or regulatory actions to limit future GHG
emissions. For example, on January 20, 2021, President Biden issued an executive order committing the United States to
the Paris Agreement, from which the United States had withdrawn under the Trump Administration. President Biden has
called for the federal government to begin formulating the United States’ nationally determined emissions reduction goal
under the agreement, which may result in the issuance of GHG limitations in the future. Additionally, the threat of climate
change may result in litigation and financial risks. Litigation risks are increasing, as a number of states, municipalities and
other plaintiffs have sought to bring suit against the largest oil and natural gas exploration and production companies in
state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that
contributed to global warming effects and therefore are responsible for roadway and infrastructure damages as a result, or
alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their
investors by failing to adequately disclose those impacts. There are also increasing financial risks for fossil fuel producers
as well as other companies handling fossil fuels, as stockholders and bondholders currently invested in fossil fuel energy
companies 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 investors who provide financing to fossil fuel energy
companies also have become more attentive to sustainability lending practices and some of them may elect not to provide
funding for fossil fuel energy companies.

From a regulatory perspective, the EPA has determined that GHG emissions present a danger to public health and the
environment, and it has adopted regulations that, among other things, restrict emissions of GHG under existing provisions
of the CAA and may require the installation of control technologies to limit emissions of GHG. For example, in 2016, the
EPA under the Obama administration published a final rule establishing new source performance standards (“NSPS”) that
require new, modified, or reconstructed facilities in the oil and natural gas sector to reduce methane gas and volatile
organic compound emissions. The 2016 rule applies to any new or significantly modified facilities that we construct in the
future that would otherwise emit large volumes of GHG together with other criteria pollutants. The 2016 new source
performance standards regulate GHGs through limitations on emissions of methane. However, the EPA under the Trump

Administration has undertaken several measures, including publishing in September 2020 final rule policy and technical
amendments to the NSPS, for stationary sources of air emissions. The policy amendments, effective September 14, 2020,
notably removed the transmission and storage sector from the regulated source category and rescinded methane and volatile
organic compound requirements for the remaining sources that were established by former President Obama's
Administration, whereas the technical amendments, effective November 16, 2020, included changes to fugitive emissions
monitoring and repair schedules, recordkeeping and reporting requirements, and more. Various states and industry and
environmental groups are separately challenging both the original 2016 standards and the EPA's September 2020 final
rules, and on January 20, 2021, President Biden issued an executive order, that among other things, directed EPA to
reconsider the technical amendments and issue a proposed rule suspending, revising or rescinding those amendments by no
later than September 2021. A reconsideration of the September 2020 policy amendments is expected to follow. The
January 20, 2021 executive order also directed the establishment of new methane and volatile organic compound standards
applicable to existing oil and gas operations, including the production, transmission, processing and storage segments.
Certain of our operations are subject to EPA rules requiring the monitoring and annual reporting of GHG emissions from
specified offshore production sources.

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

On May 14, 2020, the BOEM issued its final rule to update air quality regulations applicable to activities authorized by

BOEM on the OCS in the Central and Western Gulf of Mexico. This newly revised rule adopted changes such as
incorporation of the definition of the NAAQS, updated Significance Levels (SLs), added new requirements for PM2.5 and
PM10, updates to emissions exemption thresholds and revision to the Air Quality Spreadsheets.

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 $150.0
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.

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 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 on January 7, 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. While the rule was scheduled to
become effective on February 8, 2021, the USFWS subsequently published notice on February 9, 2021, that it was delaying
the effective date of this rule until March 8, 2021, pursuant to the Biden Administration and in conformity with the
Congressional Review Act. 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, such as has occurred under the Biden
Administration’s DOI order issued on January 20, 2021 with respect to drilling permits, or cancellation of such programs.

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

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 require us to
evacuate personnel and shut in production until the 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.

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, 2020, our personnel base consisted of 303 of our employees and over 300 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 2020 total recordable incident rate (“TRIR”) for employees was 0.3, which is far below the
industry average for the Gulf of Mexico of 0.5. Our Health, Safety and Environmental (“HS&E”) group is comprised of a
Vice President, and Environmental, Safety and Regulatory Managers and 10 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.

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, and limiting headcount to 50% or less in our offices during peak COVID-19
outbreaks in the community.

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.

Diversity and Inclusion. The key to our past and future successes is promoting a workforce culture that embraces
integrity, honesty and transparency those we interact, 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, 2020:

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 %
17 %
48 %
9 %

80 %
83 %
52 %
91 %

Exec/Sr.
Manager

40 %
20 %
—
—
—
40 %

Mid-Level
Manager

Professionals All Other
—
12%
6%
5 %
24%
8%
7 %
12%
2%
1 %
—
—
1 %
—
2%
86 %
52%
82%

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:

● changes in global supply and demand for crude oil, NGLs and natural gas;
● events that impact global market demand (e.g. the reduced demand following the COVID-19 pandemic);
● the actions of the Organization of Petroleum Exporting Countries (“OPEC”) and major oil producing countries;
● 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;
● 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;
● 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 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, as we experienced in 2020. While we have not recorded an
impairment of our oil and gas properties during the year-ended December 31, 2020, 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, and as required under the

Sixth Amended and Restated Credit Agreement (the "Credit Agreement"), we enter into oil and natural gas price
commodity derivative positions with respect to a portion of our expected production. See Financial Statements and
Supplementary Data – Note 2 – Long-Term Debt under Part II, Item 8 in this Form 10-K for a full description the Credit
Agreement. 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, 2020, three fields, accounting for approximately 0.1
MMBoe (or 1%) of our 2020 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 32% of our total proved reserves as of
December 31, 2020 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 $150.0
million that can be used to cover costs that could be incurred in responding to an oil spill our facilities on the OCS. If OPA
is amended to increase the minimum level of financial responsibility, we may experience difficulty in providing financial
assurances sufficient to comply with this requirement.

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 – Hurricane
Remediation, Insurance Claims and 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, 2020.

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 have
significantly reduced global economic activity, resulting in a decline in the demand for oil, natural gas, and other
commodities. These economic consequences have been a primary cause of the significant supply-and-demand imbalance
for oil. The current supply-and-demand imbalance and significantly lower oil pricing 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.

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 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 Executive Officers of the Registrant under Part I
following Item 3 in 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,
which may be reduced by our lenders. 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, 2020, we had $632.5 million in principal of indebtedness outstanding and $4.4 million of letters of

credit obligations outstanding, substantially all of which is secured. During 2020, we incurred $61.5 million in interest
expense. 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;

●

impair our ability to obtain additional financing 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 lenders’ 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 and Credit Agreement governing our indebtedness contain a number of significant restrictive covenants

in addition to covenants restricting the incurrence of additional debt. These covenants limit our ability and the ability of
our restricted subsidiaries, among other things, to:

● make loans and investments;
●
●
●
●
●
●
●
●

incur additional indebtedness or issue preferred stock;
create certain liens;
sell assets;
enter into agreements that restrict dividends or other payments from our restricted subsidiaries to us;
consolidate, merge or transfer all or substantially all of the assets of 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 or reduce our debt. These restrictions may also limit our ability to obtain future financings, withstand a
future downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We may
also be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us from
the restrictive covenants under our indentures governing our outstanding notes.

A breach of any covenant in the agreements governing our debt would result in a default under such agreement after

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

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.

All of our existing indebtedness under our Credit Agreement and our outstanding Second Lien Senior Notes is secured
by liens on substantially all of our oil, natural gas and NGL properties. In addition, we have certain rights to issue or incur
additional or new secured debt, including up to $105.6 million as of January 6, 2021, available for borrowing under our
Credit Agreement following the most recent redetermination, that would be secured by additional liens on the collateral and
an issuance or incurrence of such additional secured debt would dilute the value of the collateral securing our outstanding
secured debt. If the proceeds of any sale of the collateral are not sufficient to repay all amounts due in respect of our
secured debt, then claims against our remaining assets to repay any amounts still outstanding under our secured obligations

would be unsecured and our ability to pay our other unsecured obligations and any distributions in respect of our capital
stock would be significantly impaired.

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 recent election of President Biden and changes in U.S. Congress may result in significant legislative and regulatory
changes that could adversely affect our results of operations, and our ability to implement our business strategy.

Recently elected President Biden has indicated that his administration will pursue regulatory initiatives, executive
actions and legislation in support of his regulatory and political agenda, which includes the reduction in dependence on, and
use of, fossil fuels and curtailment of hydraulic fracturing on federal lands in response to climate change and other
environmental risks. 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. Under certain circumstances, U.S.
federal agencies may refuse to approve new leases for hydrocarbon exploration and development on federal lands and
waters and may refuse to grant or delay approvals required for development of existing leases on such lands and waters.
See Part I, Item 1. “Business – Compliance with Environmental Regulations” for more discussion on orders and regulatory
initiatives impacting the oil and natural gas industry that are being 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
Administration had sought to implement more stringent and costly standards under the existing federal financial assurance
requirements through issuance and implementation of NTL #2016-N01, but former President Trump’s Administration first
paused, and then in 2020 rescinded, the implementation of this NTL while the BOEM issued a proposed rulemaking in
October 2020 to amend its financial assurance program. The BOEM under the Biden Administration may in the future
reconsider offshore financial assurance requirements, including the rescinded NTL #2016-N01 and the October 2020
proposed rule, and adopt and implement more stringent requirements. Moreover, the BOEM could make 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.

President Biden and one or more of agencies under his administration has issued orders temporarily suspending leasing

or permitting of oil and natural gas activities on federal lands and waters, including the OCS, and his administration is
expected to pursue additional orders, legislation and regulatory initiatives 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, in recent years under the Trump
Administration, there have been actions by BSEE or BOEM seeking to mitigate or delay certain of those more rigorous
standards, we expect that the Biden Administration may reconsider rules and regulatory initiatives implemented under the
Trump Administration. Compliance with any added and more stringent regulatory requirements and with 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, these 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. For example, under the Trump
Administration, BSEE reviewed and delayed or revised certain offshore regulations implemented during the Obama
Administration with respect to the imposition of rigorous standards relating to well control. In light of the statements made
by President Biden, there exists a significant risk that these Obama-era regulations, or additional, more stringent regulations
impacting our business, properties and results of operations could be reimplemented or adopted during the Biden
Administration.

These regulatory actions, or any new rules, regulations, or legal 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 Environmental Regulations” for more
discussion on orders and regulatory initiatives impacting the oil and natural gas industry that are being pursued under the
Biden Administration.

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

We are required to record a liability for the present value of our ARO to plug and abandon inactive non-producing
wells, to remove inactive or damaged platforms, and inactive or damaged facilities and equipment, collectively referred to
as “idle iron,” and to restore the land or seabed at the end of oil and natural gas production operations. In December 2018,
BSEE issued an updated NTL reaffirming the obligations of offshore operators to timely decommission idle iron by means
of abandonment and removal. Pursuant to the idle iron NTL requirements, in September 2019, BSEE issued us letters,
directing us to plug and abandon certain wells that the agency identified as no longer capable of production in paying
quantities by specified timelines, with the earliest deadline being December 31, 2020. In response, we are currently

evaluating the list of wells proposed as idle iron by BSEE and currently anticipate that those wells determined to be idle
iron will be decommissioned by the specified timelines or at times as otherwise determined by BSEE following further
discussions with the agency. While we have established AROs for well decommissioning, additional AROs, significant in
amount, may be necessary to conduct plugging and abandonment of the wells designated by BSEE as idle iron, but we do
not expect the costs to plug and abandon these 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 2018 NTL 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.

The 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 otherwise 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 property interests that were sold several years prior. These indirect
obligations would affect our costs, operating profits and cash flows negatively and could be substantial.

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 – Regulation 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 – 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.

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, 2020,
three of our fields located in the conventional shelf accounted for approximately 82% our proved reserves on an energy
equivalent basis. The following table provides information for these fields:

Proved Reserves as of December 31, 2020

Mobile Bay Properties

(MMBbls)
0.1

Ship Shoal 349 (Mahogany)

15.8

Fairway

—

Oil

NGLs

Natural Gas
(Bcf)

(MMBbls)
11.9

403.3

79.3

Oil
Equivalent
(MMBoe)

Percent of
Total
Company
Proved
Reserves

1.8

2.2

40.3

24.3

75.0

14.7

54.9%

16.8%

10.2%

The Mobile Bay Properties, Ship Shoal 349 (Mahogany), and Fairway are three 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 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. The field area includes 16 Alabama state water lease
blocks and four Federal OCS lease blocks. These properties include seven major platforms and 27 flowing wells, in up to
50 feet of water. Exxon first discovered Norphlet gas play in 1978 with the first gas production from the Mary Ann Field
in 1988. We acquired varied operated working interests 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 2020, we completed
the purchase of the remaining interest in two federal Mobile Bay fields from Chevron U.S.A. Inc. ("Chevron"). Cumulative
field production through 2020 is approximately 698.3 MMBoe gross. The Mobile Bay Properties produce from the
Jurassic age Norphlet eolian sandstone at an average depth of 21,000’ total vertical depth. As of December 31, 2020, 56
Norphlet wells have been drilled on the Mobile Bay Properties, 45 wells were successful and 27 wells are currently
producing.

We acquired the Mobile Bay Properties in August 2019 and included the results of operations effective September 1,
2019 within our Consolidated Results of Operations. During September 2019 to December 2019, transitioning activities
occurred to transfer operatorship of the Mobile Bay Properties from Exxon to W&T. (Given the limited history and the
change in operatorship, production volumes, realized prices received and production costs are omitted.)

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 in
the Joint Venture Drilling Program. Cumulative field production through 2020 is approximately 56.6 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,
2020, 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 was no additional drilling activity during 2020 at Ship Shoal 349.

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

349 field over the past three years:

Net Sales:

Oil (MBbls)
NGLs (MBbls)
Natural gas (MMcf)
Total oil equivalent (MBoe)
Total natural gas equivalents (MMcfe)
Average daily equivalent sales (Boe/day)
Average daily equivalent sales (Mcfe/day)

Average realized sales prices:

Oil ($/Bbl)
NGLs ($/Bbl)
Natural gas ($/Mcf)
Oil equivalent ($/Boe)
Natural gas equivalent ($/Mcfe)

Average production costs: (1)

Oil equivalent ($/Boe)
Natural gas equivalent ($/Mcfe)

Year Ended December 31,
2019

2020

2018

1,939
148
3,015
2,590
15,539
7,076
42,456

36.69 $
14.46
1.92
30.54
5.09

4.98 $
0.83

2,444
154
3,955
3,257
19,545
8,925
53,547

58.27 $
21.96
2.53
47.84
7.97

4.77 $
0.79

1,719
167
2,508
2,307
13,841
6,320
37,920

62.83
31.14
3.41
52.78
8.80

4.87
0.81

(1) Includes lease operating expenses and gathering and transportation costs.

Fairway Field

The Fairway Field is comprised of Mobile Bay Area blocks 113 (Alabama State Lease #0531) and 132 (Alabama

State Lease #0532) located in 25 feet of water, approximately 35 miles south of Mobile, Alabama. 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. (“Shell”) in August 2011 and acquired the remaining working interest of
35.7% in September 2014. Cumulative field production through 2020 is approximately 136.4 MMBoe gross. The field
was discovered in 1985 with Well 113 #1 (now called JA). Development drilling began in 1990 and was completed in
1991 with the addition of four wells, each drilled from separate surface locations. The five producing wells came on
line in late 1991. As of December 31, 2020, six wells have been drilled, one of which was a replacement well. This
field is a Norphlet sand dune trend development with one producing horizon at an approximate depth of 21,300 feet.

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

Net Sales:

Oil (MBbls)
NGLs (MBbls)
Natural gas (MMcf)
Total oil equivalent (MBoe)
Total natural gas equivalents (MMcfe)
Average daily equivalent sales (Boe/day)
Average daily equivalent sales (Mcfe/day)

Average realized sales prices:

Oil ($/Bbl)
NGLs ($/Bbl)
Natural gas ($/Mcf)
Oil equivalent ($/Boe)
Natural gas equivalent ($/Mcfe)

Average production costs: (1)

Oil equivalent ($/Boe)
Natural gas equivalent ($/Mcfe)

Year Ended December 31,
2019

2020

2018

9
265
5,329
1,162
6,973
3,175
19,051

38.52 $
8.43
1.94
11.12
1.85

11.35 $
1.89

9
305
5,918
1,300
7,802
3,563
21,375

62.25 $
15.83
2.52
15.61
2.60

10.77 $
1.80

9
315
5,673
1,270
7,621
3,480
20,880

66.63
24.93
3.12
24.54
4.09

9.38
1.56

(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, 2020 are summarized below:

Classification of Proved
Reserves (1)
Proved developed producing
Proved developed non-producing

Total proved developed

Proved undeveloped

Total proved

Oil
(MMBbls)
19.4
4.6
24.0
8.2
32.2

NGLs
(MMBbls)

Natural
Gas
(Bcf)

0.9

15.6 510.4
39.8
16.5 550.2
19.1
17.4 569.3

0.9

Total Energy-Equivalent
Reserves (2)
Natural
Gas
Equivalent
(Bcfe)

Oil
Equivalent
(MMBoe)
120.1
12.1
132.2
12.2
144.4

% of
Total
Proved

PV-10
(In
millions)
83 % $ 573.0
73.7
646.7
94.2
100 % $ 740.9

8 %
91 %
9 %

720.4
72.9
793.3
73.2
866.5

(1) In accordance with guidelines established by the SEC, our estimated proved reserves as of December 31, 2020 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, 2020. Applying this methodology, the West Texas Intermediate ("WTI") average spot
price of $39.54 per barrel and the Henry Hub natural gas average spot price of $1.985 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 realized prices were $37.78 per barrel for oil, $10.29 per barrel for NGLs and $2.05 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) 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.

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 of discounted future net cash flows

Changes in Proved Reserves

December 31,
2020

740.9
(204.2)
536.7
(43.0)
493.7

Our total proved reserves at December 31, 2020 were 144.4 MMBoe compared to 157.4 MMBoe at December 31,
2019, representing an overall decrease of 13.0 MMBoe. Total proved reserves decreased by 27.7 MMBoe as a result of
lower commodity prices and 15.4 MMBoe due to production. Partially offsetting these decreases were increases in proved
reserves of 26.2 MMBoe due to positive technical revisions (including increased well performance), 3.6 MMBoe related to
acquisitions, 0.2 MMBoe related to extensions and discoveries. See Development of Proved Undeveloped Reserves below
for a table reconciling the change in proved undeveloped reserves during 2020. See Financial Statements and
Supplementary Data– Note 20 – Supplemental Oil and Gas Disclosures under Part II, Item 8 in this Form 10-K for
additional information.

Our estimates of proved reserves, PV-10 and the standardized measure as December 31, 2020 are calculated based
upon SEC mandated 2020 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 2020 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.

Qualifications of Technical Persons and Internal Controls over Reserves Estimation Process

Our estimated proved reserve information as of December 31, 2020 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.

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, 2020 were estimated at $94.2 million.

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

2020

December 31,
2019

2018

Proved undeveloped reserves, beginning of year

23.6

17.0

12.0

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

—
(11.4)
—
—
—
12.2

(0.5)
7.1
—
—
—
23.6

(5.0)
11.3
—
2.2
(3.5)
17.0

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

Year Scheduled for Development
2021
2022
2023
2024
Total

Activity related to PUD in 2020:

Number of
PUD Locations
1
2
1
1
5

Percentage of
PUD Reserves
Scheduled to be
Developed

22 %
15 %
59 %
4 %
100 %

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

We believe that we will be able to develop all but 2.3 MMBoe (approximately 19%) of the total 12.2 MMBoe

classified as PUDs at December 31, 2020, within five years from the date such PUDs were initially
recorded. The 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. One sidetrack PUD location at each Matterhorn and Virgo, will be delayed until an
existing well are 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 2022 and 2024.

Acreage

The following table summarizes our leasehold at December 31, 2020. Deepwater refers to acreage in over 500 feet of

water:

Developed Acreage
Net
Gross
311,370
62,067
373,437

427,222
159,209
586,431

Undeveloped Acreage
Gross

Gross

Total Acreage

99,551
50,451
150,002

Net
86,788
45,651
132,439

526,773
209,660
736,433

Net
398,158
107,718
505,876

Shelf
Deepwater
Total

Approximately 74% 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 132,439 net undeveloped acres none could expire in 2021; 960 net

acres (1%) could expire in 2022; 37,166 net acres (28%) could expire in 2023; 80,293 net acres (60%) could expire in
2024; and 14,020 net acres (11%) could expire in 2025 and beyond. In making decisions regarding drilling and operations
activity for 2020 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 41,688 net acres (8%) from December 31, 2019 due to lease expirations and

relinquishments, partially offset by acquisitions.

Production

For the years 2020, 2019 and 2018, our net daily production averaged 42,046 Boe, 40,634 Boe, and 36,510 Boe,

respectively. Production increased in 2020 from 2019 primarily due a full year of production at the Mobile Bay
properties. 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:

Net Sales:

Oil (MBbls)
NGLs (MBbls)
Oil and NGLs (MBbls)
Natural gas (MMcf)
Total oil equivalent (MBoe)
Total natural gas equivalents (MMcfe)

Year Ended December 31,
2019

2018

2020

5,629
1,696
7,325
48,384
15,389
92,334

6,675
1,271
7,946
41,310
14,831
88,987

6,687
1,307
7,994
31,991
13,326
79,956

Productive Wells

The following presents our ownership interest at December 31, 2020 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:

Offshore Wells

Oil Wells (1)

Gas Wells (2)

Total Wells

Gross

Net

Gross

Net

Gross

Net

Operated
Non-operated

Total offshore wells

85
39
124

74.1
8.4
82.5

67
22
89

58.8
7.8
66.6

152
61
213

132.9
16.2
149.1

(1) Includes six gross (4.2 net) oil wells with multiple completions.

(2) Includes three gross (2.5 net) gas wells with multiple completions.

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:

Development Wells Completed:

Gross wells
Net wells

Exploration Wells Completed:

Gross wells
Net wells

Year Ended December 31,
2019

2018

2020

—
—

3.0
1.6

3.0
0.8

3.0
1.5

3.0
1.3

Our success rates related to our development and exploration wells drilled was 100% in both 2019 and 2018, with all

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

Recent Drilling Activity

During 2020, we drilled one well, which we expect to be completed in 2021.

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.

Item 3. Legal Proceedings

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 penal sum of the bond posted is currently $8.2 million.

Monetary Sanctions by Government Authorities (Notices of Proposed Civil Penalty Assessment). During 2020 and

2019, we did not pay any civil penalties to the Bureau of Safety and Environmental Enforcement (“BSEE”) related to
Incidents of Noncompliance (“INCs”) at various offshore locations. 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, with the first installment due in March 2021. In addition, W&T committed
to implement a Safety Improvement Plan with various deliverables due over a period ending in 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.

Executive Officers of the Registrant

The following table lists our executive officers:

Name
Tracy W. Krohn
Janet Yang
William J. Williford
Stephen L. Schroeder
Shahid A. Ghauri

Age (1)
66
40
48
58
52

Position

Chairman, Chief Executive Officer and President
Executive Vice President and Chief Financial Officer
Executive Vice President and General Manager of Gulf of Mexico
Senior Vice President and Chief Technical Officer
Vice President, General Counsel and Corporate Secretary

(1) Ages as of February 23, 2021

Tracy W. Krohn has served as our Chief Executive Officer since he founded the Company in 1983, President from

1983 until 2008 and again starting in March 2017, Chairman of the Board since 2004 and Treasurer from 1997 until
2006. During 1996 to 1997, Mr. Krohn was Chairman and Chief Executive Officer of Aviara Energy Corporation. He
began his career as a petroleum engineer and offshore drilling supervisor with Mobil Oil Corporation and then as Senior
Engineer with Taylor Energy Company. Mr. Krohn serves on the board of directors for the American Petroleum Institute.
He also serves on the board of directors of a privately owned company.

Janet Yang joined the Company in 2008 and was named Executive Vice President and Chief Financial Officer in

November 2018. Previously, she served as Acting Chief Financial Officer from August 2018 to November 2018, Vice
President – Corporate and Business Development from March 2017 to November 2018, Director Strategic Planning &
Analysis from June 2012 to March 2017 and Finance Manager from December 2008 to June 2012. Prior to joining the
Company, Ms. Yang held positions in research and investment analysis at BlackGold Capital Management, investment
banking at Raymond James and energy trading at Allegheny Energy.

William J. Williford joined the Company in 2006 and was named Executive Vice President and General Manager of
Gulf of Mexico in November 2018. Since joining W&T in 2006, he has served as Reservoir Engineer, Exploration Project
Manager, General Manager Deepwater of Gulf of Mexico, and most recently, Vice President and General Manager of Gulf
of Mexico Shelf and Deepwater. Mr. Williford has over 20 years of oil and gas technical experience with large
independents in the Gulf of Mexico and Domestic Onshore. Prior to joining the Company, Mr. Williford held positions in
reservoir, production and operations at Kerr-McGee and Oryx Energy.

Stephen L. Schroeder joined the Company in 1998 and was named Senior Vice President and Chief Technical Officer

in June 2012. Previously, he served as Senior Vice President and Chief Operating Officer from July 2006 to June 2012,
Vice President of Production from 2005 to July 2006 and Production Manager from 1999 until 2005. Prior to joining the
Company, Mr. Schroeder was with Exxon USA for 12 years holding positions of increasing responsibility, ending with
Offshore Division Reservoir Engineer.

Shahid A. Ghauri joined the Company in March 2017 as Vice President, General Counsel and Corporate

Secretary. Prior to joining the Company, Mr. Ghauri served as a partner with Jones Walker, a New Orleans, Louisiana law
firm since 2015. Prior to that, Mr. Ghauri served as Assistant General Counsel of BHP Billiton Petroleum and in private
practice as a partner working with top tier oil and gas firms for 17 years.

Our management team's interests are highly aligned with those of our shareholders through our 34% stake in the

Company's equity.

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 2, 2021, there

were 172 registered holders of our common stock.

Dividends

During 2020 and 2019, 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 – Long-Term 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.

Our peer group was revised in 2020 ("New Peer Group") to be in alignment with the peer group used for executive
compensation analysis. The New Peer Group no longer includes Abraxas Petroleum Corporation and Comstock Resources;
however, Bonanza Creek Energy Inc.; Earthstone Energy Inc.; Gran Tierra Energy Inc.; Gulfport Energy Corporation;
Highpoint Resources Corporation; Kosmos Energy Ltd.; Laredo Petroleum, Inc.; Northern Oil and Gas, Inc.; and Ring
Energy, Inc. are still included. Companies used in the most recent executive compensation analysis but were excluded due
to not having a five year trading history were Talos Energy, Inc.; Berry Corporation; SilverBow Resources, Inc.; Penn
Virginia Corporation; and Centennial Resource Development, Inc. Montage Resources Corporation was included in our
compensation analysis, but excluded from the above graph as their stock was not traded during all of 2020 due to being
acquired by Southwestern Energy Company. Additionally, the New Peer Group includes QEP Resources, Inc.

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 2020, 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, 2020:

Maximum
Number (or
Approximate
Dollar
Value) of
Shares that
May Yet be
Purchased
Under the
Plans or
Programs
N/A
N/A
N/A

Total
Number of
Shares
Purchased as
Part of
Publicly
Announced
Plans or
Programs
N/A
N/A
N/A

Total
Number of
Restricted
Stock Units
Delivered

N/A
N/A
260,751 $

Average
Price per
Restricted
Stock Unit
N/A
N/A
2.57

Period
October 1, 2020 – October 31, 2020
November 1, 2020 – November 30, 2020
December 1, 2020 – December 31, 2020 (1)

(1) RSUs delivered by employees during December 2020 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, 2020 that we

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

Item 6. Selected Financial Data

SELECTED HISTORICAL FINANCIAL INFORMATION

The selected historical financial information set forth below should be read in conjunction with Management’s
Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 and with Financial
Statements and Supplementary Data under Part II, Item 8 in this Form 10-K:

Consolidated Statement of Operations

2020

Year Ended December 31,
2018
(In thousands, except per share data)

2019

2017

2016

Information:

Revenues:

Oil
NGLs
Natural gas
Other

Total revenues

Operating costs and expenses:
Lease operating expenses
Production taxes
Gathering and transportation
Depreciation, depletion and amortization
Asset retirement obligations accretion
Ceiling test write-down of oil and natural gas

properties

General and administrative expenses
Derivative (gain) loss

Total costs and expenses
Operating income (loss)

216,419 $ 399,790 $ 438,798 $
37,127
22,373
99,629
106,347
6,386
5,152
580,706
534,896

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

162,857
4,918
16,029
97,763
22,521

-
41,745
(23,808)
322,025
24,609

184,281
2,524
25,950
129,038
19,460

-
55,107
59,887
476,247
58,649

153,262
1,832
22,382
131,423
18,431

-
60,147
(53,798)
333,679
247,027

340,010 $
32,257
108,923
5,906
487,096

143,738
1,740
20,441
138,510
17,172

268,950
26,429
100,405
4,202
399,986

152,399
1,889
22,928
194,038
17,571

-
59,744
(4,199)
377,146
109,950

279,063
59,740
2,926
730,554
(330,568)

Interest expense, net
Gain on debt transactions
Other expense (income), net
(Loss) income before income tax (benefit)
expense
Income tax (benefit) expense
Net income (loss)
Basic and diluted earnings (loss) per common

61,463
(47,469)
2,978

59,569
-
188

48,645
(47,109)
(3,871)

45,521
(7,811)
5,127

84,382
(123,923)
1,369

7,637
(30,153)
37,790 $

249,362
(1,108)
535
(75,194)
74,086 $ 248,827 $

(292,396)
67,113
(43,376)
(12,569)
79,682 $ (249,020)

0.26 $

0.52 $

1.72 $

0.56 $

(2.60)

SELECTED HISTORICAL FINANCIAL INFORMATION
(continued)

2020

2019

Year Ended December 31,
2018
(In thousands)

2017

2016

Consolidated Cash Flow Information:
Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by (used in) financing

activities

108,509 $ 232,227 $ 321,763 $
(66,385)
(313,814)
(47,616)

159,408 $
(107,107)

14,180
(82,396)

(49,600)

80,727

(321,143)

(23,479)

53,038

2020

2019

December 31,
2018
(In thousands)

2017

2016

Consolidated Balance Sheet Information:
Cash and cash equivalents
Oil and natural gas properties and other, net (1)
Total assets (1)
Long-term debt (including current portion)
Shareholders' deficit (1)

32,433 $
43,726 $
686,878
748,798
940,582 1,003,719
719,533
625,286
(249,365)
(208,286)

33,293 $
515,421
848,866
633,535
(324,796)

70,236
99,058 $
547,053
579,016
907,580
829,726
992,052 1,020,727
(659,037)
(573,508)

(1) Ceiling test write-downs of $279.1 million was recorded in 2016.

HISTORICAL RESERVE AND OPERATING INFORMATION

The following tables present summary information regarding our estimated net proved oil, NGLs and natural gas
reserves and our historical operating data for the years shown below. Estimated net proved reserves are based on the
unweighted average of first-day-of-the-month commodity prices over the period January through December of the
respective year in accordance with SEC guidelines. For additional information regarding our estimated proved reserves,
please read Business under Part I, Item 1 and Properties under Part I, Item 2 of this Form 10-K. The selected historical
operating data set forth below should be read in conjunction with Management’s Discussion and Analysis of Financial
Condition and Results of Operations under Part II, Item 7 and with Financial Statements and Supplementary Data under
Part II, Item 8 in this Form 10-K:

Reserve Data: (1)
Estimated net proved reserves

Oil (MMBbls)
NGLs (MMBbls)
Natural Gas (Bcf)
Total barrel equivalents (MMBoe)
Total natural gas equivalents (Bcfe)
Proved developed producing (MMBoe)
Proved developed non-producing (MMBoe)
Total proved developed (MMBoe)
Proved undeveloped (MMBoe)

Proved developed reserves as %
Reserve additions (reductions) (MMBoe):

Revisions (2)
Extensions and discoveries
Purchases of minerals in place
Sales of minerals in place (3)
Production

Net reserve additions (reductions)

2020

2019

December 31,
2018

2017

2016

32.2
17.4
569.3
144.4
866.5
120.1
12.1
132.2
12.2
91.6 %

(1.4 )
0.2
3.6
—
(15.4 )
(13.0 )

37.8
24.5
571.1
157.4
944.5
122.3
11.5
133.8
23.6
85.0%

(3.0)
1.1
90.1
—
(14.8)
73.4

39.1
9.8
210.5
84.0
504.1
53.9
13.1
67.0
17.0
79.8 %

21.1
2.1
3.4
(3.5 )
(13.3 )
9.8

34.4
7.8
192.2
74.2
445.3
54.5
7.7
62.2
12.0
83.8 %

9.6
5.2
—
—
(14.6 )
0.2

32.9
8.2
197.8
74.0
444.0
47.3
17.4
64.7
9.3
87.4 %

13.0
—
—
—
(15.4 )
(2.4 )

(1) The conversions to barrels of oil equivalent and cubic feet equivalent were determined using the energy equivalency

ratio of six Mcf of natural gas to one barrel of crude oil, condensate or NGLs (totals may not compute due to
rounding). The conversion ratio does not assume price equivalency, and the price on an equivalent basis for oil,
NGLs and natural gas may differ significantly.

(2) Revisions include changes due to price estimated for reserves held at year-end for each year presented. Revisions in
2020 include estimated price revisions for all proved reserves and incorporate the impact of price change of the
purchase of minerals in place from the date of purchase to December 31, 2020.

(3) In 2018, sales of minerals in place primarily relate to conveyance of interest in properties to Monza.

See Financial Statements and Supplementary Data– Note 20 – Supplemental Oil and Gas Disclosures under Part II,

Item 8 in this Form 10-K for additional information.

HISTORICAL RESERVE AND OPERATING INFORMATION
(continued)

2020

Year Ended December 31,
2018

2017

2019

2016

Operating: (1)
Net sales:
Oil (MBbls)
NGLs (MBbls)
Oil and NGLs (MBbls)

Natural gas (MMcf)
Total oil equivalent (MBoe)
Total natural gas equivalents (MMcfe)
Average daily equivalent sales (Boe/day)
Average daily equivalent sales (Mcfe/day)
Average realized sales prices:

Oil ($/Bbl)
NGLs ($/Bbl)
Oil and NGLs ($/Bbl)
Natural gas ($/Mcf)
Oil equivalent ($/Boe)
Natural gas equivalent ($/Mcfe)
Average per Boe ($/Boe):

Lease operating expenses
Gathering and transportation

Production costs

Production taxes
DD&A (2)
General and administrative expenses

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

Production costs

Production taxes
DD&A (2)
General and administrative expenses

Wells drilled (gross) (3)

Productive wells drilled (gross) (3)

5,629
1,696
7,325
48,384
15,389
92,334
42,046
252,279

6,675
1,271
7,946
41,310
14,831
88,987
40,634
243,801

6,687
1,307
7,994
31,991
13,326
79,956
36,510
219,057

7,064
1,382
8,446
36,754
14,571
87,428
39,921
239,528

7,201
1,542
8,743
39,731
15,365
92,188
41,980
251,879

38.45 $
11.26
32.15
2.05
21.76
3.63

10.58 $
1.04
11.62
0.32
7.82
2.71
22.47 $

1.76 $
0.17
1.93
0.05
1.30
0.45
3.73 $

—

59.89 $
17.60
53.13
2.57
35.63
5.94

12.43 $
1.75
14.18
0.17
10.01
3.72
28.08 $

2.07 $
0.29
2.36
0.03
1.67
0.62
4.68 $

65.62 $
28.40
59.53
3.11
43.19
7.20

11.50 $
1.68
13.18
0.14
11.24
4.51
29.07 $

2.30 $
0.32
2.62
0.03
1.86
0.69
5.20 $

48.13 $
23.35
44.08
2.96
33.02
5.50

9.86 $
1.40
11.26
0.12
10.68
4.10
26.16 $

1.75 $
0.26
2.01
0.02
1.71
0.69
4.43 $

37.35
17.14
33.79
2.53
25.76
4.29

9.92
1.49
11.41
0.12
13.77
3.89
29.19

1.56
0.22
1.78
0.02
1.69
0.65
4.14

(1) The conversions to barrels of oil equivalent and cubic feet equivalent were determined using the energy equivalency

(2) DD&A - depreciation, depletion, amortization and accretion

(3) Wells drilled in the above table are all offshore wells.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis 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 Form 10-K. The following discussion includes forward-
looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those
discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are
not limited to, those discussed below and elsewhere in this Form 10-K, particularly in Risk Factors under Part I, Item 1A in
this Form 10-K.

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 (41 producing fields and
2 capable of producing). We currently have under lease approximately 737,000 gross acres (506,000 net acres) spanning
across the OCS off the coasts of Louisiana, Texas, Mississippi and Alabama, with approximately 527,000 gross acres on
the conventional shelf and approximately 210,000 gross acres in the deepwater. A majority of our daily production is
derived from wells we operate. We currently own interests in 146 offshore structures, 105 of which are located in fields
that we operate. We currently own interest in 213 productive wells, 152 of which we operate. Our interest in fields, leases,
structures and equipment are primarily owned by W&T Offshore, Inc. and our wholly-owned subsidiary, W & T Energy
VI, LLC, a Delaware limited liability company and through our proportionately consolidated interest in Monza, as
described in more detail in Financial Statements and Supplementary Data – Note 4 – Joint Venture Drilling Program under
Part II, Item 8 in this Form 10-K.

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

● 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

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 2020, average
realized commodity prices decreased from those we experienced during 2019 and 2018. Our margins in
2020 decreased from 2019 primarily due to lower average realized commodity prices, partially offset by lower operating
expenses as a result of our cost-cutting efforts in 2020. 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
increased 3.8% in 2020 from the prior year. Our proved reserves decreased by 13.0 MMBoe in 2020, primarily due to the
significant decline in commodity prices in 2020 as compared to 2019. During 2020, we drilled one additional well which
we expect to be completed in 2021.

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

Acquisition of the Mobile Bay Properties. In August 2019, we acquired the Mobile Bay Properties with the purchase

of Exxon's 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. After taking into account customary
closing adjustments and an effective date of January 1, 2019, cash consideration was $169.8 million. See Financial
Statements and Supplementary Data – Note 5 – Acquisitions and Divestures under Part II, Item 8 in this Form 10-K for a
full description of the acquisition.

As of December 31, 2020, the Mobile Bay Properties had approximately 79.3 MMBoe of net proved reserves, of
which 98% were proved developed producing reserves consisting primarily of natural gas and NGLs with 15% of the
proved net reserves from liquids on an MMBoe basis, based on SEC pricing methodology. For 2020, the average
production of the Mobile Bay Properties was approximately 15,400 net Boe per day. The properties include working
interests in nine Gulf of Mexico offshore producing fields and an onshore treatment facility that are adjacent to existing
properties owned and operated by us. With this purchase, we became the largest operator in the area. The Mobile Bay
Properties accounted for 37% of our production measured on an MMBoe basis in 2020.

Income tax benefit (expense). Deferred tax assets are recorded related to net operating losses (“NOL”) 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 NOLs 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 reduction of the valuation allowance in recent years has resulted in increases to net income that may not be
indicative of future periods. See Financial Statements and Supplementary Data – Note 12 – Income Taxes under Part II,
Item 8 in this Form 10-K for additional information.

Known Trends and Uncertainties

COVID-19. Due to circumstances related to the outbreak of COVID-19, various measures have been taken by federal,
state and local governments to reduce the rate of spread of COVID-19. These measures and other factors have resulted in a
decrease of general economic activity and a corresponding decrease in global and domestic energy demand impacting
commodity pricing. In addition, actions by the Organization of Petroleum Exporting Countries and other high oil exporting
countries like Russia (“OPEC+”) have negatively impacted crude oil prices in early 2020. These rapid and unprecedented
events pushed crude oil storage near capacity and drove prices down significantly in the second quarter of 2020. These
events have been the primary cause of the significant supply-and-demand imbalance for oil, significantly lowering oil
pricing in 2020 compared to the prior year. Through February 2021, COVID-19 outbreak levels continued and, in some
cases, increased in some areas of the United States. Should these conditions continue in future periods, they could
constrain our ability to store and move production to downstream markets, delay or curtail development activity or
temporarily shut-in production, any or all of which could further reduce our cash flow.

Volatility in Oil, NGL and Natural Gas Prices. Our realized sales prices received for our crude oil, NGLs and natural

gas production are affected by not only domestic production activities and political issues, but more importantly,
international events, including both geopolitical and economic events. During 2020, crude oil, NGLs and natural gas
average realized prices were below 2019 realized prices, decreasing 35.8%, 36.0% and 20.1%, respectively.

Prolonged period of weak commodity prices like we experienced during 2020 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.

Selected issues and data points related to crude oil, NGLs and natural gas markets are described below.

As reported by the U.S. Energy Information Administration (“EIA”) in their Short-Term Energy Outlook issued in
February 2021 (“STEO”), worldwide production of petroleum and other liquids was estimated to have decreased by 6.4%
in 2020 over the prior year, as compared to no year-over-year production growth for 2019 and a 3.1% increase in year-
over-year production growth for 2018. The decrease was due primarily to lower levels of drilling and production
curtailments by OPEC and other producers in response to lower oil prices. Consumption for 2020 decreased 8.4% over
2019, largely due to reduced economic activity from the COVID-19 pandemic.

EIA's forecasts for production, consumption, crude oil prices and natural gas prices for 2021 remain subject to
heightened levels of uncertainty because responses to COVID-19 continue to evolve. The EIA forecasts worldwide
production of petroleum and other liquids year-over-year increases for 2021 and 2022 to be 3.3% and 3.6%,
respectively. The expected increase is due primarily to increases in drilling activity in the U.S. in recent
months. Consumption for 2021 and 2022 is estimated to increase year-over-year by 5.8% and 3.6%, respectively, as a
result of the roll-out of COVID-19 vaccines. According to EIA, U.S. crude oil production (excluding other petroleum
liquids) decreased 7.6% in 2020 over 2019, and is expected to decrease year-over-year in 2021 by 2.6% and increase year-
over-year in 2022 by 4.6%. For the U.S., net imports of crude oil in the U.S. fell by 28.9% in 2020 compared to 2019 and
are expected to increase by 36.2% in 2021 from 2020.

The two primary benchmarks for our average realized crude oil sales prices are the prices for WTI and Brent crude

oil. As reported by the EIA, WTI crude oil prices averaged $39.17 per barrel for 2020, down from $56.98 barrel for
2019 (31.3% decrease). During January and February of 2021, WTI crude oil prices have ranged from as low as $47.47 per
barrel to as high as $63.43 per barrel, Brent crude oil prices averaged $41.69 per barrel for 2020, down from $64.28 per
barrel for 2019 (35.1% decrease). During January and February of 2021, Brent crude oil prices have ranged from as low as
$50.37 per barrel to as high as $66.85 per barrel, The EIA projects average crude oil prices for WTI to increase
approximately $11.00 per barrel in 2021 compared to 2020, and increase in 2022 by approximately $1.00 per barrel. The
EIA projects average Brent crude oil prices to increase approximately $11.00 per barrel in 2021 compared to 2020, and to
increase approximately $2.00 per barrel in 2022.

For 2020, our average realized crude oil sales price was $ 38.45 per barrel. 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,
volume weighting (collectively referred to as differentials) and other factors. Crude oil quality adjustments can vary
significantly by field. 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 characterized as Poseidon, Mars, Thunder horse, Light Louisiana
Sweet (“LLS”), Heavy Louisiana Sweet (“HLS”) and others. 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. 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 2020
declined on average by approximately $3.40 - $4.70 per barrel compared to 2019 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.

During 2020, our average realized NGLs sales price per barrel decreased by 36.0% compared to 2019. Two major

components of our NGLs, ethane and propane, typically make up approximately 70% of an average NGL barrel. During
2020, average prices for domestic ethane decreased by 8% and average domestic propane prices decreased by 13% from
2019 as measured using a price index for Mount Belvieu. The changes in the average price for other domestic NGLs
components in 2020 ranged from a decrease of 10% to 38% year-over-year. Per EIA, production of ethane increased 10%
in 2020 compared to 2019 and is expected to increase year-over-year by 9% and 15% for 2021 and 2022,
respectively. Propane production increased 6% in 2020 compared to 2019 and is expected to increase year-over-year by
1% for 2021 and decrease 1% for 2022. Ethane and propane inventories increased 10% and decreased 14%, respectively as
of December 31, 2020 compared to December 31, 2019. Ethane usage is not impacted by weather, but primarily by
demand from petrochemical plants. Propane usage is affected by weather as it is used for house heating fuel in certain
areas and for crop drying, along with other uses. Heating degree days decreased approximately 9% in 2020 compared to
2019.

During 2020, our average realized natural gas sales price decreased 20.1% compared to 2019. According to data from
EIA, spot prices for natural gas at Henry Hub (the primary U.S. price benchmark) were 20.7% lower in 2020 compared to
2019. During January and February of 2021, spot prices for natural gas have ranged from as low as $2.54 per Mcf to as
high as $24.74 per Mcf, Natural gas prices are more affected by domestic issues (as compared to crude oil prices), such as
weather (particularly extreme heat or cold), supply, local demand issues, other fuel competition (coal) and domestic

economic conditions, and they have historically been subject to substantial fluctuation. Natural gas inventories at the end
of 2020 were 5.2% higher than at the end of 2019. EIA projects natural gas supply to be slightly less than consumption in
2021 and forecasts Henry Hub spot prices to increase by 45% year-over-year to $3.07 per Mcf.

EIA reports that electrical power generation sourced by natural gas consumption increased to 39% in 2020 compared
to 37% in 2019 and forecasts this percentage to remain at approximately the same level in 2021 and 2022. The percentage
of electrical power generation sourced from coal fell in 2020 to 20% compared to 24% 2019 and is expected to remain at
approximately the same levels in 2021 and 2022. The percentage of electrical power sourced from renewable sources, such
as hydropower and wind, increased to 20% in 2020 as compared to 17.4% in 2019 and is forecast to exceed 22% by 2022.

According to Baker Hughes, as of December 31, 2020, there were 351 working rigs drilling for oil and natural gas in

the U.S. 805 working rigs as of December 31, 2019. The oil rig counts at the end of December 2020 and December
2019 were 267 and 677, respectively. The U.S. natural gas rig counts at the end of December 2020 and December
2019 were 83 and 125, respectively. In the Gulf of Mexico, the number of working rigs was 17 rigs (17 oil and no natural
gas rigs) at the end of December 2020 and 23 rigs (22 oil and one natural gas rigs) at the end of December 2019.

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.

Lease Operating Expense. Our lease operating expenses include the expense of operating 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 costs, facility repairs and maintenance, workover costs, insurance premiums, and gathering
and transportation costs. Our operating costs depend in part on the type of commodity produced, the level of workover
activity and the geographical location of the properties. Workover costs can vary significantly from year to year depending
on the level of activity (either required or desired) and type of equipment used. In those instances where a drilling rig is
required as opposed to some other type of intervention vessel or equipment, the costs tend to be higher and require more
time.

Hurricane and Tropical Storm Events. Our offshore operations are exposed to potential damage from hurricanes and

we normally obtain insurance to reduce, but not totally mitigate, our financial exposure risk. See Liquidity and Capital
Resources – Insurance Coverage under this Item 7 in this Form 10-K for additional information.

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–Regulation–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 2020 or 2019, we have not had to post collateral for sureties. 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.

Paycheck Protection Program ("PPP"). 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. As of the date of this
filing, we have not received a response from the SBA, regarding the SBA's acceptance of our application. Management
believes the Company has met all of the requirements under the PPP and will not be required to repay any portion of the
grant.

Results of Operations

Year Ended December 31, 2020 Compared to Year Ended December 31, 2019

Revenues. Total revenues decreased $188.3 million, or 35.2%, to $346.6 million in 2020 as compared to

$534.9 million in 2019. Oil revenues decreased $183.4 million, or 45.9%, NGLs revenues decreased $3.3 million, or
14.6%, natural gas revenues decreased $7.0 million, or 6.6%, and other revenues increased $5.4 million. The oil revenue
decrease was attributable to a 35.8% per barrel decrease in the average realized sales price to $38.45 per barrel in
2020 from $59.89 per barrel in 2019 and a 15.7% decrease in sales volumes. The NGLs revenue decrease was attributable
to a 36.0% decrease in the average realized sales price to $11.26 per barrel in 2020 from $17.60 per barrel in 2019, offset
by an increase of 33.4% in sales volumes. The decrease in natural gas revenue was attributable to a 20.1% decrease in the
average realized natural gas sales price to $2.05 per Mcf in 2020 from $2.57 per Mcf in 2019, partially offset by a 17.1%
increase in sales volumes. Overall, prices decreased 38.9% on a per Boe basis and production increased 3.5% on a per Boe
per day basis. The largest production increases for 2020 compared to 2019 were from our acquired interest in the Mobile
Bay Properties and at Magnolia. Partially offsetting the increases were production decreases related to natural production
declines and production deferral. Production for 2020 was also negatively impacted by a record number of named storms,
maintenance, well issues and pipeline outages that collectively resulted in deferred production of 2.8 MMBoe, compared to
2.1 MMBoe in 2019.

Revenues from oil and liquids as a percent of our total revenues were 67.9% for 2020 compared to 78.9% for

2019. The average realized sales price per barrel of NGLs as a percent of average realized price of crude oil per
barrel decreased to 29.3% for 2020 compared to 29.4% for 2019.

Lease operating expenses. Lease operating expenses, which include base lease operating expenses, insurance
premiums, workovers, and facilities maintenance expenses, decreased $21.4 million, or 11.63%, to $162.9 million in
2020 compared to $184.3 million in 2019. On a per Boe basis, lease operating expenses decreased to $10.58 per Boe
during 2020 compared to $12.43 per Boe during 2019. On a component basis, base lease operating expenses decreased
$7.7 million, workover expenses decreased $12.0 million and facilities maintenance expenses decreased $6.8 million.
These decreases were partially offset by an increase in hurricane repair expenses of $4.7 million and an increase of $0.3
million in insurance premiums.

Base lease operating expenses decreased primarily due to reduced expenses of $24.1 million from shutting in certain

fields; and credits to expense due to prior period royalty adjustments of $6.0 million. These decreases were partially offset
by $13.4 million increases due to the acquisitions of interests in the Mobile Bay Properties in August 2019 and December
2020, and a $9 million increase related to the acquisition of Garden Banks 783/784 ("Magnolia") field in December
2019. The decreases in workover expense and facility maintenance were due to fewer projects undertaken in 2020 as
compared to 2019.

Production taxes. Production taxes were $4.9 million in 2020, an increase of $2.4 million as compared to 2019, due to

the acquisition of the Mobile Bay Properties. Most of our production is from federal waters where no production taxes are
imposed. The Mobile Bay Properties and our Fairway field, both of which are predominantly in state waters, are subject to
production taxes.

Gathering and transportation costs. Gathering and transportation costs decreased to $16.0 million, or 38.2%, in
2020 compared to $26.0 million in 2019. Costs decreased from the prior year primarily due to lower transportation rates as
well as lower volumes in 2020 for the majority of our fields (specifically, lower oil volumes) related to downtime events,
partially offset by a full year impact of gathering and transportation costs associated with the Mobile Bay and Magnolia
acquisitions.

Depreciation, depletion, amortization and accretion. DD&A, which includes accretion for ARO, decreased to $7.82

per Boe in 2020 from $10.01 per Boe in 2019. On a nominal basis, DD&A decreased to $120.3 million (19.0%) in
2020 from $148.5 million in 2019. The year-over-year decline in the DD&A rate per Boe was driven by the large reserve
additions relative to the purchase price associated with the acquisitions of the Mobile Bay and Magnolia assets. Other
factors affecting the DD&A rate are capital expenditures and changes in future development costs on remaining reserves.

General and administrative expenses (“G&A”). For 2020, G&A expenses were $41.8 million compared to

$55.1 million in 2019. The decrease in 2020 G&A expense compared to 2019 was driven primarily by credits from W&T's
PPP funds in 2020, a decrease in share based compensation expense and cash incentive compensation expense which did
not occur in 2020, and a decrease in legal expense to adjust for the final settlement of BSEE Civil penalties. On a unit of
production basis, G&A was $2.71 per Boe in 2020 compared to $3.72 per Boe in 2019.

Derivative loss (gain). For 2020, a $23.8 million derivative gain was recorded for crude oil and natural gas derivative

contracts. We entered into derivative contracts for crude oil during 2020 for both certain crude oil and natural gas
derivative contracts. For 2019, a $59.9 million derivative loss was recorded for crude oil and natural gas derivative
contracts. The loss in 2019 and gain in 2020 are primarily due to crude oil prices rising in the latter months of 2019 and
subsequently falling in late 2020 relative to the year end 2019 crude oil price, which impacted future prices used to value
the derivative contracts in 2019 and 2020, respectively. See Financial Statements and Supplementary Data – Note 9 –
Derivative Financial Instruments under Part II, Item 8 in this Form 10-K for additional information.

Interest expense, net. Interest expense, net, was $61.5 million in 2020, increasing 4.2% from $59.6 million in

2019. The increase is primarily due to lower interest income between the two periods, partially offset by a lower principal
balance of the Senior Second Lien Notes. Interest income decreased to $0.6 million in 2020 compared to $7.7 million in
2019, primarily due to interest income related to the income tax refunds, Apache and RIK matters in 2019, each matter
containing an element of interest income. See Financial Statements and Supplementary Data - Note 2 – Long-Term Debt
under Part II, Item 8 in this Form 10-K for additional information on our debt. See Financial Statements and
Supplementary Data - Note 17 – Contingencies under Part II, Item 8 in this Form 10-K for additional information on the
Apache and RIK matters.

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 – Long-Term Debt under Part
II, Item 8 in this Form 10-K for additional information.

Other (income) expense, net. During 2020, other expense, net, was $2.9 million, compared to $0.2 million of
other income, net, for 2019. 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. For 2019, the amount consists primarily of
federal royalty obligation reductions claimed in 2019 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.

Income tax benefit (expense). Our income tax benefit for 2020 and 2019 was $30.2 million and $75.2 million,
respectively. For 2020, 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. For 2019, our income tax benefit
was primarily due to reversals of previously recorded valuation allowances and for the reversal of a liability related to an
uncertain tax position that was effectively settled with the Internal Revenue Service (“IRS”) during the year. Our annual
effective tax rates for 2020 and 2019 were not meaningful and differ from the federal statutory rates of 21% primarily due
to valuation allowance adjustments recorded for our deferred tax assets in both periods. During 2020, we recorded a net
decrease to the valuation allowance of $32.1 million related to federal and state deferred tax assets. During 2019, we
recorded a net decrease to the valuation allowance of $63.3 million related to federal and state deferred tax assets and a
reversal of an uncertain tax position resulting in a non-cash tax benefit of $11.5 million. Deferred tax assets are recorded
related to net operating losses (“NOL”) 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 NOLs 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.

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

For year-to-year comparisons between 2019 and 2018 that are not included in this Annual Report on Form 10-K, see

“Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of the
Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2019.

Liquidity and Capital Resources

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

of December 31, 2020, we had $43.7 million of available cash and $130.6 million available under our Credit Agreement,
based on a borrowing base of $215.0 million. The borrowing base was further reduced in January 2021 from $215.0 million
to $190 million, or a $25.0 million reduction, as a result of the second semi-annual redetermination of 2020. See discussion
in Credit Agreement below.

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.

We believe that we will have adequate liquidity from cash flow from operations to fund our capital expenditure plans

for 2021, fund our ARO spending for 2021 and fulfill our various other obligations. Availability under our Credit
Agreement as of December 31, 2020 was $130.6 million. Our preliminary capital expenditure budget for 2021 has been
established in the range of $30.0 million to $60.0 million, which includes our share of the Joint Venture Drilling
Program, and excludes acquisitions. In our view of the outlook for 2021, we believe this level of capital expenditure will
enhance our liquidity capacity throughout 2021 and beyond while providing liquidity to make strategic acquisitions. 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.

Joint Venture Drilling Program. To provide additional financial flexibility, we created the Joint Venture Drilling
Program with private investors during 2018 and drilled and completed nine wells by the end of 2019. 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, and we expect to complete this well in 2021. See
Financial Statements and Supplementary Data – Note 4 – Joint Venture Drilling Program under Part II, Item 8 in this
Form 10-K for additional information on the Joint Venture Drilling Program.

Credit Agreement. As of December 31, 2020, we had $80.0 million of borrowings outstanding under the Credit
Agreement and $4.4 million of letters of credit issued under the Credit Agreement. During 2020, borrowings under the
Credit Agreement ranged from $105.0 million down to $80.0 million. Subsequent to the redetermination, availability under
our Credit Agreement as of December 31, 2020 was $130.6 million. Availability under our Credit Agreement is subject to
a semi-annual redetermination of our borrowing base to occur around May 15 and November 14 each calendar year, and
certain additional redeterminations that may be requested at the discretion of either the lenders or the Company. Any
redetermination by our lenders to change our borrowing base will result in a similar change in the availability under our
Credit Agreement. As of December 31, 2020, the borrowing base was $215.0 million. Additionally, in January 2021, our
borrowing base was reduced from $215 million to $190 million as a result of the second semi-annual redetermination for
2020.

We currently have six lenders within the revolving bank credit facility, with commitments ranging from 10% to 25%
of the current borrowing base. While we have not experienced, nor do we anticipate, any difficulties in obtaining funding
from any of these lenders at this time, any lack of or delay in funding by members of our banking group could negatively
impact our liquidity position. The Credit Agreement contains financial covenants calculated as of the last day of each fiscal
quarter, which include thresholds on financial ratios, as defined in the Credit Agreement. We were in compliance with all
applicable covenants of the Credit Agreement and the other debt instruments as of December 31, 2020.

On January 6, 2021, we entered into a Waiver, Consent to Second Amendment to Intercreditor Agreement and Fifth

● Reducing the borrowing base under the Credit Agreement from $215.0 million to $190.0 million.

● Amends and waives certain hedging requirements for projected natural gas production volumes of the Company to

the extent that certain identified existing hedge contracts may cause non-compliance with minimum swap
requirements for hedged volumes for any test date related to any calendar quarterly period ended on or before
December 31, 2022 and requires that all natural gas hedge contracts entered into after December 13, 2020 until the
December 31, 2022 test date (or such earlier date as provided in the Fifth Amendment) shall be in the form of swaps
and not collars or puts until swaps represent at least 50% of natural gas hedge positions for all months required to be
hedged by the Credit Agreement.

● Establishes procedures for the Company to propose additional hedge counterparties and directs the administrative
agent to enter into hedge intercreditor agreements with one or more hedge counterparties from time to time.

● Establishes a customary anti-cash hoarding prepayment requirement in the event the cash balances of the Company

exceed $25.0 million (subject to customary adjustments) at the end of the calendar month.

Under the Fifth Amendment, the lenders under the Credit Agreement have also consented to certain conforming
amendments necessitated by the Fifth Amendment proposed to be made to that certain Intercreditor Agreement among
Toronto Dominion (Texas) LLC, as Original Priority Lien Agent and Wilmington Trust, National Association, as
Second Lien Trustee and as Second Lien Collateral Agent.

Long-Term Debt. The primary terms of our long-term debt, the conditions related to incurring additional debt, and the

conditions and limitations concerning early repayment of certain debt are disclosed in Financial Statements and
Supplementary Data - Note 2 – Long-Term Debt under Part II, Item 8 in this Form 10-K.

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 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. As of December 31,
2020, we had outstanding open derivatives for crude oil and natural gas. See Financial Statements and Supplementary Data
- Note 9 – Derivative Financial Instruments under Part II, Item 8 in this Form 10-K for additional information.

Cash Flows. Net cash provided by operating activities for 2020 was $108.5 million, decreasing $123.7 million, or
53.3%, from 2019. The change between periods is primarily due to lower realized prices for crude oil, NGLs and natural
gas, and working capital changes, partially offset by increased volumes, increased derivative settlements, lower spending
for ARO activities, and lower income tax refunds. Our combined average realized sales price per Boe decreased 38.9% in
2020, which caused total revenues to decrease $213.6 million, partially offset by increases of 3.5% in overall production
volumes which caused revenues to increase by $19.9 million.

Other items affecting operating cash flows for 2020 were: ARO settlements of $3.3 million, which decreased from

$11.4 million in 2019; cash advances from joint venture partners increased $2.0 million during 2020 compared to a
decrease of $15.3 million during 2019; derivative cash receipts, net, were $45.2 million in 2020 compared to derivative
cash receipts, net, of $13.9 million in 2019; and income tax refunds were $2.0 million in 2020 compared to income tax
refunds of $52.2 million in 2019.

Net cash used in investing activities during 2020 and 2019 was $47.6 million and $313.8 million, respectively, which

represents our acquisitions and investments in oil and gas properties and equipment. Investments in oil and natural gas
properties 2020 were $44.2 million, which was a decrease of $81.5 million from 2019. The majority of our capital
expenditures for 2020 related to investments on the conventional shelf in the Gulf of Mexico and, to a lesser extent, in the
deepwater of the Gulf of Mexico. 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. During 2019, the acquisition of
property interest of $188.0 million was primarily related to the acquisition of the Mobile Bay Properties and, to a lesser
extent, the acquisition of the Magnolia Field. There were no asset sales of significance in 2020 or 2019.

Net cash used by financing activities for 2020 was $49.6 million and net cash provided by financing activities for
2019 was $80.7 million. The 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 net
cash provided by financing activities in 2019 was from borrowings under the Credit Agreement to fund the acquisition of
the Mobile Bay Properties, of which a portion was paid down by December 31, 2019. The purchase of the Senior Second
Lien Notes are disclosed in Financial Statements and Supplementary Data - Note 2 – Long-Term Debt under Part II, Item 8
in this Form 10-K.

Capital expenditures. Our preliminary capital expenditure budget for 2021 has been established in the range of

$30.0 million to $60.0 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. Some of our expenditures incurred during 2019 impacted our
production for 2019, but most of the impact is expected to occur in 2020 and beyond. In addition, we spent $3.3 million in
2020 and $11.4 million in 2019 for ARO and plan to spend in the range of $17.0 million to $21.0 million in 2021 for ARO.

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 interest - Mobile Bay (2)
Acquisition of interest – Magnolia Field (3)
Acquisition of interest - other
Acquisition of interest – Heidelberg Field (4)
Reimbursement from Monza for 2017

expenditures
Seismic and other
Acquisitions and investments in oil and gas

2020

Year Ended December 31,
2019
(In thousands)

2018

1,837 $
11,109
1,865
831
222
—

—
4,686

17,121 $
107,662
170,689
15,950
—
—

—
14,412

49,890
47,224
—
—
—
16,782

(14,075 )
7,702

property/equipment – accrual basis

20,550 $

325,834 $

107,523

(1) Reported geographically in the subsequent table.
(2) Acquired in September 2019.
(3) Acquired in December 2019.
(4) Acquired in April 2018.

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

Conventional shelf
Deepwater
Exploration and development capital

expenditures – accrual basis

2020

Year Ended December 31,
2019
(In thousands)

2018

10,247 $
2,699

39,093 $
85,690

69,354
27,760

12,946 $

124,783 $

97,114

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

2020

Completed
2019

2018

—
—
—

3
3
5

We had a 100% success rate in 2019 and 2018. During 2020, we drilled one well, which we expect to be completed in

2021. All of these wells are in the Joint Venture Drilling Program.

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 39 leases for approximately $6.9 million from the
BOEM in the Federal Offshore Lease Sales. Per year, we acquired 4 leases ($1.2 million), 17 leases ($3.8 million), and 17
leases ($1.9 million) in the years 2020, 2019, and 2018, respectively.

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. As previously discussed, in 2018 we sold our
overriding interests in the Yellow Rose field for $56.6 million after adjustments. In 2020 and 2019, there were no property
sales of significance. See Financial Statements and Supplementary Data – Note 5 –Acquisitions and Divestitures under
Part II, Item 8 in this Form 10-K for additional information on this divestiture.

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, 2020 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 $30.0 million. 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,
2020. 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, 2020 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 $150.0 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 $10.4 million for the May/June 2020 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.

Liquidity for 2021. We believe that we will have adequate liquidity from cash flow from operations to fund our capital

expenditure plans for 2021, fund our ARO spending for 2021 and fulfill our various other obligations. Availability under
our Credit Agreement as of December 31, 2020 was $130.6 million. Our preliminary capital expenditure budget for
2021 has been established in the range of $30.0 million to $60.0 million, which includes our share of the Joint Venture
Drilling Program and excludes acquisitions. In our view of the outlook for 2021, we believe this level of capital
expenditure will enhance our liquidity capacity throughout 2021 and beyond. 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.

Income taxes. As of December 31, 2020, we have current income taxes payable of $0.2 million. During 2020, we
received refunds of $2.0 million and interest income of $0.1 million primarily related to our NOL claim for the year 2017
that was carried back to prior years. The claim was made pursuant to Internal Revenue Code ("IRC") rules for specified
liability losses, which permit certain platform dismantlement, well abandonment and site clearance costs to be carried back
10 years. Under the Tax Cuts and Jobs Act (“TJCA”), effective in 2017, NOLs including those related to specified liability
losses can no longer be carried back for tax years beginning after 2017. For 2020, we do not expect to make any significant
income tax payments.

Dividends. During 2020, 2019 and 2018, we did not pay any dividends and a suspension of dividends remains in effect.

Asset retirement obligations. Annually we review and revise our ARO estimates. Our ARO at December 31, 2020 and

2019 were $392.7 million and $355.6 million, respectively, recorded using discounted values. Our estimate of ARO
spending in 2021 is $17.0 million to $21.0 million. During 2020 and 2019, 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 6 – Asset Retirement Obligations under Part II, Item 8 in this Form 10-K for additional information regarding our
ARO.

Discretionary Bonus to Employees in 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 $7.6 million, payable in equal installments on March 15, 2021 and April 15, 2021, subject to employment on those dates.

Contractual obligations. At December 31, 2020, we did not have any capital leases. The following table summarizes

our significant contractual obligations by maturity as of December 31, 2020 (in millions):

Payments Due by Period as of December 31, 2020
One to Three
Years

Three to Five
Years

Less than
One Year

More Than
Five Years

Total

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

632.5 $
165.4
23.6
392.7

(3)
Total

94.7
1,308.9 $

— $
57.7
0.3
17.2

8.4
83.6 $

632.5 $
107.7
2.8
58.3

14.3
815.6 $

— $
—
3.5
56.1

12.8
72.4 $

—
—
17.0
261.1

59.2
337.3

(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, 2020 and
assumes no change in this interest rate in future periods. In addition, a commitment fee of 0.5% was applied on the
available balance as of December 31, 2020 and fees related to letters of credit were estimated at the rate incurred on
December 31, 2020; (b) Interest payments on the Senior Second Lien Notes were calculated per the terms of the notes.

(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, 2020 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, 2020,
we had approximately $400.6 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.

Inflation and Seasonality

Inflation. For 2020, our realized prices for crude oil decreased 35.8%, NGLs decreased 36.0% and natural gas
decreased 20.1% from 2019. These are discussed in the Overview section above. Historically, our costs for goods and
services have moved directionally with the price of crude oil, NGLs and natural gas, as these commodities affect the
demand for these goods and services. Operating costs directly related to production (lease operating expenses, production
taxes and gathering and transportation) measured on a $/Boe basis decreased by 16.8% in 2020 compared to 2019 and
increased by 7.7% in 2019 compared to 2018. These operating costs related to production are substantially impacted by
factors other than national general rates of inflation or deflation, such as workovers, facility repairs, production handling
fees for certain fields (recorded as credits to expense), production levels, hurricanes, changes in regulations, types of
commodities produced and the level of oil and gas activity in the Gulf of Mexico.

Critical Accounting Policies

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.

Full-cost accounting. We account for our investments in oil and natural gas properties using the full-cost method of
accounting. Under this method, all costs associated with the acquisition, exploration, development and abandonment of oil
and gas properties are capitalized. Capitalization of geological and geophysical costs, certain employee costs and G&A
expenses related to these activities is permitted. We amortize our investment in oil and natural gas properties, capitalized
ARO and future development costs (including ARO of wells to be drilled) through DD&A, using the units-of-production
method. The units-of-production method uses reserve information in its calculations. 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.

Our financial position and results of operations may have been significantly different had we used the successful-
efforts method of accounting for our oil and natural gas investments. GAAP allows successful-efforts accounting as an
alternative method to full-cost accounting. The primary difference between the two methods is in the treatment of
exploration costs, including geological and geophysical costs, and in the resulting computation of DD&A. Under the full-
cost method, which we follow, exploratory costs are capitalized, while under successful-efforts, the cost associated with
unsuccessful exploration activities and all geological and geophysical costs are expensed. In following the full-cost
method, we calculate DD&A based on a single pool for all of our oil and natural gas properties, while the successful-efforts
method utilizes cost centers represented by individual properties, fields or reserves. Typically, the application of the full-
cost method of accounting for oil and natural gas properties results in higher capitalized costs and higher DD&A rates,
compared to similar companies applying the successful efforts method of accounting.

DD&A can be affected by several factors other than production. The rate computation 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
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 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. Any
write downs occurring as a result of the ceiling test impairment are not recoverable or reversible in future periods. We did
not have any ceiling test impairments in 2020, 2019 or 2018, but did have ceiling test impairment in 2016. Ceiling test
impairments in future periods are highly dependent on commodity prices, and also are impacted by other factors and
events. For the effect of lower commodity prices on revenues and earnings, see Quantitative and Qualitative Disclosures
on Market Risks under Part II, Item 7A in this Form 10-K for additional information.

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. We make changes to
DD&A rates and impairment calculations in the same period that changes to our reserve estimates are made. Our proved
reserve information as of December 31, 2020 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. We have significant obligations to plug and abandon all 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 the future restoration and removal cost is difficult and
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. 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. Pursuant to GAAP, we are required to record
a separate liability for the discounted present value of our ARO, with an offsetting increase to the related oil and natural gas
properties on our balance sheet.

Inherent in the present value calculation of our liability are numerous estimates and judgments, including the ultimate
settlement amounts, inflation factors, changes to our credit-adjusted risk-free rate, timing of settlement and changes in the
legal, regulatory, environmental and political environments. Revisions to these estimates impact the value of our
abandonment liability, our oil and natural gas property balance and our DD&A rates.

Income taxes. GAAP requires the use of the liability method of computing deferred income taxes, whereby deferred
income taxes are recognized for the future tax consequences of the differences between the tax basis of assets and liabilities
and the carrying amount in our financial statements. 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 are expected to be recovered or
settled. Because our tax returns are filed after the financial statements are prepared, estimates are required in recording tax
assets and liabilities. We record adjustments to reflect actual taxes paid in the period we complete our tax returns. 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. 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.

Paycheck Protection Program. As there is no definitive guidance under U.S. GAAP, we have applied the guidance

under International Accounting Standards 20, Accounting for Government Grants and Disclosure of Government
Assistance ("IAS 20") and have elected to follow the income approach under IAS 20 and recognize earnings as funds are
applied to covered expenses and classify the application of the funds as a reduction of the related expense in the
Consolidated Statement of Operations. As a result, we have reduced expenses during the year ended December 31, 2020
and classified expense reductions consistent with our PPP fund application request.

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 from time to time to reduce the risk of fluctuations in commodity
prices and expect to use these instruments in the future. We entered into derivative contracts for crude oil and natural gas
during 2020 and had open derivative contracts as of December 31, 2020. We do not designate our commodity derivative
contracts as hedging instruments. 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. Our revenues, profitability and future rate of growth substantially depend upon market prices

for crude oil, NGLs and natural gas, which fluctuate widely. Crude oil, NGLs and natural gas price declines and volatility
could adversely affect our revenues, net cash provided by operating activities and profitability. For example, assuming a
10% decline in our average realized oil, NGLs and natural gas sales prices in 2020 and assuming no other items had
changed, our income before income tax would have decreased by approximately $35 million in 2020. If costs and expenses
of operating our properties had increased by 10% in 2020, our income before income tax would have decreased by
approximately $18 million in 2020. These amounts would be representative of the effect on operating cash flows under
these price and cost change assumptions.

Interest rate risk. As of December 31, 2020, we had $80.0 million 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 ranges from 2.75% to 3.75% depending on the amount outstanding. In 2020, if interest rates would have
been 100 basis points higher (an additional 1%); our interest expense would have increased $0.9 million during 2020. We
did not have any derivative contracts related to interest rates as of December 31, 2020.

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

Consolidated Financial Statements:

Consolidated Balance Sheets as of December 31, 2020 and 2019

Consolidated Statements of Operations for the years ended December 31, 2020, 2019 and 2018

Page
54

Consolidated Statements of Changes in Shareholders’ Deficit for the years ended December 31, 2020, 2019 and 2018

Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019 and 2018

Notes to Consolidated Financial Statements

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, 2020 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, 2020 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 Board of Directors and Shareholders 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, 2020, 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, 2020, 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,
2020 and 2019, 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, 2020, and the related notes and our report dated March 4,
2021 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 4, 2021

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders 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, 2020 and 2019, 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, 2020, 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, 2020 and
2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31,
2020, 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, 2020, 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 4, 2021 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, 2020, the net book value of the Company’s oil and natural gas properties was
$687 million, and depreciation, depletion and amortization (“DD&A”) expense was $98 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, 2020.

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

Description of the
Matter

At December 31, 2020, the asset retirement obligation (ARO) balance totaled $393 million. As
further described in Notes 1 and 6, 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.

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.

/s/ Ernst & Young LLP

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

Houston, Texas
March 4, 2021

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

Assets

Current assets:

Cash and cash equivalents
Receivables:

Oil and natural gas sales
Joint interest, net
Income taxes

Total receivables

Prepaid expenses and other assets (Note 1)

Total current assets

December 31,

2020

2019

43,726 $

32,433

38,830
10,840
—
49,670
13,832
107,228

57,367
19,400
1,861
78,628
30,691
141,752

Oil and natural gas properties and other, net – at cost: (Note 1)

686,878

748,798

Restricted deposits for asset retirement obligations
Deferred income taxes
Other assets (Note 1)

Total assets

Current liabilities:

Liabilities and Shareholders’ Deficit

Accounts payable
Undistributed oil and natural gas proceeds
Advances from joint interest partners
Asset retirement obligations
Accrued liabilities (Note 1)
Income tax payable

Total current liabilities

Long-term debt: (Note 2)

Principal
Carrying value adjustments

Long-term debt – carrying value

Asset retirement obligations, less current portion
Other liabilities (Note 1)
Deferred income taxes
Commitments and contingencies (Note 17)
Shareholders’ deficit:

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

15,806
63,916
33,447
1,003,719

48,612 $
19,167
—
17,188
29,880
153
115,000

632,460
(7,174 )
625,286

375,516
32,938
128
—

102,344
29,450
5,279
21,991
30,896
—
189,960

730,000
(10,467)
719,533

333,603
9,988
—
—

Preferred stock, $0.00001 par value; 20,000 shares authorized; 0 issued at

December 31, 2020 and December 31, 2019

Common stock, $0.00001 par value; 200,000 shares authorized; 145,174 issued

and 142,305 outstanding at December 31, 2020 and 144,538 issued and
141,669 outstanding at December 31, 2019
Additional paid-in capital
Retained deficit
Treasury stock, at cost; 2,869 shares at December 31, 2020 and December 31,

2019
Total shareholders’ deficit

Total liabilities and shareholders’ deficit

—

1
550,339
(734,459 )

(24,167 )
(208,286 )
940,582 $

1
547,050
(772,249)

(24,167)
(249,365)
1,003,719

See accompanying notes.

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

Revenues:

Oil
NGLs
Natural gas
Other

Total revenues

Total costs and expenses
Operating income

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

Income (loss) before income tax (benefit) expense

Income tax (benefit) expense

Net income

Basic and diluted earnings per common share

$
$

2020

Year Ended December 31,
2019

2018

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

162,857
4,918
16,029
97,763
22,521
41,745
(23,808 )
322,025
24,609

61,463
(47,469 )
2,978
7,637
(30,153 )
37,790 $
0.26 $

399,790 $
22,373
106,347
6,386
534,896

184,281
2,524
25,950
129,038
19,460
55,107
59,887
476,247
58,649

59,569
-
188
(1,108)
(75,194)
74,086 $
0.52 $

438,798
37,127
99,629
5,152
580,706

153,262
1,832
22,382
131,423
18,431
60,147
(53,798 )
333,679
247,027

48,645
(47,109 )
(3,871 )
249,362
535
248,827
1.72

See accompanying notes.

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

Common Stock
Outstanding

Value

Additional
Paid-In
Capital

Retained
Deficit

Treasury Stock

Value

Total
Shareholders’
Deficit

Balances at December 31,

2017
Share-based compensation
Stock issued
RSUs surrendered for

payroll taxes

Net income

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

139,091 $
—
1,553

1 $ 545,820 $ (1,095,162)
—
—
—
—

3,540
—

2,869 $
—
—

(24,167 ) $
—
—

(573,508)
3,540
—

—
—

140,644
—
1,025

—
—

141,669
—
636

—
—

1
—
—

—
—

1
—
—

—
—

(3,655)
—

—
248,827

—
—

(3,655)
248,827

545,705
3,690
—

(846,335)
—
—

2,869
—
—

(24,167 )
—
—

(324,796)
3,690
—

(2,345)
—

—
74,086

—
—

(2,345)
74,086

547,050
3,959
—

(772,249)
—
—

2,869
—
—

(24,167 )
—
—

(249,365)
3,959
—

(670)
—

—
37,790

—
—

(670)
37,790

142,305 $

1 $ 550,339 $ (734,459)

2,869 $

(24,167 ) $

(208,286)

See accompanying notes.

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

Operating activities:
Net income
Adjustments to reconcile net 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)
Derivatives cash receipts (payments), net
Gain on debt transactions
Deferred income taxes
Changes in operating assets and liabilities:

Oil and natural gas receivables
Joint interest receivables
Income taxes
Prepaid expenses and other assets
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
Proceeds from sales of assets, net
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
Issuance of Senior Second Lien Notes
Extinguishment of debt – principal
Extinguishment of debt – premiums
Payment of interest on 1.5 Lien Term Loan
Payment of interest on 2nd Lien PIK Toggle Notes
Payment of interest on 3rd Lien PIK Toggle Notes
Debt transactions costs
Other

Net cash (used in) provided by financing activities
Increase (decrease) in cash and cash equivalents

Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period

2020

Year Ended December 31,
2019

2018

37,790 $

74,086 $

248,827

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

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

148,498
5,514
3,690
59,887
13,941
—
(64,102)

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

149,854
2,850
3,540
(53,798 )
(28,164 )
(47,109 )
500

(2,361 )
5,120
11,028
3,383
(28,617 )
16,629
40,081
321,763

(17,632 )

(137,816)

(90,741 )

(26,535 )
(2,919 )
—
(530 )
(47,616 )

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

12,110
(188,019)
—
(89)
(313,814)

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

(15,450 )
(16,782 )
56,588
—
(66,385 )

61,000
(40,000 )
—
625,000
(903,194 )
(21,850 )
(6,623 )
(9,725 )
(4,672 )
(17,457 )
(3,622 )
(321,143 )
(65,765 )
99,058
33,293

See accompanying notes

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 subsidiary, W & T Energy VI, LLC (“Energy VI”) and through our proportionately
consolidated interest in Monza Energy, LLC (“Monza”), as described in more detail in Note 4.

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”).

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.

Realized Prices

The price we receive for our crude oil, natural gas liquids (“NGLs”) and natural gas production directly affects our

revenues, profitability, cash flows, liquidity, access to capital, proved reserves and future rate of growth. The average
realized prices of these commodities decreased in 2020 compared to the average realized prices in 2019.

Accounting Standard Updates Effective January 1, 2020

In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2016-13,

Financial Instruments – Credit Losses (Topic 326) (“ASU 2016-13”) and subsequently issued additional guidance on this
topic. The new guidance eliminates the probable recognition threshold and broadens the information to consider past
events, current conditions and forecasted information in estimating credit losses. This amendment did not have a material
impact on our financial statements and did not affect the opening balance of Retained Deficit.

In August 2017, the FASB issued Accounting Standards Update No. 2017-12, Derivatives and Hedging (Topic 815) –

Targeted Improvements to Accounting for Hedging Activities (“ASU 2017-12”) and subsequently issued additional
guidance on this topic. The amendments in ASU 2017-12 require an entity to present the earnings effect of the hedging
instrument in the same income statement line in which the earning effect of the hedged item is reported. This presentation
enables users of financial statements to better understand the results and costs of an entity’s hedging program. Also,
relative to current GAAP, this approach simplifies the financial statement reporting for qualifying hedging
relationships. As we do not designate our commodity derivative instruments as qualifying hedging instruments, this
amendment did not impact the presentation of the changes in fair values of our commodity derivative instruments on our
financial statements.

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.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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, 2020 and 2019, $3.5 million and $3.6 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:

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

** Less than 10%

Year Ended December 31,
2019

2018

2020

39%
10%
**
**
13%

40%
**
11%
12%
**

20%
**
30%
14%
**

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.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

2020

2019

2018

9,898 $
417

(1,192)
9,123 $

9,692 $
206

—
9,898 $

9,114
1,233

(655)
9,692

Prepaid expenses and other assets

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 bonds/insurance premiums
Prepaid deposits related to royalties
Prepayment to vendors
Other

Prepaid expenses and other assets

(1) Includes both open and closed contracts.

December 31,

2020

2019

2,752 $
4,717
4,473
1,429
461
13,832 $

7,266
4,357
7,980
10,202
886
30,691

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Properties and Equipment

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. 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.

Oil and Natural Gas Properties and Other, Net – at cost

Oil and natural gas properties and equipment are recorded at cost using the full cost method. There were no amounts

excluded from amortization as of the dates presented in the following table (in thousands):

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

Total property and equipment

Less accumulated depreciation, depletion and amortization

Oil and natural gas properties and other, net

December 31,

2020

2019

8,567,509 $
20,847
8,588,356
7,901,478
686,878 $

8,532,196
20,317
8,552,513
7,803,715
748,798

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Ceiling Test Write-Down

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 2020, 2019 or 2018. If average crude oil and natural gas prices

decrease below average pricing during 2020, we may incur ceiling test write-downs during 2021 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 6 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 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 2020, 2019 and 2018, and as of December 31,
2020, 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 2020, 2019 and 2018, 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. These derivative instruments may or may not have qualified for hedge accounting treatment.

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.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 12 for additional information.

Other Assets (long-term)

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

December 31,

2020

2019

ROU assets (Note 7)
Unamortized debt issuance costs
Investment in White Cap, LLC
Derivatives
Unamortized brokerage fee for Monza
Proportional consolidation of Monza's other assets (Note 4)
Appeal bond deposits
Other

Total other assets

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

7,936
3,798
2,590
2,653
3,423
5,308
6,925
814
33,447

Accrued Liabilities

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

Accrued interest
Accrued salaries/payroll taxes/benefits
Incentive compensation plans
Litigation accruals
Lease liability (Note 7)
Derivatives
Other

Total accrued liabilities

December 31,

2020

2019

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

10,180
2,377
9,794
3,673
2,716
1,785
371
30,896

Paycheck Protection Program ("PPP")

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. As of the date of this filing, we have not received any response
from the SBA, including any communication regarding the SBA's acceptance of our application. Management believes the
Company has met all of the requirements under the PPP and will not be required to repay any portion of the grant.

We have elected to follow the income approach under IAS 20 and recognize earnings as funds are applied to covered

expenses and classify the application of the funds as a reduction of the related expense in the Consolidated Statement of
Operations. As a result, we have reduced expenses during the year ended December 31, 2020 and classified expense
reductions consistent with our PPP fund application request. Within the Consolidated Statement of Operations, credits
to Lease operating expenses of $2.3 million, General and administrative expenses of $4.2 million and reductions to Interest
expense, net of $1.9 million were recognized for the year ended December 31, 2020. Should the SBA reject the Company's
application on the utilization of funds, the Company may be required to repay all or a portion of the funds received under
the PPP under an amortization schedule through April 2022 with an annual interest rate of 1%.

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 Other Assets (noncurrent) and unamortized debt issuance costs associated with our
other debt instruments are reported as a reduction in Long-term debt – carrying value in the Consolidated Balance
Sheets. See Note 2 for additional information.

Discounts Provided on Debt Issuance

Discounts were recorded in Long-term debt – carrying value in the Consolidated Balance Sheets and were amortized

over the term of the related debt using the effective interest method.

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 for additional information.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Other Liabilities (long-term)

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

Dispute related to royalty deductions
Dispute related to royalty-in-kind
Lease liability (Note 7)
Derivatives
Black Elk escrow
Other

Total other liabilities (long-term)

Share-Based Compensation

December 31,

2020

2019

5,467 $
—
11,360
4,384
11,103
624
32,938 $

4,687
250
4,419
—
—
632
9,988

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 10 for additional information.

Other Expense (Income), Net

For 2020, the amount consists primarily of expenses related to the amortization of the brokerage fee paid in
connection with the Joint Venture Drilling Program (as defined in Note 4). 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. For 2018, the amount consists primarily of credits related to the de-recognition of certain
liabilities that had exceeded the statute of limitations, partially offset by expense 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 13 for additional information.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Long-Term Debt

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

Credit Agreement borrowings

80,000 $

105,000

December 31,

2020

2019

Senior Second Lien Notes:

Principal
Unamortized debt issuance costs

Total Senior Second Lien Notes

552,460
(7,174)
545,286

625,000
(10,467)
614,533

Total long-term debt

625,286 $

719,533

Aggregate annual maturities of amounts recorded for long-term debt as of December 31, 2020 are as follows (in

millions): 2021–$0.0; 2022–$80.0; 2023–$552.5. See below for a discussion of our debt instruments.

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.

On and after 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 100.000% 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 101.000% 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
Credit Agreement (defined below). 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.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Credit Agreement

Concurrently with the issuance of the Senior Second Lien Notes, we renewed our credit facility by entering into the

Sixth Amended and Restated Credit Agreement (the “Credit Agreement”), dated as of October 18, 2018, among the
Company, as borrower, the Guarantor Subsidiaries from time to time party thereto, Lenders from time to time party thereto
and Toronto Dominion (Texas) LLC, as administrative agent with a maturity date of October 18, 2022. The primary
terms of the Credit Agreement as of December 31, 2020, as amended, are as follows, with certain terms defined under the
Credit Agreement:

● The borrowing base is $215.0 million.

● Letters of credit may be issued in amounts up to $30.0 million, provided availability under the Credit Agreement

exists.

● From the period ended June 30, 2020 through the period ended December 31, 2021 (the "Waiver Period"), the

Company will not be required to comply with the Leverage Ratio covenant. The Leverage Ratio, as defined in the
Credit Agreement, is limited to 3.00 to 1.00 for quarters ending March 31, 2022 and thereafter.

● During the Waiver Period, the Company will be required to maintain a 2.00 to 1.00 ratio limit of first lien debt

outstanding under the Credit Agreement on the last day of the most recent quarter to EBITDAX for the
trailing four quarters.

● The Current Ratio, as defined in the Credit Agreement, must be maintained at greater than 1.00 to 1.00.

● We are required to have deposit accounts only with banks under the Credit Agreement with certain exceptions.

● We are required to provide first priority liens on properties constituting at 90% of total proved reserves of the

Company as set forth on reserve reports required to be delivered under the Credit Agreement.

● To the extent there are borrowings, the Applicable Margins, as defined in the Credit Agreement, for Eurodollar Loans
range from 2.75% to 3.75% per annum and the Applicable Margins for ABR loans range from 1.75% to 2.75% per
annum. The specific Applicable Margin rate is based on the Borrowing Base Utilization Percentage.

● The commitment fee is 50.0 basis points.

● We are required to have derivative contracts for a minimum of 50% of projected production for 18 months based on

existing proved developed producing reserves and certain other criteria and have met this requirement. We may enter
into derivative contracts with counter parties within the Credit Agreement or with other counter parties meeting
certain criteria described in the Credit Agreement.

Availability under the Credit Agreement is subject to semi-annual redeterminations of our borrowing base to occur on

or before May 15 and November 14 each calendar year, and certain additional redeterminations that may be requested at
the discretion of either the lenders or the Company. The borrowing base is calculated by our lenders based on their
evaluation of our proved reserves and their own internal criteria. Any redetermination by our lenders to change our
borrowing base will result in a similar change in the availability under the Credit Agreement. The Credit Agreement’s
security is collateralized by a first priority lien on substantially all of our oil and natural gas properties and certain personal
property.

Borrowings outstanding under the Credit Agreement are reported in the table above. As of December 31, 2020 and
2019, we had $4.4 million and $5.8 million, respectively, outstanding in letters of credit under the Credit Agreement. The
estimated annual effective interest rate on borrowings, exclusive of debt issuance costs, commitment fees and other fees
was 3.8%.

As of December 31, 2020 and for all prior measurement periods, we were in compliance with all applicable covenants

of the Credit Agreement and Senior Second Lien Notes.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

On January 6, 2021, we entered into a Waiver, Consent to Second Amendment to Intercreditor Agreement and Fifth

Amendment to Sixth Amended and Restated Credit Agreement (the “Fifth Amendment”) dated as of January 6, 2021,
among the Company, certain of its guarantor subsidiaries, Toronto Dominion (Texas) LLC, individually and as
administrative agent, and certain of the Company’s lenders and other parties thereto (as heretofore amended, the “Credit
Agreement”). The Fifth Amendment, which became effective as of January 6, 2021, amends the Sixth Amended and
Restated Credit Agreement (the “Fifth Amendment”) dated as of October 18, 2018. The Fifth Amendment includes the
following changes, among other things, to the Credit Agreement:

● Reduces the borrowing base under the Credit Agreement from $215.0 million to $190.0 million.

● Amends and waives certain hedging requirements for projected natural gas production volumes of the Company to the
extent that certain identified existing hedge contracts may cause non-compliance with minimum swap requirements
for hedged volumes for any test date related to any calendar quarterly period ended on or before December 31, 2022
and requires that all natural gas hedge contracts entered into after December 13, 2020 until the December 31, 2022 test
date (or such earlier date as provided in the Fifth Amendment) shall be in the form of swaps and not collars or puts
until swaps represent at least 50% of natural gas hedge positions for all months required to be hedged by the Credit
Agreement.

●

Establishes procedures for the Company to propose additional hedge counterparties and directs the administrative
agent to enter into hedge intercreditor agreements with one or more hedge counterparties from time to time.

●

Establishes a customary anti-cash hoarding prepayment requirement in the event the cash balances of the Company
exceed $25.0 million (subject to customary adjustments) at the end of any calendar month.

Under the Fifth Amendment, the lenders under the Credit Agreement have also consented to and executed certain
conforming amendments necessitated by the Fifth Amendment proposed to be made to that certain Intercreditor Agreement
among Toronto Dominion (Texas) LLC, as Original Priority Lien Agent and Wilmington Trust, National Association, as
Second Lien Trustee and as Second Lien Collateral Agent.

For information about fair value measurements of our long-term debt, refer to Note 3.

Refinancing Transaction in 2018

On October 18, 2018, funds from the issuances of the Senior Second Lien Notes, borrowings under the Credit
Agreement and cash on hand were used to repurchase and retire, repay or redeem all of the prior debt instruments, which
are listed below. The issuance of the Senior Second Lien Notes, execution of the Credit Agreement and extinguishment of
the prior debt instruments are collectively referred to as the “Refinancing Transaction”. A net gain of $47.1 million was
recorded as a result of the Refinancing Transaction, comprised of the write off of carrying value adjustments of the prior
debt instruments and partially offset by premiums paid. The effect on both basic and diluted earnings per share for 2018
was $0.33 per share, which assumes the gain would not affect our income tax expense for 2018.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Prior Debt Instruments

The following debt instruments were repurchased and retired, repaid or redeemed, including interest and applicable

premiums as part of the Refinancing Transaction on October 18, 2018:

● 11.00% 1.5 Lien Term Loan, (the “1.5 Lien Term Loan”) due November 15, 2019, $75.0 million principal

outstanding on October 18, 2018.

● 9.00% Term Loan, due May 15, 2020, $300.0 million principal outstanding on October 18, 2018 (the "Second

Lien Term Loan").

● 9.00%/10.75% Senior Second Lien PIK Toggle Notes (the “Second Lien PIK Toggle Notes”), due May 15, 2020,

$177.5 million principal outstanding on October 18, 2018.

● 8.50%/10.00% Senior Third Lien PIK Toggle Notes (the “Third Lien PIK Toggle Notes”), due June 15, 2021,

$160.9 million principal outstanding on October 18, 2018.

● 8.500% Senior Notes (the “Unsecured Senior Notes”), due June 15, 2019, $189.8 million principal outstanding on

October 18, 2018.

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.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following tables present the fair value of our derivatives and long-term debt (in thousands):

December 31,

2020

2019

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

2,705 $
2,762

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

13,291
4,384

6,921
2,653

1,785
—

Liabilities:
Credit Agreement
Senior Second Lien Notes

December 31, 2020

December 31, 2019

Carrying
Value

Fair Value

Carrying
Value

Fair Value

80,000 $
545,286

80,000 $
393,352

105,000 $
614,533

105,000
597,188

As of December 31, 2020 and 2019, the carrying value of our open derivative contracts equaled the estimated fair

value. We measure the fair value of our derivative contracts by applying the income approach using models with inputs
that are classified within Level 2 of the valuation hierarchy. The inputs used to measure the fair value of our derivative
contracts 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.

The fair value of our Senior Second Lien Notes is based on quoted prices, although the market is not an active market;

therefore, the fair value is classified within Level 2. The carrying amount of debt under our Credit Agreement
approximates fair value because the interest rates are variable and reflective of current market rates.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. 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, 2020.

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.

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.

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, 2020, nine wells have been completed of which six were producing as of December 31,

2020. W&T is the operator for seven of the nine wells completed through December 31, 2020.

Through December 31, 2020, members of Monza made partner capital contributions, including our contributions of

working interest in the drilling projects, to Monza totaling $289.3 million and received cash distributions totaling
$70.8 million. Our net contribution to Monza, reduced by distributions received, as of December 31, 2020 was
$51.8 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, 2020, 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, 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. As of December 31, 2019, in the Consolidated
Balance Sheet, we recorded $16.1 million, net, in Oil and natural gas properties and other, net, $5.3 million in Other
assets, $0.1 million in ARO and $2.7 million, net, increase in working capital in connection with our proportional interest
in Monza’s assets and liabilities. Additionally, during 2020 and 2019, 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, 2020 and 2019 were $7.3 million and $5.3 million, respectively, which are included in the
Consolidated Balance Sheet in Advances from joint interest partners. For 2020, in the Consolidated Statement of
Operations, we recorded $8.4 million in Total revenues and $12.1 million in Operating costs and expenses in connection
with our proportional interest in Monza’s operations. For 2019, in the Consolidated Statement of Operations, we recorded
$11.9 million in Total revenues and $7.4 million in Operating costs and expenses in connection with our proportional
interest in Monza’s operations.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5. 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.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Heidelberg Field

On April 5, 2018, we completed the purchase of Cobalt International Energy, Inc.'s 9.375% non-operated working
interests located in Green Canyon blocks 859, 903 and 904 (the "Heidelberg Field"). After taking into account customary
closing adjustments and an effective date of January 1, 2018, cash consideration was $16.8 million which includes cash
expenses related to the acquisition. We determined that the assets acquired did not meet the definition of a business;
therefore, the transaction was accounted for as an asset acquisition. In connection with this transaction, we were required to
furnish a letter of credit of $9.4 million to a pipeline company as consignee. We recognized ARO of $3.6 million as a
component of the transaction. In conjunction with the purchase of an interest in the Heidelberg field, we assumed contracts
with certain pipeline companies that contain minimum quantities obligations through 2028 resulting in an estimated
commitment of $19.6 million as of the purchase date.

Permian Basin

On September 28, 2018, we completed the divestiture of substantially all of our ownership in an overriding royalty
interests in the Permian Basin. The net proceeds received were $56.6 million, which was recorded as a reduction to our
full-cost pool.

6. 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,

2020

2019

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

310,137
(11,443)
19,460
29,887
7,553
355,594
21,991
333,603

(1) Revisions in 2020 and 2019 were due to changes in scope, weather impact, revisions to actual

expenses versus estimates and revisions related to non-operated properties.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. 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,

2020

2019

3,060 $
1,633
4,693 $

2,902
22,152
25,054

(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, 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,

2020

2019

11,509 $

7,936

394 $
11,360
11,754 $

2,716
4,419
7,135

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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,

2020
14.8 years
10.2%

2019
14.3 years
10.4%

The table below presents the supplemental cash flow information related to leases (in thousands):

Operating cash outflow from operating leases
Right-of-use assets obtained in exchange for new operating
lease liabilities

1,825 $

5,142 $

1,827

6,373

Undiscounted future minimum payments as of December 31, 2020 are as follows (in thousands):

December 31,

2020

2019

2021
2022
2023
2024
2025
Thereafter

Total lease payments
Present value adjustment

Total

394
1,134
1,625
2,023
1,512
17,461
24,149
(12,395)
11,754

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. Restricted Deposits for ARO

Restricted deposits as of December 31, 2020 and 2019 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 15 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 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. $11.1 million was recorded
in Other Liabilities as of December 31, 2020 as our estimate of the additional asset retirement obligations to be funded
from the restricted deposit account.

9. Derivative Financial Instruments

During 2020, 2019 and 2018, 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, 2020 are presented in the following tables:

Crude Oil: Open Swap Contracts, Priced off WTI (NYMEX)

Period
Jan 2021 - Dec 2021
Jan 2022 - Feb 2022
Mar 2022 - May 2022

Period
Jan.2021 - Feb 2022
Mar 2022 - May 2022

Notional
Quantity
(Bbls/day)

Notional
Quantity (Bbls)

Weighted
Strike Price

4,000
3,000
2,044

1,460,000 $
177,000 $
188,006 $

42.06
42.98
42.33

Crude Oil: Open Collar Contracts - Priced off WTI (NYMEX)

Notional
Quantity
(Bbls/day)
1,770
2,000

Notional
Quantity
(Bbls)

Put Option
Weighted
Strike Price
(Bought)

Call Option
Weighted
Strike Price
(Sold)

750,422 $
184,000 $

35.00 $
35.00 $

50.00
48.50

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Natural Gas: Open Call Contracts, Bought, Priced off Henry Hub (NYMEX)

Period
Feb 2021 - Dec. 2022

Notional
Quantity

(MMBtu/day)
40,000

Notional
Quantity
(MMBtu)

Strike Price

27,960,000 $

3.00

Natural Gas: Open Swap Contracts, Bought, Priced off Henry Hub (NYMEX)

Period
Jan 2021 - Dec 2021
Jan 2022
Feb 2022
Mar 2022 - May 2022

Notional
Quantity

(MMBtu/day)
10,000
20,000
30,000
10,544

Notional
Quantity
(MMBtu)

Strike Price

3,650,000 $
620,000 $
840,000 $
970,075 $

2.62
2.79
2.79
2.69

Natural Gas: Open Collar Contracts, Priced off Henry Hub (NYMEX)

Period
Jan 2021 - Dec 2022
Jan 2021 - Dec 2021
Jan 2022 - Feb 2022
Mar 2022 - May 2022

Notional
Quantity
(MMBtu/day)

Notional
Quantity
(MMBtu)

Put Option
Weighted
Strike Price
(Bought)

Call Option
Weighted
Strike Price
(Sold)

40,000 29,200,000 $
30,000 10,950,000 $
30,000 1,770,000 $
92,000 $
10,000

1.83 $
2.18 $
2.20 $
2.25 $

3.00
3.00
4.50
3.40

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

fair value of open contracts and closed contracts, which had not yet settled (in thousands):

Prepaid and other assets – current
Other assets – non-current
Accrued liabilities

December 31,

2020

2019

2,752 $
2,762
13,620

7,266
2,653
1,785

The amounts recorded on the Consolidated Balance Sheets are on a gross basis. If these were recorded on a net

settlement basis, it would not have resulted in any differences in reported amounts.

Changes in the fair value and settlements of our commodity derivative contracts were as follows (in thousands):

Derivative loss (gain)

(23,808) $

59,887 $

(53,798)

Year Ended December 31,
2019

2020

2018

Cash receipts (payments), net, on commodity derivative contract settlements, which include derivative premium
payments, are included within Net cash provided by operating activities on the Consolidated Statements of Cash Flows and
were as follows (in thousands):

Derivative cash receipts (payments), net

45,196 $

13,941 $

(28,164)

Year Ended December 31,
2019

2020

2018

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. Share-Based Awards and Cash-Based Awards

Incentive Compensation Plan

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.

Share-based Awards: Restricted Stock Units

During 2019 and 2018, 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 and are granted to certain employees, and are subject to
satisfaction of certain predetermined performance criteria and adjustments at the end of the applicable performance period
based on the results achieved.

As of December 31, 2020, there were 10,347,591shares 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 2020, 2019 and 2018, 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 2019 grants, which were subject to predetermined performance criteria
applied against the applicable performance period. These RSUs continue to be subject to employment-based criteria and
vesting generally occurs in December of the second year after the grant. See the table below for anticipated vesting by
year.

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 2019 and 2018 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.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

During 2019, RSUs granted were subject to adjustments based on achievement of a combination of performance
criteria, which was comprised of: (i) net 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; litigation; and other (“Adjusted EBITDA”) for 2019 and (ii) Adjusted EBITDA as a percent of total
revenue (“Adjusted EBITDA Margin”) for 2019. Adjustments range from 0% to 100% based upon actual results compared
against pre-defined performance levels. For 2019, the Company achieved below target and above threshold for both
Adjusted EBITDA and Adjusted EBITDA Margin, therefore only a portion of the amount granted will be eligible for
vesting.

During 2018, RSUs granted were subject to adjustments based on achievement of a combination of performance

criteria, which was comprised of: (i) Adjusted EBITDA for 2018 and (ii) Adjusted EBITDA Margin for 2018. Adjustments
range from 0% to 100% based upon actual results compared against pre-defined performance levels. For 2018, the
Company achieved target for both Adjusted EBITDA and Adjusted EBITDA Margin.

A summary of activity related to RSUs is as follows:

2020

2019

2018

Weighted
Average
Grant Date
Fair Value
Per Share

Restricted
Stock Units

Nonvested,

beginning of
period
Granted
Vested
Forfeited
Nonvested, end of

period

1,614,722 $
-
(787,203)
(63,831)

5.73
-
6.90
5.80

3,355,917 $
994,698
(1,475,373)
(1,260,520)

3.90
4.51
2.76
3.37

5,765,251 $
988,955
(2,261,665)
(1,136,624)

763,688 $

4.51

1,614,722 $

5.73

3,355,917 $

2.48
6.90
2.21
2.68

3.90

Subject to the satisfaction of service conditions, the RSUs outstanding as of December 31, 2020 are eligible to vest in

2021.

RSUs fair value at grant date - There were no RSUs granted during 2020. During 2019 and 2018, the grant date fair

value of RSUs granted was $4.5 million and $6.8 million, respectively.

RSUs fair value at vested date - The fair value of the RSUs that vested during 2020, 2019 and 2018 was $2.0 million,

$7.0 million and $11.0 million, respectively, based on the Company’s closing price on the vesting date.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Share-Based Awards: Restricted Stock

Under the Directors Compensation Plan, shares of restricted stock (“Restricted Shares”) were issued in 2020, 2019 and

2018 to the Company’s non-employee directors as a component of their compensation arrangement. Vesting occurs upon
completion of the specified vesting period and one-third of each grant vests each year over a three-year period. 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, 2020, there were 473,244 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:

2020

2019

2018

Weighted
Average
Grant Date
Fair Value
Per Share

Restricted
Shares

Weighted
Average
Grant Date
Fair Value
Per Share

Restricted
Shares

Weighted
Average
Grant Date
Fair Value
Per Share

Restricted
Shares

Nonvested,

beginning of
period
Granted
Vested
Nonvested, end of

period

123,180 $
109,376
(78,428)

4.55
2.56
2.38

181,832 $
46,360
(105,012)

3.08
6.04
2.67

246,528 $
41,544
(106,240)

154,128 $

4.24

123,180 $

4.55

181,832 $

2.27
6.74
2.64

3.08

Subject to the satisfaction of service conditions, the Restricted Shares outstanding as of December 31, 2020 are

expected to vest as follows:

2021
2022
Total

Restricted
Shares

138,676
15,452
154,128

Restricted stock fair value at grant date - The grant date fair value of restricted stock granted during 2020, 2019 and

2018 was $0.3 million each year for all years presented 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 2020, 2019 and
2018 was $0.2 million, $0.5 million and $0.7 million, respectively, based on the Company’s closing price on the date of
vesting.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Share-Based Compensation

A summary of compensation expense under share-based payment arrangements is as follows (in thousands):

Year Ended December 31,
2019

2020

2018

Share-based compensation expense from:

Restricted stock units
Restricted stock
Total

3,555 $
404
3,959 $

3,410 $
280
3,690 $

3,260
280
3,540

As of December 31, 2020, unrecognized share-based compensation expense related to our awards of RSUs and

Restricted Shares was $1.2 million and $0.2 million, respectively. Unrecognized compensation expense will be recognized
through November 2021 for our RSUs and April 2022 for our Restricted Shares.

Cash-based Awards

In addition to share-based compensation, short-term, cash-based awards were granted under the Plan to substantially
all eligible employees in 2019 and 2018. The short-term, cash-based awards, which are generally a short-term component
of the Plan, are performance-based awards consisting of one or more business criteria or individual performance criteria
and a targeted level or levels of performance with respect to each of such criteria. In addition, these cash-based awards
included an additional financial condition requiring Adjusted EBITDA less reported Interest Expense Incurred for any
fiscal quarter plus the three preceding quarters to exceed defined levels measured over defined time periods for each cash-
based award. No cash-based incentive awards were granted in 2020 under the Plan, and therefore, no cash-based incentive
award compensation expense for 2020 has been recorded. The Compensation Committee has deferred its decision
regarding the potential awarding of incentive compensation, including by the exercise of discretion. During 2018, long-
term, cash awards were granted to certain employees subject to pre-define performance criteria. Expense is recognized
over the service period once the business criteria, individual performance criteria and financial condition are met.

● For the 2019 cash-based awards, a portion of the business criteria and individual performance criteria were

achieved. The financial condition requirement of Adjusted EBITDA less reported Interest Expense Incurred
exceeding $200 million over four consecutive quarters was achieved; therefore, incentive compensation expense
was recognized in 2019 for a portion of the 2019 cash-based awards. Payments were made in March 2020 and
are subject to all the terms of the 2019 Annual Incentive Award Agreement.

●

In 2018, the Company, as part of its long-term incentive program, granted cash awards to certain employees that
will vest over a three-year service period.

● For the 2018 long-term, cash-based awards, incentive compensation expense was determined based on the

Company achieving certain performance metrics for 2018 and is being recognized over the September 2018 to
November 2020 period (the service period of the award). The 2018 long-term, cash-based awards were paid on
December 15, 2020 subject to participants meeting certain employment-based criteria.

● For the 2018 short-term, cash-based awards, incentive compensation expense was determined based on the

Company achieving certain performance metrics for 2018 combined with individual performance criteria for
2018 and was recognized over the January 2018 to February 2019 period. The 2018 short-term, cash-based
awards were paid during March 2019.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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):

Share-based compensation included in:

General and administrative

3,959 $

3,690 $

3,540

Year Ended December 31,
2019

2020

2018

Cash-based incentive compensation

included in:
Lease operating expense
General and administrative

Total charged to operating income

849
4,019
8,827 $

2,206
8,897
14,793 $

3,596
9,586
16,722

Discretionary Bonus to Employees in 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 $7.6 million, payable in equal installments on
March 15, 2021 and April 15, 2021, subject to employment on those dates.

11. Employee Benefit Plan

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 2020,
2019, and 2018 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 $2.3 million, $2.0 million, and $2.0 million for
2020, 2019 and 2018, respectively.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. Income Taxes

Income Tax (Benefit) Expense

Components of income tax (benefit) expense were as follows (in thousands):

Current
Deferred

Total income tax (benefit) expense

Year Ended December 31,
2019

2020

2018

134 $
(30,287)
(30,153) $

(11,092) $
(64,102)
(75,194) $

35
500
535

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

2020

Year Ended December 31,
2019

2018

1,604 $
1,373
75
—
(21,345 )
(12,018 )
158
(30,153 ) $

(233) $
971
(175)
(11,523)
—
(64,704)
470
(75,194) $

52,366
457
560
—
487
(53,980 )
645
535

Our effective tax rate for the years 2020, 2019 and 2018 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,
effective tax rates for the years presented above are not meaningful.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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:

Property and equipment
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,

2020

2019

37,535 $
—
8,070
2,588
48,193

—
3,416
84,332
47,307
8,136
16,304
419
(22,361)
4,843
142,396
94,203 $

21,647
—
14,716
2,283
38,646

—
1,409
76,924
15,265
7,393
48,458
965
(54,436)
6,584
102,562
63,916

Income Taxes Receivable, Refunds and Payments

As of December 31, 2020, we do not have any current income taxes receivable. As of December 31, 2019, we

had current income taxes receivable of $1.9 million which was received in 2020 and related to a net operating loss (“NOL”)
carryback claim for the year 2017 that we carried back to prior years. During 2019, we received refunds of $51.8 million
related to our NOL carryback claims for the years 2012, 2013 and 2014 that were carried back to prior years. Additionally,
we received $4.5 million in interest income associated with the refunds in 2019. These carryback claims, in addition to the
2017 claim, were 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, 2020 and 2019, 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, 2020 (in thousands):

Federal net operating loss
State net operating loss
Interest expense limitation carryover

Amount

Expiration
Year

225,274 earliest is 2037
2026-2038
136,440
N/A
75,341

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Valuation Allowance

During 2020 and 2019, we recorded a decrease in the valuation allowance of $32.1 million and $63.3 million,

respectively, related to federal and state deferred tax assets. 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.

Throughout 2020, the Company has been assessing the realizability of our deferred tax assets by considering positive
factors such as, when considering the Company’s results for the twelve months ended December 31, 2018, 2019 and 2020,
the Company has cumulative pre-tax income during this three year period. Based on the assessment, we determined that
the Company’s ability to maintain long-term profitability despite near-term changes in commodity prices and operating
costs demonstrated that a portion of the Company’s net deferred tax assets would more likely than not be realized. During
2020, we released $32.1 million of the valuation allowance, resulting in an income tax benefit in 2020 primarily as a result
of 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 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,
2020, the Company’s valuation allowance was $22.4 million.

Uncertain Tax Positions

The table below sets forth the beginning and ending balance of the total amount of unrecognized tax benefits. During

2019, the settlement of our net operating loss carryback claims with the IRS effectively allowed us to also settle our
uncertain tax position which resulted in a change in our unrecognized tax benefits and materially impacted our income
tax benefit.

Reconciliation of the balances of our uncertain tax positions are as follows (in thousands):

Balance, beginning of period
Decrease during the period
Balance, end of period

Years open to examination

December 31,

2020

2019

— $
—
— $

9,482
(9,482)
—

The tax years from 2017 through 2020 remain open to examination by the tax jurisdictions to which we are subject.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. 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):

2020

Year Ended December 31,
2019

2018

Net income
Less portion allocated to nonvested shares
Net income allocated to common shares
Weighted average common shares outstanding
Basic and diluted earnings per common share

37,790 $
437
37,353 $
141,622
0.26 $

74,086 $
1,371
72,715 $
140,583
0.52 $

248,827
9,727
239,100
139,002
1.72

14. Supplemental Cash Flow Information

The following table reflects our supplemental cash flow information (in thousands):

Supplemental cash items:
Cash paid for interest (1)
Cash paid for income taxes
Cash refunds received for income taxes
Cash paid for share-based compensation (2)
Cash received for interest income

Non-cash investing activities:
Accruals of property and equipment
ARO - additions, dispositions and revisions, net

2020

Year Ended December 31,
2019

2018

59,183 $
159
2,007
—
603

66,720 $
51
51,833
—
7,720

3,035
17,928

29,662
37,440

61,501
138
11,126
1,130
2,385

18,575
19,877

(1) During 2018, cash paid for interest included amounts related to the debt instruments issued during 2016, which

were accounted for under ASC 470-60 and recorded against the carrying value of the debt instruments on the
Consolidated Balance Sheets and included in financing activities on the Consolidated Statements of Cash
Flows. No interest was capitalized in the periods presented.

(2) During 2020 and 2019, only common shares were used to settle vested RSUs and Restricted Shares. During 2018,

cash was used to settle vested RSUs related to the retirement of executive officers and shares of common stock were
used to settle all other vested RSUs and to settle Restricted Shares.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

15. Commitments

See Note 7 for information on leases.

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, 2020, we had surety bonds related
to the agreement with Total E&P totaling $93.7 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, 2020, 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 $30.0 million of surety bonds as of December 31, 2020. This amount increases on June 1 of the following years to
$33.0 million - 2021; $36.3 million - 2022; $40.0 million - 2023; $44.0 million - 2024; $48.3 million - 2025, and future
increases in increments ranging $4.0 million to $9.0 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 2020, 2019 and 2018, 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 Total E&P and Shell
agreements described above, were $5.4 million, $4.7 million, and $5.9 million during 2020, 2019 and 2018,
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: 2021–$5.8 million; 2022–$5.6 million; 2023 - $5.7 million; 2024 - $5.6 million; 2025–$5.6 million
and thereafter–$57.9 million. 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 2028. For 2020, 2019 and 2018 expense recognized
for the difference between the quantities shipped and the minimum obligations was $4.5 million, $4.5 million and $2.3
million, respectively. As of December 31, 2020, the estimated future costs are: 2021–$2.5 million; 2022–$1.8 million;
2023–$1.2 million; 2024 - $0.8 million; 2025 - $0.6 million and thereafter–$0.7 million.

We have no drilling rig commitments as of December 31, 2020.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16. Related Parties

During 2020, 2019 and 2018, there were certain transactions between us and other companies our 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 $0.3 million, $1.2 million and $1.3 million for the years
2020, 2019 and 2018 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 $14.4 million, $22.8 million
and $21.0 million in 2020, 2019 and 2018, respectively. The spouse received commissions partially based on services
rendered to W&T which were approximately $0.1 million in 2020, 2019 and 2018. 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. See Note 4 for information on a related party transaction concerning Monza.

17. Contingencies

Apache Lawsuit

On December 15, 2014, Apache filed a lawsuit against the Company, Apache Deepwater, L.L.C. vs. W&T Offshore,
Inc., alleging that W&T breached the joint operating agreement related to, among other things, the abandonment of three
deepwater wells in the Mississippi Canyon area of the Gulf of Mexico. A trial court judgment was rendered from the U.S.
District Court for the Southern District of Texas on May 31, 2017 directing the Company to pay Apache $49.5 million
including prejudgment interest, attorney's fees and costs. We unsuccessfully appealed that judgment through a process
ending with the denial of a writ of certiorari to the United States Supreme Court. A deposit of $49.5 million we made in
June of 2017 with the registry of the court was distributed during 2019 pursuant to an agreement with Apache.

Due to funds being distributed during 2019, amounts previously recorded of $49.5 million in Other assets (long-term)

and $49.5 million recorded in Other liabilities (long-term) on the Consolidated Balance Sheet as of December 31,
2018 were reversed during 2019 and interest income of $1.9 million was recorded in Interest expense, net on the
Consolidated Statements of Operations in 2019.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 penal 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, 2020 to such amount.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Notices of Proposed Civil Penalty Assessment

During 2020 and 2019, we did not pay any civil penalties to the BSEE related to Incidents of Noncompliance

(“INCs”) at various offshore locations. In January 2021, we executed a Settlement Agreement with the Bureau of Safety
and Environmental Enforcement (“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, with the first installment due in
March 2021. In addition, W&T committed to implement a Safety Improvement Plan with various deliverables due over a
period ending in 2022.

Royalties – “Unbundling” Initiative

The ONRR has publicly announced an “unbundling” initiative to revise the methodology employed by producers in

determining the appropriate allowances for transportation and processing costs that are permitted to be deducted in
determining royalties under Federal oil and gas leases. The ONRR’s initiative requires re-computing allowable
transportation and processing costs using revised guidance from the ONRR going back 84 months for every gas processing
plant that processed our gas. In the second quarter of 2015, pursuant to the initiative, we received requests from the ONRR
for additional data regarding our transportation and processing allowances on natural gas production related to a specific
processing plant. We also received a preliminary determination notice from the ONRR asserting that our allocation of
certain processing costs and plant fuel use at another processing plant was not allowed as deductions in the determination
of royalties owed under Federal oil and gas leases. We have submitted revised calculations covering certain plants and time
periods to the ONRR. As of the filing date of this Form 10-K, we have not received a response from the ONRR related to
our submissions. These open ONRR unbundling reviews, and any further similar reviews, could ultimately result in an
order for payment of additional royalties under our Federal oil and gas leases for current and prior periods. During 2020,
2019 and 2018, we paid $0.2 million, $0.4 million and $0.6 million, respectively, of additional royalties and expect to pay
more in the future. We are not able to determine the range of any additional royalties or if such amounts would be material.

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 2020 or 2019.

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.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

18. Selected Quarterly Financial Data—UNAUDITED

Unaudited quarterly financial data are as follows (in thousands, except per share amounts):

1st Quarter 2nd Quarter 3rd Quarter 4th Quarter

Year Ended December 31, 2020

Revenues
Operating (loss) income
Net (loss) income (1)
Basic and diluted (loss) earnings

per common share (2)

124,128 $
71,811
65,980

55,241 $
(28,041)
(5,904)

72,517
(19,510)
(13,339)

94,748
349
(8,947)

0.46

(0.04)

(0.09)

(0.06)

Year Ended December 31, 2019

Revenues
Operating income
Net (loss) income (1)
Basic and diluted earnings per

common share (2)

116,080 $
(30,976)
(47,761)

134,701 $
37,379
36,389

132,221 $
35,399
75,899

151,894
16,847
9,559

(0.34)

0.25

0.53

0.07

(1)

During 2020, we recorded a derivative (gain) loss of $(61.9) million, 15.4 million,
11.2 million, and $11.5 million in the first, second, third and fourth quarters,
respectively. During 2020, we recorded gain on debt transactions of
$47.5 million. During 2020, we recorded income tax expense (benefit) of $6.5 million,
($8.7) million, ($21.1) million and ($6.9) million in the first, second, third and fourth
quarters, respectively. During 2019, we recorded a derivative loss (gain) of $48.9
million, ($1.8) million, ($5.9) million, and $18.7 million in the first, second, third and
fourth quarters, respectively. During 2019, we recorded income tax expense (benefit)
of $0.2 million, ($11.7) million, ($55.5) million and ($8.2) million in the first, second,
third and fourth quarters, respectively.

(2)

The sum of the individual quarterly earnings (loss) per common share may not agree
with the yearly amount due to each quarterly calculation is based on income for that
quarter and the weighted average common shares outstanding for that quarter.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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:

Proved oil and natural gas properties and

equipment

8,567.5 $

8,532.2 $

8,169.9

2020

December 31,
2019

2018

Accumulated depreciation, depletion and
amortization related to oil, NGLs and
natural gas activities
Net capitalized costs related to

(7,890.9)

(7,793.3)

(7,665.1)

producing activities

676.6 $

738.9 $

504.8

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) (3)
Development

Year Ended December 31,
2019

2020

2018

8.1 $
7.4
23.6

223.8 $
30.6
114.5

24.1
49.9
56.2

Total costs incurred in oil and gas

property acquisition, exploration
and development activities

39.1 $

368.9 $

130.2

(1) Includes net additions from capitalized ARO of $15.2 million, $37.5 million, and $20.3

million during 2020, 2019, and 2018, respectively. These adjustments for ARO are associated
with acquisitions, liabilities incurred, divestitures and revisions of estimates.

(2) Includes seismic costs of $0.3 million, $7.8 million, and $1.5 million incurred during 2020,

2019, and 2018, respectively.

(3) Includes geological and geophysical costs charged to expense of $4.5 million, $5.7 million, and

$5.4 million during 2020, 2019, and 2018, respectively.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Depreciation, depletion, amortization and accretion expense

The following table presents our depreciation, depletion, amortization and accretion expense per barrel equivalent

(“Boe”) of products sold:

Depreciation, depletion, amortization and

accretion per Boe

7.82 $

10.01 $

11.24

Year Ended December 31,
2019

2020

2018

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 22.1% of our proved developed non-
producing reserves as of December 31, 2020 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, 2020. In prior
years, we were not the operator of substantially all proved undeveloped reserves.

The following sets forth estimated quantities of our net proved, proved developed and proved undeveloped oil, NGLs
and natural gas 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”.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Oil (MMBbls)

NGLs
(MMBbls)

Natural Gas
(Bcf)

Oil Equivalent
(MMBoe)

Natural Gas
Equivalent
(Bcfe)

Total Energy Equivalent
Reserves (1)

Proved reserves as of Dec. 31,

2017
Revisions of previous

estimates (2)

Extensions and discoveries

(3)

Purchase of minerals in

place (4)

Sales of minerals in place

(5)

Production

Proved reserves as of Dec. 31,

2018
Revisions of previous

estimates (6)

Extensions and discoveries

(7)

Purchase of minerals in

place (8)
Production

Proved reserves as of Dec. 31,

2019
Revisions of previous

estimates (9)

Extensions and discoveries

(10)

Purchase of minerals in

place (11)

Production

Proved reserves as of Dec. 31,

2020

Year-end proved developed

reserves:
2020
2019
2018

Year-end proved undeveloped

reserves:
2020 (12)
2019
2018

34.4

11.6

0.5

1.5

(2.2)
(6.7)

7.8

2.8

0.3

0.4

(0.2)
(1.3)

192.2

74.2

40.4

21.1

7.7

9.4

(7.2)
(32.0)

2.1

3.4

(3.5 )
(13.3 )

445.3

126.7

12.6

20.7

(21.2 )
(80.0 )

39.1

9.8

210.5

84.0

504.1

1.4

0.9

3.1
(6.7)

(1.5)

(16.9)

(3.0 )

(18.2 )

0.1

17.4
(1.3)

1.2

1.1

6.7

417.6
(41.3)

90.1
(14.8 )

540.9
(89.0 )

37.8

24.5

571.1

157.4

944.5

(0.9)

0.2

0.7
(5.6)

(5.9)

31.6

0.0

0.4
(1.7)

0.2

14.8
(48.4)

(1.4 )

0.2

3.6
(15.4 )

(8.8 )

1.3

21.8
(92.3 )

32.2

17.3

569.3

144.4

866.5

24.0
28.0
31.5

8.2
9.8
7.6

16.5
21.7
7.8

550.2
504.9
166.8

132.2
133.8
67.0

0.9
2.8
2.0

19.1
66.2
43.7

12.2
23.6
17.0

793.3
802.9
402.2

73.2
141.6
101.9

Volume measurements:
MMBbls – million barrels for crude oil, condensate or NGLs
MMBoe – million barrels of oil equivalent

Bcf – billion cubic feet
Bcfe – billion cubic feet of gas equivalent

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(1)

(2)

(3)

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.

Primarily related to upward revisions at our Mahogany field and our Ship Shoal 028 field. Additionally, increases of 2.3
MMBoe were due to price revisions.

Primarily related to extensions and discoveries of 1.3 MMBoe at our Viosca Knoll 823 (Virgo) field and 0.7 MMBoe at
our Ewing Bank 910 field.

(4)

Primarily related to our Ship Shoal 028 field and our Green Canyon 859 field (Heidelberg).

(5)

Primarily related to conveyance of interest in properties related to the JV Drilling Program.

(6)

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.

(7)

Primarily related to extensions and discoveries of 0.9 MMBoe at our Mississippi Canyon 800 (Gladden) field.

(8)

Primarily related to the Mobile Bay Properties and Magnolia acquisitions.

(9) 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.

(10) Primarily related to the discovery at East Cameron 338 field.

(11) Primarily related to the Mobile Bay Properties and Mahogany working interest acquisitions.

(12) We believe that we will be able to develop all but 2.3 MMBoe (approximately 19%) of the total of 12.2 MMBoe
reserves classified as proved undeveloped (“PUDs”) at December 31, 2020, within five years from the date such
reserves 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 2022 and 2024.

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 - per barrel
NGLs per barrel
Natural gas per Mcf

December 31,

2020

2019

2018

2017

37.78 $
10.29
2.05

58.11 $
18.72
2.63

65.21 $
29.73
3.13

46.58
22.65
2.86

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 2021 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):

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

Year Ended December 31,
2019

2020

2018

2,561.2 $

4,153.8 $

3,500.9

(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 $

(958.5)
(628.3)
(293.9)

1,620.2
(553.2)
1,067.0

100

W&T OFFSHORE, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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):

Changes in Standardized Measure

Standardized measure, beginning of year
Increases (decreases):

2020

Year Ended December 31,
2019

2018

986.9 $

1,067.0 $

740.6

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

(168.6)

(503.7)

2.8
(15.9)

1.4
(65.2)
111.8
87.7
44.6
—

11.9
(493.2)
493.7 $

(315.8)

(376.4)

27.0
(6.0)

19.3
116.4
107.4
62.9
298.3
—

(13.2)
(80.1)
986.9 $

(398.1)

571.5

53.6
(114.7)

48.4
307.6
50.5
(133.4)
27.8
(54.1)

(32.7)
326.4
1,067.0

101

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.

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, 2020 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,
2020, 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, 2020, 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, 2020 that have materially affected, or are reasonably likely to materially affect, our internal control
over financial reporting.

Item 9B. Other Information

None.

102

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 with

the SEC within 120 days after the end of our fiscal year covered by this Form 10-K and to the information set forth
following Item 3 of this report.

Item 11. Executive Compensation

The information required by this item is incorporated by reference from our definitive proxy statement to be filed with

the SEC within 120 days after the end of our fiscal year covered by this Form 10-K.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required by this item is incorporated by reference from our definitive proxy statement to be filed with

the SEC within 120 days after the end of our fiscal year covered by this Form 10-K.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required by this item is incorporated by reference from our definitive proxy statement to be filed with

the SEC within 120 days after the end of our fiscal year covered by this Form 10-K.

Item 14. Principal Accountant Fees and Services

The information required by this item is incorporated by reference from our definitive proxy statement to be filed with

the SEC within 120 days after the end of our fiscal year covered by this Form 10-K.

103

Item 15. Exhibits and Financial Statement Schedules

(a) Documents filed as a part of this report:

PART IV

1. Financial Statements. See “Index to Consolidated Financial Statements” in Part II, Item 8 of this Form 10-K.

All schedules are omitted because they are not applicable, not required or the required information is included in the

consolidated financial statements or related notes.

2. Exhibits:

Exhibit
Number

Description

3.1

3.2

3.3

3.4

3.5

4.1

4.2

Amended and Restated Articles of Incorporation of W&T Offshore, Inc. (Incorporated by reference to
Exhibit 3.1 of the Company’s Current Report on Form 8-K, filed February 24, 2006 (File No. 001-32414))

Amended and Restated Bylaws of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.2 of the
Company’s Registration Statement on Form S-1, filed May 3, 2004 (File No. 333-115103))

Certificate of Amendment to the Amended and Restated Articles of Incorporation of W&T Offshore, Inc.
(Incorporated by reference to Exhibit 3.3 of the Company’s Quarterly Report on Form 10-Q, filed July 31,
2012 (File No. 001-32414))

Form of Certificate of Amendment No. 2 to the Amended and Restated Articles of Incorporation of W&T
Offshore, Inc. (Incorporated by reference to Appendix A to the Company’s Definitive Proxy Statement on
Schedule 14A filed March 24, 2016 (File No. 001-32414))

Certificate of Amendment to the Amended and Restated Articles of Incorporation of W&T Offshore, Inc.,
dated as of September 6, 2016 (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report
on Form 8-K, filed September 6, 2016 (File No. 001-32414))

Specimen Common Stock Certificate (Incorporated by reference to Exhibit 4.1 of the Company’s
Registration Statement on Form S-1, filed May 3, 2004 (File No. 333-115103))

Indenture, dated as of October 18, 2018, by and among W&T Offshore, Inc., W&T Energy VI, LLC, and

W&T Energy VII, LLC, as subsidiary guarantors the Guarantors (as defined) and Wilmington Trust,
National Association, as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report
on Form 8-K, filed on October 24, 2018 (File No. 001-32414))

4.3

Description of Securities Registered Under Section 12 of the Securities Exchange Act of 1934, as amended

(Incorporated by reference to Exhibit 4.3 of the Company’s Annual Report on Form 10-K for the year ended
December 31, 2019 (File No. 001-32414)).

10.1*

2004 Directors Compensation Plan of W&T Offshore, Inc. (Incorporated by reference to Exhibit 10.11 of
the Company’s Registration Statement on Form S-1, filed May 3, 2004 (File No. 333-115103))

10.2*

First Amendment to the 2004 Directors Compensation Plan of W&T Offshore, Inc. (Incorporated by

reference to Appendix A of the Company’s Definitive Proxy Statement, filed March 26, 2020 (File No. 001-
32414))

104

10.3*

10.4*

10.5*

10.6*

10.7*

10.8*

10.9*

10.10*

10.11

Indemnification and Hold Harmless Agreement by and between W&T Offshore, Inc. and Stephen L.
Schroeder, dated July 5, 2006 (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report
on Form 8-K, filed July 12, 2006 (File No. 001-32414))

W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (Incorporated by reference from
Appendix A to the Company’s Definitive Proxy Statement on Schedule 14A, filed April 2, 2010 (File No.
001-32414))

First Amendment to W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan
(Incorporated by reference to Appendix A to the Company’s Definitive Proxy Statement on Schedule 14A
filed April 3, 2013 (File No. 001-32414))

Second Amendment to W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan
(Incorporated by reference to Appendix B to the Company’s Definitive Proxy Statement on Schedule 14A
filed April 3, 2013 (File No. 001-32414))

Third Amendment to W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan
(Incorporated by reference to Appendix B to the Company’s Definitive Proxy Statement on Schedule 14A
filed March 24, 2016 (File No. 001-32414))

Fourth Amendment to W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan
(Incorporated by reference to Appendix A to the Company’s Definitive Proxy Statement on Schedule 14A
filed March 24, 2017 (File No. 001-32414))

Employment Agreement between W&T Offshore, Inc. and Tracy W. Krohn dated as of November 1, 2010
(Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed on
November 5, 2010 (File No. 001-32414))

Form of Indemnification and Hold Harmless Agreement between W&T Offshore, Inc. and each of its
directors (Incorporated by reference to Exhibit 10.1 to the Company’s Annual Report on Form 10-K for the
year ended December 31, 2011 (File No. 001-32414))

Purchase Agreement dated October 5, 2018 by and among W&T Offshore, Inc., W&T Energy VI, LLC,
W&T Energy VII, LLC and Morgan Stanley & Co. LLC, as representative of the Initial Purchasers named
therein. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed on
October 11, 2018 (File No. 001-32414))

10.12

Intercreditor Agreement, dated May 11, 2015, by and among W&T Offshore, Inc. Toronto Dominion

(Texas) LLC, as priority lien agent, Morgan Stanley Senior Funding, Inc. as second lien collateral trustee,
and the various agents and lenders party thereto (Incorporated by reference to Exhibit 10.3 of the
Company’s Current Report on Form 8-K, filed May 14, 2015 (File No. 001-32414))

10.13

First Amendment to Intercreditor Agreement, dated as of October 18, 2018, by and among Toronto
Dominion (Texas) LLC, as Original Priority Lien Agent, Morgan Stanley Senior Funding, Inc., as Original
Second Lien Collateral Trustee, Wilmington Trust, National Association, as Original Second Lien Trustee,
Wilmington Trust, National Association, as Second Lien Trustee, Wilmington Trust, National Association,
as Second Lien Collateral Trustee, Cortland Capital Market Services LLC, as Priority Lien Agent,
Wilmington Trust, National Association as Third Lien Collateral Trustee and Wilmington Trust, National
Association as Third Lien Trustee. (Incorporated by reference to Exhibit 10.1 of the Company’s Current
Report on Form 8-K, filed on October 24, 2018 (File No. 001-32414))

105

10.14

Priority Confirmation Joinder, dated as of September 18, 2018, by and between Toronto Dominion (Texas)

LLC, as Original Priority Lien Agent, Morgan Stanley Senior Funding, Inc., as Original Second Lien
Collateral Trustee, Wilmington Trust, National Association, as Original Second Lien Trustee, Second Lien
Collateral Trustee, Third Lien Collateral Trustee and Third Lien Trustee and Cortland Capital Market
Services LLC, Priority Lien Agent. (Incorporated by reference to Exhibit 10.2 of the Company’s Current
Report on Form 8-K, filed on October 24, 2018 (File No. 001-32414))

10.15

Sixth Amended and Restated Credit Agreement, dated as of October 18, 2018, by and among W&T

Offshore, Inc., Toronto Dominion (Texas) LLC, as agent and the various agents and lenders party thereto.
(Incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K, filed on October
24, 2018 (File No. 001-32414))

10.16

First Amendment to Sixth Amended and Restated Credit Agreement, dated November 27, 2019, by and

among W&T Offshore, Inc., Toronto Dominion (Texas) LLC, as agent and the various agents and lenders
party thereto (Incorporated by reference to Exhibit 10.14 of the Company’s Annual Report on Form 10-K
for the year ended December 31, 2019, filed on March 5, 2020).

10.17

Second Amendment to Sixth Amended and Restated Credit Agreement, dated February 24, 2020, by and
among W&T Offshore, Inc., Toronto Dominion (Texas) LLC, as agent and the various agents and lenders
party thereto (Incorporated by reference to Exhibit 10.15 of the Company’s Annual Report on Form 10-Kfor
the year ended December 31, 2019, filed on March 5, 2020).

10.18

Third Amendment and Waiver to Sixth Amended and Restated Credit Agreement, Dated June 17, 2020, by

and among W&T Offshore, Inc., Toronto Dominion (Texas) LLC, as agent and the various agents and
lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly report on Form
10-Q, filed on June 23, 2020 (File No. 001-32414)).

10.19**

Fourth Amendment to Sixth Amended and Restated Credit Agreement, dated July 24, 2020., by and Among
W&T Offshore, Inc., Toronto Dominion (Texas) LLC, as agent and the various agents and lenders party
thereto.

10.20

Waiver, Consent to Second Amendment to Intercreditor Agreement and Fifth Amendment to Sixth

Amended and Restated Credit Agreement, dated January 6, 2021, by and among W&T Offshore, Inc.,
Toronto Dominion (Texas) LLC, as agent and the various agents and lenders party thereto (Incorporated by
reference to exhibit 10.1 of the Company’s Current Report on Form 8-K, filed on January 12, 2021 (File
No. 001-32414))

10.21*

Form of 2016 Executive Restricted Stock Unit Agreement (Incorporated by reference to Exhibit 10.10 of

the Company’s Quarterly Report on Form 10-Q, filed November 3, 2016 (File No. 001-32414))

10.22*

Form of 2017 Executive Restricted Stock Unit Agreement (Incorporated by reference to Exhibit 10.2 of the

Company’s Quarterly Report on Form 10-Q, filed May 4, 2017 (File No. 001-32414))

10.23*

10.24*

10.25

Form of Executive Annual Incentive Agreement for Fiscal 2018 (Incorporated by reference to Exhibit 10.5
of the Company’s Quarterly Report on Form 10-Q, filed November 1, 2018 (File No. 001-32414))

Form of 2018 Executive Long Term Incentive Agreement (Incorporated by reference to Exhibit 10.6 of the
Company’s Quarterly Report on Form 10-Q, filed November 1, 2018 (File No. 001-32414))

Form of Executive Annual Incentive Award Agreement for Fiscal Year 2019 (Incorporated by reference to
Exhibit 10.2 of the Company's Quarterly Report on Form 10-Q filed October 31, 2019 (File No. 001-
32414)).

106

10.26*

10.27

Form of 2019 Executive Long Term Incentive Plan Agreement (Incorporated by reference to Exhibit 10.3 of
the Company's Quarterly Report on Form 10-Q filed October 31, 2019 (File No. 001-32414)).

Purchase and Sale Agreement, dated as of January 1, 2019, between Exxon Mobil Corporation, Mobil Oil
Exploration & Producing Southeast Inc., XH, LLC, Exxon Mobile Bay Limited Partnership, ExxonMobil
U.S. Properties Inc. and W&T Offshore, Inc. (Incorporated by reference to Exhibit 10.1 of the Company’s
Quarterly Report on Form 10-Q, filed August 1, 2019 (File No. 001-32414))

21.1**

Subsidiaries of the Registrant.

23.1**

Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm.

23.2**

Consent of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers and Geologists.

31.1**

Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.

31.2**

Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.

32.1**

Certification of Chief Executive Officer and Chief Financial Officer of W&T Offshore, Inc. pursuant to 18
U.S.C. § 1350.

99.1**

Report of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers and Geologists.

101.INS**

Inline XBRL Instance Document.

101.SCH**

Inline XBRL Schema Document.

101.CAL**

Inline XBRL Calculation Linkbase Document

101.DEF**

Inline XBRL Definition Linkbase Document.

101.LAB**

Inline XBRL Label Linkbase Document.

101.PRE**

Inline XBRL Presentation Linkbase Document.

104**

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

* Management Contract or Compensatory Plan or Arrangement.
** Filed or furnished herewith.

107

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly

caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 4, 2021.

SIGNATURES

W&T OFFSHORE, INC.

By:

/S/ JANET YANG
Janet Yang
Executive Vice President and Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the

following persons on behalf of the registrant and in the capacities indicated on March 4, 2021.

/S/ TRACY W. KROHN
Tracy W. Krohn

Chairman, Chief Executive Officer, President and Director
(Principal Executive Officer)

/S/ JANET YANG
Janet Yang

Executive Vice President and Chief Financial Officer

(Principal Financial and Accounting Officer)

/S/ VIRGINIA BOULET
Virginia Boulet

/S/ STUART B. KATZ
Stuart B. Katz

/S/ S. JAMES NELSON, JR
S. James Nelson, Jr.

/S/ B. FRANK STANLEY
B. Frank Stanley

Director

108

Board of Directors

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

Stuart Katz*
Presiding Director

Virginia Boulet
Director

S. James Nelson, Jr.*
Director

B. Frank Stanley
Director

Executive Officers

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

Janet Yang
Executive Vice
President and Chief
Financial Officer

William J. Williford
Executive Vice
President and General
Manager Gulf
of Mexico

Stephen L. Schroeder
Senior Vice President
and Chief Technical
Officer

Shahid A. Ghauri
Vice President,
General Counsel and
Corporate Secretary

Corporate Office

Independent Auditors

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 or change of
address notifications should be
directed to the transfer agent.

Computershare Investor
Services, L.L.C.
2 North La Salle Street
Chicago, IL 60602
Tel 312.588.4990
us.computershare.com

Ernst & Young LLP, Houston, TX

Independent Petroleum Consultants

Netherland, Sewell & Associates, Inc.
1601 Elm Street, Suite 4500
Dallas, TX 75201-4754

Annual Meeting

The Company’s 2021 Annual Meeting
of Shareholders will be held at 8 a.m.
Central Time on Tuesday, May 4,
2021, at the Corporate Office, 5718
Westheimer Road, Suite 700,
Houston, TX 77057.

Form 10-K & Quarterly Reports /
Investor Contact

A copy of the W&T Offshore, Inc. Form
10-K for the year ended December
31, 2020 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.

* Messrs. Katz and Nelson have elected to retire from our Board effective with the 2021 annual meeting. It is expected that the Board will elect
Virginia Boulet to serve as the Presiding Director.

W&T Offshore, Inc.

5718 Westheimer Rd, Suite 700

Houston, TX 77057-5745

wtoffshore.com