TALOS ENERGY INC. Management's Discussion and Analysis of Financial Condition and Results of Operations (form 10-Q)

Unless otherwise indicated or the context otherwise requires, references in this
Quarterly Report to "us," "we," "our" or the "Company" are to Talos Energy Inc.
and its wholly-owned subsidiaries.

The following discussion and analysis of our financial condition and results of
operations is based on, and should be read in conjunction with our Condensed
Consolidated Financial Statements and notes thereto in Part I, Item 1.
"Condensed Consolidated Financial Statements" of this Quarterly Report, as well
as our audited Consolidated Financial Statements and the notes thereto in our
2021 Annual Report and the related Management's Discussion and Analysis of
Financial Condition and Results of Operations included in Part II, Item 7.
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" of our 2021 Annual Report.

Our Business

We are a technically driven independent exploration and production company
focused on safely and efficiently maximizing long-term value through our
operations, currently in the United States ("U.S.") and offshore Mexico both
through upstream oil and gas exploration and production and the development of
carbon capture and sequestration ("CCS") opportunities. We leverage decades of
technical and offshore operational expertise towards the acquisition,
exploration and development of assets in key geological trends that are present
in many offshore basins around the world. With a focus on environmental
stewardship, we also utilize our expertise to explore opportunities to reduce
industrial emissions through our CCS initiatives both in and along the coast of
the U.S. Gulf of Mexico.

We have historically focused our operations in the U.S. Gulf of Mexico because
of our deep experience and technical expertise in the basin, which maintains
favorable geologic and economic conditions, including multiple reservoir
formations, comprehensive geologic and geophysical databases, extensive
infrastructure and an attractive and robust asset acquisition market.
Additionally, we have access to state-of-the-art three-dimensional seismic data,
some of which is aided by new and enhanced reprocessing techniques that have not
been previously applied to our current acreage position. We use our broad
regional seismic database and our reprocessing efforts to generate a large and
expanding inventory of high-quality prospects, which we believe greatly improves
our development and exploration success. The application of our extensive
seismic database, coupled with our ability to effectively reprocess this seismic
data, allows us to both optimize our organic drilling program and better
evaluate a wide range of business development opportunities, including
acquisitions and collaborative arrangement opportunities, among others.

In order to determine the most attractive returns for our drilling program, we
employ a disciplined portfolio management approach to stochastically evaluate
all of our drilling prospects, whether they are generated organically from our
existing acreage, an acquisition or joint venture opportunities. We add to and
reevaluate our inventory in order to deploy capital as efficiently as possible.

Significant Developments

Below is a cumulative list of significant developments that have occurred since
the filing of our Quarterly Report on Form 10-Q for the period ended June 30,
2022.

EnVen Acquisition - On September 21, 2022, we executed a merger agreement to
acquire EnVen Energy Corporation ("EnVen"), a private operator in the Deepwater
U.S. Gulf of Mexico, for approximately $1.1 billion in stock and cash
consideration (the "EnVen Acquisition," and such agreement, the "EnVen Merger
Agreement"). The EnVen Acquisition is expected to double our operated Deepwater
facility footprint by adding key infrastructure in our existing operating areas.
Upon closing, we expect this to increase our production by approximately 40% or
24.0 MBoep/d and increase our gross acreage by 35%.

Consideration for the EnVen Acquisition consists of 43.8 million shares of our
common stock and $212.5 million in cash, subject to certain adjustments.
Following the EnVen Acquisition, our shareholders will own approximately 66% of
the pro forma company and EnVen's equity holders will own the remaining 34%. The
closing of the EnVen Acquisition is expected to occur by late December 2022 or
early January 2023.

On October 21, 2022, Talos Production Inc. commenced a consent solicitation to
obtain the requisite holders' consent to certain amendments to the indenture
governing its 12.00% Notes (as defined below under " - Liquidity and Capital
Resources - Overview of Debt Instruments") to permit the incurrence of
indebtedness with respect to EnVen's 11.75% Senior Secured Second Lien Notes due
2026. See Part I, Item 1. "Condensed Consolidated Financial Statements - Note 10
- Commitments and Contingencies" for additional information.
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2022 Drilling Program - We recently commenced drilling operations with the
Seadrill Sevan Louisiana rig on our Lime Rock prospect near our operated Ram
Powell facility and the rig will move to drill the adjacent Venice prospect once
the Lime Rock drilling operations are complete. We own a 60% working interest in
both prospects and expect first oil within 12-18 months from beginning drilling
operations at each prospect. Prior to commencing operations at Lime Rock, we
encountered issues related to strong looping ocean currents while performing a
well recompletion project. The recompletion operation has been suspended and we
plan to return to the project at a later date.

Phoenix Field Update - Production from one of our Tornado wells generated
increased water volumes during the third quarter primarily as a result of the
ongoing sub-surface water flood project in the Phoenix Field. This water
breakthrough occurred earlier than originally expected, though within the range
of projected outcomes in previous reservoir simulations used for the 2021
year-end reserves. We currently expect minor negative revisions to proved
reserves as a result of timing impacts of early water breakthrough.

Oxy Transaction - In August 2022, we entered into an eight block cross
assignment (the "Joint Area") with Occidental Petroleum Corporation ("Oxy"),
which resulted in Oxy being the operator with a 70% working interest and we have
the remaining 30% working interest. We contributed 100% working interest in two
blocks within Green Canyon area to the Joint Area. We and Oxy will commence
drilling an exploration well in the Joint Area in the first half of 2023.

Inflation Reduction Act of 2022 (the "IRA") - On August 16, 2022, President
Biden signed the IRA into law. The inclusion of several provisions in the IRA is
expected to benefit both our upstream and CCS businesses. Specifically, the IRA
directs the Department of the Interior ("DOI") to:

•

accept the highest bids received for Lease Sale 257, which was vacated by US District Court for the District of Columbia in January 2022; and

•

move forward with Lease Sales 259 and 261 in the Gulf of Mexico by March 31,
2023 and September 30, 2023, respectively, notwithstanding the June 30, 2022
expiration of the 2017-2022 Outer Continental Shelf Oil and Gas Leasing Program.

We were one of the most active bidders in Lease Sale 257 and were the high
bidder on 10 blocks and awarded leases on 9 blocks. The IRA also links issuance
of federal wind and solar development rights to requirements to offer for sale
federal oil and gas leases for a 10-year period of time. The IRA requires the
federal government to offer for sale a minimum of 60 million acres for offshore
oil and gas leases during the one-year period immediately preceding granting an
offshore wind lease on the U.S. Outer Continental Shelf.

The IRA incentivizes additional capital investment in CCS projects by developers and sponsors through the following:

•

increases the Section 45Q tax credit value from $50 per metric ton to $85 per
metric ton for qualified carbon oxide captured from an industrial source and
stored in secure geologic formations if certain prevailing wage and
apprenticeship requirements are met;

•

expands eligibility for carbon capture and sequestration credits under Section
45Q by extending the beginning of the construction deadline from before January
1, 2026 to before January 1, 2033; and

•

allows taxpayers to now claim the value of a Section 45Q tax credit with respect
to carbon capture equipment originally placed in service after December 31, 2022
as a direct pay option (i.e.; through a tax refund as if there had been an
overpayment of taxes). Both taxable and tax-exempt entities may elect the direct
pay option, but any taxable entity may only elect such option for the first 5
years of the tax credit period that is otherwise available.

The IRA also raises the minimum oil and gas royalty rate for new offshore leases
from the current 12.5% to 16.7% and caps the royalty rate at 18.8% for 10 years;
however this provision does not affect existing offshore leases. The 18.8% cap
is commensurate with existing offshore royalty rate for leases in water depth
exceeding 200 meters.
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Additionally, the IRA imposes a first-ever federal fee on greenhouse gases
through a methane emissions charge. The IRA amends the federal Clean Air Act to
impose a charge on emissions of methane from sources required to report their
GHG emissions to the U.S. Environmental Protection Agency ("EPA"), including
those sources in the offshore and onshore oil and gas production, and onshore
processing, transmission and compression, gathering, and boosting station source
categories. For such qualifying facilities, the charge starts at $900 per metric
ton of methane reported for calendar year 2024, increasing to $1,200 per metric
ton of methane for calendar year 2025 and again to $1,500 per metric ton of
methane for calendar year 2026 and year thereafter. Calculation of the charge is
based on certain thresholds established in the IRA. The charge will be based on
the prior year's emissions, and the charge starts in 2025 based on 2024 data.
The methane emissions charge could increase our operating costs and adversely
affect our business.

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

The following items affect the comparability of our financial condition and results of operations for periods presented herein and could potentially continue to affect our future financial condition and results of operations.

Planned Downtime - We are vulnerable to downtime events impacting the
transportation, gathering and processing of production. We produce the Phoenix
Field through the Helix Producer I (the "HP-I") that is operated by Helix Energy
Solutions Group, Inc. ("Helix"). Helix is required to disconnect and dry-dock
the HP-I every two to three years for inspection as required by the U.S. Coast
Guard, during which time we are unable to produce the Phoenix Field.

During the three months ended September 30, 2022, Helix dry-docked the HP-I.
After conducting sea trials, production resumed in mid-September, resulting in a
total shut-in period of 41 days. The shut-in resulted in an estimated deferred
production of approximately 6.2 MBoepd and 2.1 MBoepd for the three and nine
months ended September 30, 2022, respectively, based on production rates prior
to the shut-in.

During the third quarter of 2022, we experienced approximately 17 days of
planned third-party downtime due to maintenance of the Shell Odyssey Pipeline,
which carries our production primarily from our Ram Powell Field, Main Pass 288
Field and non-operated Delta House facility. Production resumed in October 2022.
We estimate the shut-in resulted in deferred production of approximately 1.8
MBoepd and 0.6 MBoepd for the three and nine months ended September 30, 2022,
respectively, based on production rates prior to the shut-in.

Eugene Island Pipeline System - During the first quarter of 2022, we experienced
approximately 40 days of unplanned third-party downtime due to maintenance of
the Eugene Island Pipeline System, which carries our production from the Phoenix
Field and Green Canyon 18 Field. For the nine months ended September 30, 2022,
we estimate the shut-in resulted in deferred production of approximately 1.5
MBoepd based on production rates prior to the shut-in.

Hurricanes and Tropical Storms - During the third quarter of 2021, production
from the U.S. Gulf of Mexico was impacted due to Hurricane Ida. While our assets
did not sustain significant damage, the storm impacted key third-party
downstream infrastructure, which prevented us from restoring the majority of our
production for several weeks. For the three and nine months ended September 30,
2021, we estimate that deferred production related to this storm was
approximately 12.7 MBoepd and 4.3 MBoepd, respectively, based on production
rates prior to the storm. We did not experience any disruptions to our
operations from hurricanes or tropical storms during the three and nine months
ended September 30, 2022.

Known Trends and Uncertainties

See Part II, Item 7. "Management's Discussion and Analysis of Financial
Condition and Results of Operations" in our 2021 Annual Report for a detailed
discussion of known trends and uncertainties. The following carries forward or
provides an update to known trends and uncertainties discussed in our 2021
Annual Report.

Volatility in Oil, Natural Gas and NGL Prices - Historically, the markets for
oil and natural gas have been volatile. Oil, natural gas and NGL prices are
subject to wide fluctuations in supply and demand. Our revenue, profitability,
access to capital and future rate of growth depends upon the price we receive
for our sales of oil, natural gas and NGL production.
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Significant progress has been made to reduce the risk of spreading COVID-19 and
its multiple variants, however, certain regions in the world remain negatively
impacted by outbreaks of COVID-19 that continue to degrade economic activity.
Additionally, the risk of a new variant of COVID-19 disrupting global economic
activity remains persistent and its impact on our operational and financial
performance will depend on developments that are difficult to predict, including
the duration and spread of the outbreak and its impact on our personnel,
customer activity and third-party providers.

During the period January 1, 2022 through September 30, 2022, the daily spot
prices for NYMEX WTI crude oil ranged from a high of $123.64 per Bbl to a low of
$75.99 per Bbl, and the daily spot prices for NYMEX Henry Hub natural gas ranged
from a high of $9.85 per MMBtu to a low of $3.73 per MMBtu. Although we cannot
predict the occurrence of events that may affect future commodity prices or the
degree to which these prices will be affected, the prices for any commodity that
we produce will generally approximate current market prices in the geographic
region of production. We hedge a portion of our commodity price risk to mitigate
the impact of price volatility on our business. See Part I, Item 1. "Condensed
Consolidated Financial Statements - Note 4 - Financial Instruments" for
additional information regarding our commodity derivative positions as of
September 30, 2022.

The U.S. Energy Information Administration ("EIA") published its latest
Short-Term Energy Outlook on October 12, 2022. The EIA expects the Henry Hub
spot price will average $9.03 per MMBtu in the fourth quarter of 2022 and then
fall to an average $6.01 per MMBtu in 2023 as U.S. natural gas production rises.
The EIA also expects the WTI spot price will average $91.98 per Bbl in the
fourth quarter of 2022 and average $90.91 per Bbl in 2023. The EIA expects
average crude oil prices to mostly remain between $90.00 per Bbl - $100.00 per
Bbl 2023, with the possibility for significant volatility around those averages.
Recent events contributing to increased uncertainty in the crude oil market
include: (i) the impact of the OPEC Plus decision to reduce crude oil production
by 2.0 MBbl per day beginning in November 2022 and the potential for further
production cuts in the future; (ii) the threat of increasing conflict following
the outbreak of violent clashes in the Libyan capital of Tripoli; (iii)
uncertainty around the potential expiration of the current coordinated petroleum
release from the U.S. Strategic Petroleum Reserves to reduce domestic gasoline
prices; (iv) the potential re-negotiation of a nuclear agreement with Iran that
could lift sanctions on the country and allow Iran's crude oil exports into the
market; and (v) the risk associated with hurricanes and tropical storms.

Inflation of Cost of Goods, Services and Personnel - Due to the cyclical nature
of the oil and gas industry, fluctuating demand for oilfield goods and services
can put pressure on the pricing structure within our industry. As commodity
prices rise, the cost of oilfield goods and services generally also increase,
while during periods of commodity price declines, oilfield costs typically lag
and do not adjust downward as fast as oil prices do. In addition, the U.S.
inflation rate has been steadily increasing since 2021 and into 2022. These
inflationary pressures may also result in increases to the costs of our oilfield
goods, services and personnel, which would in turn cause our capital
expenditures and operating costs to rise. Sustained levels of high inflation
could likely cause the U.S. Federal Reserve and other central banks to further
increase interest rates, which could have the effects of raising the cost of
capital and depressing economic growth, either or both of which could hurt our
business.

Impairment of Oil and Natural Gas Properties - Under the full cost method of
accounting, the "ceiling test" under SEC rules and regulations specifies that
evaluated and unevaluated properties' capitalized costs, less accumulated
amortization and related deferred income taxes (the "Full Cost Pool"), should be
compared to a formulaic limitation (the "Ceiling") each quarter on a
country-by-country basis. If the Full Cost Pool exceeds the Ceiling, an
impairment must be recorded. For the three and nine months ended September 30,
2022 and 2021, we did not recognize an impairment based on the ceiling test
computations. At September 30, 2022 our ceiling test computation was based on
SEC pricing of $93.61 per Bbl of oil, $6.56 per Mcf of natural gas and $35.94
per Bbl of NGLs.

There is a significant degree of uncertainty with the assumptions used to
estimate the present value of future net cash flows from estimated production of
proved oil and gas reserves due to, but not limited to the risk factors referred
to in Part I, Item 1A. "Risk Factors" included in our 2021 Annual Report. The
discounted present value of our proved reserves is a major component of the
Ceiling calculation. Any decrease in pricing, negative change in price
differentials or increase in capital or operating costs could negatively impact
the estimated future discounted net cash flows related to our proved oil and
natural gas properties.
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With respect to our operations in Mexico, our oil and natural gas properties are
classified as unproved properties, not subject to amortization. The submission
of the Unit Development Plan for the Zama Field to the National Hydrocarbon
Commission, which will set out the terms on which the reservoir will be jointly
developed, is expected by March 2023 and could adversely affect the value of the
Mexico oil and natural gas assets and result in an impairment of our unevaluated
oil and gas properties.

BOEM Bonding Requirements - In 2016, the BOEM issued the 2016 Notice to Lessees
and Operators ("NTL"), which bolstered supplemental bonding requirements. The
NTL was not fully implemented as the BOEM under the Trump Administration first
paused, and then in 2020 rescinded, this NTL.

The future cost of compliance with respect to supplemental bonding, including
the obligations imposed on us, whether as current or predecessor lessee or grant
holder, as a result of the implementation of a new NTL analogous to the 2016 NTL
to the extent finalized, as well as to the provisions of any other new, more
stringent NTLs or final rules on supplemental bonding published by the BOEM
under the Biden Administration, could materially and adversely affect our
financial condition, cash flows and results of operations. Moreover, the BOEM
has the right to issue liability orders in the future, including if it
determines there is a substantial risk of nonperformance of the current interest
holder's decommissioning liabilities and the Biden Administration may elect to
pursue more stringent supplemental bonding requirements.

Deepwater Operations - We have interests in Deepwater fields in the U.S. Gulf of
Mexico. Operations in Deepwater can result in increased operational risks as has
been demonstrated by the Deepwater Horizon disaster in 2010. Despite
technological advances since this disaster, liabilities for environmental
losses, personal injury and loss of life and significant regulatory fines in the
event of a disaster could be well in excess of insured amounts and result in
significant current losses on our statements of operations as well as going
concern issues.

Oil Spill Response Plan - We maintain a Regional Oil Spill Response Plan that
defines our response requirements, procedures and remediation plans in the event
we have an oil spill. Oil spill response plans are generally approved by the
BSEE bi-annually, except when changes are required, in which case revised plans
are required to be submitted for approval at the time changes are made.
Additionally, these plans are tested and drills are conducted periodically at
all levels.

Hurricanes and Tropical Storms - Since our operations are in the U.S. Gulf of
Mexico, we are particularly vulnerable to the effects of hurricanes and tropical
storms on production and capital projects. Significant impacts could include
reductions and/or deferrals of future oil and natural gas production and
revenues, increased lease operating expenses for evacuations and repairs and
possible acceleration of plugging and abandonment costs.

Five-Year Offshore Oil and Gas Leasing Program Update - Under the Outer
Continental Shelf Lands Act ("OCSLA"), as amended, the BOEM within the DOI must
prepare and maintain forward-looking five-year plans-referred to by BOEM as
national programs or five-year programs-to schedule proposed oil and gas lease
sales on the U.S. Outer Continental Shelf. On May 11, 2022, the DOI cancelled
two lease auctions in the Gulf of Mexico, Lease Sales 259 and 261, and one
auction in the Cook Inlet, Alaska, Lease Sale 258, under the 2017-2022 national
program that was developed under the Obama Administration, which expired on June
30, 2022. The DOI cited "conflicting court rulings" as the primary reason for
not holding the two Gulf of Mexico lease sales. As discussed above under " -
Significant Developments," President Biden signed the IRA into law on August 16,
2022. The IRA reinstates Lease Sale 257 held in November 2021, and requires the
DOI to both accept all valid high bids received in Lease Sale 257 and issue
leases to the high bidders. We were one of the most active bidders in Lease Sale
257 and we were the the high bidder on 10 blocks and awarded leases on 9 blocks.
Furthermore, the DOI must hold Gulf of Mexico lease sales 259 and 261 by March
31, 2023, and September 30, 2023, respectively.

BOEM's development of a new national program typically takes place over several
years, during which successive drafts of the program are published for review
and comment. At the end of the process, the Secretary of the Interior must
submit the Proposed Final Program to the President and to Congress for a period
of at least 60 days, after which the program may be approved by the Secretary of
the Interior and may take effect with no further regulatory or legislative
action.
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BOEM took the first formal step in pursuit of a new five-year national program
in January 2018 by releasing a Draft Proposed Program. The OCSLA and its
implementing regulations call for two subsequent drafts, a Proposed Program
("PP"), which is open for public comment for a period of at least 90 days, and
then a Proposed Final Program, which is submitted to Congress and the President
for 60 days before implementation. These later program stages also are
accompanied by publication of a draft and final Programmatic Environmental
Impact Statement ("PEIS"), with a period for public comment on the draft PEIS.
The PP and a draft PEIS for the 2023-2028 five-year period were published in the
Federal Register on July 8, 2022, with a 90-day comment period. The public
comment period has now closed, and BOEM is reviewing the comments received. The
PP includes no more than ten potential lease sales in the Gulf of Mexico;
however, BOEM's subsequent Proposed Final Program for 2023-2028 could reduce the
number of Gulf of Mexico lease sales in the national program.

When the 2023-2028 national program will be approved and implemented remains
uncertain. Congress may influence the Biden Administration's development and
implementation of the five-year 2023-2028 national program by submitting public
comments during formal comment periods, by evaluating programs in committee
oversight hearings, and, more directly, by enacting legislation with program
requirements. It is possible that the program could be delayed if opponents of
offshore oil and gas production initiate lawsuits challenging BOEM's actions.

How We Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:

•

production volumes;

•

realized prices on the sale of oil, natural gas and NGLs, including the effect of our commodity derivative contracts;

•
lease operating expenses;

•
capital expenditures; and

•

Adjusted EBITDA, which is discussed under "-Supplemental Non-GAAP Measure" below.

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Results of Operations

Revenue

The information below provides a discussion of, and an analysis of significant
variance in, our oil, natural gas and NGL revenues, production volumes and sales
prices (in thousands):

                             Three Months Ended
                                September 30,                    Nine Months Ended September 30,
                             2022          2021        Change        2022             2021          Change
Revenues:
Oil                       $  295,585    $   246,208   $ 49,377   $  1,078,800    $       743,759   $ 335,041
Natural gas                   68,360         31,723     36,637        181,747             86,088      95,659
NGL                           13,183         12,978        205         49,232             31,738      17,494
Total revenues            $  377,128    $   290,909   $ 86,219   $  1,309,779    $       861,585   $ 448,194

Total Production Volumes:
Oil (MBbls)                    3,258          3,609       (351 )       11,020             11,827        (807 )
Natural gas (MMcf)             7,292          6,975        317         24,746             24,055         691
NGL (MBbls)                      403            429        (26 )        1,372              1,344          28
Total production volume
(MBoe)                         4,876          5,200       (324 )       16,516             17,180        (664 )

Daily Production Volumes
by

Product:

Oil (MBblpd)                    35.4           39.2       (3.8 )         40.4               43.3        (2.9 )
Natural gas (MMcfpd)            79.3           75.8        3.5           90.6               88.1         2.5
NGL (MBblpd)                     4.4            4.7       (0.3 )          5.0                4.9         0.1
Total production volume
(MBoepd)                        53.0           56.5       (3.5 )         60.5               62.9        (2.4 )

Average Sale Price Per
Unit:
Oil (per Bbl)             $    90.73    $     68.22   $  22.51   $      97.89    $         62.89   $   35.00
Natural gas (per Mcf)     $     9.37    $      4.55   $   4.82   $       7.34    $          3.58   $    3.76
NGL (per Bbl)             $    32.71    $     30.25   $   2.46   $      35.88    $         23.61   $   12.27
Price per Boe             $    77.34    $     55.94   $  21.40   $      79.30    $         50.15   $   29.15
Price per Boe (including
realized

commodity derivatives) $ 60.70 $ 42.17 $ 18.53 $ 56.99 $ 39.13 $ 17.86

The information below provides an analysis of the change in our oil, natural gas
and NGL revenues due to changes in sales prices and production volumes (in
thousands):

                      Three Months Ended                   Nine Months Ended
                  September 30, 2022 vs 2021          September 30, 2022 vs 2021
                 Price       Volume      Total       Price      Volume       Total
Revenues:
Oil            $   73,322   $ (23,945 ) $ 49,377   $ 385,793   $ (50,752 ) $ 335,041
Natural gas        35,195       1,442     36,637      93,185       2,474      95,659
NGL                   992        (787 )      205      16,833         661      17,494
Total revenues $  109,509   $ (23,290 ) $ 86,219   $ 495,811   $ (47,617 ) $ 448,194


Three Months Ended September 30, 2022 and 2021 Volumetric Analysis - Production
volumes decreased by 3.5 MBoepd to 53.0 MBoepd. The decrease in production
volumes was primarily due to the third party downtime associated with the HP-I
dry-dock in our Phoenix Field and the Shell Odyssey Pipeline shut-in primarily
impacting our Ram Powell Field, Main Pass 288 Field and non-operated Delta House
facility, which resulted in 6.2 MBoepd and 1.8 MBoepd of deferred production,
respectively. Additionally, production volumes decreased 4.3 MBoepd and 1.8
MBoepd primarily attributable to well performance and natural production
declines in our Phoenix Field and Green Canyon 18 Field, respectively. The
decrease was partially offset by an increase of 12.7 MBoepd in deferred
production attributable to Hurricane Ida in 2021.
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Nine Months Ended September 30, 2022 and 2021 Volumetric Analysis - Production
volumes decreased by 2.4 MBoepd to 60.5 MBoepd. The decrease in production
volumes was primarily due to the third party downtime for the HP-I dry-dock in
our Phoenix Field, the Eugene Island Pipeline System shut-in primarily impacting
HP-I and Green Canyon 18 Field and the Shell Odyssey Pipeline shut-in primarily
impacting our Ram Powell Field, Main Pass 288 Field and non-operated Delta House
facility, which resulted in 4.2 MBoepd of deferred production. Additionally,
production volumes decreased 1.7 MBoepd at Delta House, a non-operated facility
located in Mississippi Canyon, primarily related to temporary shut-ins for
repairs and maintenance and natural production declines. The decrease was
partially offset by an increase of 4.3 MBoepd in deferred production
attributable to Hurricane Ida in 2021.

Operating Expenses

Lease Operating Expense

The following table highlights lease operating expense items in total and on a
cost per Boe production basis. The information below provides the financial
results and an analysis of significant variances in these results (in thousands,
except per Boe data):

                                     Three Months Ended September 30,       

Nine Months Ended September 30,

                                        2022                  2021                2022                2021

Lease operating expenses $ 81,760 $ 70,034 $ 229,156 $ 208,675 Lease operating expenses per Boe $

           16.77     $           13.47   

$ 13.87 $ 12.15

Three Months Ended September 30, 2022 and 2021 - Lease operating expense for the
three months ended September 30, 2022 increased by approximately $11.7 million,
or 17%. The increase is primarily due to a $4.9 million increase in facility and
workover expense related to repairs and maintenance at the Phoenix Field and the
Pompano Field. Additionally, there was a $1.7 million increase in company and
contract labor compared to the same period in 2021 and $1.4 million reduction in
production handling fees related to reimbursements for costs from certain third
parties.

Nine Months Ended September 30, 2022 and 2021 - Lease operating expense for the
nine months ended September 30, 2022 increased by approximately $20.5 million,
or 10%. The increase is primarily due to a $19.8 million increase in facility
and workover expense related to repairs and maintenance at the Phoenix Field and
the Gunflint Field. Additionally, there was a $4.8 million increase in company
and contract labor compared to the same period in 2021. This increase was
partially offset by $7.0 million in additional production handling fees related
to reimbursements for costs from certain third parties.

Depreciation, Depletion and Amortization

The following table highlights depreciation, depletion and amortization items in
total and on a cost per Boe production basis. The information below provides the
financial results and an analysis of significant variances in these results (in
thousands, except per Boe data):

                                     Three Months Ended September 30,       

Nine Months Ended September 30,

                                        2022                  2021                2022                2021
Depreciation, depletion and
amortization                      $          92,323     $          88,596   $        295,174    $        290,094
Depreciation, depletion and
amortization
 per Boe                          $           18.93     $           17.04   $          17.87    $          16.89


Three Months Ended September 30, 2022 and 2021 - Depreciation, depletion and
amortization expense for the three months ended September 30, 2022 increased by
approximately $3.7 million, or 4%. This was primarily due to an increase of
$1.85 per Boe, or 11%, in the depletion rate on our proved oil and natural gas
properties partially offset by decreased production of 3.5 MBoepd.

Nine Months Ended September 30, 2022 and 2021 - Depreciation, depletion and
amortization expense for the nine months ended September 30, 2022 increased by
approximately $5.1 million, or 2%. This was primarily due to an increase of
$1.00 per Boe, or 6% in the depletion rate on our proved oil and natural gas
properties partially offset by decreased production of 2.4 MBoepd.
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General and Administrative Expense

The following table highlights general and administrative expense items in total
and on a cost per Boe production basis. The information below provides the
financial results and an analysis of significant variances in these results (in
thousands, except per Boe data):

                                     Three Months Ended September 30,       

Nine Months Ended September 30,

                                        2022                  2021                2022                  2021
General and administrative
expense                           $          25,289     $          20,427   $          70,742     $          58,993
General and administrative
expense per Boe                   $            5.19     $            3.93   $            4.28     $            3.43


Three Months Ended September 30, 2022 and 2021 - General and administrative
expense for the three months ended September 30, 2022 increased by approximately
$4.9 million, or 24%. This increase was primarily related to non-cash
equity-based compensation of $4.3 million, or $0.88 per Boe, during the three
months ended September 30, 2022, which is an increase of $1.7 million.
Additionally, there was an increase in transaction costs of $2.8 million
primarily related to the EnVen Acquisition. On a per unit basis, general and
administrative expense increased $1.26 Boe primarily due to decreased production
of 3.5 MBoepd.

Nine Months Ended September 30, 2022 and 2021 - General and administrative
expense for the nine months ended September 30, 2022 increased by approximately
$11.7 million, or 20%. This increase was primarily related to $5.6 million of
expenses incurred by our emerging CCS operating segment during the nine months
ended September 30, 2022, an increase of $4.1 million. There was an increase in
transaction costs of $2.0 million primarily related to the EnVen Acquisition.
Additionally, general and administrative expense includes non-cash equity-based
compensation of $11.7 million, or $0.71 per Boe, during the nine months ended
September 30, 2022, an increase of $3.4 million. On a per unit basis, general
and administrative expense increased $0.85 per Boe primarily due to decreased
production of 2.4 MBoepd.

Miscellaneous

The following table highlights miscellaneous items in total. The information
below provides the financial results and an analysis of significant variances in
these results (in thousands):

                                  Three Months Ended September 30,     Nine Months Ended September 30,
                                      2022              2021               2022                2021
Accretion expense                 $      13,179    $        13,668   $         42,400    $         44,110
Other operating (income) expense  $        (366 )  $         5,081   $         12,142    $          6,864
Interest expense                  $      29,265    $        32,390   $         91,531    $        100,036
Price risk management activities
(income)
 expense                          $    (114,180 )  $        81,479   $        231,133    $        405,604
Equity method investment income   $         991    $             -   $         14,599    $              -
Other (income) expense            $        (692 )  $        (4,475 ) $        (31,991 )  $          7,916
Income tax (benefit) expense      $         121    $          (364 ) $          2,256    $            718

Three Months Ended September 30, 2022 and 2021 -

Other Operating (Income) Expense - During the three months ended September 30,
2022, we recorded $0.1 million of estimated decommissioning obligations
primarily as a result of working interest partners or counterparties of
divesture transactions that were unable to perform the required abandonment
obligations due to bankruptcy or insolvency. During the three months ended
September 30, 2021, we recorded $4.1 million of estimated decommissioning
obligations. See further discussion in Part I, Item 1. "Condensed Consolidated
Financial Statements - Note 10 - Commitments and Contingencies."

Interest Expense - During the three months ended September 30, 2022, we recorded
$29.3 million of interest expense compared to $32.4 million during the three
months ended September 30, 2021. The change is primarily the result of the
decrease in interest associated with the Bank Credit Facility (as defined below
under " - Liquidity and Capital Resources - Overview of Debt Instruments") with
outstanding borrowings of $60.0 million as of September 30, 2022 when compared
to $400.0 million as of September 30, 2021.
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Price Risk Management Activities - The income of $114.2 million for the three
months ended September 30, 2022 consists of $195.3 million in non-cash gains
from the increase in the fair value of our open derivative contracts partially
offset by $81.1 million in cash settlement losses. The expense of $81.5 million
for the three months ended September 30, 2021 consists of $71.6 million in cash
settlement losses and $9.8 million in non-cash losses from the decrease in the
fair value of our open derivative contracts.

These unrealized gains or losses on open derivative contracts relate to
production for future periods; however, changes in the fair value of all of our
open derivative contracts are recorded as a gain or loss on our Condensed
Consolidated Statements of Operations at the end of each month. As a result of
the derivative contracts we have on our anticipated production volumes through
December 2024, we expect these activities to continue to impact net income
(loss) based on fluctuations in market prices for oil and natural gas. See Part
I, Item 1. "Condensed Consolidated Financial Statements - Note 4 - Financial
Instruments."

Equity Method Investment Income - During the three months ended September 30,
2022, we recorded equity losses of $0.4 million offset by a $1.4 million gain on
partial sale of our equity method investment in Bayou Bend. See Part I, Item 1.
"Condensed Consolidated Financial Statements - Note 9 - Related Party
Transactions" for additional information.

Other (Income) Expense - During the three months ended September 30, 2021, we
recorded a $4.4 million gain as a result of the settlement related to the
Whistler Acquisition that is further discussed in Part I, Item 1. "Condensed
Consolidated Financial Statements - Note 9 - Related Party Transactions."

Income Tax (Benefit) Expense - During the three months ended September 30, 2022,
we recorded $0.1 million of income tax expense compared to $0.4 million of
income tax benefit during the three months ended September 30, 2021. The income
tax expense for each period is primarily a result of recording a valuation
allowance on our deferred tax assets. The realization of our deferred tax asset
depends on recognition of sufficient future taxable income in specific tax
jurisdictions in which temporary differences or net operating losses relate. In
assessing the need for a valuation allowance, we consider whether it is more
likely than not that some portion of all of the deferred tax assets will not be
realized. See additional information on the valuation allowance as described in
Part I, Item 1. "Condensed Consolidated Financial Statements - Note 7 - Income
Taxes."

Nine Months Ended September 30, 2022 and 2021 -

Other Operating (Income) Expense - During the nine months ended September 30,
2022, we recorded $10.6 million of estimated decommissioning obligations
primarily as a result of working interest partners or counterparties of
divesture transactions that were unable to perform the required abandonment
obligations due to bankruptcy or insolvency. During the nine months ended
September 30, 2021, we recorded $6.9 million of estimated decommissioning
obligations. See further discussion in Part I, Item 1. "Condensed Consolidated
Financial Statements - Note 10 - Commitments and Contingencies."

Interest Expense - During the nine months ended September 30, 2022, we recorded
$91.5 million of interest expense compared to $100.0 million during the nine
months ended September 30, 2021. The change is primarily a result of the
interest associated with the Bank Credit Facility with outstanding borrowings of
$60.0 million as of September 30, 2022 when compared to $400.0 million as of
September 30, 2021.

Price Risk Management Activities - The expense of $231.1 million for the nine
months ended September 30, 2022 consists of $368.5 million in cash settlement
losses partially offset by $137.4 million in non-cash gains from the increase in
the fair value of our open derivative contracts. The expense of $405.6 million
for the nine months ended September 30, 2021 consists of $216.4 million in
non-cash losses from the decrease in the fair value of our open derivative
contracts and $189.3 million in cash settlement losses.

These unrealized gains or losses on open derivative contracts relate to
production for future periods; however, changes in the fair value of all of our
open derivative contracts are recorded as a gain or loss on our Condensed
Consolidated Statements of Operations at the end of each month. As a result of
the derivative contracts we have on our anticipated production volumes through
December 2024, we expect these activities to continue to impact net income
(loss) based on fluctuations in market prices for oil and natural gas. See Part
I, Item 1. "Condensed Consolidated Financial Statements - Note 4 - Financial
Instruments."
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Equity Method Investment Income - During the nine months ended September 30,
2022, we recorded equity losses of $0.7 million offset by a $15.3 million gain
on partial sale of our equity method investment in Bayou Bend. See Part I, Item
1. "Condensed Consolidated Financial Statements - Note 9 - Related Party
Transactions" for additional information.

Other (Income) Expense - During the nine months ended September 30, 2022, we
recorded a $27.5 million gain as a result of the settlement agreement to resolve
a previously pending litigation that was filed in October 2017 that is further
discussed in Part I, Item 1. "Condensed Consolidated Financial Statements - Note
10 - Commitments and Contingencies." During the nine months ended September 30,
2021, we recorded a $13.2 million loss on extinguishment of debt as a result of
the redemption of the 11.00% Second-Priority Senior Secured Notes (the "11.00%
Notes"). This was partially offset by a $4.4 million gain as a result of the
settlement related to the Whistler Acquisition that is further discussed in Part
I, Item 1. "Condensed Consolidated Financial Statements - Note 9 - Related Party
Transactions."

Income Tax (Benefit) Expense - During the nine months ended September 30, 2022,
we recorded $2.3 million of income tax expense compared to $0.7 million of
income tax expense during the nine months ended September 30, 2021. The change
is primarily a result of a discrete tax expense and recording a valuation
allowance on our deferred tax assets. The realization of our deferred tax asset
depends on recognition of sufficient future taxable income in specific tax
jurisdictions in which temporary differences or net operating losses relate. In
assessing the need for a valuation allowance, we consider whether it is more
likely than not that some portion of all of the deferred tax assets will not be
realized. See additional information on the valuation allowance as described in
Part I, Item 1. "Condensed Consolidated Financial Statements - Note 7 - Income
Taxes."

Supplemental Non-GAAP Measure

EBITDA and Adjusted EBITDA

"EBITDA" and "Adjusted EBITDA" are non-GAAP financial measures used to provide
management and investors with (i) additional information to evaluate, with
certain adjustments, items required or permitted in calculating covenant
compliance under our debt agreements, (ii) important supplemental indicators of
the operational performance of our business, (iii) additional criteria for
evaluating our performance relative to our peers and (iv) supplemental
information to investors about certain material non-cash and/or other items that
may not continue at the same level in the future. EBITDA and Adjusted EBITDA
have limitations as analytical tools and should not be considered in isolation
or as substitutes for analysis of our results as reported under GAAP or as
alternatives to net income (loss), operating income (loss) or any other measure
of financial performance presented in accordance with GAAP.

We define these as the following:

•

EBITDA - Net income (loss) plus interest expense, income tax expense (benefit), depreciation, depletion and amortization, and accretion expense.

•

Adjusted EBITDA - EBITDA plus non-cash write-down of oil and natural gas
properties, transaction and other (income) expenses, the net change in the fair
value of derivatives (mark to market effect, net of cash settlements and
premiums related to these derivatives), (gain) loss on debt extinguishment,
non-cash write-down of other well equipment inventory and non-cash equity-based
compensation expense.
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The following table presents a reconciliation of the GAAP financial measure of net income (loss) to Adjusted EBITDA for each of the periods indicated (in thousands):

                                    Three Months Ended September 30,      

Nine Months Ended September 30,

                                        2022              2021               2022                 2021
Net income (loss)                   $    250,465    $        (16,691 ) $         379,165    $        (263,964 )
Interest expense                          29,265              32,390              91,531              100,036
Income tax (benefit) expense                 121                (364 )             2,256                  718
Depreciation, depletion and
amortization                              92,323              88,596             295,174              290,094
Accretion expense                         13,179              13,668              42,400               44,110
EBITDA                                   385,353             117,599             810,526              170,994
Transaction and other (income)
expenses(1)(3)(4)                          3,239               1,370             (28,303 )              7,231
Derivative fair value loss
(gain)(2)                               (114,180 )            81,479             231,133              405,604
Net cash paid on settled derivative
instruments(2)                           (81,162 )           (71,634 )          (368,483 )           (189,252 )
Loss on extinguishment of debt                 -                   -                   -               13,225
Non-cash equity-based compensation
expense                                    4,310               2,613              11,677                8,294
Adjusted EBITDA                     $    197,560    $        131,427   $         656,550    $         416,096



(1)
Includes transaction-related expenses, decommissioning obligations and other
miscellaneous income and expenses. See Part I, Item 1. "Condensed Consolidated
Financial Statements - Note 10 - Commitments and Contingencies" for additional
information on decommissioning obligations.
(2)
The adjustments for the derivative fair value (gains) losses and net cash
receipts (payments) on settled commodity derivative instruments have the effect
of adjusting net loss for changes in the fair value of derivative instruments,
which are recognized at the end of each accounting period because we do not
designate commodity derivative instruments as accounting hedges. This results in
reflecting commodity derivative gains and losses within Adjusted EBITDA on an
unrealized basis during the period the derivatives settled.
(3)
Includes a $27.5 million gain as a result of the settlement agreement to resolve
previously pending litigation for the nine months ended September 30, 2022 that
was filed in October 2017 that is further discussed in Part I, Item 1.
"Condensed Consolidated Financial Statements - Note 10 - Commitments and
Contingencies."
(4)
Includes a $1.4 million and $15.3 million gain on partial sale of our equity
method investment in Bayou Bend for the three and nine months ended September
30, 2022, respectively, that is further discussed in Part I, Item 1. "Condensed
Consolidated Financial Statements - Note 9 - Related Party Transactions."

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated by our operations and
borrowings under our Bank Credit Facility. Our primary uses of cash are for
capital expenditures, working capital, debt service and for general corporate
purposes. Our working capital deficit has decreased since December 31, 2021
primarily due to a decrease of $87.3 million in liabilities from price risk
management activities and an increase of $26.4 million in assets from price risk
management activities. See Part I, Item 1. "Condensed Consolidated Financial
Statements - Note 4 - Financial Instruments." As of September 30, 2022, our
available liquidity (cash plus available capacity under the Bank Credit
Facility) was $806.8 million.

We fund exploration and development activities primarily through operating cash
flows, cash on hand and through borrowings under the Bank Credit Facility, if
necessary. Historically, we have funded significant property acquisitions with
the issuance of senior notes, borrowings under the Bank Credit Facility and
through additional equity issuances. We occasionally adjust our capital budget
in response to changing operating cash flow forecasts and market conditions,
including the prices of oil, natural gas and NGLs, acquisition opportunities and
the results of our exploration and development activities.

Capital Expenditures - The following is a table of our capital expenditures, excluding acquisitions, for the nine months ended September 30, 2022 (in thousands):

U.S. drilling & completions                           $ 120,510
Mexico appraisal & exploration                              301
Asset management                                         80,704

Seismic and G&G, land, capitalized G&A and other 35,667 CCS(1)

                                                    2,027
Total capital expenditures                              239,209
Plugging & abandonment                                   60,304

Total capital expenditures and plugging & abandonment $ 299,513

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(1)

Excludes $2.4 million of expenditures reflected as "Other operating (income) expense" on the Condensed Consolidated Statements of Operations.

Based on our current level of operations and available cash, we believe our cash
flows from operations, combined with availability under the Bank Credit
Facility, provide sufficient liquidity to fund the remainder of our board
approved 2022 capital spending program of $450.0 million to $480.0 million, of
which approximately $30.0 million is allocated to CCS. However, our ability to
(i) generate sufficient cash flows from operations or obtain future borrowings
under the Bank Credit Facility, and (ii) repay or refinance any of our
indebtedness on commercially reasonable terms or at all for any potential future
acquisitions, joint ventures or other similar transactions, depends on operating
and economic conditions, some of which are beyond our control. To the extent
possible, we have attempted to mitigate certain of these risks (e.g. by entering
into oil and natural gas derivative contracts to reduce the financial impact of
downward commodity price movements on a substantial portion of our anticipated
production), but we could be required to, or we or our affiliates may from time
to time, take additional future actions on an opportunistic basis. To address
further changes in the financial and/or commodity markets, future actions may
include, without limitation, issuing debt, including secured debt, or issuing
equity to directly or independently repurchase or refinance our outstanding
indebtedness.

Overview of Cash Flow Activities - The following table summarizes cash flows provided by (used in) by type of activity, for the following periods (in thousands):

                        Nine Months Ended September 30,

                           2022                 2021
Operating activities $         538,928    $         287,648
Investing activities $        (198,652 )  $        (212,153 )
Financing activities $        (345,638 )  $         (50,301 )


Operating Activities - Net cash provided by operating activities increased
$251.3 million in the nine months ended September 30, 2022 compared to the
corresponding period in 2021 primarily attributable to an increase in revenues
net of the change in lease operating expense of $427.7 million. This was offset
by an increase in cash payments on derivative instruments of $179.2 million.

Investing Activities - Net cash used in investing activities decreased $13.5
million in the nine months ended September 30, 2022 compared to the
corresponding period in 2021 primarily due to $15.0 million in cash proceeds
from a partial sale of our investment in Bayou Bend and decreased capital
expenditures of $2.0 million offset by contributions to equity investees of $2.3
million. See Part I, Item 1. "Condensed Consolidated Financial Statements - Note
9 - Related Party Transactions" for additional information.

Financing Activities - Cash flow from financing activities decreased $295.3
million in the nine months ended September 30, 2022 compared to the
corresponding period in 2021. During the nine months ended September 30, 2022,
net repayments of $315.0 million reduced the Bank Credit Facility. Additionally,
we redeemed $6.1 million of our 7.50% Senior Notes.

During the nine months ended September 30, 2021, the issuance of the 12.00% Notes in January 2021 generated $579.4 million after original discount and deferred financing costs. The net proceeds from the 12.00% Notes funded the $356.8 million redemption of the 11.00% Notes and reduced the indebtedness under the Bank Credit Facility by $175.0 million in the first quarter of 2021. Indebtedness under the Bank Credit Facility was reduced further by $65.0 million.

Overview of Debt Instruments

Bank Credit Facility - matures November 2024 - We maintain a Bank Credit
Facility with a syndicate of financial institutions (the "Bank Credit
Facility"). The Bank Credit Facility provides for determination of the borrowing
base based on our proved producing reserves and a portion of our proved
undeveloped reserves. The borrowing base is redetermined by the lenders at least
semi-annually during the second quarter and fourth quarter each year. On May 4,
2022, our borrowing base increased from $950.0 million to $1.1 billion and
commitments increased from $791.3 million to $806.3 million. The next scheduled
redetermination is expected to occur in the fourth quarter of 2022. See Part I,
Item 1. "Condensed Consolidated Financial Statements - Note 5 - Debt" for more
information.
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12.00% Second-Priority Senior Secured Notes - due January 2026 - The 12.00%
Second-Priority Senior Secured Notes (the "12.00% Notes") were issued pursuant
to an indenture dated January 4, 2021 and the first supplemental indenture dated
January 14, 2021 between Talos Energy Inc. (the "Parent Guarantor"); Talos
Production Inc. (the "Issuer"); the Subsidiary Guarantors (defined below); and
Wilmington Trust, National Association, as trustee and collateral agent. The
12.00% Notes rank pari passu in right of payment and constitute a single class
of securities for all purposes under the indentures. The 12.00% Notes are
secured on a second-priority senior secured basis by liens on substantially the
same collateral as the Issuer's existing first-priority obligations under its
Bank Credit Facility. The 12.00% Notes mature on January 15, 2026 and have
interest payable semi-annually each January 15 and July 15. See Part I, Item 1.
"Condensed Consolidated Financial Statements - Note 5 - Debt" for more
information.

7.50% Senior Notes - redeemed May 2022 - The 7.50% Senior Notes matured and were
redeemed on May 31, 2022. See Part I, Item 1. "Condensed Consolidated Financial
Statements - Note 5 - Debt" for more information.

Guarantor Financial Information - We own no operating assets and have no
operations independent of our subsidiaries. The 12.00% Notes are fully and
unconditionally guaranteed, jointly and severally, on a senior unsecured basis
by the Parent Guarantor and on a second-priority senior secured basis by each of
the Issuer's present and future direct or indirect wholly owned material
restricted domestic subsidiaries (collectively, the "Subsidiary Guarantors" and,
together with the Parent Guarantor, the "Guarantors") that guarantees the
Issuer's senior reserve-based revolving credit facility. Our non-domestic
subsidiaries and our unrestricted CCS domestic subsidiaries (the
"Non-Guarantors") are 100% owned by us but do not guarantee the 12.00% Notes.

In lieu of providing separate financial statements for the Issuer and the
Guarantors, we have presented the accompanying supplemental summarized combined
balance sheet and statement of operations information for the Issuer and the
Guarantors on a combined basis after elimination of intercompany transactions
and amounts related to investment in any subsidiary that is a Non-Guarantor.

The following table presents the balance sheet information for the respective
periods (in thousands):

                                                    September 30, 2022     December 31, 2021
Current assets                                     $            342,980   $           330,415
Non-current assets                                            2,323,141             2,305,855
Total assets                                       $          2,666,121   $         2,636,270

Current liabilities                                $            552,275   $           598,062
Non-current liabilities                                       1,101,695             1,405,382
Talos Energy Inc. stockholders' equity                        1,012,151     

632,826

Total liabilities and stockholders' equity $ 2,666,121 $

2,636,270

The following table presents the statement of operations information (in thousands):

                    Nine Months Ended September 30, 2022
Revenues           $                            1,309,779
Costs and expenses                               (936,118 )
Net income         $                              373,661



Material Cash Requirements

We have various contractual obligations in the normal course of our operations.
There have been no material changes to our material cash requirements from known
contractual obligations since those reported in our 2021 Annual Report except:

•

The aggregate principal amount of our Bank Credit Facility decreased from $375.0 million to $60.0 million;

•

Interest expense through the maturity of our debt instruments decreased in the
aggregate by approximately $19.1 million primarily due to the lower borrowings
under the Bank Credit Facility;
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•

Vessel commitments increased by approximately $33.6 million due to the execution
of an offshore drilling rig agreement on April 6, 2022. These commitments
represent gross contractual obligations and, accordingly, other joint owners in
the properties operated by us will be billed for their working interest share of
such costs;

•

Derivative net liabilities decreased from $196.7 million to $59.4 million; and

•

Purchase obligations increased from $3.2 million to $57.8 million through 2023 primarily due to increased committed purchase orders to execute planned Deepwater drilling activities.

Performance Obligations - As of September 30, 2022, we had secured performance
bonds totaling $689.5 million primarily related to plugging and abandonment of
wells and removal of facilities in the U.S. Gulf of Mexico and certain
obligations under the production sharing contracts with Mexico from third party
sureties. Additionally, we had secured letters of credit issued under our Bank
Credit Facility totaling $3.9 million. Letters of credit that are outstanding
reduce the available revolving credit commitments.

See the subsection entitled "- Known Trends and Uncertainties - BOEM Bonding
Requirements" for additional information on the future cost of compliance with
respect to BOEM supplemental bonding requirements that could have a material
adverse effect on our business, properties, results of operations and financial
condition. See Part I, Item 1. "Condensed Consolidated Financial Statements -
Note 5 - Debt" for further information on the Bank Credit Facility.

Critical Accounting Policies and Estimates

We consider accounting policies related to oil and natural gas properties,
proved reserve estimates, fair value measure of financial instruments, asset
retirement obligations, revenue recognition, imbalances and production handling
fees and income taxes as critical accounting policies. The policies include
significant estimates made by management using information available at the time
the estimates are made. However, these estimates could change materially if
different information or assumptions were used. There have been no changes to
our critical accounting policies, which are summarized in the Part II, Item 7.
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" section in our 2021 Annual Report.

Recently Adopted Accounting Standards

None.

Recently Issued Accounting Standards

There was no recently issued accounting standards material to us.

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