TALOS ENERGY INC. (TALO) FY 2021 MD&A

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

The following discussion and analysis of our financial condition and results of operations is based on, and should be read in conjunction with our Consolidated Financial Statements and the Notes to Consolidated Financial Statements set forth in Part IV, Item 15. Exhibits and Financial Statement Schedules; Part I, Items 1 and 2. Business and Properties; Part I, Item 1A. Risk Factors; and Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk. This discussion and analysis contains forward-looking statements that involve risk and uncertainties. Actual results may differ materially from those anticipated in these forward-looking statements.

This section of this Annual Report generally discusses 2021 and 2020 items and year-to-year comparisons between 2021 and 2020. Discussions of 2019 items and year-to-year comparisons between 2020 and 2019 that are not included in this Annual Report can be found in “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the Company’s Annual Report on Form 10-K for the year ended December 31, 2020 filed on March 11, 2021.

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 U.S. Gulf of Mexico and offshore Mexico both upstream through oil and gas exploration and production and downstream through the development of future carbon capture and storage 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 carbon capture and storage collaborative arrangements 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.

Outlook

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

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While the current outlook for commodity prices is favorable and our operations are no longer significantly impacted by confinement restrictions, the risk of disruption to our operations continues as the emergence of a new variant of COVID-19 could adversely impact our operations, or commodity prices could significantly decline from current levels. The ongoing COVID-19 outbreak continues to evolve and, during the fourth quarter of 2021, a new variant emerged, the Omicron variant. It is difficult to assess if it will cause meaningful disruptions in economic activity across the world and if there will be any significant impacts in demand for energy. Additionally, while OPEC Plus remained committed to steady and predictable production increases throughout 2021, it is difficult to determine whether it will change its production output policy or whether its members will remain committed to the production quotas set by the organization.

In January 2022, the Energy Information Administration published its short-term energy outlook. WTI spot prices are expected to average $71.32 per Bbl for 2022. Global oil production is forecasted to outpace global oil consumption during 2022 resulting in rising global oil inventories. Oil market balances are subject to significant uncertainties which could keep oil prices volatile. Henry Hub spot prices are expected to average $3.82 per MMBtu in the first quarter of 2022 and average $3.79 per MMBtu for all of 2022.

Looking at external events impacting the oil and gas industry, the focus on the transition and evolution to cleaner forms of energy continues to accelerate as governments across the world discuss how to reduce GHG emissions. Governments will continue to emphasize the importance of utilizing cleaner sources of energy and industry-wide investments in renewables and carbon capture and storage in order to meet the emission reduction targets that will limit the impact of GHG emissions. We believe that the pressure on our industry to manage its carbon footprint will continue to grow as governments find ways to meet their carbon reduction targets. We see the transition to providing cleaner forms of energy as an opportunity to position ourselves to support our industry's efforts to reduce our carbon footprint through the use of commercially available technologies that allow us to capture and store significant volumes of CO2.

Significant Developments

The following encompasses significant developments since our Annual Report on Form 10-K for the year ended December 31, 2020:

Carbon Capture Initiatives — On February 15, 2022, we announced our entry into (i) a lease agreement for a major carbon capture and sequestration project along the Mississippi River industrial corridor and (ii) a memorandum of understanding with EnLink Midstream, LLC to jointly develop a carbon capture, transportation and sequestration joint service offering focused on the Mississippi River industrial corridor. See Part I, Items 1 and 2. Business and Properties — Carbon Capture & Sequestration for additional information regarding this project and previously announced projects.

Eugene Island Pipeline System — We have experienced approximately 30 days of unplanned third-party downtime to date in the first quarter of 2022 resulting from maintenance of the Eugene Island Pipeline System, which carries our production from the HP-I and Green Canyon 18 facilities. As of the filing of this Annual Report, the shut-in has resulted in a production impact of approximately 3.5 to 4.0 MBoepd for the first quarter of 2022 or 0.8 to 1.0 MBoepd for the full year 2022.

Zama Update — See Part I, Items 1 and 2. Business and Properties — Hydrocarbon Properties — Mexico — Block 7.

Federal Lease Sale — In November 2021, we announced that we were named as the high bidder on ten Deepwater blocks comprising 57,600 acres, or 36,720 net acres, for a net total consideration of approximately $4.8 million. As of December 31, 2021, the BOEM has not announced whether we have been awarded these leases. In January 2022, a federal judge invalidated the lease sale, finding that BOEM failed to consider the impact on foreign greenhouse gas emissions if the November 2021 lease sale was not held and the court determined that this failure was a violation of the National Environmental Policy Act.

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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.

LLOG Asset Acquisition — On November 16, 2020, we completed the acquisition of select interests in oil and natural gas assets from LLOG Exploration & Production Company, LLC (the “LLOG Acquisition”). See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions for more information.

Castex Energy 2005 Asset Acquisition — On August 5, 2020, we completed the acquisition of select interest in oil and natural gas assets from affiliates of Castex Energy 2005 Holdco, LLC (the “Castex 2005 Acquisition”). See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions for more information.

ILX and Castex Acquisition — On February 28, 2020 we acquired the outstanding limited liability interests in certain wholly owned subsidiaries of ILX Holdings, LLC, ILX Holdings II, LLC, ILX Holdings III LLC and Castex Energy 2014, LLC, each a related party and an affiliate with the entities controlled by or affiliated with Riverstone Energy Partners V, L.P. (the “Riverstone Sellers”), and Castex Energy 2016, LP (together with the Riverstone Sellers, the “Sellers” and collectively, the “ILX and Castex Acquisition”). See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions for more information.

Hurricanes and Tropical Storms — During 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 year ended December 31, 2021, we estimate deferred production related to this storm was approximately 4.2 MBoepd.

During 2020, production from the U.S. Gulf of Mexico was impacted due to precautionary shut-ins of facilities and evacuations associated with Hurricanes Hanna, Laura, Marco, Sally, Delta and Zeta and Tropical Storms Cristobal and Beta. Although there was no major storm-related damage to our facilities, we incurred production downtime associated with the shut-ins for the storms. For the year ended December 31, 2020, we estimate deferred production related to these storms was approximately 4.1 MBoepd.

Ram Powell Shut-In — Production at our Ram Powell facility was shut-in in late June 2020 while waiting for the repair of the platform’s oil export riser. We received final regulatory approvals and completed the repair of the export riser. Production commenced on November 21, 2020. For the year ended December 31, 2020, the Ram Powell facility shut-in resulted in deferred production of 2.1 MBoepd.

Known Trends and Uncertainties

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.

Oil prices have benefited from the continuation of coordinated production policies by OPEC Plus and capital discipline by oil and gas producers. Despite the recent upswing in oil prices, we believe that commodity prices will remain cyclical and volatile. During January 1, 2021 through December 31, 2021, the daily spot prices for NYMEX WTI crude oil ranged from a high of $85.64 per Bbl to a low of $47.47 per Bbl and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $23.86 per MMBtu to a low of $2.43 per MMBtu. The spread between the high and low natural gas prices was caused by a severe winter storm that precipitated both an immediate constraint in the supply of and a significant increase in the demand for natural gas. 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 IV, Item 15. Exhibits and Financial Statement Schedules — Note 6 — Financial Instruments for more additional information regarding our commodity derivative positions as of December 31, 2021.

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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. During 2021, 2020 and 2019 our ceiling test computations for our U.S. oil and gas properties resulted in a write down of nil, $267.9 million and nil, respectively. At December 31, 2021, the Company’s ceiling test computation was based on SEC pricing of $67.14 per Bbl of oil, $3.71 per Mcf of natural gas and $26.62 per Bbl of NGLs.

There is a significant degree of uncertainty with the assumptions used to estimate future undiscounted cash flows due to, but not limited to the risk factors referred to in Part I, Item 1A. Risk Factors. 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 undiscounted cash flows related to our proved oil and natural gas properties.

With respect to our operations in Mexico, our oil and natural gas properties are classified as unproved properties, not subject to amortization. The finalization of the unitization and unit operating agreement, which sets out the terms on which the Block 7 reservoir will be jointly developed, and the outcome of the dispute with the Government of Mexico over decisions taken by SENER with respect to the Zama discovery could adversely affect the value of the oil and natural gas assets and result in an impairment of our unevaluated oil and gas properties prior to reaching a final investment decision or of our evaluated properties upon reaching a final investment decision. We recorded an impairment of $18.1 million for our unproved property investment in Block 31 during the year ended December 31, 2021. See Part I, Items 1 and 2. Business and Properties — Hydrocarbon Properties — Mexico — Block 31 for additional information.

Third Party Planned Downtime — Since our operations are offshore, we are vulnerable to third party downtime events impacting the transportation, gathering and processing of production. We produce the Phoenix Field through the HP-I that is operated by Helix. Helix is required to disconnect and dry-dock the HP-I every two to three years for inspection as required by the United States Coast Guard, during which time we are unable to produce the Phoenix Field. The next dry-dock is scheduled for mid-2022 with an estimated shut-in lasting approximately 45 to 60 days.

BOEM Bonding Requirements — In 2016, the BOEM issued the 2016 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 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 the 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.

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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.

Basis of Presentation

Sources of Revenues

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs, that are extracted from our natural gas during processing. Our oil, natural gas and NGL revenues do not include the effects of derivatives, which are reported in “Price risk management activities income (expense)” on our Consolidated Statements of Operations. The following table presents a breakout of each revenue component:

Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

Realized Prices on the Sale of Oil, Natural Gas and NGLs — The NYMEX WTI prompt month oil settlement price is a widely used benchmark in the pricing of domestic oil in the United States. The actual prices we realize from the sale of oil differ from the quoted NYMEX WTI price as a result of quality and location differentials. For example, the prices we realize on the oil we produce are affected by the Gulf of Mexico Basin’s proximity to U.S. Gulf Coast refineries and the quality of the oil production sold in Eugene Island Crude, Louisiana Light Sweet Crude and Heavy Louisiana Sweet Crude markets.

The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. The actual prices we realize from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. Currently, the sales points of our gas production are generally within close proximity to the Henry Hub which creates a minimal differential in the prices we receive for our production versus average Henry Hub prices.

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In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue, as indicated in the table below, which provides the high, low and average prices for NYMEX WTI and NYMEX Henry Hub monthly contract prices as well as our average realized oil, natural gas, and NGL sales prices for the periods indicated.

To achieve more predictable cash flow, and to reduce exposure to adverse fluctuations in commodity prices, we enter into commodity derivative arrangements for a portion of our anticipated production. By removing a significant portion of price volatility associated with our anticipated production, we believe it will mitigate, but not eliminate, the potential negative effects of reductions in oil and natural gas prices on our cash flow from operations for those periods. However, our price risk management activity may also reduce our ability to benefit from increases in prices. We will sustain losses to the extent our commodity derivatives contract prices are lower than market prices and, conversely, we will sustain gains to the extent our commodity derivatives contract prices are higher than market prices.

We will continue to use commodity derivative instruments to manage commodity price risk in the future. Our hedging strategy and future hedging transactions will be determined in accordance with both our Bank Credit Facility and Hedging Policy and may be different from what we have done on a historical basis.

Expenses

Lease Operating Expense — Lease operating expense consists of the daily costs incurred to bring oil, natural gas and NGLs out of the underground formation and to the market, together with the daily costs incurred to maintain our producing properties. Expenses for direct labor, insurance, a portion of the HP-I lease, materials and supplies, rental and third party costs comprise the most significant portion of our lease operating expense. It further consists of costs associated with major remedial operations on completed wells to restore, maintain or improve the well’s production. Because the amount of workover and maintenance expense is closely correlated to the levels of workover activity, which is not regularly scheduled, workover and maintenance expense is not necessarily comparable from period-to-period. There is a reduction in our lease operating expenses for production handling fees related to certain reimbursements for costs from certain third parties.

Production Taxes — Production taxes consist of severance taxes levied by the Louisiana Department of Revenue on production of oil and natural gas from land or water bottoms within the boundaries of the state of Louisiana.

Depreciation, Depletion and Amortization expense — Depreciation, depletion and amortization expense is the expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas reserves. We use the full cost method of accounting for oil and natural gas activities. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies for further discussion.

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Accretion Expense — We have obligations associated with the retirement of our oil and natural gas wells and related infrastructure. We have obligations to plug wells when production on those wells is exhausted, when we no longer plan to use them or when we abandon them. We accrue a liability with respect to these obligations based on our estimate of the timing and amount to replace, remove or retire the associated assets. Accretion of the liability is recognized for changes in the value of the liability as a result of the passage of time over the estimated productive life of the related assets as the discounted liabilities are accreted to their expected settlement values.

General and Administrative Expense — General and administrative expense generally consists of costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production operations, bad debt expense, equity-based compensation expense, audit and other fees for professional services and legal compliance.

Interest Expense — We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our Bank Credit Facility and term-based debt. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. Interest includes interest incurred under our debt agreements, the amortization of deferred financing costs (including origination and amendment fees), commitment fees, imputed interest on our capital lease, performance bond premiums and annual agency fees. Interest expense is net of capitalized interest on expenditures made in connection with exploratory projects that are not subject to current amortization.

Price Risk Management Activities — We utilize commodity derivative instruments to reduce our exposure to fluctuations in the price of oil and natural gas. We recognize gains and losses associated with our open commodity derivative contracts as commodity prices and the associated fair value of our commodity derivative contracts change. The commodity derivative contracts we have in place are not designated as hedges for accounting purposes. Consequently, these commodity derivative contracts are marked-to-market each quarter with fair value gains and losses recognized currently as a gain or loss in our results of operations. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

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Results of Operations

Revenues

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):

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):

Volumetric Analysis — Production volumes increased by 9.7 MBoepd to 64.4 MBoepd for the year ended December 31, 2021. The increase in production volumes was due to an increase of 7.6 MBoepd from the Green Canyon 18 Field, primarily due to the Kaleidoscope and Tokum wells drilled as part of the Green Canyon 18 Field platform rig program. Additionally, production volumes increased 2.1 MBoepd from temporary shut-ins for repairs and maintenance on the Ram Powell Field export riser that were completed in the fourth quarter of 2020.

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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):

Total lease operating expenses for the year ended December 31, 2021 increased by approximately $37.0 million, or 15%. We had an overall increase in direct operating expenses and labor costs of $6.2 million due to the temporary shuttering of the non-operated Garden Banks Field, Vermilion Field and High Island Field related to cost cutting measures taken during the second half of 2020 because of the economic environment caused by the COVID-19 pandemic. There was an additional $19.4 million increase attributable to facility and workover expense across our portfolio. Due to the Castex 2005 Acquisition and LLOG Acquisition in the second half of 2020, we had an increase of $12.9 million in total lease operating expenses during the year ended December 31, 2021. On a per unit basis, lease operating expense decreased $0.26 per Boe to $12.07 per Boe primarily due to higher production volumes.

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):

Depreciation, depletion and amortization expense for the year ended December 31, 2021 increased by approximately $31.6 million, or 9%. This increase was primarily due to increased production of 9.7 MBoepd offset by a decrease of $1.32 per Boe, or 7% in the depletion rate on our proved oil and natural gas properties as a result of the impairment on oil and gas properties in the fourth quarter of 2020.

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):

General and administrative expense for the year ended December 31, 2021, decreased by approximately $0.5 million, or 1%. Transaction and non-recurring costs were $5.4 million or $0.23 per Boe for 2021, which is a decrease of $9.6 million primarily due to the ILX and Castex Acquisition and Castex 2005 Acquisition in 2020. The decrease was offset with general and administrative expenses of $4.3 million incurred by our emerging carbon capture and sequestration operating segment during the year ended December 31, 2021. Additionally, general and administrative expense includes non-cash equity-based compensation of $11.0 million, or $0.47 per Boe, during the year ended December 31, 2021, which is an increase of $2.1 million. On a per unit basis, general and administrative expense decreased $0.61 per Boe.

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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):

Write-Down of Oil and Natural Gas Properties — Due to our non-consent to the Block 31 appraisal program, we recorded an impairment of $18.1 million for our unproved property investment in Block 31 during the year ended December 31, 2021 as the costs were not recoverable. During the year ended December 31, 2020, we recorded a $267.9 million write-down of our oil and natural gas properties as a result of our ceiling test evaluation for our oil and gas properties in the United States as described in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 4 — Property, Plant and Equipment.

Other Operating (Income) Expense — During the year ended December 31, 2021, we recorded $21.1 million of estimated decommissioning obligations primarily as a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 12 — Commitments and Contingencies. Additionally, we recorded an impairment of $5.6 million related to the adjustment of other well equipment inventory to net realizable value, which was expensed and reflected in “Other operating (income) expense” on the Consolidated Statements of Operations. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies.

During the year ended December 31, 2020, we recorded $8.9 million in income related to our multi-year federal royalty refund claim from the ONRR. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies.

Interest Expense — During the year ended December 31, 2021, we recorded $133.1 million of interest expense compared to $99.4 million during the year ended December 31, 2020. The change is primarily a result of the interest associated with the 12.00% Notes issued in January 2021 with an aggregate principal amount of $650.0 million when compared to the interest on the 11.00% Second-Priority Senior Secured Notes (the “11.00% Notes”) that were redeemed in January 2021. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Debt.

Price Risk Management Activities — Price risk management activities for year ended December 31, 2021 resulted in a decrease of approximately $506.8 million, or 578%. The expense of $419.1 million for the year ended December 31, 2021 consisted of $290.2 million in cash settlement losses and $128.9 million in non-cash losses from the decrease in the fair value of our open derivative contracts. The income of $87.7 million for the year ended December 31, 2020 consisted of $143.9 million in cash settlement gains that was offset by $56.2 million in non-cash losses from the decrease in the fair value of our open derivative contracts.

These unrealized gains and losses on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on our Consolidated Statements of Operations at the end of each month. As a result of the derivative contracts we have on our anticipated production volumes through December 2023, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas.

Other (Income) Expense — During the year ended December 31, 2021, we recorded a $13.2 million loss on extinguishment of debt as a result of the redemption of the 11.00% Notes further discussed in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Debt. 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 IV, Item 15. Exhibits and Financial Statement Schedules — Note 11 — Related Party Transactions.

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Income Tax Benefit (Expense) — During the year ended December 31, 2021, we recorded $1.6 million of income tax benefit compared to $35.6 million of income tax expense during the year ended December 31, 2020. The change is primarily a result of the recognition of a valuation allowance for its excess federal and state deferred tax assets in the year ended December 31, 2020. 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 IV, Item 15. Exhibits and Financial Statement Schedules — Note 9 — Income Taxes.

Commitments and Contingencies

For a further discussion of our commitments and contingencies, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 12 — Commitments and Contingencies. Additionally, we are party to lawsuits arising in the ordinary course of our business. We cannot predict the outcome of any such lawsuit with certainty, but our management believes it is remote that any such pending or threatened lawsuit will have a material adverse impact on our financial condition. See Part I, Item 3. Legal Proceedings for additional information.

Due to the nature of our business, we are, from time-to-time, involved in other routine litigation or subject to disputes or claims related to business activities, including workers’ compensation claims, employment related disputes and civil penalties by regulators. In the opinion of our management, none of these other pending litigations, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations. See Part I, Item 3. Legal Proceedings for additional information.

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 non-recurring 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 tables present a reconciliation of the GAAP financial measure of net income (loss) to Adjusted EBITDA for each of the periods indicated (in thousands):

(1)
Includes transaction-related expenses, restructuring expenses, cost saving initiatives and other miscellaneous income and expenses.

(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.

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 increased since December 31, 2020 primarily due to an increase of $120.5 million in liabilities from price risk management activities. As of December 31, 2021, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $472.6 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 year ended December 31, 2021 (in thousands):

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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 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, raising debt, including secured debt, or issuing equity to directly or independently repurchase or refinance our outstanding debt.

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):

Operating Activities — Cash provided by operating activities increased $109.5 million in 2021 compared to 2020 primarily attributable to an increase in revenues net of lease operating expense of $631.6 million. This was offset by an increase in cash payments on derivatives of $434.1 million, interest expense of $33.7 million and settlements of asset retirement obligations of $24.1 million.

Investing Activities — Cash used in investing activities decreased $385.2 million in 2021 compared to 2020 primarily due to a decrease in payments for acquisitions of $310.6 million and in capital expenditures of $69.6 million.

Financing Activities — Cash used in financing activities increased $406.2 million in 2021 compared to 2020. During 2021, the issuance of the 12.00% Notes in January 2021 generated $579.0 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 then further reduced by $90.0 million during the remainder of 2021.

During 2020, net borrowings under the Bank Credit Facility was $290.0 million and proceeds from the issuance of common stock was $71.1 million. These cash inflows were primarily offset by finance lease payments of $17.5 million and other deferred payments of $11.9 million.

Overview of Debt Instruments

Financing Arrangements — As of December 31, 2021, total debt, net of discount and deferred financing costs, was approximately $962.7 million, comprised of our $650.0 million aggregate principal amount of the 12.00% Notes and $6.1 million aggregate principal amount of our 7.50% Senior Notes due 2022 issued by Stone (“7.50% Notes”), and $367.8 million outstanding under our Bank Credit Facility. We were in compliance with all debt covenants at December 31, 2021. For additional details on our debt, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Debt.

Bank Credit Facility – matures November 2024 — We maintain a Bank Credit Facility with a syndicate of financial institutions. 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. For additional details on our Bank Credit Facility, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Debt.

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12.00% Second-Priority Senior Secured Notes—due January 2026 — 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, commencing on July 15, 2021. We made an interest payment of $39.0 million on January 14, 2022. For additional details on the 12.00% Notes, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Debt.

Redemption of the 11.00% Second-Priority Senior Secured Notes—due April 2022 — On January 13, 2021, we redeemed the 11.00% Notes using the proceeds from the issuance of the 12.00% Notes. For additional details on this redemption, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Debt.

7.50% Senior Notes – due May 2022 — The 7.50% Notes mature May 31, 2022 and have interest payable semi-annually each May 31 and November 30. For additional details on the 7.50% Notes, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Debt.

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 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 (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 income statement 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):

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

Material Cash Requirements — We are party to various contractual obligations. Some of these obligations may be reflected in our accompanying Consolidated Financial Statements, while other obligations, such as certain operating leases and capital commitments, are not reflected on our accompanying Consolidated Financial Statements.

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The following table and discussion summarizes our material cash requirements from known contractual obligations as of December 31, 2021 (in thousands):

(1)
Includes commitments for drilling rigs we will utilize for certain Deepwater well intervention and decommissioning activities. 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.

(2)
Lease agreement for the HP-I floating production facility in the Phoenix Field.

(3)
Includes committed purchase orders to execute planned future drilling activities.

(4)
This table does not include our estimated discounted liability for dismantlement, abandonment and restoration costs of oil and natural gas properties of $434.0 million as of December 31, 2021. For additional information regarding these liabilities, please see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 4 — Property, Plant and Equipment. Additionally, this table does not include liabilities associated with our decommissioning obligations. For additional information regarding our decommissioning obligations, please see please see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 12 — Commitment and Contingencies.

Performance Obligations — As of December 31, 2021, we had secured performance bonds from third party sureties and letters of credit issued under its Bank Credit Facility primarily related to P&A of wells and removal of facilities in the U.S. Gulf of Mexico and certain obligations under the Mexico PSCs totaling approximately $724.4 million and $13.6 million, respectively.

For additional information about certain of our obligations and contingencies, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 12 — Commitments and Contingencies.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with GAAP requires our management to make estimates and assumptions that affect the reported amount of assets, liabilities, revenue and expense, and the disclosures of contingent assets and liabilities. We consider our critical accounting estimates to be those estimates that require complex or subjective judgment in the application of the accounting policy and that could significantly impact our financial results based on changes in those judgments. Changes in facts and circumstances may result in revised estimates and actual results may differ materially from those estimates. Our management has identified the following critical accounting estimates. Our significant accounting policies are described in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies.

Oil and Natural Gas Properties — The Company follows the full cost method of accounting for oil and natural gas exploration and development activities. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the internal costs directly related to acquisition, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and assessed for impairment on a quarterly basis through a ceiling test calculation as discussed below.

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Capitalized costs associated with proved reserves are amortized on a country-by-country basis over the life of the total proved reserves using the unit of production method, computed quarterly. Conversely, capitalized costs associated with unproved properties and related geological and geophysical costs, exploration wells currently drilling and capitalized interest are initially excluded from the amortizable base. The Company transfers unproved property costs into the amortizable base when properties are determined to have proved reserves or when the Company has completed an unproved properties evaluation resulting in an impairment. The Company evaluates each of these unproved properties individually for impairment at least quarterly. Additionally, the amortizable base includes future development costs, dismantlement, restoration and abandonment costs, net of estimated salvage values, and geological and geophysical costs incurred that cannot be associated with specific unproved properties or prospects in which the Company owns a direct interest. The Company capitalizes overhead costs that are directly related to exploration, acquisition and development activities.

The Company’s capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10%, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. Any costs in excess of the ceiling for U.S. oil and gas properties are recognized as a non-cash “Write-down of oil and natural gas properties” on the Consolidated Statements of Operations and an increase to “Accumulated depreciation, depletion and amortization” on the Company’s Consolidated Balance Sheets. The expense may not be reversed in future periods, even though higher oil, natural gas and NGL prices may subsequently increase the ceiling. The Company performs this ceiling test calculation each quarter. In accordance with the SEC rules and regulations, the Company utilizes SEC Pricing when performing the ceiling test. The Company also holds prices and costs constant over the life of the reserves, even though actual prices and costs of oil and natural gas are often volatile and may change from period to period.

Under the full cost method of accounting for oil and natural gas operations, assets whose costs are currently being depreciated, depleted or amortized are assets in use in the earnings activities of the enterprise and do not qualify for capitalization of interest cost. Investments in unproved properties for which exploration and development activities are in progress and other major development projects that are not being currently depreciated, depleted or amortized are assets qualifying for capitalization of interest costs.

When the Company sells or conveys interests in oil and natural gas properties, the Company reduces its oil and natural gas reserves for the amount attributable to the sold or conveyed interest. The Company treats sales proceeds on non-significant sales as reductions to the cost of the Company’s oil and natural gas properties. The Company does not recognize a gain or loss on sales of oil and natural gas properties, unless those sales would significantly alter the relationship between capitalized costs and proved reserves.

Proved Reserve Estimates — We estimate our proved oil, natural gas and NGL reserves in accordance with the guidelines established by the SEC. Proved oil, natural gas and NGL reserves are those quantities of oil, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future periods from known reservoirs and under existing economic conditions, operating methods and governmental regulations. Prices are determined using SEC pricing.

Our estimates of proved reserves are made using available geological and reservoir data, as well as production performance data. The estimates of proved reserves are reviewed annually by internal reservoir engineers and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions. Decreases in price, for example, may cause a reduction in some proved reserves due to reaching economic limits at an earlier projected date. A material adverse change in the estimated volumes of proved reserves could have a negative impact on depreciation, depletion and amortization or could result in property impairments.

Fair Value Measure of Financial Instruments — Our financial instruments generally consisted of cash and cash equivalents, accounts receivable, commodity derivatives, accounts payable and debt as of December 31, 2021. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to the highly liquid nature of these instruments.

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Fair value accounting standards define fair value, establish a consistent framework for measuring fair value and stipulate the related disclosure requirements for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis. These standards also clarify fair value as an exit price, presenting the amount that would be received to sell an asset or paid to transfer a liability, in an orderly transaction between market participants. We follow a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value depending on the degree to which they are observable as follows:

•
Level 1 — Inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

•
Level 2 — Inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial statement.

•
Level 3 — Inputs to the valuation methodology are unobservable (little or no market data), which require us to develop our own assumptions, and are significant to the fair value measurement.

Assets and liabilities measured at fair value are based on one or more of three valuation techniques. The valuation techniques are as follows:

•
Market Approach — Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.

•
Cost Approach — Amount that would be required to replace the service capacity of an asset (replacement cost).

•
Income Approach — Techniques to convert expected future cash flows to a single present value amount based on market expectations (including present value techniques, option-pricing and excess earnings models).

Authoritative guidance on financial instruments requires certain fair value disclosures to be presented. The estimated fair value amounts have been determined using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

Asset Retirement Obligations — The Company has obligations associated with the retirement of its oil and natural gas wells and related infrastructure. The Company has obligations to plug wells when production on those wells is exhausted, when the Company no longer plans to use them or when the Company abandons them. The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount to replace, remove or retire the associated assets.

In estimating the liability associated with its asset retirement obligations, the Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate. Changes in estimate in the table below represent changes to the expected amount and timing of payments to settle its asset retirement obligations. Typically, these changes result from obtaining new information about the timing of its obligations to plug and abandon oil and natural gas wells and the costs to do so. After initial recording, the liability is increased for the passage of time, with the increase being reflected as “Accretion expense” on the Company’s Consolidated Statements of Operations. If the Company incurs an amount different from the amount accrued for asset retirement obligations, the Company recognizes the difference as an adjustment to proved properties.

Revenue Recognition and Imbalances — Revenues are recorded based from the sale of oil, natural gas and NGLs based on quantities of production sold to purchasers under short-term contracts (less than twelve months) at market prices when delivery to the customer has occurred, title has transferred, prices are fixed and determinable and collection is reasonably assured. This occurs when production has been delivered to a pipeline or when a barge lifting has occurred.

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Revenues are recorded based on the actual sales volumes sold to purchasers. An imbalance receivable or payable is recorded only to the extent the imbalance is in excess of its share of remaining proved developed reserves in an underlying property. Our imbalances are presented gross on our Consolidated Balance Sheets. At December 31, 2021 and 2020, our imbalance receivable was approximately $1.7 million and $1.7 million, respectively, and imbalance payable was approximately $2.5 million and $3.6 million, respectively.

Income Taxes — Our provision for income taxes includes U.S. state and federal and foreign taxes. We record our federal income taxes in accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. As of December 31, 2021, we believe it is more likely than not that some or all of the benefits from our federal and state deferred tax assets will not be realized and reduced the net federal and state deferred tax assets by a valuation allowance. We maintain a valuation allowance on most of our Mexico deferred tax assets.

We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from our estimates, which could impact our financial position, results of operations and cash flows.

We also account for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority.

Recently Adopted Accounting Standards

None.

Recently Issued Accounting Standards

There were no recently issued accounting standards material to us.