TALOS ENERGY INC. Unless otherwise indicated or the context otherwise requires, references in this Quarterly Report to "us," "we," "our" or the "Company" are toTalos 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 inthe United States ("U.S.")Gulf of Mexico and offshoreMexico both through upstream oil and gas exploration and production and the development ofcarbon 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 third-party industrial CO2 emissions through our CCS collaborative arrangements along the coast of theU.S. Gulf of Mexico . We have historically focused our operations in theU.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 endedMarch 31, 2022 . CCS Initiatives - OnMarch 11, 2022 , we announced thatBayou Bend CCS LLC ("Bayou Bend"), our equity method investment withCarbonvert, Inc. ("Carbonvert"), executed definitive lease documentation with theTexas General Land Office , formalizing the previously announced CCS site located offshoreJefferson County, Texas , near theBeaumont andPort Arthur, Texas industrial corridor. Additionally, we announced that we had established a CCS strategic alliance with Core Laboratories N.V., to provide technical evaluation and assurance services for CCS subsurface analysis, including analysis for our upcoming 2022 stratigraphic evaluation well. 21
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OnMay 24, 2022 , the execution of definitive documentation and closing of an expanded venture to jointly develop the Bayou Bend project was announced by us, through our Talos LowCarbon Solutions division, Carbonvert, andChevron U.S.A., Inc. ("Chevron"), through its Chevron New Energies division. Under the terms of the transaction,Chevron acquired a 50% membership interest in Bayou Bend.Chevron purchased a 25% membership interest from both us and Carbonvert for gross consideration of$50.0 million , consisting of$30.0 million of cash at closing and up to$20.0 million of gross contributions to Bayou Bend, expected to cover our and Carbonvert's share of capital expenditures through the project's final investment decision. We, Carbonvert andChevron hold a 25%, 25% and 50% membership interest in Bayou Bend, respectively, and we remain the project's operator. The three companies have also established an area of mutual interest over the full acreage in theJefferson County offshore region contemplated in theState of Texas's original request for proposal, aligning the parties for future expansion opportunities. See Part I, Item 1. "Condensed Consolidated Financial Statements - Note 9 - Related Party Transactions" for additional information. OnJuly 20, 2022 , we entered into an amended and restated collaboration agreement (the "Collaboration Agreement") withStoregga Limited ("Storegga"). Per the terms of the Collaboration Agreement, Storegga paid us$3.4 million to cover their share of past costs incurred by us associated with three projects, two of which have been previously announced. Storegga will reimburse us for its share of third-party expenditures for each project. See Part I, Item 1. "Condensed Consolidated Financial Statements - Note 1 - Organization, Nature of Business and Basis of Presentation" for additional information regarding operating expenses incurred by the CCS Segment during the three months and six months endedJune 30, 2022 .
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.
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 Helix Producer I (the "HP-I") andGreen Canyon 18 facilities. For the six months endedJune 30, 2022 , we estimate the shut-in resulted in deferred production of approximately 2.3 MBoepd based on production rates prior to the shut-in.
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. 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 the Company's 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 periodJanuary 1, 2022 throughJune 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$9.44 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 ofJune 30, 2022 . 22
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The U.S. Energy Information Administration ("EIA") published its latest Short-Term Energy Outlook onJuly 12, 2022 . The EIA expects the Henry Hub spot price will average$5.97 per MMBtu in the second half of 2022 and average$4.76 per MMBtu in 2023. The EIA also expects the WTI spot price will average$95.54 per Bbl in the second half of 2022 and average$89.75 per Bbl in 2023. The EIA indicates that crude oil prices increased in the first half of 2022 followingRussia's full-scale invasion ofUkraine in February. As a result of the war, several countries imposed sanctions on imports of crude oil and petroleum products fromRussia . In addition, many international oil companies and other firms ended operations inRussia and limited or stopped tradingRussia's crude oil and petroleum products. These actions have reducedRussia's oil production and caused crude oil prices to rise. Several OPEC Plus members have produced below their targets, which has also put additional upward pressure on oil prices. These factors, along with already low global inventories, have intensified both upward oil price pressures and oil price volatility. The EIA noted crude oil prices decreased in early July in response to some indications of slowing economic growth. For example, theFederal Reserve's interest rate increase of 75 basis points onJune 15th and onJuly 27th is likely reducing expectations for economic growth and inflation, both of which could decrease the price of crude oil. Crude oil prices remain high, likely as a result of low inventories and continued uncertainty surroundingRussia's future oil supply. 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, theU.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 theU.S. Federal Reserve and other central banks to increase interest rates, which could have the effects of raising the cost of capital and depressing economic growth, either of which-or the combination thereof-could hurt our business. Impairment ofOil and Natural Gas Properties - Under the full cost method of accounting, the "ceiling test" underSEC 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 theFull Cost Pool exceeds the Ceiling, an impairment must be recorded. For the three and six months endedJune 30, 2022 and 2021, we did not recognize an impairment based on the ceiling test computations. AtJune 30, 2022 our ceiling test computation was based onSEC pricing of$86.69 per Bbl of oil,$5.30 per Mcf of natural gas and$36.04 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. With respect to our operations inMexico , our oil and natural gas properties are classified as unproved properties, not subject to amortization. The finalization of the Unit Development Plan for the Zama Field, which sets out the terms on which the reservoir will be jointly developed, could adversely affect the value of the oil and natural gas assets and result in an impairment of our unevaluated oil and gas properties. 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 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 theU.S. Coast Guard , during which time we are unable to produce the Phoenix Field. The initiation of the HP-I dry-dock commenced onAugust 3, 2022 with an estimated shut-in lasting approximately 45 to 60 days. 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 theTrump Administration first paused, and then in 2020 rescinded, this NTL. 23
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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 theBiden 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 theBiden Administration may elect to pursue more stringent supplemental bonding requirements. Deepwater Operations - We have interests in Deepwater fields in theU.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 theU.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 theDepartment of the Interior ("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 theU.S. Outer Continental Shelf. OnMay 11, 2022 , the DOI cancelled two lease auctions in theGulf 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 theObama Administration , which expired onJune 30, 2022 . The DOI cited "conflicting court rulings" as the primary reason for not holding these offshore lease sales.The Trump Administration published a first draft of a new national program in 2018. BOEM's development of a new five-year 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 toCongress 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. The BOEM took the first formal step in pursuit of a new five-year national program inJanuary 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 toCongress 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 theFederal Register onJuly 8, 2022 , with comments due byOctober 6, 2022 . The PP includes no more than ten potential lease sales in theGulf of Mexico ; however, BOEM's subsequent Proposed Final Program for 2023-2028 could reduce the number ofGulf of Mexico lease sales in the national program. When the 2023-2028 national program will be approved and implemented remains uncertain.Congress may influence theBiden 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. 24
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OnJuly 27, 2022 ,Senate Democrats released a budget reconciliation bill called the Inflation Reduction Act (the "Act"). Included in the Act is the (i) requirement for the DOI Secretary to accept the high bids and grant leases to the winning bidders in Lease Sale 257, held onNovember 17, 2021 , which Lease Sale 257 was previously vacated by theU.S. District Court for the District of Columbia onJanuary 27, 2022 pursuant to litigation, and (ii) requirement to conduct Lease Sales 258, 259 and 261, previously cancelled by DOI, notwithstanding expiration of the 2017-2022 national lease program. Whether the Act is approved byCongress , is signed by the President and becomes law in its current form remains uncertain.
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.
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 June 30 ,
Six Months Ended
2022 2021 Change 2022 2021 Change
Revenues:
Oil $ 429,329 $ 267,990 $ 161,339 $ 783,215 $ 497,551 $ 285,664
Natural gas 70,406 26,131 44,275 113,387 54,365 59,022
NGL 19,350 9,647 9,703 36,049 18,760 17,289
Total revenues $ 519,085 $ 303,768 $ 215,317 $ 932,651 $ 570,676 $ 361,975
Total Production Volumes:
Oil (MBbls) 3,974 4,169 (195 ) 7,762 8,218 (456 )
Natural gas (MMcf) 8,805 8,572 233 17,454 17,080 374
NGL (MBbls) 512 433 79 969 915 54
Total production volume
(MBoe) 5,953 6,031 (78 ) 11,640 11,980 (340 )
Daily Production Volumes
by
Product:
Oil (MBblpd) 43.7 45.8 (2.1 ) 42.9 45.4 (2.5 )
Natural gas (MMcfpd) 96.8 94.2 2.6 96.4 94.4 2.0
NGL (MBblpd) 5.6 4.8 0.8 5.4 5.1 0.3
Total production volume
(MBoepd) 65.4 66.3 (0.9 ) 64.3 66.2 (1.9 )
Average Sale Price Per
Unit:
Oil (per Bbl) $ 108.03 $ 64.28 $ 43.75 $ 100.90 $ 60.54 $ 40.36
Natural gas (per Mcf) $ 8.00 $ 3.05 $ 4.95 $ 6.50 $ 3.18 $ 3.32
NGL (per Bbl) $ 37.79 $ 22.28 $ 15.51 $ 37.20 $ 20.50 $ 16.70
Price per Boe $ 87.20 $ 50.37 $ 36.83 $ 80.12 $ 47.64 $ 32.48
Price per Boe (including
realized commodity
derivatives) $ 60.28 $ 38.89 $ 21.39 $ 55.44 $ 37.82 $ 17.62
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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 June 30, 2022 vs 2021 Six Months Ended June 30, 2022 vs 2021
Price Volume Total Price Volume Total
Oil $ 173,874 $ (12,535 ) $ 161,339 $ 313,270 $ (27,606 ) $ 285,664
Natural gas 43,564 711 44,275 57,833 1,189 59,022
NGL 7,943 1,760 9,703 16,182 1,107 17,289
Total revenues $ 225,381 $ (10,064 ) $ 215,317 $ 387,285 $ (25,310 ) $ 361,975
Three Months Ended June 30, 2022 and 2021 Volumetric Analysis - Production
volumes decreased by 0.9 MBoepd to 65.4 MBoepd. There was a 1.9 MBoepd decrease
in production volumes attributable to well performance and natural production
declines at the Green Canyon 18 Field. Additionally, production volumes
decreased 1.2 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 in production of 3.3 MBoepd in the Phoenix Field primarily due to
the recompletion of the Tornado 3 well in the third quarter of 2021.
Six Months Ended June 30, 2022 and 2021 Volumetric Analysis - Production volumes
decreased by 1.9 MBoepd to 64.3 MBoepd. The decrease in production volumes was
primarily due to the unplanned third party downtime at the Eugene Island
Pipeline System resulting in 2.3 MBoepd of deferred production for the six
months ended June 30, 2022 . Additionally, production volumes decreased 2.2
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 in
production of 3.9 MBoepd in the Phoenix Field primarily due to the recompletion
of the Tornado 3 well in the third quarter of 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 June 30, Six Months Ended June 30,
2022 2021 2022 2021
Lease operating expenses $ 87,582 $ 72,013 $ 147,396 $ 138,641
Lease operating expenses per Boe $ 14.71 $ 11.94 $
12.66
Three Months EndedJune 30, 2022 and 2021 - Lease operating expense for the three months endedJune 30, 2022 increased by approximately$15.6 million , or 22%. The increase is primarily due to a$16.0 million increase in facility and workover expense related to repairs and maintenance at the Phoenix Field and the Gunflint Field. Additionally, there was a$2.2 million increase in company and contract labor compared to the same period in 2021. This increase was partially offset by$4.8 million in additional production handling fees related to certain reimbursements for costs from certain third parties. Six Months EndedJune 30, 2022 and 2021 - Lease operating expense for the six months endedJune 30, 2022 increased by approximately$8.8 million , or 6%. The increase is primarily due to a$12.6 million increase in facility and workover expense for repairs and maintenance at the Phoenix Field. Additionally, there was a$3.0 million increase in company and contract labor compared to the same period in 2021. This increase was partially offset by$8.4 million in additional production handling fees related to certain reimbursements for costs from certain third parties. 26
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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 June 30, Six Months Ended June 30,
2022 2021 2022 2021
Depreciation, depletion and
amortization $ 104,511 $ 99,841 $ 202,851 $ 201,498
Depreciation, depletion and
amortization per Boe $ 17.56 $ 16.55 $ 17.43 $ 16.82 Three Months Ended
Six Months Ended
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 June 30 ,
Six Months Ended
2022 2021 2022 2021
General and administrative expense
45,453 $ 38,566
General and administrative expense
per Boe $ 3.85 $ 3.21 $
3.90
Three Months EndedJune 30, 2022 and 2021 - General and administrative expense for the three months endedJune 30, 2022 increased by approximately$3.5 million , or 18%. This increase was primarily related to general and administrative expenses of$3.6 million incurred by our emerging CCS operating segment during the three months endedJune 30, 2022 . Additionally, general and administrative expense includes non-cash equity-based compensation of$4.0 million , or$0.68 per Boe, during the three months endedJune 30, 2022 , which is an increase of$1.1 million . On a per unit basis, general and administrative expense increased$0.64 per Boe. Six Months EndedJune 30, 2022 and 2021 - General and administrative expense for the six months endedJune 30, 2022 increased by approximately$6.9 million , or 18%. This increase was primarily related to general and administrative expenses of$5.9 million incurred by our emerging CCS operating segment during the six months endedJune 30, 2022 . Additionally, general and administrative expense includes non-cash equity-based compensation of$7.4 million , or$0.63 per Boe, during the six months endedJune 30, 2022 , which is an increase of$1.7 million . On a per unit basis, general and administrative expense increased$0.68 per Boe.
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 June 30, Six Months Ended June 30,
2022 2021 2022 2021
Accretion expense $ 14,844 $ 15,457 $ 29,221 $ 30,442
Other operating expense $ 12,372 $ 2,783 $ 12,508 $ 1,783
Interest expense $ 30,776 $ 33,570 $ 62,266 $ 67,646
Price risk management activities expense $ 64,094 $ 186,617 $ 345,313 $ 324,125
Equity method investment income $ 13,466 $ - $ 13,608 $ -
Other (income) expense $ (3,165 ) $ (1,559 ) $ (31,299 ) $ 12,391
Income tax expense $ 2,607 $ 498 $ 2,135 $ 1,082
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Three Months Ended
Other Operating Expense - During the three months endedJune 30, 2022 , we recorded$10.2 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 endedJune 30, 2021 , we recorded$2.8 million of estimated decommissioning obligations. See further discussion in Part I, Item 1. "Condensed Consolidated Financial Statements - Note 10 - Commitments and Contingencies." Price Risk Management Activities - The expense of$64.1 million for the three months endedJune 30, 2022 consists of$160.2 million in cash settlement losses partially offset by$96.1 million in non-cash gains from the increase in the fair value of our open derivative contracts. The expense of$186.6 million for the three months endedJune 30, 2021 consists of$117.4 million in non-cash losses from the decrease in the fair value of our open derivative contracts and$69.2 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 throughJune 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 endedJune 30, 2022 , we recorded equity losses of$0.4 million offset by a$13.9 million gain on partial sale of our investment in Bayou Bend. See Part I, Item 1. "Condensed Consolidated Financial Statements - Note 9 - Related Party Transactions" for additional information. Income Tax (Benefit) Expense - During the three months endedJune 30, 2022 , we recorded$2.6 million of income tax expense compared to$0.5 million of income tax expense during the three months endedJune 30, 2021 . The change 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."
Six Months Ended
Other Operating Expense - During the six months endedJune 30, 2022 , we recorded$10.5 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 six months endedJune 30, 2021 , we recorded$2.8 million of estimated decommissioning obligations. See further discussion in Part I, Item 1. "Condensed Consolidated Financial Statements - Note 10 - Commitments and Contingencies." Price Risk Management Activities - The expense of$345.3 million for the six months endedJune 30, 2022 consists of$287.3 million in cash settlement losses and$58.0 million in non-cash losses from the decrease in the fair value of our open derivative contracts. The expense of$324.1 million for the six months endedJune 30, 2021 consists of$206.5 million in non-cash losses from the decrease in the fair value of our open derivative contracts and$117.6 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 throughJune 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 six months endedJune 30, 2022 , we recorded equity losses of$0.3 million offset by a$13.9 million gain on partial sale of our investment in Bayou Bend. See Part I, Item 1. "Condensed Consolidated Financial Statements - Note 9 - Related Party Transactions" for additional information. 28
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Other (Income) Expense - During the six months endedJune 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 inOctober 2017 that is further discussed in Part I, Item 1. "Condensed Consolidated Financial Statements - Note 10 - Commitments and Contingencies." During the six months endedJune 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"). Income Tax (Benefit) Expense - During the six months endedJune 30, 2022 , we recorded$2.1 million of income tax expense compared to$1.1 million of income tax expense during the six months endedJune 30, 2021 . The change 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."
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 June 30, Six Months Ended June 30,
2022 2021 2022 2021
Net income (loss) $ 195,141 $ (125,782 ) $ 128,700 $ (247,273 )
Interest expense 30,776 33,570 62,266 67,646
Income tax expense 2,607 498 2,135 1,082
Depreciation, depletion and
amortization 104,511 99,841 202,851 201,498
Accretion expense 14,844 15,457 29,221 30,442
EBITDA 347,879 23,584 425,173 53,395
Transaction and other (income)
expenses(1)(3)(4) (5,010 ) 4,083 (31,542 ) 5,861
Derivative fair value loss(2) 64,094 186,617 345,313 324,125
Net cash paid on settled derivative
instruments(2) (160,235 ) (69,237 ) (287,321 ) (117,618 )
Loss on extinguishment of debt - - - 13,225
Non-cash equity-based compensation
expense 4,049 3,017 7,367 5,681
Adjusted EBITDA $ 250,777 $ 148,064 $ 458,990 $ 284,669
(1)
Includes transaction-related expenses 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.
(3)
Includes a $27.5 million gain as a result of the settlement agreement to resolve
previously pending litigation for the six months ended June 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 $13.9 million gain on partial sale of our investment in Bayou Bend
for the three and six months ended June 30, 2022 that is further discussed 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 (defined below). Our primary uses of cash are for capital expenditures, working capital, debt service and for general corporate purposes. Our working capital deficit has increased sinceDecember 31, 2021 primarily due to an increase of$52.5 million in liabilities from price risk management activities. As ofJune 30, 2022 , our available liquidity (cash plus available capacity under the Bank Credit Facility) was$702.1 million . We fund exploration and development activities primarily through operating cash flows, cash on hand and through borrowings under the Bank Credit Facility, if necessary. Historically, we have funded significant property acquisitions with the issuance of senior notes, borrowings under the Bank Credit Facility and through additional equity issuances. We occasionally adjust our capital budget in response to changing operating cash flow forecasts and market conditions, including the prices of oil, natural gas and NGLs, acquisition opportunities and the results of our exploration and development activities.
Capital Expenditures - The following is a table of our capital expenditures,
excluding acquisitions, for the six months ended
U.S. drilling & completions$ 70,491 Mexico appraisal & exploration 196 Asset management 37,764
Seismic and G&G, land, capitalized G&A and other 19,829 CCS(1)
2,585
Total capital expenditures 130,865
Plugging & abandonment 39,768
Total capital expenditures and plugging & abandonment
(1)
Excludes
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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 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):
Six Months Ended June 30,
2022 2021
Operating activities $ 354,365 $ 199,094
Investing activities $ (117,235 ) $ (126,633 )
Financing activities $ (198,501 ) $ (41,340 )
Operating Activities - Net cash provided by operating activities increased
$155.3 million in the six months ended June 30, 2022 compared to the
corresponding period in 2021 primarily attributable to an increase in revenues
net of lease operating expense of $353.2 million . This was offset by an increase
in cash payments on derivative instruments of $169.7 million .
Investing Activities - Net cash used in investing activities decreased $9.4
million in the six months ended June 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 offset by increased 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 $157.2
million in the six months ended June 30, 2022 compared to the corresponding
period in 2021. During the six months ended June 30, 2022 , net repayments of
$175.0 million reduced the Bank Credit Facility. Additionally, we redeemed $6.1
million of our 7.50% Senior Notes.
During the six months ended June 30, 2021 , the issuance of the 12.00% Notes
(defined below) in January 2021 generated $578.6 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. We
further reduced our indebtedness under the Bank Credit Facility by $65.0 million
during the second quarter of 2021.
Overview of Debt Instruments
Bank Credit Facility - maturesNovember 2024 - We maintain aBank 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. OnMay 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. 31
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12.00% Second-Priority Senior Secured Notes - dueJanuary 2026 - The 12.00% Second-Priority Senior Secured Notes (the "12.00% Notes") were issued pursuant to an indenture datedJanuary 4, 2021 and the first supplemental indenture datedJanuary 14, 2021 betweenTalos Energy Inc. (the "Parent Guarantor");Talos Production Inc. (the "Issuer"); the Subsidiary Guarantors (defined below); andWilmington 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 onJanuary 15, 2026 and have interest payable semi-annually eachJanuary 15 andJuly 15 . We made an interest payment of$39.0 million onJuly 15, 2022 . See Part I, Item 1. "Condensed Consolidated Financial Statements - Note 5 - Debt" for more information. 7.50% Senior Notes - redeemedMay 2022 - The 7.50% Senior Notes matured and were redeemed onMay 31, 2022 . See Part I, Item 1. "Condensed Consolidated Financial Statements - Note 5 - Debt" for more information. Guarantor Financial Information - We own no operating assets and have no operations independent of our subsidiaries. The 12.00% Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by the Parent Guarantor and on a second-priority senior secured basis by each of the Issuer's present and future direct or indirect wholly owned material restricted domestic subsidiaries (collectively, the "Subsidiary Guarantors" and, together with the Parent Guarantor, the "Guarantors") that guarantees the Issuer's senior reserve-based revolving credit facility. Our non-domestic subsidiaries and our unrestricted CCS domestic subsidiaries (the "Non-Guarantors") are 100% owned by us but do not guarantee the 12.00% Notes. In lieu of providing separate financial statements for the Issuer and the Guarantors, we have presented the accompanying supplemental summarized combined balance sheet and statement of operations information for the Issuer and the Guarantors on a combined basis after elimination of intercompany transactions and amounts related to investment in any subsidiary that is a Non-Guarantor. The following table presents the balance sheet information for the respective periods (in thousands): June 30, 2022 December 31, 2021 Current assets$ 448,537 $ 330,415 Non-current assets 2,269,033 2,305,855 Total assets$ 2,717,570 $ 2,636,270 Current liabilities$ 696,985 $ 598,062 Non-current liabilities 1,264,189 1,405,382 Talos Energy Inc. stockholders' equity 756,396
632,826
Total liabilities and stockholders' equity
The following table presents the statement of operations information (in thousands):
Six Months Ended June 30, 2022
Revenues $ 932,651
Costs and expenses (809,312 )
Net income $ 123,339
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
•
Interest expense through the maturity of our debt instruments decreased in the aggregate by approximately$8.9 million primarily due to the lower borrowings under the Bank Credit Facility; 32
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•
Vessel commitments increased by approximately$33.6 million due to the execution of an offshore drilling rig agreement onApril 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 increased from
•
Purchase obligations increased from
Performance Bonds - As ofJune 30, 2022 , we had secured performance bonds from third party sureties and letters of credit issued under our Bank Credit Facility primarily related to plugging and abandonment of wells and removal of facilities in theU.S. Gulf of Mexico and certain obligations under the Mexico PSCs totaling approximately$689.0 million and$12.6 million , respectively. 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.
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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