Talos Energy Announces Second Quarter 2022 Operational and Financial Results

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HOUSTON, Aug. 4, 2022 -- Talos Energy Inc. ("Talos" or the "Company") (NYSE: TALO) today announced its operational and financial results for the second quarter of 2022.

Key Highlights:

  • Production of 65.4 thousand barrels of oil equivalent per day ("MBoe/d") (67% oil, 75% liquids).
  • Revenue of $519.1 million, driven by realized prices (excluding hedges) of $108.03 per barrel for oil, $37.79 per barrel for natural gas liquids ("NGLs") and $8.00 per thousand cubic feet ("Mcf") for natural gas.
  • Net Income of $195.1 million, or $2.33 Net Income per diluted share, and Adjusted Net Income(1) of $100.6 million, or $1.20 Adjusted Net Income per diluted share.
  • Adjusted EBITDA(1) of $250.8 million, or $42.13 Adjusted EBITDA per Boe; Adjusted EBITDA excluding hedges of $411.0 million, or $69.04 per Boe.
  • Capital Expenditures of $85.9 million, inclusive of plugging and abandonment.
  • Free Cash Flow(1) (before changes in working capital) of $134.1 million.
  • Achieved 1.0x leverage ratio as of June 30, 2022 through the repayment of $146.1 million in credit facility borrowings and 7.5% Notes and achieved record liquidity of $702.2 million; Net Debt has been reduced by $344.1 million since March 31, 2021.
  • Expanded the Bayou Bend carbon capture and sequestration ("CCS") joint venture through Chevron U.S.A Inc.'s ("Chevron") acquisition of a 50% interest in exchange for $50 million of gross consideration.

President and Chief Executive Officer Timothy S. Duncan commented: "It was a strong quarter for Talos as we achieved rapid debt reduction led by record-breaking revenue and cost control efforts despite macro inflationary pressures. Through our steady focus on significant free cash flow generation and substantial debt paydown, we've achieved the lowest leverage multiple and highest liquidity in the history of Talos. In the second half of the year we will initiate our operated open water rig program testing a series of exciting, high-impact drilling opportunities and expect to spud our Puma West appraisal well early in the fourth quarter."

Duncan continued: "In our CCS business, we closed the previously announced Bayou Bend transaction with Chevron and Carbonvert, welcoming Chevron into the joint venture that is developing the country's first and only major offshore CO2 sequestration project. We expect to spud the first stratigraphic evaluation well this year to expedite the EPA Class VI permitting process while continuing to engage potential industrial customers. Utilizing our technical and commercial skill sets, gained through decades of regional experience, to provide CCS-as-a-Service along the U.S. Gulf Coast exemplifies our commitment to balancing responsible energy production with tangible carbon management solutions for the future, a combination that we believe underpins what the energy company of the future looks like for all of its stakeholders."

RECENT DEVELOPMENTS AND OPERATIONS UPDATE

Debt Repayment: Talos repaid $140.0 million of credit facility borrowings and $6.1 million of 7.5% Notes at maturity in the second quarter, reducing overall leverage to 1.0x Net Debt to LTM Adjusted EBITDA. The Company ended the quarter with liquidity of $702.2 million, the highest in Talos's history, and expects to continue to reduce credit facility borrowings in the second half of 2022.

Inflation Reduction Act: Talos is closely monitoring recent legislative developments regarding the Inflation Reduction Act, which contain numerous provisions relevant to the Company's Upstream and CCS business units. Among the Upstream provisions are the reinstatement of winning bids from OCS Lease Sale 257, in which Talos was one of the most active bidders and was the high bidder on over 57,000 gross acres across ten deepwater blocks. Additionally, the legislation would mandate three specific additional lease sales in the future and require oil and gas lease sales in conjunction with offshore wind lease sales going forward. For the Company's CCS business, the legislation includes provisions that could increase the 45Q credit for permanent CO2 sequestration to $85/ton from the current $50/ton, as well as adding a direct pay component to the current federal income tax credit structure. The Inflation Reduction Act has not been passed in the U.S. Senate and any final legislation may be different from the legislative text that is currently proposed.

CCS: Talos, through its Talos Low Carbon Solutions division, and Carbonvert, Inc. ("Carbonvert") announced and subsequently closed a transaction to expand the Bayou Bend CCS joint venture through the acquisition of a 50% interest by Chevron for $30.0 million of gross upfront cash and up to $20.0 million of gross future capital cost reimbursement, expected to cover capital expenditures through FID. Equity interests in the venture are now 25% Talos, 25% Carbonvert and 50% Chevron, and Talos is the operator. The three companies also established an Area of Mutual Interest ("AMI") over the full ~231,000-acre Jefferson County offshore region contemplated in the State of Texas's original request for proposal, aligning the parties for future expansion opportunities.

Third Quarter Expected Downtime: Following deferral of the planned dry-dock maintenance process from June 2022 into the third quarter, Talos has begun mobilizing the HP-1 vessel to shore for regulatory-required maintenance. Talos expects dry-dock to result in 6.0 – 9.0 MBoe/d of deferred production as well as incremental operating and capital costs in the third quarter. Preparatory costs of approximately $11.5 million are included in the second quarter operating expenses. Additionally, Talos expects planned third-party midstream downtime and other miscellaneous planned downtime activities to result in 4.0 – 5.0 MBoe/d of deferred production. Talos's previously issued annual operational and financial guidance is inclusive of both the HP-1 dry-dock and third-party midstream downtime estimates, as well as hurricane risking. However, the majority of hurricane downtime impact is typically incurred in the third quarter.

Operated Deepwater Rig Program: Talos expects to take possession of the Seadrill Sevan Louisiana deepwater rig in mid-August, initiating its open water program that includes six total operations between second half of 2022 and first half of 2023, four of which are exploitation wells targeting 65-100 million barrels of oil equivalent ("MMBoe") of cumulative gross unrisked resources and utilizing Talos-operated facilities for accelerated subsea development. The Company will spud the Lime Rock prospect, the first of the four exploitation targets, following a deepwater recompletion. Prior to initiating the rig program, Talos successfully obtained industry validation for these prospects, attracting non-operated working interest partners in each of the Lime Rock, Venice and Rigolets projects. Talos now owns a 60% working interest in each of these projects. Additionally, if successful, we expect each well to produce between 5.0 – 15.0 MBoe/d gross with expected timeline to first oil between 12-18 months.

Non-Operated Deepwater Rig Program: Talos expects the Puma West appraisal well to spud early in the fourth quarter with results expected by early 2023. The appraisal follows the successful 2021 exploration discovery well along with co-owners bp plc ("bp") (Operator) and Chevron. The well has been permitted to a depth of approximately 26,700 feet and will be drilled with the Diamond Ocean BlackHornet rig, currently working for bp. In the Gunflint Field, (9.6% working interest) Talos has participated in two successful workovers and anticipates initiating the MC 992 #1 sidetrack well by year-end. Lastly, Talos is actively working with a large industry partner to finalize a five-block exploration unit comprising 28,800 gross acres in the Walker Ridge and Green Canyon areas on which the Company expects to participate in a high-impact exploration prospect in the first half of 2023.

Zama: Talos is actively working with Petróleos Mexicanos ("Pemex") and its Block 7 partners Wintershall Dea and Harbour Energy to finalize the Zama Field Development Plan ("FDP"), targeting submission to National Hydrocarbons Commission ("CNH") latest by March 2023, as required in the unitization resolution. Upon approval, the parties will then move toward FID later in 2023. Concurrently, the parties are discussing the formation of an Integrated Project Team, which would include representatives of each company and would report to the Unit Operating Committee, to manage the field's development.

Pompano Platform Rig Program: The Company's Seville exploitation well failed to discover commercial quantities of hydrocarbons in late July. The platform rig program has shifted to begin preparations for the Mount Hunter development well, with spud expected in the third quarter and first oil in early 2023.

SECOND QUARTER 2022 RESULTS

Key Financial Highlights:


Three Months Ended
June 30, 2022


Period results ($ million):



Total Revenues

$

519.1


Net Income

$

195.1


Net Income per diluted share

$

2.33


Adjusted Net Income(1)

$

100.6


Adjusted Net Income per diluted share(1)

$

1.20


Adjusted EBITDA(1)

$

250.8


Adjusted EBITDA excluding hedges(1)

$

411.0


Capital Expenditures (including Plug & Abandonment)

$

85.9


Adjusted EBITDA Margin:



Adjusted EBITDA per Boe

$

42.13


Adjusted EBITDA excluding hedges per Boe

$

69.04


Production
Production for the quarter was 65.4 MBoe/d net and was 67% oil and 75% liquids.



Three Months Ended
June 30, 2022


Average net daily production volumes




Oil (MBbl/d)



43.7


Natural Gas (MMcf/d)



96.8


NGL (MBbl/d)



5.6


Total average net daily (MBoe/d)



65.4


 


Three Months Ended June 30, 2022



Production


% Oil


% Liquids


% Operated


Average net daily production volumes by Core Area (MBoe/d)









Green Canyon Area


23.2



81

%


87

%


98

%

Mississippi Canyon Area


26.6



72

%


82

%


58

%

Shelf and Gulf Coast


15.6



36

%


46

%


50

%

Total average net daily (MBoe/d)


65.4



67

%


75

%


70

%

Capital Expenditures
Capital expenditures for the quarter, including plugging and abandonment activities, totaled $85.9 million. Capital expenditures for the Company's CCS business includes the impact of the sale of 50% of the Company's investment in Bayou Bend CCS joint venture to Chevron (i.e., the Company recouped 50% of its original $2.25 million investment).


Three Months Ended
June 30, 2022


Capital Expenditures



U.S. Drilling & Completions

$

41.1


Mexico Appraisal & Exploration


0.1


Asset Management


17.5


Seismic and G&G / Land / Capitalized G&A and other


8.5


CCS(2)


(1.1)


Total Capital Expenditures


66.1


Plugging & Abandonment


19.8


Total Capital Expenditures and Plugging & Abandonment

$

85.9


Liquidity and Leverage
At quarter-end the Company had approximately $702.2 million of liquidity, with $606.3 million undrawn on its RBL facility and approximately $108.5 million in cash, less approximately $12.6 million in outstanding letters of credit. On June 30, 2022, Talos had $877.4 million in total debt, inclusive of $27.4 million related to the HP-1 finance lease. Net Debt was $768.9 million(1). Net Debt to Credit Facility LTM Adjusted EBITDA(1), as determined in accordance with the Company's credit agreement, was 1.0x(1).

Footnotes:

(1)

Adjusted Net Income, Adjusted Net Income per diluted share, Adjusted EBITDA, Adjusted EBITDA excluding hedges, Adjusted EBITDA margin, Adjusted EBITDA margin excluding hedges, Credit Facility LTM Adjusted EBITDA, Net Debt, Net Debt to Credit Facility LTM Adjusted EBITDA and Free Cash Flow are non-GAAP financial measures. See "Supplemental Non-GAAP Information" below for additional detail and reconciliations of GAAP to non-GAAP measures.

(2)

Excludes $1.8 million of expenditures reflected as "Other operating (income) expense" on the Condensed Consolidated Statements of Operations.

HEDGES

The following table reflects contracted volumes and weighted average prices the Company will receive under the terms of its derivative contracts as of August 4, 2022 and includes contracts entered into after June 30, 2022:



Instrument Type


Avg. Daily
Volume


Weighted Avg. Swap
Price

Crude – WTI




(Bbls)


(Per Bbl)

  July - September 2022


Swaps


18,000


$52.20

  October - December 2022


Swaps


19,326


$55.05

  January - March 2023


Swaps


23,000


$69.44

  April - June 2023


Swaps


19,000


$73.78

  July - September 2023


Swaps


9,000


$73.09

  October - December 2023


Swaps


8,000


$75.20

  January - March 2024


Swaps


6,000


$76.32

  April - June 2024


Swaps


4,000


$76.85








Natural Gas – HH NYMEX




(MMBtu)


(Per MMBtu)

  July - September 2022


Swaps


31,000


$2.63

  October - December 2022


Swaps


34,000


$2.72

  January - March 2023


Swaps


42,000


$3.87

  April - June 2023


Swaps


34,000


$3.38

  July - September 2023


Swaps


15,000


$3.46

  October - December 2023


Swaps


15,000


$4.62

  January - March 2024


Swaps


10,000


$3.25

  April - June 2024


Swaps


10,000


$3.25

CONFERENCE CALL AND WEBCAST INFORMATION

Talos will host a conference call, which will be broadcast live over the internet, on Friday, August 5, 2022 at 10:00 AM Eastern Time (9:00 AM Central Time). Listeners can access the conference call through a webcast link on the Company's website at: https://www.talosenergy.com/investor-relations/events-calendar/. Alternatively, the conference call can be accessed by dialing (888) 348-8927 (U.S. toll free), (855) 669-9657 (Canada toll-free) or (412) 902-4263 (international). Please dial in approximately 15 minutes before the teleconference is scheduled to begin and ask to be joined into the Talos Energy call. A replay of the call will be available one hour after the conclusion of the conference until August 12, 2022 and can be accessed by dialing (877) 344-7529 and using access code 1898121.

ABOUT TALOS ENERGY

Talos Energy (NYSE: TALO) is a technically driven independent exploration and production company focused on safely and efficiently maximizing long-term value through its operations, currently in the United States and offshore Mexico, both through upstream oil and gas exploration and production and the development of carbon capture and sequestration opportunities. As one of the Gulf of Mexico's largest public independent producers, 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 are also utilizing our expertise to explore opportunities to reduce industrial emissions through our carbon capture and sequestration initiatives along the U.S. Gulf Coast and Gulf of Mexico. For more information, visit www.talosenergy.com.

INVESTOR RELATIONS CONTACT

Sergio Maiworm
+1.713.328.3008
investor@talosenergy.com 

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

This communication may contain "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact included in this communication, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this communication, the words "will," "could," "believe," "anticipate," "intend," "estimate," "expect," "project," "forecast," "may," "objective," "plan" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.

We caution you that these forward-looking statements are subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility due to the continued impact of the coronavirus disease 2019 ("COVID-19"), including any new strains or variants, and governmental measures related thereto on global demand for oil and natural gas and on the operations of our business; the ability or willingness of OPEC and other state-controlled oil companies ("OPEC Plus"), such as Saudi Arabia and Russia, to set and maintain oil production levels; the impact of any such actions; the lack of a resolution to the war in Ukraine and its impact on certain commodity markets; lack of transportation and storage capacity as a result of oversupply, government and regulations; lack of availability of drilling and production equipment and services; adverse weather events, including tropical storms, hurricanes and winter storms; cybersecurity threats; sustained inflation and the impact of central bank policy in response thereto; environmental risks; failure to find, acquire or gain access to other discoveries and prospects or to successfully develop and produce from our current discoveries and prospects; geologic risk; drilling and other operating risks; well control risk; regulatory changes; the uncertainty inherent in estimating reserves and in projecting future rates of production; cash flow and access to capital; the timing of development expenditures; potential adverse reactions or competitive responses to our acquisitions and other transactions; the possibility that the anticipated benefits of our acquisitions are not realized when expected or at all, including as a result of the impact of, or problems arising from, the integration of acquired assets and operations, and the other risks discussed in Part I, Item 1A. "Risk Factors" of Talos Energy Inc.'s Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 25, 2022, Part II, Item 1A. "Risk Factors" of Talos Energy Inc.'s Quarterly Report on Form 10-Q for the period ended March 31, 2022, filed with the SEC on May 5, 2022 and Part II, Item 1A. "Risk Factors" of Talos Energy Inc's Quarterly Report on Form 10-Q for the period ended June 30, 2022, to be filed with the SEC subsequent to the issuance of this communication. Should one or more of the risks or uncertainties described herein occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this communication are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this communication.

Estimates for our future production volumes are based on assumptions of capital expenditure levels and the assumption that market demand and prices for oil and gas will continue at levels that allow for economic production of these products. The production, transportation, marketing and storage of oil and gas are subject to disruption due to transportation, processing and storage availability, mechanical failure, human error, hurricanes and numerous other factors. Our estimates are based on certain other assumptions, such as well performance, which may vary significantly from those assumed. Therefore, we can give no assurance that our future production volumes will be as estimated.

RESERVE INFORMATION

Reserve engineering is a process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions upward or downward of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling.

Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered. In addition, we use the term "cumulative gross unrisked resource" in this release, which is not a measure of "reserves" prepared in accordance with SEC guidelines or permitted to be included in SEC filings. These resource estimates are inherently more uncertain than estimates of reserves prepared in accordance with SEC guidelines.

 

Talos Energy Inc.

Condensed Consolidated Balance Sheets

(In thousands, except per share amounts)



June 30, 2022


December 31, 2021



(Unaudited)




ASSETS





Current assets:





Cash and cash equivalents

$

108,481


$

69,852


Accounts receivable:





Trade, net


244,883



173,241


Joint interest, net


25,875



28,165


Other, net


11,409



18,062


Assets from price risk management activities


3,686



967


Prepaid assets


76,907



48,042


Other current assets


4,244



1,674


Total current assets


475,485



340,003


Property and equipment:





Proved properties


5,413,489



5,232,479


Unproved properties, not subject to amortization


203,117



219,055


Other property and equipment


30,154



29,091


Total property and equipment


5,646,760



5,480,625


Accumulated depreciation, depletion and amortization


(3,294,797)



(3,092,043)


Total property and equipment, net


2,351,963



2,388,582


Other long-term assets:





Assets from price risk management activities


3,051



2,770


Equity method investments


1,131




Other well equipment inventory


17,583



17,449


Operating lease assets


5,587



5,714


Other assets


8,300



12,297


Total assets

$

2,863,100


$

2,766,815


LIABILITIES AND STOCKHOLDERSʼ EQUITY





Current liabilities:





Accounts payable

$

102,390


$

85,815


Accrued liabilities


152,401



130,459


Accrued royalties


80,254



59,037


Current portion of long-term debt




6,060


Current portion of asset retirement obligations


55,542



60,311


Liabilities from price risk management activities


239,022



186,526


Accrued interest payable


37,084



37,542


Current portion of operating lease liabilities


1,846



1,715


Other current liabilities


32,797



33,061


Total current liabilities


701,336



600,526


Long-term liabilities:





Long-term debt, net of discount and deferred financing costs


788,468



956,667


Asset retirement obligations


396,889



373,695


Liabilities from price risk management activities


22,434



13,938


Operating lease liabilities


15,367



16,330


Other long-term liabilities


41,096



45,006


Total liabilities


1,965,590



2,006,162


Commitments and contingencies (Note 10)





Stockholdersʼ equity:





Preferred stock, $0.01 par value; 30,000,000 shares authorized and
  no shares issued or outstanding as of June 30, 2022 and December 31, 2021





Common stock $0.01 par value; 270,000,000 shares authorized;
  82,541,345 and 81,881,477 shares issued and outstanding as of
  June 30, 2022 and December 31, 2021, respectively


825



819


Additional paid-in capital


1,684,949



1,676,798


Accumulated deficit


(788,264)



(916,964)


Total stockholdersʼ equity


897,510



760,653


Total liabilities and stockholdersʼ equity

$

2,863,100


$

2,766,815


 

Talos Energy Inc.

Condensed Consolidated Statements of Operations

(In thousands, except per common share amounts)



Three Months Ended June 30,


Six Months Ended June 30,



2022


2021


2022


2021


Revenues:









Oil

$

429,329


$

267,990


$

783,215


$

497,551


Natural gas


70,406



26,131



113,387



54,365


NGL


19,350



9,647



36,049



18,760


Total revenues


519,085



303,768



932,651



570,676


Operating expenses:









Lease operating expense


87,582



72,013



147,396



138,641


Production taxes


864



953



1,715



1,775


Depreciation, depletion and amortization


104,511



99,841



202,851



201,498


Accretion expense


14,844



15,457



29,221



30,442


General and administrative expense


22,925



19,377



45,453



38,566


Other operating expense


12,372



2,783



12,508



1,783


Total operating expenses


243,098



210,424



439,144



412,705


Operating income


275,987



93,344



493,507



157,971


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)


Net income (loss) before income taxes


197,748



(125,284)



130,835



(246,191)


Income tax expense


(2,607)



(498)



(2,135)



(1,082)


Net income (loss)

$

195,141


$

(125,782)


$

128,700


$

(247,273)











Net income (loss) per common share:









Basic

$

2.36


$

(1.54)


$

1.56


$

(3.03)


Diluted

$

2.33


$

(1.54)


$

1.55


$

(3.03)


Weighted average common shares outstanding:









Basic


82,566



81,823



82,320



81,630


Diluted


83,665



81,823



83,247



81,630


 

Talos Energy Inc.

Condensed Consolidated Statements of Cash Flows

(In thousands)



Six Months Ended June 30,



2022


2021


Cash flows from operating activities:





Net income (loss)

$

128,700


$

(247,273)


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





Depreciation, depletion, amortization and accretion expense


232,072



231,940


Amortization of deferred financing costs and original issue discount


6,952



6,934


Equity-based compensation expense


7,367



5,681


Price risk management activities expense


345,313



324,125


Net cash paid on settled derivative instruments


(287,321)



(117,618)


Equity method investment income


(13,608)




Loss on extinguishment of debt




13,225


Settlement of asset retirement obligations


(39,768)



(36,329)


Loss (gain) on sale of assets


390



(853)


Changes in operating assets and liabilities:





Accounts receivable


(57,394)



(12,633)


Other current assets


(31,435)



(19,409)


Accounts payable


23,360



3,776


Other current liabilities


33,284



48,597


Other non-current assets and liabilities, net


6,453



(1,069)


Net cash provided by operating activities


354,365



199,094


Cash flows from investing activities:












Exploration, development and other capital expenditures


(128,082)



(125,846)


Cash paid for acquisitions, net of cash acquired


(3,500)



(5,399)


Proceeds from sale of property and equipment, net


1,597



4,612


Contributions to equity method investees


(2,250)




Proceeds from sale of equity method investment


15,000




Net cash used in investing activities


(117,235)



(126,633)


Cash flows from financing activities:





Issuance of senior notes




600,500


Redemption of senior notes and other long-term debt


(6,060)



(356,803)


Proceeds from Bank Credit Facility


35,000




Repayment of Bank Credit Facility


(210,000)



(240,000)


Deferred financing costs


(129)



(25,981)


Other deferred payments




(5,575)


Payments of finance lease


(12,836)



(10,361)


Employee stock awards tax withholdings


(4,476)



(3,120)


Net cash used in financing activities


(198,501)



(41,340)







Net increase in cash and cash equivalents


38,629



31,121


Cash and cash equivalents:





Balance, beginning of period


69,852



34,233


Balance, end of period

$

108,481


$

65,354







Supplemental non-cash transactions:





Capital expenditures included in accounts payable and accrued liabilities

$

47,354


$

95,724


Supplemental cash flow information:





Interest paid, net of amounts capitalized

$

47,570


$

19,006


SUPPLEMENTAL NON-GAAP INFORMATION

Certain financial information included in our financial results are not measures of financial performance recognized by accounting principles generally accepted in the United States, or GAAP. These non-GAAP financial measures are "Adjusted Net Income (Loss)," "Adjusted Earnings per Share," "EBITDA," "Adjusted EBITDA," "Adjusted EBITDA excluding hedges," "Adjusted EBITDA Margin," "Adjusted EBITDA Margin excluding hedges," "Free Cash Flow," "Net Debt," "LTM Adjusted EBITDA," "Credit Facility LTM Adjusted EBITDA", "Net Debt to Credit Facility LTM Adjusted EBITDA" and "Leverage". These disclosures may not be viewed as a substitute for results determined in accordance with GAAP and are not necessarily comparable to non-GAAP measures which may be reported by other companies.

Reconciliation of Net Income (Loss) to EBITDA and Adjusted EBITDA

"EBITDA" and "Adjusted EBITDA" are 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.

We also present Adjusted EBITDA excluding hedges and as a percentage of revenue to further analyze our business, which are outlined below:

Adjusted EBITDA Margin. EBITDA divided by Revenue, as a percentage. It is also defined as Adjusted EBITDA divided by the total production volume, expressed in Boe, in the period, and described as dollar per Boe. We believe the presentation of Adjusted EBITDA margin is important to provide management and investors with information about how much we retain in Adjusted EBITDA terms as compared to the revenue we generate and how much per barrel we generate after accounting for certain operational and corporate costs.

The following table presents a reconciliation of the GAAP financial measure of net income (loss) to EBITDA, Adjusted EBITDA, Adjusted EBITDA excluding hedges, Adjusted EBITDA Margin and Adjusted EBITDA Margin excluding hedges for each of the periods indicated (in thousands, except for Boe, $/Boe and percentage data):


Three Months Ended


($ thousands, except per Boe)

June 30, 2022


March 31,
2022


December 31,
2021


September 30,
2021


Reconciliation of net income (loss) to Adjusted
EBITDA:









Net Income (loss)

$

195,141


$

(66,441)


$

81,012


$

(16,691)


Interest expense


30,776



31,490



33,102



32,390


Income tax expense (benefit)


2,607



(472)



(2,353)



(364)


Depreciation, depletion and amortization


104,511



98,340



105,900



88,596


Accretion expense


14,844



14,377



14,019



13,668


EBITDA


347,879



77,294



231,680



117,599


Write-down of oil and natural gas properties






18,123




Transaction and other (income) expenses(1)(4)(5)


(5,010)



(26,532)



19,710



1,370


Derivative fair value loss(2)


64,094



281,219



13,473



81,479


Net cash payments on settled derivative
   instruments(2)


(160,235)



(127,086)



(100,912)



(71,634)


Non-cash write-down of other well equipment
  inventory






5,606




Non-cash equity-based compensation expense


4,049



3,318



2,698



2,613


Adjusted EBITDA


250,777



208,213



190,378



131,427


Add: Net cash payments on settled derivative
   instruments(2)


160,235



127,086



100,912



71,634


Adjusted EBITDA excluding hedges

$

411,012


$

335,299


$

291,290


$

203,061


Production and Revenue:









Boe(3)


5,953



5,687



6,320



5,200


Revenue - Operations


519,085



413,566



382,955



290,909


Adjusted EBITDA margin and Adjusted EBITDA
  excl hedges margin:









Adjusted EBITDA divided by Revenue -
  Operations (%)


48

%


50

%


50

%


45

%

Adjusted EBITDA per Boe(3)

$

42.13


$

36.61


$

30.12


$

25.27


Adjusted EBITDA excl hedges divided by Revenue
- Operations (%)


79

%


81

%


76

%


70

%

Adjusted EBITDA excl hedges per Boe(3)

$

69.04


$

58.96


$

46.09


$

39.05


(1)

Includes transaction-related expenses and other miscellaneous income and expenses.

(2)

The adjustments for the derivative fair value (gain) loss and net cash receipts (payments) on settled derivative instruments have the effect of adjusting net income (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)

One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

(4)

Includes $27.5 million gain as a result of the settlement agreement to resolve previously pending litigation that was filed in October 2017 for the three months ended March 31, 2022.

(5)

Includes a $13.9 million gain on partial sale of our investment in Bayou Bend for the three months ended June 30, 2022.

Reconciliation of Adjusted EBITDA to Free Cash Flow
"Free Cash Flow" before changes in working capital provides management and investors with (i) important supplemental indicators of the operational performance of our business, (ii) additional criteria for evaluating our performance relative to our peers and (iii) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. Free Cash Flow has limitations as an analytical tool 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:

Capital Expenditures and Plugging & Abandonment. Actual capital expenditures and plugging & abandonment recognized in the quarter, inclusive of accruals.

Interest Expense. Actual interest expense per the income statement.

Talos did not pay any cash taxes in the period, therefore cash taxes have no impact to the reported Free Cash Flow before changes in working capital number.

($ thousands, except per share amounts)

Three Months Ended
June 30, 2022


Reconciliation of Adjusted EBITDA to Free Cash Flow (before changes in working capital)



Adjusted EBITDA

$

250,777


Less: Capital Expenditures and Plugging & Abandonment


(85,927)


Less: Interest Expense


(30,776)


Free Cash Flow (before changes in working capital)

$

134,074


Reconciliation of Net Income (Loss) to Adjusted Net Income (Loss) and Adjusted Earnings per Share
"Adjusted Net Income (Loss)" and "Adjusted Earnings per Share" are to provide management and investors with (i) important supplemental indicators of the operational performance of our business, (ii) additional criteria for evaluating our performance relative to our peers and (iii) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. Adjusted Net Income (Loss) and Adjusted Earnings per Share have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP or as an alternative to net income (loss), operating income (loss), earnings per share or any other measure of financial performance presented in accordance with GAAP.

Adjusted Net Income (Loss). Net income (loss) plus accretion expense, transaction related costs, derivative fair value (gain) loss, net cash receipts (payments) on settled derivative instruments and non-cash equity-based compensation expense.

Adjusted Earnings per Share. Adjusted Net Income (Loss) divided by the number of common shares.

($ thousands, except per share amounts)

Three Months Ended
June 30, 2022


Reconciliation of Net Income to Adjusted Net Income:



Net Income

$

195,141


Transaction and other income(2)(3)


(5,010)


Derivative fair value loss(1)


64,094


Cash payments on settled derivative instruments(1)


(160,235)


Non-cash income tax expense


2,607


Non-cash equity-based compensation expense


4,049


Adjusted Net Income

$

100,646





Weighted average common shares outstanding at June 30, 2022:



Basic


82,566


Diluted


83,665





Net Income per common share:



Basic

$

2.36


Diluted

$

2.33





Adjusted Net Income per common share:



Basic

$

1.22


Diluted

$

1.20


(1)

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.

(2)

Includes transaction-related expenses and other miscellaneous income and expenses.

(3)

Includes a $13.9 million gain on partial disposal of our investment in Bayou Bend for the three months ended June 30, 2022.

Reconciliation of Total Debt to Net Debt and Net Debt to LTM Adjusted EBITDA and Credit Facility LTM Adjusted EBITDA
We believe the presentation of Net Debt, LTM Adjusted EBITDA, Credit Facility LTM Adjusted EBITDA, Net Debt to LTM Adjusted EBITDA and Net Debt to Credit Facility LTM Adjusted EBITDA is important to provide management and investors with additional important information to evaluate our business. These measures are widely used by investors and ratings agencies in the valuation, comparison, rating and investment recommendations of companies

Net Debt. Total Debt principal of the Company plus the finance lease balance minus cash and cash equivalents.

Net Debt to LTM Adjusted EBITDA. Net Debt divided by the LTM Adjusted EBITDA.

Net Debt to Credit Facility LTM Adjusted EBITDA. Net Debt divided by the Credit Facility LTM Adjusted EBITDA.

Reconciliation of Net Debt ($ thousands) at June 30, 2022:




12.00% Second-Priority Senior Secured Notes – due January 2026

$

650,000


Bank Credit Facility – matures November 2024


200,000


Finance lease


27,386


Total Debt


877,386


Less: Cash and cash equivalents


(108,481)


Net Debt

$

768,905






Calculation of LTM EBITDA:




Adjusted EBITDA for three months period ended September 30, 2021

$

131,427


Adjusted EBITDA for three months period ended December 31, 2021


190,378


Adjusted EBITDA for three months period ended March 31, 2022


208,213


Adjusted EBITDA for three months period ended June 30, 2022


250,777


LTM Adjusted EBITDA

$

780,795


Acquired Assets Adjusted EBITDA for pre-closing periods


---


Credit Facility LTM Adjusted EBITDA

$

780,795






Reconciliation of Net Debt to LTM Adjusted EBITDA:




Net Debt / LTM Adjusted EBITDA


1.0

x

Net Debt / Credit Facility LTM Adjusted EBITDA


1.0

x

The Adjusted EBITDA information included in this communication provides additional relevant information to our investors and creditors. Talos needs to comply with a financial covenant included in its Bank Credit Facility that requires it to maintain a Net Debt to Credit Facility LTM Adjusted EBITDA ratio, as determined in accordance with the Company's credit agreement, equal to or lower than 3.0x. For purposes of covenant compliance, Credit Facility LTM Adjusted EBITDA, with certain adjustments, is calculated as the sum of quarterly Adjusted EBITDA for the 12-month period ended on that quarter, inclusive of revenue less direct operating expenditures of the Acquired Assets for periods prior to closing of the Transaction.

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SOURCE Talos Energy