Talos Energy Announces First Quarter 2021 Results

HOUSTON, May 5, 2021 /PRNewswire/ — Talos Energy Inc. («Talos» or the «Company») (NYSE: TALO) today announced its operational and financial…

HOUSTON, May 5, 2021 /PRNewswire/ — Talos Energy Inc. («Talos» or the «Company») (NYSE: TALO) today announced its operational and financial results for the first quarter of 2021.

Key Highlights:

  • Successful high-impact sub-salt Miocene deepwater exploration discovery at Puma West, located approximately 15 miles from the prolific Mad Dog field.
  • Successful multi-well drilling program at Green Canyon 18 concluded. Rig mobilizing to Pompano to begin multi-well campaign.
  • Completed two high-yield transactions that increased liquidity and materially extended the Company’s maturity profile.
  • Record production of 66.1 thousand barrels of oil equivalent per day («MBoe/d») net (68% oil, 76% liquids). This is the Company’s highest quarterly production since inception.
  • Net Loss of $121.5 million, inclusive of $137.5 million in commodity hedging losses, or $1.49 loss per diluted share, and Adjusted Net Loss(1) of $27.3 million, inclusive of $48.4 million of realized hedging losses, or $0.34 adjusted loss per diluted share.
  • Adjusted EBITDA(1) of $136.6 million, or approximately $23 per Boe. Adjusted EBITDA excluding hedges of $185.0 million, or over $31 per Boe.
  • Capital expenditures, inclusive of plugging and abandonment costs, of $71.2 million.
  • Free Cash Flow(1) of $31.3 million before changes in working capital, reflecting the quarter’s strong operational performance.

President and Chief Executive Officer Timothy S. Duncan commented: «The first quarter of 2021 was a busy period for Talos with multiple development and exploration projects underway. We achieved success across the board on those projects, ranging from in-field developments to a high-impact deepwater sub-salt discovery at Puma West. We believe this discovery builds momentum around our sub-salt Miocene portfolio in our Green Canyon and Mississippi Canyon core areas, where we are focused on accelerating significant value creation in the coming years through exploration. On the development and exploitation front, we look forward to drilling an additional well at Tornado to maximize our water flood project, as well as starting the Pompano platform rig program campaign, which should deliver high-value projects in the second half of 2021 and into 2022.»

Duncan continued: «It was also a strong quarter financially with over $31 million of free cash flow generation, despite hedge settlements, winter weather events and planned downtime at Pompano. Thematically, the results of the quarter illustrate what’s possible with our high-quality asset base, diverse project inventory and competitive cost structure, all of which allowed us to generate over $31 per Boe of Adjusted EBITDA margin before hedge settlements. With our oil-weighted asset base we expect this high margin trend to continue and we believe our balanced capital program will generate solid returns moving forward.»

RECENT DEVELOPMENTS AND OPERATIONS UPDATE

Puma West: The Puma West deepwater sub-salt discovery was drilled on Green Canyon Block 821 to a total depth of 23,530 feet. The well encountered high quality Miocene pay with similar rock and fluid properties as other significant discoveries in the prolific sub-salt Miocene basin. bp is the operator and holds a 50.0% working interest. Talos and Chevron each hold a 25.0% working interest. Talos holds over 17,000 acres in the surrounding area. Additionally, the Company also holds an inventory of sub-salt Miocene prospects throughout its Green Canyon and Mississippi Canyon core areas and is active in exploration business development activities in similar high-impact opportunities.

Platform Rig Program: Talos recently completed a year-long redevelopment campaign in the Green Canyon 18 field. The project included four new completions, which added net production of over 7.5 – 8.0 MBoe/d, significantly lowering the production cost per barrel in the asset and enhancing its margins. The drilling program also generated several future asset management opportunities that the Company plans to execute in due course. The platform rig will next move to the Company’s Pompano platform to begin a multi-well development and exploitation campaign through the remainder of 2021 and into 2022.

Zama Unitization: Talos continues to work to finalize unitization beyond the March 2021 deadline previously established by Mexico’s Ministry of Energy («SENER»). A final unitization agreement will address operatorship, initial participating interest splits and the mechanism to re-determine participating interest splits in the future, among other key topics. Talos is continuing to finalize its field development plans in parallel and is prepared to rapidly advance the project to Final Investment Decision («FID») following the conclusion of unitization.

Tornado Attic well: Signed a contract with the Seadrill West Neptune deepwater rig to drill the Tornado Attic well to build on the water flood project in the Tornado field. The rig is expected to be on location in the first half of May with drilling activities commencing soon thereafter. Production impact from this well is expected sometime in the third quarter of 2021. This additional infill well will provide additional production and have pressure support from the previously completed deepwater intra-well, or «dump flood» water flood project, which was a first of its kind in the deepwater Gulf of Mexico.

Spring Borrowing Base Redetermination: Talos has begun working on its semi-annual redetermination, including seeking a material extension of its credit facility maturity. Finalization and announcement is expected in the second quarter of 2021.

Environmental, Social and Governance: Talos renamed the Safety Committee of the Board of Directors to the Safety, Sustainability and Corporate Responsibility Committee to better reflect the Company’s expanded environment stewardship initiatives to lower emissions from operations, explore investments in evolving offshore carbon reduction markets and reinforce engagement within local communities. Talos expects to deliver its next annual ESG report in the coming months. The Company also announced the nomination of Paula Glover to the Board of Directors.

FIRST QUARTER 2021 RESULTS

Key Financial Highlights:



Three Months Ended March 31, 2021


Period results ($ million):





Total Revenues and other


$

267.9


Net Loss


$

(121.5)


Net Loss per diluted share


$

(1.49)


Adjusted Net Loss


$

(27.3)


Adjusted Net Loss per diluted share


$

(0.34)


Adjusted EBITDA


$

136.6


Adjusted EBITDA excluding hedges


$

185.0


Adjusted EBITDA Margin:





Adjusted EBITDA per Boe


$

22.96


Adjusted EBITDA excluding hedges per Boe


$

31.10


Production

Production in the first quarter of 2021 averaged 66.1 MBoe/d, the Company’s highest quarterly production since inception. This production level was achieved despite the unplanned downtime related to significant winter storms as well as planned downtime at the Pompano facility for preventative maintenance and topsides preparation to host the third-party Praline well.

In addition to planned Praline tieback downtime at Pompano, the Company expects to mobilize the platform rig from Green Canyon 18 to Pompano. As a result, significant downtime is expected at both platforms in the second quarter of 2021.



Three Months Ended

March 31, 2021


Average net daily production volumes





Oil (MBbl/d)



45.0


Natural Gas (MMcf/d)



94.5


NGL (MBbl/d)



5.4


Total average net daily (MBoe/d)



66.1














Three Months Ended March 31, 2021




Production



% Oil



% Liquids



% Operated


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

















Green Canyon Area



18.3




82

%



88

%



97

%

Mississippi Canyon Area



29.6




78

%



86

%



47

%

Shelf and Gulf Coast



18.2




39

%



49

%



50

%

Total average net daily (MBoe/d)



66.1




68

%



76

%



62

%

Capital Expenditures



Three Months Ended

March 31, 2021


Capital Expenditures





U.S. Drilling & Completions


$

38.2


Mexico Appraisal & Exploration



0.6


Asset Management



6.1


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



16.2


Total Capital Expenditures



61.1


Plugging & Abandonment



10.1


Total Capital Expenditures and Plugging & Abandonment


$

71.2


Liquidity and Leverage

At quarter-end, the Company had approximately $546.4 million of liquidity, nearing all-time highs, with $495.0 million undrawn on its credit facility and approximately $65.0 million in cash, less approximately $13.6 in outstanding letters of credit. The Company expects to continue its solid operational performance, aimed at generating significant free cash flow in 2021 and beyond. Excess free cash flow is generally expected to be used to pay down the Company’s revolving credit facility, thus further enhancing liquidity in the future.

On March 31, 2021, Talos had $1,178.0 million in total debt, inclusive of $57.0 million related to the HP-I finance lease. Net Debt was $1,113.0 million. Net Debt to Credit Facility LTM Adjusted EBITDA, as determined in accordance with the Company’s credit agreement, was 2.6x.

As an additional measure of the performance of the Company’s assets during the quarter, by annualizing the Company’s first quarter Adjusted EBITDA excluding hedges, Talos’s net leverage ratio would have been 1.5x.

Footnotes:

(1)

Adjusted Net Loss, Adjusted Loss per Share, Adjusted EBITDA, Adjusted EBITDA margin, Credit Facility LTM Adjusted EBITDA, Net Debt to Credit Facility LTM Adjusted EBITDA, Free Cash Flow and PV-10 are non-GAAP financial measures. See «Supplemental Non-GAAP Information» below for additional detail and reconciliations of GAAP to non-GAAP measures.

HEDGES

The following table reflects contracted volumes and weighted average prices the Company will receive under the terms of its derivative contracts as of May 4, 2021 and includes contracts entered into after March 31, 2021:



Instrument Type


Avg. Daily Volume


Weighted Avg. Swap Price


Weighted Avg. Put Price


Weighted Avg. Call Price

Crude – WTI




(Bbls)


(Per Bbl)


(Per Bbl)


(Per Bbl)

  April – December 2021


Swaps


25,098


$45.33



  April – December 2021


Collars


1,000



$30.00


$40.00

  January – December 2022


Swaps


18,849


$48.41



  January – June 2023


Swaps


3,000


$54.07














Crude – LLS











  April – December 2021


Swaps


3,335


$41.06














Natural Gas – HH NYMEX




(MMBtu)


(Per MMBtu)


(Per MMBtu)


(Per MMBtu)

  April – December 2021


Swaps


55,724


$2.53



  April – December 2021


Collars


5,000



$2.50


$3.10

  January – December 2022


Swaps


32,641


$2.61



  January – June 2023


Swaps


5,000


$2.61



CONFERENCE CALL AND WEBCAST INFORMATION

Talos will host a conference call, which will be broadcast live over the internet, on Thursday, May 6, 2021 at 11:00 AM Eastern Time (10:00 AM Central Time). Listeners can access the conference call live over the Internet through a webcast link on the Company’s website at: https://www.talosenergy.com/investors. Alternatively, the conference call can be accessed by dialing (888) 428-7458 (U.S. and Canada toll-free) or (862) 298-0702 (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 for seven days and can be accessed by dialing (888) 539-4649 and using access code 155603.

ABOUT TALOS ENERGY

Talos Energy (NYSE: TALO) is a technically driven independent exploration and production company focused on safely and efficiently maximizing cash flows and long-term value through its operations, currently in the United States Gulf of Mexico and offshore Mexico. As one of the U.S. Gulf of Mexico’s largest public independent producers, we leverage decades of geology, geophysics and offshore operations expertise towards the acquisition, exploration, exploitation and development of assets in key geological trends that are present in many offshore basins around the world. Our activities in offshore Mexico provide high impact exploration opportunities in an oil rich emerging basin. 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 «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, including the sharp decline in oil prices beginning in March 2020, the impact of the coronavirus disease 2019 («COVID-19») 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 the Organization of Petroleum Exporting Countries («OPEC») and non-OPEC countries, such as Saudi Arabia and Russia, to set and maintain oil production levels and the impact of any such actions, lack of transportation and storage capacity as a result of oversupply, government regulations and actions or other factors, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, 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, the possibility that the anticipated benefits of recent acquisitions are not realized when expected or at all, including as a result of the impact of, or problems arising from, the integration of such acquisitions, and other factors that may affect our future results and business, generally, including those discussed under the heading «Risk Factors» in our Annual Report on Form 10-K for the year ended December 31, 2020, filed with the SEC on March 11, 2021 and our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2021, to be filed with the SEC subsequent to the issuance of this communication.

Should one or more of these risks 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, 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, 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.

CAUTIONARY NOTE TO INVESTORS

The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC’s definitions for such terms. In this communication, the Company uses certain broader terms such as «contingent resources» and «2C resources» that the SEC’s guidelines strictly prohibit the Company from including in filings with the SEC. These types of estimates do not represent, and are not intended to represent, any category of reserves based on SEC definitions, are by their nature more speculative than estimates of proved, probable and possible reserves and do not constitute «reserves» within the meaning of the SEC’s rules. These estimates are subject to greater uncertainties, and accordingly, are subject to a substantially greater risk of actually being realized. Investors are urged to consider closely the disclosures and risk factors in the reports the Company files with the SEC.

 

Talos Energy Inc.

Condensed Consolidated Balance Sheets

(In thousands, except per share amounts)










March 31, 2021



December 31, 2020




(Unaudited)






ASSETS









Current assets:









Cash and cash equivalents


$

64,979



$

34,233


Accounts receivable









Trade, net



135,415




106,220


Joint interest, net



42,020




50,471


Other



13,371




18,448


Assets from price risk management activities



1,720




6,876


Prepaid assets



32,733




29,285


Other current assets



1,761




1,859


Total current assets



291,999




247,392


Property and equipment:









Proved properties



4,996,802




4,945,550


Unproved properties, not subject to amortization



266,321




254,994


Other property and equipment



33,086




32,853


Total property and equipment



5,296,209




5,233,397


Accumulated depreciation, depletion and amortization



(2,798,885)




(2,697,228)


Total property and equipment, net



2,497,324




2,536,169


Other long-term assets:









Assets from price risk management activities



2,123




945


Other well equipment inventory



20,069




18,927


Operating lease assets



6,722




6,855


Other assets



21,457




24,258


Total assets


$

2,839,694



$

2,834,546


LIABILITIES AND STOCKHOLDERSʼ EQUITY









Current liabilities:









Accounts payable


$

72,770



$

104,864


Accrued liabilities



140,552




163,379


Accrued royalties



42,741




27,903


Current portion of asset retirement obligations



45,478




49,921


Liabilities from price risk management activities



133,167




66,010


Accrued interest payable



20,410




9,509


Current portion of operating lease liabilities



1,927




1,793


Other current liabilities



25,192




24,155


Total current liabilities



482,237




447,534


Long-term liabilities:









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



1,049,365




985,512


Asset retirement obligations



406,690




392,348


Liabilities from price risk management activities



27,617




9,625


Operating lease liabilities



18,015




18,554


Other long-term liabilities



48,616




54,372


Total liabilities



2,032,540




1,907,945


Commitments and contingencies (Note 11)









Stockholdersʼ Equity:









Preferred stock, $0.01 par value; 30,000,000 shares authorized and no shares issued or outstanding as of March 31, 2021 and December 31, 2020







Common stock $0.01 par value; 270,000,000 shares authorized; 81,707,214 and 81,279,989 shares issued and outstanding as of March 31, 2021 and December 31, 2020, respectively



817




813


Additional paid-in capital



1,661,840




1,659,800


Accumulated deficit



(855,503)




(734,012)


Total stockholdersʼ equity



807,154




926,601


Total liabilities and stockholdersʼ equity


$

2,839,694



$

2,834,546


 

Talos Energy Inc.

Condensed Consolidated Statements of Operations

(In thousands, except per common share amounts)







Three Months Ended March 31,



2021


2020

Revenues and other:









Oil


$

229,561



$

166,624


Natural gas



28,234




11,898


NGL



9,113




4,301


Other



1,000




4,941


Total revenues and other



267,908




187,764


Operating expenses:









Lease operating expense



66,628




58,241


Production taxes



822




249


Depreciation, depletion and amortization



101,657




93,543


Write-down of oil and natural gas properties






57


Accretion expense



14,985




12,417


General and administrative expense



19,189




27,469


Total operating expenses



203,281




191,976


Operating income (expense)



64,627




(4,212)


Interest expense



(34,076)




(25,850)


Price risk management activities income (expense)



(137,508)




243,217


Other expense



(13,950)




(146)


Net income (loss) before income taxes



(120,907)




213,009


Income tax expense



(584)




(55,260)


Net income (loss)


$

(121,491)



$

157,749











Net income (loss) per common share:









Basic


$

(1.49)



$

2.71


Diluted


$

(1.49)



$

2.69


Weighted average common shares outstanding:









Basic



81,435




58,240


Diluted



81,435




58,572


 

Talos Energy Inc.

Condensed Consolidated Statements of Cash Flows

(In thousands)







Three Months Ended March 31,



2021


2020

Cash flows from operating activities:









Net income (loss)


$

(121,491)



$

157,749


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









Depreciation, depletion, amortization and accretion expense



116,642




105,960


Write-down of oil and natural gas properties and other well inventory






190


Amortization of deferred financing costs and original issue discount



3,142




1,466


Equity based compensation, net of amounts capitalized



2,664




1,627


Price risk management activities expense (income)



137,508




(243,217)


Net cash received (paid) on settled derivative instruments



(48,381)




36,460


Loss on extinguishment of debt



13,225





Settlement of asset retirement obligations



(10,120)




(6,302)


Gain on sale of assets



(319)





Changes in operating assets and liabilities:









Accounts receivable



(17,108)




(11,578)


Other current assets



(3,350)




18,318


Accounts payable



(10,978)




(18,547)


Other current liabilities



5,328




13,337


Other non-current assets and liabilities, net



194




54,769


Net cash provided by operating activities



66,956




110,232


Cash flows from investing activities:









Exploration, development and other capital expenditures



(64,745)




(83,588)


Cash paid for acquisitions, net of cash acquired



(8,322)




(293,095)


Proceeds from sale of oil and gas properties



330





Net cash used in investing activities



(72,737)




(376,683)


Cash flows from financing activities:









Issuance of Senior Notes



600,500





Redemption of Senior Notes and other long-term debt



(356,803)





Proceeds from Bank Credit Facility






300,000


Repayment of Bank Credit Facility



(175,000)





Deferred financing costs



(19,387)




(1,285)


Other deferred payments



(5,575)




(7,575)


Payments of finance lease



(5,058)




(4,049)


Employee stock transactions



(2,150)




(710)


Net cash provided by financing activities



36,527




286,381











Net increase in cash, cash equivalents and restricted cash



30,746




19,930


Cash, cash equivalents and restricted cash:









Balance, beginning of period



34,233




87,022


Balance, end of period


$

64,979



$

106,952











Supplemental Non-Cash Transactions:









Capital expenditures included in accounts payable and accrued liabilities


$

65,755



$

66,712


Supplemental Cash Flow Information:









Interest paid, net of amounts capitalized


$

13,712



$

4,906


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,» «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» and «Net Debt to Credit Facility LTM Adjusted EBITDA.» 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 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, loss on debt extinguishment, transaction related costs, derivative fair value (gain) loss, net cash receipts (payments) on settled derivatives, non-cash (gain) loss on sale of assets, 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)


March 31, 2021


December 31, 2020


September 30, 2020


June 30, 2020

Reconciliation of net loss to Adjusted EBITDA:

















Net loss


$

(121,491)



$

(430,743)



$

(52,000)



$

(140,611)


Interest expense



34,076




23,251




24,124




26,190


Income tax expense (benefit)



584




57,967




(28,252)




(49,392)


Depreciation, depletion and amortization



101,657




101,813




80,547




88,443


Accretion expense



14,985




11,993




11,537




13,794


EBITDA



29,811




(235,719)




35,956




(61,576)


Write-down of oil and natural gas properties






267,859








Transaction and non-recurring expenses



1,778




2,054




1,607




3,498


Derivative fair value loss(1)



137,508




66,968




19,882




68,682


Net cash receipts (payments) on settled derivative instruments(2)



(48,381)




2,376




19,030




86,039


(Gain) loss on extinguishment of debt



13,225




(18)




(174)




(1,470)


Non-cash write-down of other well equipment inventory






566








Non-cash equity-based compensation expense



2,664




2,348




2,347




2,347


Adjusted EBITDA



136,605




106,434




78,648




97,520


Net cash receipts (payments) on settled derivative instruments(1)



48,381




(2,376)




(19,030)




(86,039)


Adjusted EBITDA excluding hedges


$

184,986



$

104,058



$

59,618



$

11,481


Production and Revenue:

















Boe(2)



5,949




5,467




4,470




4,775


Revenue – Operations



266,908




172,602




132,936




87,575


Adjusted EBITDA margin and Adjusted EBITDA excl hedges margin:

















Adjusted EBITDA divided by Revenue – Operations (%)



51

%



62

%



59

%



111

%

Adjusted EBITDA per Boe(2)


$

22.96



$

19.47



$

17.59



$

20.42


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



69

%



60

%



45

%



13

%

Adjusted EBITDA excl hedges per Boe(2)


$

31.10



$

19.03



$

13.34



$

2.40




(1)

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 a cash basis during the period the derivatives settled.

(2)

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.

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

March 31, 2021

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





Adjusted EBITDA


$

136,605


Less: Capital Expenditures and Plugging & Abandonment



(71,223)


Less: Interest Expense



(34,076)


Free Cash Flow (before changes in working capital)


$

31,306


Reconciliation of Net Income (Loss) to Adjusted Net Income and Adjusted Earnings per Share

«Adjusted Net Income» 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 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. 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 divided by the number of common shares.

 ($ thousands, except per share amounts)


Three Months Ended March 31, 2021

Reconciliation of Net Loss to Adjusted Net Loss:





Net Loss


$

(121,491)


Write-down of oil and natural gas properties




Transaction related costs and non-recurring expenses



1,778


Derivative fair value loss(1)



137,508


Net cash payments on settled derivative instruments(1)



(48,381)


Non-cash income tax expense



584


Non-cash equity-based compensation expense



2,664


Adjusted Net Loss


$

(27,338)







Weighted average common shares outstanding at March 31, 2021:





Basic



81,435


Diluted



81,435







Net Loss per common share:





Basic


$

(1.49)


Diluted


$

(1.49)







Adjusted Net Loss per common share:





Basic


$

(0.34)


Diluted


$

(0.34)




(1)

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 Net Income on a cash basis during the period the derivatives settled.

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.

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.

($ thousands)



As of

March 31, 2021


Reconciliation of Net Debt:





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


$

650,000


7.50% Senior Notes – due May 2022



6,060


Bank Credit Facility – matures May 2022



465,000


Finance lease



56,968


Total Debt



1,178,028


Less: Cash and cash equivalent



(64,979)


Net Debt


$

1,113,049







Calculation of LTM EBITDA:





Adjusted EBITDA for three months period ended June 30, 2020


$

97,520


Adjusted EBITDA for three months period ended September 30, 2020



78,648


Adjusted EBITDA for three months period ended December 31, 2020



106,434


Adjusted EBITDA for three months period ended March 31, 2021



136,605


LTM Adjusted EBITDA


$

419,207


Acquired Assets Adjusted EBITDA for pre-closing periods



2,323


Credit Facility LTM Adjusted EBITDA


$

421,530







Reconciliation of Net Debt to LTM Adjusted EBITDA:





Net Debt / LTM Adjusted EBITDA



2.7


Net Debt / Credit Facility LTM Adjusted EBITDA



2.6


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