Talos Energy Announces Fourth Quarter And Full Year 2019 Financial And Operational Results And Reduction Of 2020 Spending Guidance

Talos Energy Announces Fourth Quarter And Full Year 2019 Financial And Operational Results And Reduction Of 2020 Spending Guidance

PR Newswire

HOUSTON, March 11, 2020

HOUSTON, March 11, 2020 /PRNewswire/ -- Talos Energy Inc. ("Talos," or the "Company") (NYSE: TALO) today announced its financial and operational results for the fourth quarter of 2019 and provided an operations update. Additionally, in response to recent commodity price trends, the Company will reduce its previously announced 2020 spending guidance by more than $125 million. Inclusive these reductions, Talos expects to remain free cash flow positive for 2020 with average WTI prices of $30 per barrel or higher. Specific details of the revised 2020 guidance will be disclosed in the coming weeks.

Key fourth quarter of 2019 highlights:

 

(1)

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

President and Chief Executive Officer Timothy S. Duncan commented: "We exited 2019 with another consecutive quarter generating significant free cash flow and adjusted earnings per share. Talos also exited the year with one of the lowest leverage ratios in our sector, with a 1.2x Net Debt to LTM Adjusted EBITDA, and high levels of liquidity.  Because of the oil-weighted and highly proved developed nature of our reserve base, significant value is sustained at various commodity prices, with additional upside from our probable reserves and our drilling portfolio. The results from the Claiborne #3 well, which just reached total depth, came in above pre-drill expectations and the well will be tied to existing infrastructure in order to be brought online by mid-year, demonstrating the upside potential of the assets we acquired."

Duncan continued, "With the closing of our recent acquisition, we are a larger, more diverse, and more resilient business with an improved combination of free cash flowing assets and a strong balance sheet. As we look into 2020 with the context of recent commodity price trends, we are re-examining costs throughout the organization in order to maintain our healthy leverage and liquidity metrics while also remaining free cash flow positive despite the challenging price environment. We have flexibility in our previously announced capital program for the year through our short-term rig contract structures, and will utilize this flexibility to reduce our discretionary capital investments. Talos's management team and employees have weathered this situation before. In order to be prepared for these situations, we always strive to maintain a conservative leverage position, high liquidity and a strong hedge book. We believe we are well-positioned to safely navigate current market conditions."

RECENT DEVELOPMENTS AND OPERATIONS UPDATE

Closing of Transformative Acquisition of U.S. Gulf of Mexico Portfolio
On February 28, 2020, Talos closed the acquisition of affiliates of ILX Holdings, among other entities (the "Acquired Assets," the "Acquisition," or the "Transaction"). After taking into account customary closing adjustments based on an effective date of July 1, 2019, total cash consideration paid by Talos was reduced from $385.0 million to $291.6 million as the Acquired Assets generated approximately $100.0 million of free cash flow in the eight-month period since the effective date, partially offset by a small working capital position acquired in conjunction with one of the assets. The cash consideration was funded primarily through the Company's revolving credit facility and cash on hand. In addition to the cash consideration, the Company delivered 110,000 shares of Series A Convertible Preferred Stock to certain of the sellers. The preferred shares are expected to automatically convert into 11.0 million common shares on March 30, 2020.

The Acquired Assets' average production in the fourth quarter of 2019, impacted by certain downtime, was 18.7 MBoe/d. Also included in the Transaction are over 700,000 gross acres, of which approximately 480,000 are primary term.

Borrowing Base Increase
On February 28, 2020, concurrently with the closing of the Acquisition, the borrowing base under Talos's credit facility was upsized from $950.0 million to $1,150.0 million.

Macro-Economic Developments and Revised 2020 Guidance
In response to recent trends in oil and gas commodity markets, Talos is reducing its previous 2020 capital and operating expenditure guidance. Among other items, Talos expects to utilize the flexibility provided by its short-term rig contracts to reduce its 2020 guidance by more than $125 million of capital and operating expense from the original budget. Talos expects that, following these changes, it will be able to generate positive free cash flow in 2020 with average WTI prices of $30.00 per barrel or above, inclusive of the Company's existing hedge position.

Talos plans to provide additional detail on the revised 2020 guidance in the coming weeks.

Drilling and Exploration Activities – U.S. Gulf of Mexico

Drilling and Exploration Activities – Mexico

 

 

FOURTH QUARTER 2019 RESULTS


Key Financial Highlights:


Period results ($ million):





Revenues(2)

$


233.2


Net Income

$


0.3


Earnings per share – diluted

$


0.01


Adjusted Net Income(1)

$


71.6


Adjusted Earnings per share – diluted(1)

$


1.31


Adjusted EBITDA(1)

$


155.8


Adjusted EBITDA excl. hedges(1)

$


157.4


Capital Expenditures (including Plug & Abandonment)

$


86.8


Adjusted EBITDA Margin(1):





Adjusted EBITDA (% of Revenue)



67

%

Adjusted EBITDA per Boe

$


31.37


Adjusted EBITDA excl. hedges (% of Revenue)



67

%

Adjusted EBITDA excl. hedges per Boe

$


 

31.70







Production, Realized Prices and Revenue
Production for the fourth quarter of 2019 was 5.0 MMBoe, with oil production accounting for 73% of the total. Oil price realizations, net of certain gathering, transportation, quality differentials and other costs, were $57.65 per barrel, representing an average for the quarter of $0.83 per barrel above the average WTI price over the same period.


Three Months Ended
December 31, 2019


Production volumes




Oil production volume (MBbls)


3,619


NGL production volume (MBbls)


313


Natural Gas production volume (MMcf)


6,205


Total production volume (MBoe)


4,966






Average net daily production volumes




Oil (MBbl/d)


39.3


NGL (MBbl/d)


3.4


Natural Gas (MMcf/d)


67.4


Total average net daily (MBoe/d)


54.0






Average realized prices (excluding hedges)(3)




Oil ($/Bbl)

$57.65


NGL ($/Bbl)

$14.62


Natural Gas ($/Mcf)

$2.18


Average Realized Price ($/Boe)

$47.90






Average NYMEX prices




WTI ($/Bbl)

$

56.82


Henry Hub ($/MMBtu)

$

2.40






Revenues ($ million)




Oil

$

208.6


NGL


4.6


Natural Gas


13.5


Revenue – Operations


226.7


Other revenue


6.5


Total revenue

$

233.2


 


Three Months Ended December 31, 2019



Production



% Oil



% Liquids



%
Operated


Average net daily production volumes by asset (MBoe/d)
















Green Canyon
















Phoenix Complex


19.2




80

%



86

%



100

%

Green Canyon 18


1.0




88

%



92

%



100

%

Green Canyon Area


20.2




80

%



86

%



100

%

















Mississippi Canyon
















Amberjack


2.1




90

%



93

%



99

%

Pompano


10.9




83

%



88

%



100

%

Ram Powell


4.7




63

%



74

%



100

%

Gunflint


1.0




79

%



84

%



0

%

Mississippi Canyon Area


18.7




79

%



85

%



94

%

















Shelf and Other Deepwater
















Shelf


13.3




54

%



61

%



92

%

Other deepwater


1.8




67

%



75

%



74

%

Shelf and Other Deepwater Area


15.1




56

%



62

%



90

%

















Total average net daily (MBoe/d)


54.0




73

%



79

%



95

%

Expenses
Total lease operating expenses ("LOE"), inclusive of Workover and Maintenance and insurance costs for the fourth quarter of 2019 were $59.2 million or $11.92/Boe. General and administrative expenses ("G&A") for the quarter were $17.5 million (excluding $1.8 million of stock-based compensation and $4.1 million of transaction-related expenses), or $3.52/Boe.


Three Months Ended
December 31, 2019



Per Boe


Lease Operating Expenses – includes workover & maintenance and insurance(4)

$

59.2



$

11.92


General & Administrative Expenses(4)(5)

$

17.5



$

3.52


Other Financial Metrics

Capital Expenditures & Asset Management Activities
Capital expenditures for the fourth quarter of 2019 were $86.8 million, inclusive of plugging & abandonment costs.


Three Months Ended
December 31, 2019


Capital Expenditures




U.S. Drilling & Completions

$

48.2


Mexico Appraisal & Exploration


(2.9)


Asset Management


8.8


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


11.8


Total Capital Expenditures

$

65.9


Plugging & Abandonment


20.9


Total Capital Expenditures and Plugging & Abandonment

$

86.8


Liquidity
As of December 31, 2019, the Company had approximately $826.5 million in total debt, inclusive of the HP-I finance lease. Already accounted for in this figure is the additional $35.0 million borrowed from the Company's credit facility to pay for the $31.8 million deposit related to the Acquisition, and the $5.0 million acquisition of certain leases from Venari Resources.

Talos had a liquidity position of $673.4 million as of year-end 2019, including $586.4 million available under the Bank Credit Facility and approximately $87.0 million of cash. LTM Adjusted EBITDA(1) for the twelve month period ended December 31, 2019 was $614.2 million. Net Debt to LTM Adjusted EBITDA(1) ratio was 1.2x.

PROVED RESERVES – AS OF DECEMBER 31, 2019

As of December 31, 2019, Talos had proved reserves of 141.7 MMBoe, with 82% comprised of liquids (75% crude oil and 7% NGLs).

The discovered resources associated with the Company's offshore Mexico assets are not yet qualified as proved reserves per Securities and Exchange Commission (the "SEC") rules and, therefore, are not included in any of the reserves information provided in this press release.

The standardized measure of proved reserves and the present value of the Company's proved reserves, discounted at 10% ("PV-10")(1), at year-end 2019 were $2.5 billion and $3.0 billion, respectively. Standardized measure and PV-10 include the present value of all asset retirement obligations associated with the relevant assets and properties. 

The following table summarizes our proved reserves at December 31, 2019:



Summary of Proved Reserves(7)




MBoe



Percent of
Total
Proved



Percent
Oil



Standardized
Measure



PV-10(6)


(in thousands)

(in thousands)

Proved Developed Producing




68,331




48%




79%







$

1,837,964

Proved Developed Non-Producing




29,648




21%




62%








378,244

Total Proved Developed




97,979




69%




74%








2,216,208

Proved Undeveloped




43,756




31%




79%








776,814

Total Proved




141,735











$

2,537,595



$

2,993,022

 



(6)

PV-10 is a non-GAAP financial measure and differs from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. See "Supplemental Non-GAAP Information" below for additional detail and reconciliations of GAAP to non-GAAP measures, including a reconciliation of PV-10 of our proved reserves to the standardized measure of discounted future net cash flows at December 31, 2019.



(7)

Proved oil, natural gas and NGL reserves attributable to our net interests in oil and natural gas properties were estimated and compiled for reporting purposes by our reservoir engineers and audited by Netherland, Sewell & Associates, Inc.

The following table summarizes our proved reserves by asset at December 31, 2019:



Estimated Proved Reserves(7)





Full Year 2019(7)




MBoe





% Oil





% Natural

Gas





% NGLs





% Proved

Developed





Net
Production

(MBoe)





%
Operated


United States Core Properties









































Phoenix Complex



55,381






80

%





14

%





6

%





51

%





5,980






100

%

Pompano



27,241






80

%





12

%





8

%





85

%





3,946






100

%

Ram Powell



12,795






55

%





32

%





13

%





100

%





2,039






100

%

Amberjack



8,581






92

%





6

%





2

%





100

%





784






99

%

United States Core Properties Subtotal



103,998






78

%





15

%





7

%





70

%





12,749

















































Other United States Properties(8)



37,737






69

%





27

%





4

%





66

%





6,207






82

%

Total United States



141,735






75

%





18

%





7

%





69

%





18,956










(8)

Other United States Properties includes Gulf of Mexico shelf and deepwater.

Pro Forma proved and probable reserves – as of December 31, 2019

Pro forma for the Acquired Assets, Talos proved reserves as of December 31, 2019, were 181.3 MMBoe, with 70% crude oil. The PV-10 at year-end 2019 was 3.6 billion.

The following table summarizes Talos's pro forma proved reserves at December 31, 2019 at SEC Pricing:



Summary of Pro Forma Proved Reserves(9) – SEC prices




MBoe



Percent of
Total Proved



Percent
Oil


PV-10



(in thousands)

Proved Developed Producing




90,203




50%




74%


$

2,303,981

Proved Developed Non-Producing




41,568




23%




58%



504,997

Total Proved Developed




131,771




73%




69%



2,808,978

Proved Undeveloped




49,521




27%




74%



817,798

Total Proved




181,292










$

3,626,776


















In addition to the proved reserves, Talos's pro forma probable reserves at year-end 2019 were 61.4 MMBoe and had a PV-10 of $1.5 billion.

In accordance with guidelines established by the SEC, the Company's estimated proved reserves as of December 31, 2019 were determined to be economically producible under existing economic conditions, which requires the use of the 12-month average price for each commodity, calculated as the unweighted arithmetic average of the price on the first day of each month for the year end December 31, 2019. The West Texas Intermediate spot price and the Henry Hub spot price were utilized as the referenced price and appropriately adjusted for quality, transportation, fees, energy content and basis differentials. Therefore, the standardized measure and PV-10 of Talos's proved reserves at December 31, 2019, are based on an average crude oil price of $55.69 per barrel and an average natural gas price of $2.58 per MMBtu, prior to being adjusted for quality, transportation, fees, energy content and basis differentials.

The following table provides a supplement sensitivity for Talos's pro forma proved reserves at December 31, 2019 at flat $45.00 WTI and $2.00 Henry Hub pricing:




Summary of Pro Forma Proved Reserves – $45.00/Bbl WTI




MBoe



Percent of
Total Proved



Percent
Oil


PV-10



(in thousands)

Proved Developed Producing




85,297




51%




74%



$

1,670,417

Proved Developed Non-Producing




35,987




22%




58%




308,325

Total Proved Developed




121,284




73%




69%




1,978,743

Proved Undeveloped




45,407




27%




75%




514,649

Total Proved




166,691











$

2,493,392




















In addition to the proved reserves, Talos's pro forma probable reserves at year-end 2019 were 61.9 MMBoe and had a PV-10 of $1.1 billion.

Footnotes:

(1)

Adjusted Net Income, Adjusted Earnings per Share, Adjusted EBITDA, Adjusted EBITDA excluding hedges, Adjusted EBITDA Margin, Adjusted EBITDA Margin excluding hedges and Net Debt to LTM Adjusted EBITDA are non-GAAP financial measures. See "Supplemental Non-GAAP Information" below for additional detail and reconciliations of GAAP to non-GAAP measures.

(2)

Includes $6.5 million of federal royalty refund.

(3)

Average realized prices are net of certain gathering, transportation, quality differentials and other costs.

(4)

Includes insurance costs.

(5)

Excludes non-cash stock based compensation and transaction-related expenses.

(6)

PV-10 is a non-GAAP financial measure and differs from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. See "Supplemental Non-GAAP Information" below for additional detail and reconciliations of GAAP to non-GAAP measures, including a reconciliation of PV-10 of our proved reserves to the standardized measure of discounted future net cash flows at December 31, 2019.

(7)

Proved oil, natural gas and NGL reserves attributable to our net interests in oil and natural gas properties were estimated and compiled for reporting purposes by our reservoir engineers and audited by Netherland, Sewell & Associates, Inc.

(8)

Other United States Properties includes Gulf of Mexico shelf and deepwater.

(9)

Pro forma proved oil, natural gas and NGL reserves attributable to our net interests in oil and natural gas properties were estimated and compiled for reporting purposes by our reservoir engineers. Approximately 85% of the reserves were audited by Netherland, Sewell & Associates, Inc. and Cawley, Gillespie and Associates.

HEDGES

The following table reflects the contracted volumes and weighted average prices the Company will receive under the terms of its derivative contracts as of December 31, 2019, including contracts entered into following the end of the fiscal year:

Production Period


Instrument

Type


Average

Daily

Volumes



Weighted

Average

Swap Price



Weighted

Average

Put Price



Weighted

Average

Call Price


Crude Oil – WTI:




(Bbls)



(per Bbl)



(per Bbl)



(per Bbl)


January 2020 – December 2020


Swap



21,366



$

53.72



$



$


January 2021 – December 2021


Swap



2,984



$

50.08



$



$


January 2020 – December 2020


Collar



7,481



$



$

55.00



$

64.23


Natural Gas – Henry Hub NYMEX:




(MMBtu)



(per MMBtu)



(per MMBtu)



(per MMBtu)


January 2020 – December 2020


Swaps



20,724



$

2.65



$



$


January 2021 – December 2021


Swaps



5,000



$

2.39



$



$


CONFERENCE CALL AND WEBCAST INFORMATION

Talos will host an earnings conference call, which will be broadcast live over the internet, tomorrow, Thursday, March 12, 2020 at 10:00 AM Eastern Time.

Listeners can access the earnings 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 1-888-348-8927 (U.S. toll-free), 1-855-669-9657 (Canada toll-free) or 1-412-902-4263 (International). Please dial in approximately 10 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 through March 19, 2020 and can be accessed by dialing 1-877-344-7529 and using access code 10139354.

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, 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, potential adverse reactions or changes to competitive responses to the business combination between Talos Energy LLC and Stone Energy Corporation, the possibility that the anticipated benefits of such business combination are not realized when expected or at all, including as a result of the impact of, or problems arising from, the integration of the two companies, 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, 2019, 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 and marketing of oil and gas are subject to disruption due to transportation and processing 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 "gross recoverable 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)




Year Ended December 31,




2019



2018


ASSETS









Current assets:









Cash and cash equivalents


$

87,022



$

139,914


Restricted cash






1,248


Accounts receivable









Trade, net



107,842




103,025


Joint interest, net



16,552




20,244


Other



6,346




19,686


Assets from price risk management activities



8,393




75,473


Prepaid assets



65,877




38,911


Income tax receivable



116




10,701


Other current assets



1,836




7,644


Total current assets



293,984




416,846


Property and equipment:









Proved properties



4,066,260




3,629,430


Unproved properties, not subject to amortization



194,532




108,209


Other property and equipment



29,843




33,191


Total property and equipment



4,290,635




3,770,830


Accumulated depreciation, depletion and amortization



(2,065,023)




(1,719,609)


Total property and equipment, net



2,225,612




2,051,221


Other long-term assets:









Other well equipment inventory



7,732




9,224


Operating lease assets



7,779





Other assets



54,375




2,695


Total assets


$

2,589,482



$

2,479,986


LIABILITIES AND STOCKHOLDERS' EQUITY









Current liabilities:









Accounts payable


$

71,357



$

51,019


Accrued liabilities



154,816




188,650


Accrued royalties



31,729




38,520


Current portion of long-term debt






443


Current portion of asset retirement obligations



61,051




68,965


Liabilities from price risk management activities



19,476




550


Accrued interest payable



10,249




10,200


Current portion of operating lease liabilities



1,594





Other current liabilities



20,180




22,071


Total current liabilities



370,452




380,418


Long-term liabilities:









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



732,981




654,861


Asset retirement obligations



308,427




313,852


Liabilities from price risk management activities



511





Operating lease liabilities



17,239





Other long-term liabilities



81,595




123,359


Total liabilities



1,511,205




1,472,490


Commitments and contingencies (Note 12)









Stockholders' Equity:









Preferred stock, $0.01 par value; 30,000,000 shares authorized and no shares issued or outstanding as of December 31, 2019 and December 31, 2018







Common stock $0.01 par value; 270,000,000 shares authorized; 54,197,004 and 54,155,768 shares issued and outstanding as of December 31, 2019 and December 31, 2018, respectively



542




542


Additional paid-in capital



1,346,142




1,334,090


Accumulated deficit



(268,407)




(327,136)


Total stockholders' equity



1,078,277




1,007,496


Total liabilities and stockholders' equity


$

2,589,482



$

2,479,986


 

Talos Energy Inc.

Condensed Consolidated Statements of Operations

(In thousands, except per common share amounts)




Three  Months
Ended
December 31,
2019



Twelve  Months
Ended
December 31,
2019



Three  Months

Ended
December 31,
2018



Twelve Months
Ended
December 31,
2018


Revenues:

















Oil revenue


$

208,632



$

833,118



$

225,861



$

781,815


Natural gas revenue



13,540




55,278




24,246




73,610


NGL revenue



4,573




19,668




8,557




35,863


Other



6,495




19,556








Total revenue



233,240




927,620




258,664




891,288


Operating expenses:







-










Lease operating expense



59,197




243,427




64,464




226,291


Production taxes



282




1,349




456




1,989


Depreciation, depletion and amortization



97,413




345,931




84,145




288,719


Write-down of oil and natural gas properties



(1,557)




12,221








Accretion expense



7,521




34,389




10,930




35,344


General and administrative expense



23,414




77,209




24,696




85,816


Total operating expenses



186,270




714,526




184,691




638,159


Operating income



46,970




213,094




73,973




253,129


Interest expense



(24,574)




(97,847)




(23,857)




(90,114)


Price risk management activities income (expense)



(59,508)




(95,337)




256,917




60,435


Other income



847




2,678




2,175




1,012


Net income (loss) before income taxes



(36,265)




22,588




309,208




224,462


Income tax benefit (expense)



36,569




36,141




(2,922)




(2,922)


Net income (loss)


$

304



$

58,729



$

306,286



$

221,540


 

Talos Energy Inc.

Condensed Consolidated Statements of Cash Flows

(In thousands)




Year Ended December 31,




2019



2018



2017


Cash flows from operating activities:













Net income (loss)


$

58,729



$

221,540



$

(62,868)


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













Depreciation, depletion, amortization and accretion expense



380,320




324,063




176,647


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



12,386




244




260


Amortization of deferred financing costs and original issue discount



5,207




4,253




2,383


Equity based compensation, net of amounts capitalized



6,964




2,893




875


Price risk management activities expense (income)



95,337




(60,435)




27,563


Net cash received (paid) on settled derivative instruments



(8,820)




(111,147)




23,834


Settlement of asset retirement obligations



(75,331)




(112,946)




(32,573)


Changes in operating assets and liabilities:













Accounts receivable



5,788




(786)




(9,132)


Other current assets



(15,114)




(2,624)




(4,441)


Accounts payable



7,523




(48,825)




2,409


Other current liabilities



(35,459)




32,044




46,364


Other non-current assets and liabilities, net



(43,797)




15,171




4,732


Net cash provided by operating activities



393,733




263,445




176,053


Cash flows from investing activities:













Exploration, development and other capital expenditures



(463,409)




(240,914)




(155,177)


Cash (paid for) received from acquisitions, net of cash acquired



(37,916)




278,409




(2,464)


Proceeds from sale of other property and equipment



5,369








Net cash provided by (used in) investing activities



(495,956)




37,495




(157,641)


Cash flows from financing activities:













Redemption of Senior Notes and other long-term debt



(10,567)




(25,257)




(1,000)


Proceeds from Bank Credit Facility



110,000




319,000




10,000


Repayment of Bank Credit Facility



(25,000)




(54,000)





Repayment of LLC Bank Credit Facility






(403,000)




(15,000)


Deferred financing costs



(1,963)




(17,002)





Other deferred payments



(9,921)








Payments of finance lease



(14,133)




(12,952)




(12,412)


Employee stock transactions



(333)








Net cash provided by (used in) financing activities



48,083




(193,211)




(18,412)















Net increase (decrease) in cash, cash equivalents and restricted

   cash



(54,140)




107,729





Cash, cash equivalents and restricted cash:













Balance, beginning of period



141,162




33,433




33,433


Balance, end of period


$

87,022



$

141,162



$

33,433















Supplemental Non-Cash Transactions:













Capital expenditures included in accounts payable and accrued liabilities


$

90,956



$

100,664



$

40,626


Supplemental Cash Flow Information:













Interest paid, net of amounts capitalized


$

62,571



$

53,476



$

47,994


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" and "Net Debt to 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 excluding hedges. Adjusted EBITDA plus net cash receipts (payments) on settled derivative instruments. We believe the presentation of Adjusted EBITDA excluding hedges is important to provide management and investors with information about the impact of actual commodity price changes on our business.

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.

Adjusted EBITDA Margin excluding hedges bears the same definition and our intended utility of Adjusted EBITDA Margin, but using Adjusted EBITDA excluding hedges instead of Adjusted EBITDA.

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 Margins and Adjusted EBITDA Margins excluding hedges for each of the periods indicated (in thousands, except for Boe, $/Boe and percentage data):

($ thousands, except per Boe)

Three Months
Ended,

December 31,
2019



Twelve Months
Ended,

December 31,
2019



Twelve  Months
Ended,

December 31,
2018



Twelve Months
Ended,

December 31,
2017


Reconciliation of net income (loss) to Adjusted EBITDA:
















Net income (loss)

$

304



$

58,729



$

221,540



$

(62,868)


Interest expense


24,574




97,847




90,114




80,934


Income tax expense (benefit)


(36,569)




(36,141)




2,922





Depreciation, depletion and amortization


97,413




345,931




288,719




157,352


Accretion expense


7,521




34,389




35,344




19,295


EBITDA


93,243




500,755




638,639




194,713


Write-down of oil and natural gas properties


(1,557)




12,221








Loss on debt extinguishment


132




132




1,764





Transaction related costs


4,111




7,460




32,484




9,652


Derivative fair value (gain) loss(1)


59,508




95,337




(60,435)




27,563


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


(1,618)




(8,820)




(111,147)




23,834


Non-cash (gain) loss on sale of assets








(1,710)





Non-cash write-down of other well equipment inventory


165




165




244




260


Non-cash equity-based compensation expense


1,800




6,964




2,893




875


Adjusted EBITDA

$

155,784



$

614,214



$

502,732



$

256,897


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


1,618




8,820




111,147




(23,834)


Adjusted EBITDA excluding hedges

$

157,402



$

623,034



$

613,879



$

233,063


Production and Revenue:
















Production – MBoe(2)


4,966




18,959




16,742




10,472


Revenue


233,240




927,620




891,288




412,828


Adjusted EBITDA margin and Adjusted EBITDA excl hedges margin:
















Adjusted EBITDA divided by Revenue (%)


67

%



66

%



56

%



62

%

Adjusted EBITDA per Boe(2)

$

31.37



$

32.40



$

30.03



$

24.53


Adjusted EBITDA excl hedges divided by Revenue (%)


67

%



67

%



69

%



56

%

Adjusted EBITDA excl hedges per Boe(2)

$

31.70



$

32.86



$

36.67



$

22.26




(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

We believe the presentation of Free Cash Flow is important to provide investors with additional important information to evaluate our business. These measures are widely used by investors in the valuation, comparison, rating and investment recommendations of companies. Please see "Reconciliation of Net Income (Loss) to EBITDA and Adjusted EBITDA" above.

($ thousands, except per share amounts)

Three Months Ended
December 31, 2019


Reconciliation of Adjusted EBITDA to Free Cash Flow:




Adjusted EBITDA

$

155,784


Less: Capital Expenditures and Plugging & Abandonment


(86,836)


Less: Interest expense


(24,574)


Free Cash Flow

$

44,374


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
December 31, 2019


Reconciliation of Net Income to Adjusted Net Income:




Net Income

$

304


Accretion expense


7,521


Transaction related costs


4,111


Derivative fair value (gain) loss(1)


59,508


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


(1,618)


Non-cash equity-based compensation expense


1,800


Adjusted Net Income

$

71,626






Weighted average common shares outstanding at December 31, 2019:




Basic


54,203


Diluted


54,559






Net Income per common share (Earnings Per Share):




Basic

$

0.01


Diluted

$

0.01






Adjusted Net Income per common share (Adjusted Earnings Per Share):




Basic

$

1.32


Diluted

$

1.31




(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

We believe the presentation of Net Debt, LTM Adjusted EBITDA and Net Debt to 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.

Reconciliation of Total Debt to Net Debt ($ thousands) at December 31, 2019:




Debt principal

$

746,928


Finance lease


79,535


Total Debt


826,463


Less: Cash and cash equivalents


(87,022)


Net Debt

$

739,441






Calculation of LTM EBITDA:




Adjusted EBITDA for the twelve month period ended December 31, 2019


614,214


LTM Adjusted EBITDA


614,214






Calculation of Net Debt to LTM Adjusted EBITDA:




Net Debt / LTM Adjusted EBITDA


1.2

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 LTM Adjusted EBITDA ratio equal to or lower than 3.0x. For purposes of covenant compliance, LTM Adjusted EBITDA, with certain adjustments, is calculated, as of December 31, 2019 and in subsequent quarters, as the sum of quarterly Adjusted EBITDA for the 12-month period ended on that quarter.

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