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Talos Energy Announces Third Quarter 2019 Financial And Operational Results

HOUSTON, Nov. 6, 2019 /PRNewswire/ -- Talos Energy Inc. ("Talos," or the "Company") (TALO) today announced its financial and operational results for the third quarter of 2019 and provided an operations update.

(PRNewsfoto/Talos Energy)

Key third quarter highlights include:

  • Production of 52.6 thousand barrels of oil equivalent per day ("MBoe/d"), or 4.8 million barrels of oil equivalent ("MMBoe") in total, of which 73% was oil and 80% was liquids. As previously disclosed, third quarter production was impacted by Hurricane Barry, resulting in the deferral of approximately 4.0 MBoe/d.
  • Revenue(1) of $228.9 million and average realized prices of $59.54/Bbl of oil and $2.12/Mcf of natural gas, net of deductions. 93% of operating revenues were derived from oil production and reflect a significant realized price premium, which is net of transport and quality deductions, of $3.09/Bbl above the average WTI benchmark price of $56.45/Bbl during the same period.
  • Net Income of $73.3 million ($1.35 earnings per share – diluted) and Adjusted Net Income(2) of $44.3 million ($0.81 adjusted earnings per share – diluted).
  • Adjusted EBITDA(2) of $157.8 million and Adjusted EBITDA excluding hedges(2) of $152.4 million. Adjusted EBITDA Margin(2) per Boe of $32.57, or 69%, and Adjusted EBITDA Margin excluding hedges(2) per Boe of $31.47, or 67%.
  • Capital expenditures of $115.8 million, including investment of $99.7 million in the U.S. Gulf of Mexico and $16.1 million in offshore Mexico.
  • As of September 30, 2019, liquidity position of $612.1 million. Net Debt to Last Twelve Months ("LTM") Adjusted EBITDA(2) was 1.1x.
  • In the third quarter of 2019, the Company had a successful discovery in offshore Mexico Block 31, executed two separate exploration transactions with BP and ExxonMobil, respectively, and drilled and completed its Grand Isle 82 A-22 exploration well, which achieved first production in October 2019.
  • The Company was added to the S&P SmallCap 600 Index on November 1, 2019. Talos was included in the Index as one of just 19 exploration and production companies and was the sixth largest by market capitalization amongst the Energy Sector designated companies. Talos was also included in the S&P SmallCap 600 GICS Oil and Gas Exploration and Production Sub-Industry Index.

(1)

Includes $1.0 million of federal royalty refund.

(2)

Adjusted Net Income, Adjusted Earnings per Share, Adjusted EBITDA, Adjusted EBITDA excluding hedges, Adjusted EBITDA Margin and 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.

President and Chief Executive Officer Timothy S. Duncan commented: "I am proud of our team for achieving another positive earnings quarter, bolstered by another period of generating significant free cash flow in our U.S. Gulf of Mexico business. Our focus on investing in opportunities around core infrastructure that we own or operate continues to allow us to achieve top quartile net back margins, which are enhanced by better than expected results of our cost control initiatives throughout 2019. We also continue to balance those investments with high impact exploration projects, including more success in offshore Mexico.

As we begin to focus on our 2020 drilling campaign, success in our Bulleit project and acceleration of first oil at Orlov provide a strong foundation, with additional potential upside from our exploration activities related to our recent Puma West and Hershey transactions. Among other activities, we plan to execute a platform rig contract for a near-field drilling program around assets we acquired in the past year and we look forward to progressing our offshore Mexico discoveries closer to final investment decisions.

We believe our strategy of combining low entry cost M&A with field development upside and high impact exploration, while also maintaining a prudent financial and conservative leverage profiles and strong free cash flow generation, allows us to grow equity value while maintaining a strong balance sheet. We are excited about the direction of the Company moving forward."

RECENT DEVELOPMENTS AND OPERATIONS UPDATE

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

  • Puma West Prospect: Talos entered an agreement with BP to drill the Puma West prospect located on Green Canyon Block 821. BP is the operator of the prospect holding a 50% working interest, Talos retained a 25% working interest, and Chevron now also has a 25% working interest. The Puma West well is being drilled by the Seadrill West Auriga ultra-deepwater drillship and was spud in October, targeting Miocene sands similar to those seen in the Mad Dog development located less than 15 miles away.
  • Bulleit Prospect: As previously disclosed, the Green Canyon Block 21 Bulleit exploration well encountered approximately 140 feet of net true vertical depth ("TVD") oil pay in the shallow target, the DTR-10 Sand, and approximately 110 feet of net TVD oil pay in the deeper MP Sand. Talos expects first production in the third quarter of 2020 with a possible initial flow rate of 7.0 – 10.0 MBoe/d gross, 2.8 – 4.0 MBoe/d net. Talos holds a 50.0% working interest in the Bulleit prospect and is the operator, with EnVen and Otto Energy holding 33.3% and 16.7% working interests, respectively.
  • Orlov Prospect: After successfully discovering oil pay in the main target Aspen J sand in the Green Canyon 200 Orlov project, the operator, Fieldwood Energy, is finalizing drilling operations and plans to complete the well by year end. Talos expects that the project could produce 7.0 – 10.0 MBoe/d gross, 1.8 – 2.5 MBoe/d net with first production recently accelerated and now expected in early first quarter of 2020. Talos owns a 30% working interest in the project.
  • Hershey Prospect: Talos acquired a 100% working interest and operatorship of Green Canyon Blocks 326, 327, 370 and 371, constituting approximately 23,000 gross acres. The Hershey prospect is targeting a potential large sub-salt Miocene accumulation with potential oil-weighted, gross unrisked resources of 100 – 300 MMBoe. Consideration for the transaction is 100% contingent-based and the agreement contains no well commitment. Talos expects to initiate a process to sell-down a portion of its working interest in the project in the fourth quarter of 2019.
  • 2020 Rig Contracts: In advance of the Company's 2020 drilling and completions program, Talos is finalizing contractual terms with two drilling contractors following a competitive bidding process. One contractor is expected to provide a deepwater drillship to be used for the Company's deepwater exploration and exploitation activities. The second contractor is expected to provide a platform rig to be used for near-field drilling opportunities in assets that were acquired over the last 18 months, starting with our Green Canyon 18 asset in the first quarter of 2020, with the option of subsequently moving to our Pompano and Amberjack assets in our Mississippi Canyon core area in the fourth quarter of 2020.

Drilling and Exploration Activities – Mexico

  • Block 7: Following the successful completion of the Zama appraisal program, Talos is working with Netherland, Sewell & Associates, Inc. to complete a formal resource report by year end 2019. The Company reiterates its previously stated resource guidance in the upper half of its pre-appraisal estimated range of 400 – 800 MMBoe gross recoverable resources. Talos has initiated early FEED work to allow for the earliest possible initial production date and is utilizing all of the appraisal data to create an optimal development plan for the field. Zama unitization discussions with Petróleos Mexicanos ("Pemex") are ongoing. As previously announced in September 2019, the Company was also recently granted a two-year contract term extension as well as regulatory approvals to allow for exploration activities on additional retained acreage in Block 7, which is separate and incremental to the Zama asset.
  • Block 31: The Block 31 exploration project consisted of two wells, Xaxamani-2EXP and Tolteca-1EXP, both drilled in the third quarter of 2019. The Xaxamani-2EXP well logged approximately 148 feet (45 meters) of gross TVD pay, with a net to gross ratio of approximately 78% in two shallow oil sands. Subsequently, the Tolteca-1EXP well logged approximately 123 feet (37 meters) of gross TVD pay, with a net to gross ratio of approximately 97%, all located in the deeper of the two sands found in the Xaxamani-2EXP well. The Tolteca-1EXP well expected to find an oil-water contact but logged hydrocarbons "full to base," exceeding pre-drill expectations for reservoir thickness and areal extent, thereby increasing resource expectations not only in the drilling program to date, but also increasing expectations of similar geophysical anomalies that could open up a shallow oil play in the contract area.
    The Xaxamani discovery is located approximately one mile from shore in less than 100 feet of water. Talos holds a 25% working interest in Block 31. Since 2017, Talos has now drilled or participated in eight wells in offshore Mexico, including five exploration wells, resulting in two material oil discoveries.

Derivatives Activities

  • Derivatives Update: The following table reflects the contracted volumes and weighted average prices the Company will receive under its derivative contracts as of September 30, 2019. During the third quarter of 2019, Talos hedged additional fourth quarter 2019 and fiscal year 2020 oil production of 1,967,500 Bbls and natural gas production of 2,750,000 MMBtu. The weighted average prices the Company will receive under these West Texas Intermediate and Henry Hub swap contracts are $55.40 per Bbl and $2.45 per MMBtu, respectively.

 

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)


Oct 2019 - Dec 2019


Swap



29,468



$

56.04



$



$


Jan 2020 - Dec 2020


Swap



13,492



$

56.13



$



$


Jan 2020 - Dec 2020


Costless collars



7,481



$



$

55.00



$

64.23


Natural Gas – Henry Hub NYMEX:




(MMBtu)



(per MMBtu)



(per MMBtu)



(per MMBtu)


Oct 2019 - Dec 2019


Swap



37,475



$

2.92



$



$


Jan 2020 - Dec 2020


Swap



16,216



$

2.78



$



$


 

THIRD QUARTER 2019 RESULTS


Key Financial Highlights:


Period results ($ million):




Revenues(1)

$

228.9


Net Income

$

73.3


Earnings per share – diluted

$

1.35


Adjusted Net Income(2)

$

44.3


Adjusted Earnings per share – diluted(2)

$

0.81


Adjusted EBITDA(2)

$

157.8


Adjusted EBITDA excl. hedges(2)

$

152.4


Capital Expenditures (including Plug & Abandonment)

$

115.8


Adjusted EBITDA Margin(2):




Adjusted EBITDA (% of Revenue – Operations)


69

%

Adjusted EBITDA per Boe

$

32.57


Adjusted EBITDA excl. hedges (% of Revenue – Operations)


67

%

Adjusted EBITDA excl. hedges per Boe

$

31.47


Production, Realized Prices and Revenue
Production for the third quarter of 2019 was 4.8 MMBoe, with oil production accounting for 73% of the total. Oil price realizations, net of certain gathering, transportation, quality differentials and other costs, were $59.54 per barrel, representing an average for the quarter of $3.09 per barrel above the average WTI price over the same period. As previously disclosed, third quarter production was impacted by Hurricane Barry, which prompted the shut-in of approximately 85% of the Company's production for approximately one week on average, and resulted in the production deferral of approximately 4.0 MBoe/d.


Three Months Ended
September 30, 2019

Production volumes



Oil production volume (MBbls)


3,559

NGL production volume (MBbls)


299

Natural Gas production volume (MMcf)


5,909

Total production volume (MBoe)


4,843




Average net daily production volumes



Oil (MBbl/d)


38.7

NGL (MBbl/d)


3.2

Natural Gas (MMcf/d)


64.2

Total average net daily (MBoe/d)


52.6




Average realized prices (excluding hedges)(3)



Oil ($/Bbl)

$59.54

NGL ($/Bbl)

$11.32

Natural Gas ($/Mcf)

$2.12

Average Realized Price ($/Boe)

$47.04




Average NYMEX prices



WTI ($/Bbl)

$

56.45

Henry Hub ($/MMBtu)

$

2.23




Revenues ($ million)



Oil

$

211.9

NGL


3.4

Natural Gas


12.6

Revenue – Operations


227.9

Other revenue


1.0

Total revenue

$

228.9

 


Three Months Ended September 30, 2019



Production



% Oil



% Liquids



% Operated


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
















Green Canyon
















Phoenix Complex


18.7




81

%



87

%



100

%

Green Canyon 18


1.0




89

%



91

%



100

%

Green Canyon Area


19.7




81

%



87

%



100

%

















Mississippi Canyon
















Amberjack


2.1




90

%



92

%



99

%

Pompano


10.9




83

%



89

%



100

%

Ram Powell


4.9




61

%



74

%



100

%

Gunflint


1.1




79

%



84

%



0

%

Mississippi Canyon Area


19.0




77

%



84

%



94

%

















Shelf and Other Deepwater
















Shelf


12.6




55

%



61

%



88

%

Other deepwater


1.3




73

%



77

%



73

%

Shelf and Other Deepwater Area


13.9




61

%



67

%



87

%

















Total average net daily (MBoe/d)


52.6




73

%



80

%



94

%

Expenses
Total lease operating expenses ("LOE") for the third quarter of 2019 were $47.6 million, inclusive of insurance costs, or $9.83/Boe. LOE/Boe for the quarter was negatively impacted by reduced production volumes as a result of the production shut-in related to Hurricane Barry. Workover and maintenance expense for the quarter was $14.2 million, or $2.93/Boe. Workover and maintenance expense was also negatively impacted by Hurricane Barry with approximately $2.0 million of incremental, one-time expenses. General and administrative expenses ("G&A") for the quarter were $15.4 million (excluding $1.9 million of stock-based compensation), or $3.18/Boe. Total G&A expenses continues to be lower than expected due to continuous focus on cost control; however, G&A/Boe for the quarter was negatively impacted by the deferred production volumes associated with Hurricane Barry.


Three Months Ended
September 30,



Per Boe

Lease Operating Expenses

$

47.6



$

9.83

Workover and Maintenance Expenses

$

14.2



$

2.93

General & Administrative Expenses (excluding non-cash items)(5)

$

15.4



$

3.18

Other Financial Metrics

Capital Expenditures & Asset Management Activities
Capital expenditures for the third quarter of 2019 were $115.8 million, inclusive of plugging & abandonment costs. Asset management workover and recompletion activities accounted for incremental production of 2.7 MBoe/d gross, 1.5 MBoe/d, net to Talos in the third quarter. The combined net production conversion cost was $3,422 per Boe/d.


Three Months Ended
September 30, 2019

Capital Expenditures



U.S. Drilling & Completions

$

52.6

Mexico Appraisal & Exploration


12.6

Asset Management


14.0

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


14.5

Total Capital Expenditures

$

93.6

Plugging & Abandonment


22.2

Total Capital Expenditures and Plugging & Abandonment

$

115.8

Liquidity
As of September 30, 2019, the Company had approximately $795.3 million in total debt, inclusive of the HP-I finance lease, and a liquidity position of $612.1 million, including $521.4 million available under the Bank Credit Facility and approximately $90.7 million of cash. LTM Adjusted EBITDA(2) for the twelve month period ended September 30, 2019 was $617.2 million. Net Debt to LTM Adjusted EBITDA(2) ratio was 1.1x.

2019 GUIDANCE UPDATES

Updates and adjustments to the Company's 2019 full year financial guidance are listed in the table below.

2019 Guidance ($ millions)


  Production (MBoe/d)

53 – 56

Full Year 2019 production is expected near the low end of the previously guided range, driven mainly by already disclosed impacts from Hurricane Barry, Boris 3 production and Pompano shut-in in the first quarter of 2019


  Lease Operating Expenses(4)

$195 – $205

Expected near lower end of range


  Workover & Maintenance Expenses

$60 – $65

Expected near higher end of range


  General & Administrative Expenses(4)(5)

$60 – $65

Expected near lower end of range


  Capital Expenditures(6)

$540 – $550

Updated range, primarily driven by:

1)   $20 – $25 million: Puma West well cost

2)   $15 – $20 million: Success-driven capital expenditures as a result of the expected full realization of development spending for Bulleit, Orlov and Ewing Bank 306

3)   $30 – $35 million: Timing shifts mainly related to acceleration of non-operated projects, including pull-forward of Orlov first oil







(1)

Includes $1 million of federal royalty refund.

(2)

Adjusted Net Income, Adjusted Earnings per Share, Adjusted EBITDA, Adjusted EBITDA excluding hedges, Adjusted EBITDA Margin and 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.

(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 expense.

(6)

Includes $70 - $75 million of Mexico capital expenditures.

CONFERENCE CALL AND WEBCAST INFORMATION

Talos will host a conference call, which will also be broadcast live over the internet, on November 7, 2019 at 9:00 AM CST. 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 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 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 call through November 14, 2019 and can be accessed by dialing 1-877-344-7529 and using access code 10136203.

ABOUT TALOS ENERGY

Talos Energy (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, 2018, filed with the SEC on March 14, 2019, and in our Quarterly Report on Form 10-Q for the quarter ended September 30, 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 unrisked resources" and "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)




September 30, 2019



December 31, 2018




(Unaudited)






ASSETS









Current assets:









Cash and cash equivalents


$

90,682



$

139,914


Restricted cash






1,248


Accounts receivable









Trade, net



108,354




103,025


Joint interest, net



17,562




20,244


Other



31,768




19,686


Assets from price risk management activities



43,058




75,473


Prepaid assets



39,378




38,911


Income tax receivable






10,701


Other current assets



1,952




7,644


Total current assets



332,754




416,846


Property and equipment:









Proved properties



4,012,100




3,629,430


Unproved properties, not subject to amortization



178,174




108,209


Other property and equipment



28,690




33,191


Total property and equipment



4,218,964




3,770,830


Accumulated depreciation, depletion and amortization



(1,967,610)




(1,719,609)


Total property and equipment, net



2,251,354




2,051,221


Other long-term assets:









Assets from price risk management activities



7,820





Other well equipment inventory



9,251




9,224


Operating lease assets



8,082





Other assets



2,624




2,695


Total assets


$

2,611,885



$

2,479,986


LIABILITIES AND STOCKHOLDERS' EQUITY









Current liabilities:









Accounts payable


$

95,737



$

51,019


Accrued liabilities



169,152




188,650


Accrued royalties



37,763




38,520


Current portion of long-term debt






443


Current portion of asset retirement obligations



63,404




68,965


Liabilities from price risk management activities



3,832




550


Accrued interest payable



21,058




10,200


Current portion of operating lease liabilities



1,416





Other current liabilities



18,993




22,071


Total current liabilities



411,355




380,418


Long-term liabilities:









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



697,192




654,861


Asset retirement obligations



321,808




313,852


Liabilities from price risk management activities



750





Operating lease liabilities



17,249





Other long-term liabilities



88,707




123,359


Total liabilities



1,537,061




1,472,490


Commitments and contingencies (Note 11)









Stockholders' equity:









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







Common stock $0.01 par value; 270,000,000 shares authorized; 54,196,145 and 54,155,768 shares
     issued and outstanding as of September 30, 2019 and December 31, 2018, respectively



542




542


Additional paid-in capital



1,342,993




1,334,090


Accumulated deficit



(268,711)




(327,136)


Total stockholders' equity



1,074,824




1,007,496


Total liabilities and stockholders' equity


$

2,611,885



$

2,479,986


 

Talos Energy Inc.

Condensed Consolidated Statements of Operations

(In thousands, except per common share amounts)

(Unaudited)




Three Months Ended September 30,



Nine Months Ended September 30,




2019



2018



2019



2018


Revenues and other:

















Oil revenue


$

211,899



$

248,100



$

624,486



$

555,954


Natural gas revenue



12,545




20,193




41,738




49,364


NGL revenue



3,384




14,575




15,095




27,306


Other



1,029







13,061





Total revenue



228,857




282,868




694,380




632,624


Operating expenses:

















Direct lease operating expense



43,439




42,090




122,243




101,065


Insurance



4,167




4,125




12,462




11,059


Production taxes



(21)




578




1,067




1,533


Total lease operating expense



47,585




46,793




135,772




113,657


Workover and maintenance expense



14,210




25,084




49,525




49,703


Depreciation, depletion and amortization



88,125




87,808




248,518




204,574


Write-down of oil and natural gas properties



1,417







13,778





Accretion expense



7,316




10,162




26,868




24,414


General and administrative expense



17,321




21,660




53,795




61,120


Total operating expenses



175,974




191,507




528,256




453,468


Operating income



52,883




91,361




166,124




179,156


Interest expense



(23,123)




(24,837)




(73,273)




(66,257)


Price risk management activities income (expense)



43,760




(53,330)




(35,829)




(196,482)


Other income (expense)



567




(85)




1,831




(1,163)


Income (loss) before income taxes



74,087




13,109




58,853




(84,746)


Income tax benefit



(790)







(428)





Net income (loss)


$

73,297



$

13,109



$

58,425



$

(84,746)



















Net income (loss) per common share:

















Basic


$

1.35



$

0.24



$

1.08



$

(1.96)


Diluted


$

1.35



$

0.24



$

1.07



$

(1.96)


Weighted average common shares outstanding:

















Basic



54,200




54,156




54,178




43,329


Diluted



54,430




54,164




54,364




43,329


 

Talos Energy Inc.

Condensed Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)




Nine Months Ended September 30,




2019



2018


Cash flows from operating activities:









Net income (loss)


$

58,425



$

(84,746)


Adjustments to reconcile net loss to net cash provided by operating activities









Depreciation, depletion, amortization and accretion expense



275,386




228,988


Write-down of oil and natural gas properties



13,778





Amortization of deferred financing costs and original issue discount



3,723




3,589


Equity based compensation, net of amounts capitalized



5,164




2,129


Price risk management activities expense



35,829




196,482


Net cash paid on settled derivative instruments



(7,202)




(94,802)


Settlement of asset retirement obligations



(54,406)




(85,674)


Changes in operating assets and liabilities:









Accounts receivable



(14,729)




(4,460)


Other current assets



11,384




(14,524)


Accounts payable



32,541




(54,029)


Other current liabilities



(26,753)




40,410


Other non-current assets and liabilities, net



(727)




10,324


Net cash provided by operating activities



332,413




143,687


Cash flows from investing activities:









Exploration, development and other capital expenditures



(372,920)




(174,349)


Cash (paid for) acquired in acquisitions



(32,916)




278,409


Proceeds from sale of other property and equipment



5,369





Net cash provided by (used in) investing activities



(400,467)




104,060


Cash flows from financing activities:









Redemption of Senior Notes and other long-term debt



(10,567)




(25,151)


Proceeds from Bank Credit Facility



75,000




319,000


Repayment of Bank Credit Facility



(25,000)




(54,000)


Repayment of LLC Bank Credit Facility






(403,000)


Deferred financing costs



(1,268)




(16,990)


Other deferred payments



(9,921)





Payments of finance lease



(10,344)




(9,874)


Employee stock transactions



(326)





Net cash provided by (used in) financing activities



17,574




(190,015)











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



(50,480)




57,732


Cash, cash equivalents and restricted cash:









Balance, beginning of period



141,162




33,433


Balance, end of period


$

90,682



$

91,165











Supplemental Non-Cash Transactions:









Capital expenditures included in accounts payable and accrued liabilities


$

24,622



$

36,775


Supplemental Cash Flow Information:









Interest paid, net of amounts capitalized


$

36,011



$

27,307


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," "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,
2018



Three Months
Ended,

March 31,
2019



Three Months
Ended,

June 30,
2019



Three Months
Ended
September 30,
2019


Reconciliation of net income (loss) to Adjusted EBITDA:
















Net income (loss)

$

306,286



$

(109,636)



$

94,764



$

73,297


Interest expense


23,857




25,218




24,932




23,123


Income tax expense (benefit)


2,922




(6,359)




5,997




790


Depreciation, depletion and amortization


84,145




64,587




95,806




88,125


Accretion expense


10,930




9,607




9,945




7,316


EBITDA


428,140




(16,583)




231,444




192,651


Write-down of oil and natural gas properties








12,361




1,417


Loss on debt extinguishment












Transaction related costs


4,579




2,493




710




146


Derivative fair value (gain) loss(1)


(256,917)




109,579




(29,990)




(43,760)


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


(16,345)




(3,019)




(9,543)




5,360


Non-cash (gain) loss on sale of assets


(1,710)











Non-cash write-down of other well equipment inventory


244











Non-cash equity-based compensation expense


764




1,259




1,961




1,944


Adjusted EBITDA

$

158,755



$

93,729



$

206,943



$

157,758


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


16,345




3,019




9,543




(5,360)


Adjusted EBITDA excluding hedges

$

175,100



$

96,748



$

216,486



$

152,398


Production and Revenue:
















Boe(2)


4,910




3,782




5,369




4,843


Revenue – Operations


258,664




175,192




278,299




227,828


Adjusted EBITDA margin and Adjusted EBITDA excl hedges margin:
















Adjusted EBITDA divided by Revenue – Operations (%)


61

%



54

%



74

%



69

%

Adjusted EBITDA per Boe(2)

$

32.33



$

24.78



$

38.54



$

32.57


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


68

%



55

%



78

%



67

%

Adjusted EBITDA excl hedges per Boe(2)

$

35.66



$

25.58



$

40.32



$

31.47




(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 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
September 30, 2019


Reconciliation of Net Income to Adjusted Net Income:




Net Income

$

73,297


Accretion expense


7,316


Transaction related costs


146


Derivative fair value (gain) loss(1)


(43,760)


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


5,360


Non-cash equity-based compensation expense


1,944


Adjusted Net Income

$

44,303






Weighted average common shares outstanding at September 30, 2019:




Basic


54,200


Diluted


54,430






Net Income per common share (Earnings Per Share):




Basic

$

1.35


Diluted

$

1.35






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




Basic

$

0.82


Diluted

$

0.81




(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 September 30, 2019:




Debt principal

$

711,928


Finance lease


83,324


Total Debt


795,252


Cash


(90,682)


Net Debt

$

704,570






Calculation of LTM EBITDA:




Adjusted EBITDA for the three month period ended December 31, 2018


158,755


Adjusted EBITDA for the three month period ended March 31, 2019


93,729


Adjusted EBITDA for the three month period ended June 30, 2019


206,943


Adjusted EBITDA for the three month period ended September 30, 2019


157,758


LTM Adjusted EBITDA


617,185






Calculation of Net Debt to LTM Adjusted EBITDA:




Net Debt / LTM Adjusted EBITDA


1.1


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 September 30, 2019 and in subsequent quarters, as the sum of quarterly Adjusted EBITDA for the 12-month period ended on that quarter.

Cision

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