Talos Energy Announces Second Quarter 2020 Financial And Operational Results

HOUSTON, Aug. 5, 2020 /PRNewswire/ — Talos Energy Inc. (“Talos,” or the “Company”) (NYSE: TALO) today announced its financial and operational…

HOUSTON, Aug. 5, 2020 /PRNewswire/ — Talos Energy Inc. (“Talos,” or the “Company”) (NYSE: TALO) today announced its financial and operational results for the second quarter of 2020.

Key Highlights:

  • Production of 52.4 thousand barrels of oil equivalent per day (“MBoe/d”), of which 69% was oil and 76% was liquids. Production for the quarter was impacted by 14.4 MBoe/d of production deferrals associated with voluntary shut-ins, accelerated maintenance, Tropical Storm Cristobal and other miscellaneous items.
  • Net Loss of $140.6 million in the quarter, or $2.14 loss per diluted share, and Adjusted Net Loss(1) in the quarter of $29.4 million, or $0.45 adjusted loss per diluted share. Year-to-date, Net Income of $17.1 million, or $0.28 per diluted share, and year-to-date Adjusted Net Loss(1) of $13.8 million, or $0.22 per diluted share.
  • Adjusted EBITDA(1) of $97.5 million for the second quarter and Adjusted EBITDA(1) of $245.2 million for the first half of the year.
  • Capital expenditures, inclusive of plugging and abandonment costs, of $129.1 million during the quarter. Year-to-date capital expenditures were $202.3 million.
  • As of June 30, 2020, proved reserves for the Company totaled 189.5 MMBoe with a PV-10 of $2.8 billion. Additionally, probable reserves were 79.7 MMBoe with a PV-10 of $1.3 billion. Figures are presented pro forma for the recently closed acquisition.
  • Eliminated $39.2 million, or approximately 10% of the outstanding balance, of the Company’s 11.00% Second Lien Notes.
  • On August 5, 2020, closed the acquisition of additional working interests in 16 selected producing properties from affiliates of Castex 2005.
  • As of June 30, 2020, maintained a leverage position of 1.4x Net Debt to Credit Facility LTM Adjusted EBITDA(1).
  • Over $400.0 million of liquidity from $107.9 million in cash and availability under the Company’s $985.0 million borrowing base.

 

(1)

Adjusted Net Loss, Adjusted Loss per Share, Adjusted EBITDA, Adjusted EBITDA Margin, Free Cash Flow, Credit Facility LTM Adjusted EBITDA 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: “Although the second quarter presented unprecedented challenges for our industry, we took several actions in the quarter that have made us a stronger company for the remainder of this year and beyond, including opportunistically lowering our debt, significantly reducing our costs, adding to our working interest in several producing assets we currently own and deepening our inventory of high impact prospects.

“We successfully completed our Tornado IV project, which will provide additional production from the main producing interval in the near term before we turn the well into a water injection well in early 2021. We are currently on location in our Kaleidoscope and Bulleit projects with first oil expected from both late in the third quarter, establishing a strong foundation for 2021.

“In Mexico, we are making progress on our Zama project by finalizing engineering design while continuing to work with Pemex on unitization as part of the formal instructions to reach an agreement in the next six months. Separately, Netherland, Sewell and Associates completed their review of our Xaxamani discovery in Block 31, providing a “best estimate” of the gross resources in the contract area at over 100.0 MMBoe. Xaxamani is our second major discovery in offshore Mexico and highlights our capabilities to drive exploration success in basins beyond the U.S. Gulf of Mexico.”

Duncan continued: “We lowered our capital program in 2020 compared to 2019 and, even with the integration of new assets, we currently expect to complete the year well inside our capital, cash operating and general and administrative expense guidance. Our teams are working tirelessly during a stressful time to keep us on track in realizing these savings. Looking ahead, we expect to exit the year with a production rate between 71.0 – 73.0 MBoe/d, remain free cash flow positive for the year and sustain one of the most competitive credit profiles amongst our peers. We remain focused on continuing to drive down our lifting cost structure while bolstering our deep project inventory and executing on ample business development opportunities to become a more diversified and resilient company.”

RECENT DEVELOPMENTS AND OPERATIONS UPDATE

Corporate Activities

  • Cost Reduction Initiatives: Talos continues to realize substantial cost reductions across its cash operating, general and administrative and capital expense categories. In total, the Company expects over $200 million in cumulative savings for the full year 2020 from its original financial guidance released in February 2020, which will allow the Company to maintain a positive free cash flow profile for the year despite lower commodity prices and associated shut-ins. Additionally, compared to 2019 on a pro forma basis, Talos expects to reduce general and administrative costs approximately by $20.0 million, or approximately 25%. Cash operating expenses is expected to reduce by approximately $40.0 million, or approximately 12%.
  • Debt Exchange Transaction: During the second quarter Talos eliminated $39.2 million of debt, primarily from one exchange transaction that eliminated $37.2 million of its 11.00% Second Lien Notes. The exchange transaction will eliminate future cash interest payments on the Notes of approximately $7.5 million from settlement through maturity.
  • Bolt-On Acquisition: On August 5, 2020, Talos closed the value accretive acquisition of additional working interest in 16 selected producing properties from affiliates of Castex Energy 2005. The transaction was valued at PV-20 of PDP, provides strong incremental cash flow and ensures operational control over most of the assets, which the Company already held working interest in. At closing, the Company issued approximately 4.60 million common shares to the sellers, bringing the current outstanding share count to 73.0 million. Talos has entered into several gas hedging contracts accounting for the majority of the PDP volumes associated with the acquired assets through year-end 2022.
  • Lease Sale 254: Results of the March 2020 lease sale were recently finalized, with Talos acquiring four Green Canyon area blocks in a joint package bid with affiliates of bp plc. The Company acquired a 25.0% working interest in several sub-salt Miocene prospects in Green Canyon blocks 319, 320, 322 and 363, comprising 23,040 gross or 5,760 net acres, for a net cost of approximately $0.9 million, or $159/acre. As of June 30, 2020, Talos holds approximately 1.4 million gross acres of leasehold in the U.S. Gulf of Mexico (0.7 million net), of which approximately 50% is held by production and 50% is primary term.
  • Production Shut-ins: Production deferrals for the quarter totaled approximately 1.3 MMBoe or 14.4 MBoe/d, primarily comprised from non-operated well and facilities shut-ins, Talos accelerated maintenance projects and Tropical Storm Cristobal. Additionally, the company permanently shuttered approximately 0.6 MBoe/d from legacy shallow water properties that had higher operating costs.
  • Ram Powell Platform: Production at the Company’s Ram Powell facility is currently shut-in for an unplanned riser repair procedure. Talos expects production at the facility to resume in September of 2020 pending the completion and certification of repairs. Prior to the shut-in, Talos’s net production from Ram Powell was approximately 4.8 MBoe/d net.
  • COVID-19 Response: In response to COVID-19, Talos has continued to take precautionary measures to protect the safety of its employees and contractors as well as to ensure operational continuity. Talos corporate employees are continuing to work from home until further notice regarding formal office location re-openings. The Company has instituted numerous safety procedures and health checks for offshore staff, resulting in zero facility downtime to date due to COVID-19.

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

  • Claiborne: The Claiborne #3 development well and Claiborne #1 recompletion project were finalized in the second quarter and brought online late June, collectively increasing production rates from the field by 13.5 MBoe/d gross, 2.6 MBoe/d net.
  • Tornado IV: Drilling operations encountered geological and pressure conditions in line with expectations and logged 87 feet of net pay in the B-6 Upper zone. Talos has finalized the completion of the B-6 Upper zone and expects first production by the end of the third quarter.
  • Kaleidoscope: Drilling operations from the Company’s Green Canyon 18 facility are ongoing with the first objective expected to be encountered early August. Talos expects to initiate completion activities soon thereafter with first production expected by the end of the third quarter of 2020.
  • Bulleit: Following start-up of the Tornado IV well, the rig will mobilize to the Green Canyon 21 Bulleit well and commence completion activities. Tie-in activities to Talos’s Green Canyon 18 facility are ongoing in preparation for first production, which is expected by the end of the third quarter of 2020.

Upon completion of these projects by the end of September, the Company’s capital investment is expected to be significantly reduced, with the fourth quarter expected to have the lowest level of investment of 2020.

Drilling and Exploration Activities – Mexico

  • Block 7: On July 7, 2020, the Company received a notice from Mexico’s Ministry of Energy (“SENER”) instructing the partners of Block 7 and Petróleos Mexicanos (“Pemex”) to unitize the Zama field. The formal notice establishes a firm deadline to advance the unitization process, which is required before a field development plan can be finalized and the partners can reach Final Investment Decision (“FID”).
  • Block 31: Netherland, Sewell and Associates, Inc. (“NSAI”) recently completed an independent resource evaluation of the Xaxamani discovery. NSAI provided a “best estimate” of the gross resources for the asset at over 100.0 MMBoe, with approximately 95% oil. The discovery is located in very shallow waters (approximately 60 feet) and is less than two miles from shore. Talos holds a 25% participation interest in Block 31.

2020 Guidance

Talos expects to exit 2020 with a production rate between 71.0 – 73.0 MBoe/d.

For the full year 2020, the Company expects production at the low end of its previously stated production forecast range of 61.0 – 64.4 MBoe/d primarily due to greater than anticipated second quarter shut-ins across our portfolio and Ram Powell repairs impacting third-quarter production, offset by production from the recently acquired assets.

Talos expects cash operating expenses and general and administrative expenses to be in the lower-end of its previously stated forecast ranges of $275$300 million and $57$62 million, respectively, for the full year 2020. The full year expectations reflect Talos’s progress in realizing operational efficiencies and more appropriately sizing project and corporate staffing for current activity levels. The Company’s expectations are inclusive of incremental lease operating expenses and other costs associated with the recently closed acquisition as well as additional expenses associated with operational safety related to COVID-19.

Talos expects capital expenditures to remain in line with its forecast range of $355$380 million for the full year 2020.

Mid-Year 2020 Reserves

As of June 30, 2020, Talos had proved reserves of 189.5 MMBoe, with 67.0% oil and 76.0% proved developed, pro forma for the recently closed acquisition. The PV-10 of proved reserves was $2.8 billion. The reserves and associated PV-10 are fully burdened by and net of all plugging & abandonment costs associated with the properties included in the reserves report. The following table summarizes Talos’s pro forma proved reserves at June 30, 2020:


Summary of Pro Forma Proved Reserves


MBoe

%of Total Proved

Percent Oil

PV-10(1) ($MM)

Proved Developed Producing

93,298

49.2%

69.6%

$1,822

Proved Developed Non-Producing

50,641

26.7%

61.7%

548

Total Proved Developed

143,938

76.0%

66.8%

2,370

Proved Undeveloped

45,527

24.0%

67.4%

450

Total Proved

189,465

100.0%

67.0%

$2,820

In addition to the proved reserves, Talos’s pro forma probable reserves at mid-year 2020 were 79.7 MMBoe and had a PV-10 of $1.3 billion.

In accordance with guidelines established by the SEC, the Company’s estimated proved reserves as of June 30, 2020 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 June 30, 2020. 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 PV-10 of Talos’s proved reserves at June 30, 2020 is based on an average crude oil price of $47.17 per barrel and an average natural gas price of $2.07 per MMBtu, prior to being adjusted for quality, transportation, fees, energy content and basis differentials.

FIRST QUARTER 2020 RESULTS

Key Financial Highlights:


Three Months Ended

June 30, 2020


Period results ($ million, except per share and per Boe amounts):




Total Revenues(2) (inclusive of hedges)

$

174.9


Net Loss

$

(140.6)


Loss per diluted share

$

(2.14)


Adjusted Net Loss (1)

$

(29.4)


Adjusted Loss per diluted share(1)

$

(0.45)


Adjusted EBITDA(1)

$

97.5


Capital Expenditures (including Plug & Abandonment)

$

129.1


Adjusted EBITDA Margin(1):




Adjusted EBITDA (% of Revenue, inclusive of hedges)


56

%

Adjusted EBITDA per Boe

$

20.41


Production, Realized Prices and Revenue

Production for the second quarter of 2020 was 4.8 MMBoe, with oil production accounting for 69% of the total. Oil price realizations, net of certain gathering, transportation, quality differentials and other costs, were $22.71 per barrel equivalent, before hedges.



Three Months Ended

June 30, 2020


Production volumes





Oil production volume (MBbls)



3,279


Natural Gas production volume (MMcf)



6,997


NGL production volume (MBbls)



330


Total production volume (MBoe)



4,775







Average net daily production volumes





Oil (MBbl/d)



36.0


Natural Gas (MMcf/d)



76.9


NGL (MBbl/d)



3.6


Total average net daily (MBoe/d)



52.4







Average realized prices (excluding hedges)(3)





Oil ($/Bbl)


$

22.71


Natural Gas ($/MMBtu)



1.59


NGL ($/Bbl)



5.95


Average realized price ($/Boe)



18.34







Average NYMEX prices





WTI ($/Bbl)


$

27.96


Henry Hub ($/MMBtu)


$

1.71







Revenues ($ million)





Oil


$

74.5


Natural Gas



11.1


NGL



2.0


Revenue – Operations


$

87.6


Other revenue



1.3


Total revenue


$

88.9


Net cash receipts (payments) on settled derivative instruments



86.0


Total revenue inclusive of realized impact of hedges


$

$174.9


 


Three Months Ended June 30, 2020


Production


% Oil


% Liquids


% Operated

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








Green Canyon Area

12.8


80%


87%


96%

Mississippi Canyon Area

25.0


79%


87%


65%

Shelf and Gulf Coast

14.7


41%


47%


69%

Total average net daily (MBoe/d)

52.4


69%


76%


75%

Expenses

Total lease operating expenses (“LOE”), inclusive of workover and maintenance and insurance costs for the quarter, were $63.9 million or $13.38/Boe. General and administrative expenses (“G&A”) for the quarter, excluding stock-based compensation, transaction-related expenses and other one-time time expenses, was $11.3 million, or $2.38/Boe.



Three Months

Ended June 30,

2020



Per Boe


Lease Operating Expenses


$

63.9



$

13.38


General & Administrative Expenses (excluding non-cash and non-recurring items)


$

11.3



$

2.38


Other Financial Metrics

Capital Expenditures & Asset Management Activities

Capital expenditures for the quarter were $129.1 million, inclusive of plugging & abandonment costs.



Three Months Ended

June 30, 2020


Capital Expenditures





U.S. Drilling & Completions


$

90.3


Mexico Appraisal & Exploration



(0.1)


Asset Management



11.4


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



15.1


Total Capital Expenditures


$

116.9


Plugging & Abandonment



12.2


Total Capital Expenditures and Plugging & Abandonment


$

129.1


Liquidity & Debt

Talos has over $400.0 million of liquidity and as of June 30, 2020, maintained $107.9 million in cash on hand and $650.0 million drawn on the $985.0 million borrowing base under its credit facility. Not included in the liquidity number is an additional $25.0 million the Company could have access to, pending certain lender approvals.

The Company had approximately $1,079 million in total debt, inclusive of $71.2 million related to the HP-I finance lease. Inclusive of eight months contribution from the recent ILX/Castex acquisition, Net Debt to Credit Facility LTM Adjusted EBITDA(1), as determined in accordance with the Company’s credit agreement, was 1.4x. Credit Facility LTM Adjusted EBITDA(1) does not include any pro forma impact from the Company’s most recently announced acquisition of assets from Castex Energy 2005. Excluding the ILX/Castex contribution, Net Debt to LTM Adjusted EBITDA(1) ratio was 1.7x.

Footnotes:

(1)

Adjusted Net Loss, Adjusted Loss per Share, Adjusted EBITDA, Adjusted EBITDA Margin, Credit Facility LTM Adjusted EBITDA 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 $1.3 million of federal royalty refund.

(3)

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

HEDGES

The following table reflects the current contracted volumes and weighted average prices the Company will receive under the terms of its derivative contracts, including contracts entered into following the end of the quarter:



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)

  July – December 2020


Swaps


30,674


$44.45


̶


̶

  July – December 2020


Collars


5,000


̶


$50.00


$57.09

  January – December 2021


Swaps


11,718


$42.29


̶


̶

  January – December 2021


Collars


1,000


̶


$30.00


$40.00

  January – December 2022


Swaps


3,496


$44.25


̶


̶












Crude-LLS











  January – December 2021


Swaps


3,000


$38.83


̶


̶












Natural Gas-HH NYMEX




(MMBtu)


(Per MMBtu)


(Per MMBtu)


(Per MMBtu)

  July – December 2020


Swaps


64,261


$2.26


̶


̶

  January – December 2021


Swaps


48,737


$2.47


̶


̶

  January – December 2021


Collars


5,000


̶


$2.50


$3.10

  January – December 2022


Swaps


15,490


$2.42


̶


̶

CONFERENCE CALL AND WEBCAST INFORMATION

Talos will host an earnings conference call, which will be broadcast live over the internet, tomorrow, Thursday, August 6, 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 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 through August 13, 2020 and can be accessed by dialing 1-877-344-7529 and using access code 10146030.

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, including with respect to repairs to the Ram Powell facility, 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, 2019 and our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2020, 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.

Talos Energy Inc.

Condensed Consolidated Balance Sheets

(In thousands, except per share amounts)



June 30, 2020



December 31, 2019



(Unaudited)






ASSETS








Current assets:








Cash and cash equivalents

$

107,855



$

87,022


Accounts receivable








Trade, net


67,042




107,842


Joint interest, net


52,777




16,552


Other


21,697




6,346


Assets from price risk management activities


72,666




8,393


Prepaid assets


45,689




65,877


Other current assets


1,982




1,952


Total current assets


369,708




293,984


Property and equipment:








Proved properties


4,674,529




4,066,260


Unproved properties, not subject to amortization


274,690




194,532


Other property and equipment


32,262




29,843


Total property and equipment


4,981,481




4,290,635


Accumulated depreciation, depletion and amortization


(2,247,009)




(2,065,023)


Total property and equipment, net


2,734,472




2,225,612


Other long-term assets:








Assets from price risk management activities


1,409





Other well equipment inventory


14,458




7,732


Operating lease assets


7,351




7,779


Other assets


47,250




54,375


Total assets

$

3,174,648



$

2,589,482


LIABILITIES AND STOCKHOLDERS’ EQUITY








Current liabilities:








Accounts payable

$

104,151



$

71,357


Accrued liabilities


184,992




154,816


Accrued royalties


12,772




31,729


Current portion of asset retirement obligations


44,977




61,051


Liabilities from price risk management activities


26,615




19,476


Accrued interest payable


10,603




10,249


Current portion of operating lease liabilities


1,695




1,594


Other current liabilities


22,073




20,180


Total current liabilities


407,878




370,452


Long-term liabilities:








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


997,041




732,981


Asset retirement obligations


387,083




308,427


Liabilities from price risk management activities


7,018




511


Operating lease liabilities


19,228




17,239


Other long-term liabilities


61,847




81,595


Total liabilities


1,880,095




1,511,205


Commitments and contingencies (Note 11)








Stockholders’ Equity:








Preferred stock, $0.01 par value; 30,000,000 shares authorized and no shares issued or outstanding as of June 30, 2020 and December 31, 2019






Common stock $0.01 par value; 270,000,000 shares authorized; 68,414,782 and 54,197,004 shares issued and outstanding as of June 30, 2020 and December 31, 2019, respectively


684




542


Additional paid-in capital


1,545,138




1,346,142


Accumulated deficit


(251,269)




(268,407)


Total stockholders’ equity


1,294,553




1,078,277


Total liabilities and stockholders’ equity

$

3,174,648



$

2,589,482


 

Talos Energy Inc.

Condensed Consolidated Statements of Operations

(In thousands, except per common share amounts)



Three Months Ended June 30,



Six Months Ended June 30,



2020



2019



2020



2019


Revenues:
















Oil revenue

$

74,471



$

256,908



$

241,095



$

412,587


Natural gas revenue


11,140




14,746




23,038




29,193


NGL revenue


1,964




6,645




6,265




11,711


Other


1,299




8,511




6,240




12,032


Total revenue


88,874




286,810




276,638




465,523


Operating expenses:
















Lease operating expense


63,882




54,455




122,123




122,414


Production taxes


166




506




415




1,088


Depreciation, depletion and amortization


88,443




95,806




181,986




160,393


Write-down of oil and natural gas properties





12,361




57




12,361


Accretion expense


13,794




9,945




26,211




19,552


General and administrative expense


17,192




18,865




44,661




36,474


Total operating expenses


183,477




191,938




375,453




352,282


Operating income (expense)


(94,603)




94,872




(98,815)




113,241


Interest expense


(26,190)




(24,932)




(52,040)




(50,150)


Price risk management activities income (expense)


(68,682)




29,990




174,535




(79,589)


Other income (expense)


(528)




831




(674)




1,264


Net income (loss) before income taxes


(190,003)




100,761




23,006




(15,234)


Income tax benefit (expense)


49,392




(5,997)




(5,868)




362


Net income (loss)

$

(140,611)



$

94,764



$

17,138



$

(14,872)


















Net income (loss) per common share:
















Basic

$

(2.14)



$

1.75



$

0.28



$

(0.27)


Diluted

$

(2.14)



$

1.74



$

0.28



$

(0.27)


Weighted average common shares outstanding:
















Basic


65,807




54,178




62,023




54,167


Diluted


65,807




54,451




62,318




54,167


 

Talos Energy Inc.

Condensed Consolidated Statements of Cash Flows

(In thousands)



Six Months Ended June 30,



2020



2019


Cash flows from operating activities:








Net income (loss)

$

17,138



$

(14,872)


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








Depreciation, depletion, amortization and accretion expense


208,197




179,945


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


190




12,361


Amortization of deferred financing costs and original issue discount


3,985




2,393


Equity based compensation, net of amounts capitalized


3,974




3,220


Price risk management activities expense (income)


(174,535)




79,589


Net cash received (paid) on settled derivative instruments


122,499




(12,562)


Gain on extinguishment of debt


(1,470)





Settlement of asset retirement obligations


(18,496)




(32,206)


Changes in operating assets and liabilities:








Accounts receivable


(5,164)




(32,118)


Other current assets


15,128




12,259


Accounts payable


12,645




23,646


Other current liabilities


16,039




(37,164)


Other non-current assets and liabilities, net


(8,518)




(1,870)


Net cash provided by operating activities


191,612




182,621


Cash flows from investing activities:








Exploration, development and other capital expenditures


(154,628)




(229,601)


Cash paid for acquisitions, net of cash acquired


(296,966)




(32,916)


Proceeds from sale of other property and equipment





5,369


Net cash (used in) investing activities


(451,594)




(257,148)


Cash flows from financing activities:








Redemption of Senior Notes and other long-term debt


(1,209)




(10,567)


Proceeds from Bank Credit Facility


300,000




75,000


Repayment of Bank Credit Facility





(25,000)


Deferred financing costs


(1,287)





Other deferred payments


(7,575)




(9,921)


Payments of finance lease


(8,323)




(6,759)


Employee stock transactions


(791)




(283)


Net cash provided by financing activities


280,815




22,470










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


20,833




(52,057)


Cash, cash equivalents and restricted cash:








Balance, beginning of period


87,022




141,162


Balance, end of period

$

107,855



$

89,105










Supplemental Non-Cash Transactions:








Capital expenditures included in accounts payable and accrued liabilities

$

113,461



$

165,310


Debt exchanged for common stock

$

35,960





Supplemental Cash Flow Information:








Interest paid, net of amounts capitalized

$

34,163



$

31,413


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,” “Cash-Based G&A,” “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 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 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

June

30, 2020


Three

Months

ended

March

31, 2020


Three

Months

ended

December

31, 2019


Three

Months

ended

September

30, 2019

Reconciliation of net income (loss) to Adjusted EBITDA:












  Net income (loss)

$

(140,611)


$

157,749


$

304


$

73,297

Interest expense


26,190



25,850



24,574



23,123

Income tax expense (benefit)


(49,392)



55,260



(36,569)



790

Depreciation, depletion and amortization


88,443



93,543



97,413



88,125

Accretion expense


13,794



12,417



7,521



7,316

  EBITDA


(61,576)



344,819



93,243



192,651

Write-down of oil and natural gas properties




57



(1,557)



1,417

Transaction and non-recurring expenses(2)


3,498



7,758



4,111



146

Derivative fair value (gain) loss(1)


68,682



(243,217)



59,508



(43,760)

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


86,039



36,460



(1,618)



5,360

Gain on extinguishment of debt


(1,470)





(1,470)



Non-cash write-down of other well equipment inventory




133



165



Non-cash equity-based compensation expense


2,347



1,627



1,800



1,944

  Adjusted EBITDA


97,520



147,637



154,182



157,758

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


(86,039)



(36,460)



1,618



(5,360)

Adjusted EBITDA excluding hedges


11,481



111,177



155,800



152,398

Production and Revenue:












Boe(2)


4,775



5,287



4,966



4,843

Revenue – Operations


87,575



182,823



233,240



227,828

Adjusted EBITDA margin and Adjusted EBITDA excl hedges margin:












Adjusted EBITDA divided by Revenue – Operations (%)


111%



81%



66%



69%

Adjusted EBITDA per Boe(2)

$

20.41


$

27.92


$

31.05


$

32.57

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


13%



61%



67%



67%

Adjusted EBITDA excl hedges per Boe(2)

$

2.40


$

21.03


$

31.37


$

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 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

June 30, 2020


Reconciliation of Adjusted EBITDA to Free Cash Flow





Adjusted EBITDA


$

97,519


Less: Capital Expenditures and Plugging & Abandonment



(129,050)


Less: Interest Expense



(26,190)


Free Cash Flow


$

(57,721)


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

June 30, 2020


Reconciliation of Net Income to Adjusted Net Income:





Net Income


$

(140,611)


Transaction related costs



3,498


Derivative fair value (gain) loss(1)



68,682


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



86,039


Non-cash income tax expense



(49,392)


Non-cash equity-based compensation expense



2,347


Adjusted Net Income


$

(29,437)







Weighted average common shares outstanding at March 31, 2020:





Basic



65,807


Diluted



65,807







Loss per common share:





Basic


$

(2.14)


Diluted


$

(2.14)







Adjusted Loss per common share:





Basic


$

(0.45)


Diluted


$

(0.45)




(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.

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





11.00% Second-Priority Senior Secured Notes – due April 2022


$

351,659


7.50% Senior Notes – due May 2022



6,060


Bank Credit Facility – matures May 2022



650,000


Finance lease



71,212


Total Debt


$

1,078,931


Less: Cash and cash equivalent



(107,855)


Net Debt


$

971,076







Calculation of LTM EBITDA:





Adjusted EBITDA for three months period ended September 30, 2019


$

157,758


Adjusted EBITDA for three months period ended December 31, 2019



155,784


Adjusted EBITDA for three months period ended March 31, 2020



147,619


Adjusted EBITDA for three months period ended June 30, 2020



97,519


LTM Adjusted EBITDA


$

558,680


ILX/Castex Assets Adjusted EBITDA for eight months prior to closing



135,345


Credit Facility LTM Adjusted EBITDA


$

694,025







Reconciliation of Net Debt to LTM Adjusted EBITDA:





Net Debt / LTM Adjusted EBITDA



1.7x


Net Debt / Credit Facility LTM Adjusted EBITDA



1.4x


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