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

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Mar 11, 2020, 18:00 ET

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:

Net Income of $0.3 million ($0.01 earnings per share – diluted) for the fourth quarter and Adjusted Net Income⁽¹⁾ of $71.6 million ($1.31 adjusted earnings per share – diluted) in the fourth quarter of 2019.
Production of 54.0 thousand barrels of oil equivalent per day ("MBoe/d") in the fourth quarter, of which 73% was oil and 79% was liquids.
Average realized prices of $57.65/Bbl of oil in the fourth quarter, net of transport and quality deductions, or $0.83/Bbl above the average WTI benchmark price of $56.82/Bbl during the same period.
Adjusted EBITDA⁽¹⁾ of $155.8 million in the fourth quarter and Adjusted EBITDA excluding hedges⁽¹⁾ of $157.4 million. Adjusted EBITDA Margin⁽¹⁾ per Boe of $31.37, or 67%, and Adjusted EBITDA Margin excluding hedges⁽¹⁾ per Boe of $31.70, or 67%.
Capital expenditures, inclusive of plugging and abandonment costs, were $86.8 million in the fourth quarter.
Free Cash Flow⁽¹⁾ of $44.4 million in the fourth quarter.
Year-end 2019 proved reserves of 141.7 million barrels of oil equivalent ("MMBoe"), of which 69% is proved developed with a PV-10 of $3.0 billion and Standardized Measure of $2.5 billion. Pro forma year-end 2019 proved reserves for the recently closed transaction, inclusive of plugging and abandonment obligations:

At SEC prices, 181.3 MMBoe, of which 73% is proved developed, and PV-10 of $3.6 billion.
As a supplemental sensitivity, at $45.00 WTI / $2.00 Henry Hub, 166.7 MMBoe, of which 73% is proved developed, and PV-10 of $2.5 billion.

As of December 31, 2019, liquidity position of $673.4 million. Net Debt to Last Twelve Months ("LTM") Adjusted EBITDA⁽¹⁾ was 1.2x. Liquidity as of February 28, 2020 was approximately $600.0 million.
Borrowing base increased to $1,150.0 million from $950.0 million as of February 28, 2020.
Approximately 10.6 million barrels of oil hedged for 2020 with a weighted average price of $54.05 per barrel of WTI.

(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

Claiborne Drilling Success: The third development well (MC 794 #3) being drilled in the Claiborne field has reached total depth and has determined to be a success. The well logged 284 feet of true vertical pay across five different pay sands. The well was drilled on budget, exceeds pre-drill expectations and will allow partners to materially increase production and more efficiently develop the asset. The well will be tied-back to the Coelacanth production facility via existing subsea infrastructure with first production expected by mid-year 2020. Completion operations in the MC 794#3 well will follow workover and recompletion activities in the MC 794 #1ST1 well, currently underway, that are designed to target highly productive existing pay sands in the Disc 12 reservoir. Talos owns a 25.3% working interest in the project. The Claiborne field is operated by Beacon Offshore Energy, and partners include affiliates of LLOG Exploration, Ridgewood Claiborne, LLC, a managed entity of Ridgewood Energy Corporation, Red Willow Offshore and CL&F Offshore.

Drilling and Exploration Activities – Mexico

Block 7: Following the successful completion of the Zama appraisal program, Talos engaged Netherland, Sewell & Associates, Inc. ("Netherland Sewell", or "NSAI") to complete an independent analysis of the discovery. Netherland Sewell's "Best Estimate" of the 2C gross recoverable resource estimate is approximately 670 MMBoe, with 60% of those volumes on Talos's Block 7. NSAI's "High Estimate" of the 3C gross recoverable resource estimate is approximately 1,010 MMBoe, exceeding the high end of the Company's pre-appraisal estimated range of 400 – 800 MMBoe. Talos continues to progress the project closer towards a final investment decision ("FID") by focusing efforts on the front-end engineering and design ("FEED"). Talos continues to be engaged in unitization discussions with Petroleos Mexicanos ("Pemex") with the goal of declaring FID in 2020; however, as previously disclosed, the timing to FID is in part dependent on finalizing unitization discussions with Pemex. Talos holds a 35% participating interest and is Operator of Block 7.

Since 2017, Talos has drilled or participated in eight wells in offshore Mexico, with six successful results leading to two material oil discoveries.

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⁾
		MBoe		Percent of Total Proved		Percent Oil		(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
		MBoe		Percent of Total Proved		Percent Oil		(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
	MBoe		Percent of Total Proved		Percent Oil		(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
[email protected]

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.

SOURCE Talos Energy