talo-10q_20190930.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)

☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2019

☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 001-38497

Talos Energy Inc.

(Exact Name of Registrant as Specified in its Charter)

Delaware	82-3532642
( State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
333 Clay Street, Suite 3300 Houston, TX	77002
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (713) 328-3000

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class		Trading Symbol(s)		Name of Each Exchange on Which Registered
Common Stock		TALO		NYSE

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☐	Accelerated filer	☒
Non-accelerated filer	☐	Smaller reporting company	☐
Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

As of November 1, 2019, the registrant had 54,196,984 shares of common stock, $0.01 par value per share, outstanding.

TABLE OF CONTENTS

		Page

GLOSSARY		1

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		2

PART I – FINANCIAL INFORMATION

Item 1.	Condensed Consolidated Financial Statements	4

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	42

Item 4.	Controls and Procedures	42

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	43

Item 1A.	Risk Factors	43

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	43

Item 3.	Defaults upon Senior Securities	43

Item 4.	Mine Safety Disclosures	43

Item 5.	Other Information	43

Item 6.	Exhibits	44

	Signatures	45

GLOSSARY

Barrel or Bbl. One stock tank barrel, or 42 United States gallons liquid volume.

Boe. One barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate.

Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water one degree Fahrenheit.

Completion. The installation of permanent equipment for the production of oil or natural gas.

Deepwater. Water depths of more than 600 feet.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.

MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.

MBblpd. One thousand barrels of crude oil or other liquid hydrocarbons per day.

MBoe. One thousand barrels of oil equivalent.

MBoepd. One thousand barrels of oil equivalent per day.

Mcf. One thousand cubic feet of natural gas.

Mcfpd. One thousand cubic feet of natural gas per day.

MMBtu. One million Btus.

MMcf. One million cubic feet of natural gas.

MMcfpd. One million cubic feet of natural gas per day.

NGL. Natural gas liquid. Hydrocarbons which can be extracted from wet natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs consist primarily of ethane, propane, butane and natural gasoline.

NYMEX. The New York Mercantile Exchange.

Proved reserves. Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Proved undeveloped reserves. In general, proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. The Securities and Exchange Commission provides a complete definition of undeveloped oil and gas reserves in Rule 4-10(a)(31) of Regulation S-X.

SEC. The Securities and Exchange Commission.

SEC pricing. The unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the prior twelve months, adjusted by lease for market differentials (quality, transportation, fees, energy content, and regional price differentials). The Securities and Exchange Commission provides a complete definition of prices in “Modernization of Oil and Gas Reporting” (Final Rule, Release Nos. 33-8995; 34-59192).

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in or incorporated by reference into this report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this report, 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 report, 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. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. Forward-looking statements may include statements about:

•

business strategy;

•

reserves;

•

exploration and development drilling prospects, inventories, projects and programs;

•

our ability to replace the reserves that we produce through drilling and property acquisitions;

•

financial strategy, liquidity and capital required for our development program and other capital expenditures;

•

realized oil and natural gas prices;

•

timing and amount of future production of oil, natural gas and NGLs;

•

our hedging strategy and results;

•

future drilling plans;

•

availability of pipeline connections on economic terms;

•

competition, government regulations and political developments;

•

our ability to obtain permits and governmental approvals;

•

pending legal, governmental or environmental matters;

•

our marketing of oil, natural gas and NGLs;

•

leasehold or business acquisitions on desired terms;

•

costs of developing properties;

•

general economic conditions;

•

credit markets;

•

impact of new accounting pronouncements on earnings in future periods;

•

estimates of future income taxes;

•

our estimates and forecasts of the timing, number, profitability and other results of wells we expect to drill and other exploration activities;

•

uncertainty regarding our future operating results and our future revenues and expenses; and

•

plans, objectives, expectations and intentions contained in this report that are not historical.

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, failure to find, acquire or gain access to other discoveries and prospects or to successfully develop and produce from our current discoveries and prospects, geologic risk, drilling and other operating risks, well control risk, 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 and the other risks discussed in “Part I, Item 1A. Risk Factors” of Talos Energy Inc.’s Annual Report for the year ended December 31, 2018.

Reserve engineering is a process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify upward or downward revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

Should one or more of the risks or uncertainties described herein 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, included in this report 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. All forward-looking statements speak only as of the date of this report. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this report.

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

TALOS ENERGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except 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

The accompanying notes are an integral part of these condensed consolidated financial statements.

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 expense		(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

The accompanying notes are an integral part of these condensed consolidated financial statements.

TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

STOCKHOLDERS’ EQUITY (DEFICIT)

(In thousands, except share amounts)

(Unaudited)

						Additional						Total
	Common Stock					Paid-in			Accumulated			Stockholders'
	Shares			Amounts		Capital			Deficit			Equity
Balance at June 30, 2018		54,155,768		$	542	$	1,331,834		$	(646,531	)	$	685,845
Equity based compensation	—				—		810			—			810
Net income	—				—		—			13,109			13,109
Balance at September 30, 2018		54,155,768		$	542	$	1,332,644		$	(633,422	)	$	699,764

Balance at June 30, 2019		54,191,693		$	542	$	1,339,507		$	(342,008	)	$	998,041
Equity based compensation		6,527			—		3,529			—			3,529
Shares withheld for taxes on equity transactions		(2,075	)		—		(43	)		—			(43	)
Net income	—				—		—			73,297			73,297
Balance at September 30, 2019		54,196,145		$	542	$	1,342,993		$	(268,711	)	$	1,074,824

												Total
						Additional						Stockholders'
	Common Stock					Paid-in			Accumulated			Equity
	Shares			Amounts		Capital			Deficit			(Deficit)
Balance at December 31, 2017		31,244,085		$	312	$	493,952		$	(548,351	)	$	(54,087	)
Cumulative effect adjustment	—				—		—			(325	)		(325	)
Sponsor Debt Exchange		2,874,049			29		101,971			—			102,000
Stone Combination		20,037,634			201		731,763			—			731,964
Equity based compensation		—			—		4,958			—			4,958
Net loss	—				—		—			(84,746	)		(84,746	)
Balance at September 30, 2018		54,155,768		$	542	$	1,332,644		$	(633,422	)	$	699,764

Balance at December 31, 2018		54,155,768		$	542	$	1,334,090		$	(327,136	)	$	1,007,496
Equity based compensation		52,574			—		9,229			—			9,229
Shares withheld for taxes on equity transactions		(12,197	)		—		(326	)		—			(326	)
Net income	—				—		—			58,425			58,425
Balance at September 30, 2019		54,196,145		$	542	$	1,342,993		$	(268,711	)	$	1,074,824

The accompanying notes are an integral part of these condensed consolidated financial statements.

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

The accompanying notes are an integral part of these condensed consolidated financial statements.

TALOS ENERGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2019

(Unaudited)

Note 1 — Formation and Basis of Presentation

Formation and Nature of Business

Talos Energy Inc. (“Talos,” the “Company,” “we,” “us” or “our”) is a technically driven independent exploration and production company focused on safely and efficiently maximizing cash flows and long-term value through our operations in the United States (“U.S.”) Gulf of Mexico and offshore Mexico. As one of the largest public independent producers in the U.S. Gulf of Mexico, we leverage decades of geology, geophysics and offshore operational expertise in acquisition, exploration, exploitation and development of deep and shallow water assets in key geological trends that are present in many offshore basins around the world. Our activities offshore Mexico provide high impact exploration opportunities in an oil rich emerging basin.

Talos was formed in connection with the business combination between Talos Energy LLC and Stone Energy Corporation (“Stone”) that occurred on May 10, 2018, pursuant to which Talos Energy LLC and Stone became indirect wholly-owned subsidiaries of Talos Energy Inc.

Talos Energy LLC

Talos Energy LLC was formed in 2011 and commenced commercial operations on February 6, 2013. Prior to February 6, 2013, Talos Energy LLC incurred certain general and administrative expenses associated with the start-up of its operations.

On February 3, 2012, Talos Energy LLC completed a transaction with certain funds and other alternative investment vehicles managed by Apollo Management VII, L.P. and Apollo Commodities Management, L.P., with respect to Series I (“Apollo Funds”), and entities controlled by or affiliated with Riverstone Energy Partners V, L.P. (“Riverstone Funds”) and members of management pursuant to which Talos Energy LLC received a private equity capital commitment.

Stone Combination

On May 10, 2018 (the “Closing Date”), the Company consummated the transactions contemplated by that certain Transaction Agreement dated as of November 21, 2017 (the “Transaction Agreement”), pursuant to which, among other items, each of Stone, Talos Production LLC and Talos Energy LLC became wholly-owned subsidiaries of the Company (the “Stone Combination”). Concurrently with the consummation of the Transaction Agreement, the Company consummated the transactions contemplated by that certain Exchange Agreement, dated as of November 21, 2017 (the “Exchange Agreement”) pursuant to which (i) the Apollo Funds and Riverstone Funds contributed $102.0 million in aggregate principal amount of 9.75% Senior Notes due 2022 issued by Talos Production LLC and Talos Production Finance, Inc. (together, “Talos Issuers”) to the Company in exchange for an aggregate of 2,874,049 shares of Talos common stock; (ii) the holders of second lien bridge loans (“11.00% Bridge Loans”) exchanged such 11.00% Bridge Loans for $172.0 million aggregate principal amount of 11.00% Second-Priority Senior Secured Notes due 2022 of the Talos Issuers (“11.00% Senior Secured Notes”) and (iii) certain holders of 7.50% Senior Secured Notes due 2022 issued by Stone (“7.50% Stone Senior Notes”) exchanged such notes for $137.4 million aggregate principal amount of 11.00% Senior Secured Notes. Prior to the Closing Date, the Company did not conduct any material activities other than those incident to its formation and the matters contemplated by the Transaction Agreement. See Note 2 – Acquisitions for further details regarding the Stone Combination.

Substantially concurrently therewith, the Company consummated an exchange offer and consent solicitation, pursuant to which other holders of the 7.50% Stone Senior Notes exchanged their 7.50% Stone Senior Notes for 11.00% Senior Secured Notes and a cash payment. Approximately $81.5 million in aggregate principal amount of the 7.50% Stone Senior Notes were validly tendered, and approximately $6.1 million in aggregate principal amount of 7.50% Stone Senior Notes remained outstanding as of the Closing Date.

Basis of Presentation and Consolidation

The condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Accordingly, certain information and disclosures normally included in complete financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to such rules and regulations. In the opinion of management, these financial statements include all adjustments, which unless otherwise disclosed, are of a normal recurring nature, necessary for a fair presentation of the financial position, results of operations, cash flows and changes in equity for the periods presented. The results for interim periods are not necessarily indicative of results for the entire year. The Company has evaluated subsequent events through the date the condensed consolidated financial statements were issued. The unaudited financial statements and related notes included in this Quarterly Report on Form 10-Q (this “Quarterly Report”) should be read in conjunction with the Company’s audited Consolidated Financial Statements and related notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018 (our “2018 Annual Report”).

Talos Energy LLC was considered the accounting acquirer in the Stone Combination under GAAP. Accordingly, the historical financial and operating data of Talos Energy Inc., which covers periods prior to the Closing Date, reflects the assets, liabilities and results of operations of Talos Energy LLC and does not reflect the assets, liabilities and results of operations of Stone. For the periods prior to May 10, 2018, the Company retrospectively adjusted its Statements of Changes in Stockholders’ Equity and the weighted average shares used in determining earnings per share to reflect the number of shares Talos Energy LLC received in the Stone Combination. Beginning on May 10, 2018, common stock is presented to reflect the legal capital of Talos Energy Inc.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates.

The Company has one reportable segment, exploration and production of oil and natural gas. Substantially all of the Company’s proved reserves and production sales are related to the Company’s operations in the U.S.

Unless otherwise indicated or the context otherwise requires, references in this Quarterly Report to “Talos,” the “Company,” “we,” “us” or “our” refer to Talos Energy Inc. and its wholly-owned subsidiaries.

Recently Adopted Accounting Standards

Leases. In February 2016, the Financial Accounting Standards Board issued Accounting Standards Codification 2016-02, Leases (“Topic 842”) requiring an entity to recognize a right-of-use asset representing the right to use an underlying asset for the lease term and a lease liability representing the obligation associated with future lease payments for virtually all leases. The pattern of expense recognition in the income statement is dependent on lease classification as finance or operating. A lease is defined as a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment (an identified asset) for a period of time in exchange for consideration. However, Topic 842 does not apply to leases of mineral rights.

On January 1, 2019, the Company adopted Topic 842, using the modified retrospective approach, which does not require an adjustment to comparative-period financial statements. As such, results for reporting periods beginning January 1, 2019 are presented in accordance with Topic 842, while prior period amounts are reported in accordance with previous lease accounting treatment. The Company elected the package of practical expedients permitted under the transition guidance within the new standard, which, among other items, allowed Talos not to reassess whether expired or existing contracts, including land easements, contain a lease or reassess the classification and indirect costs associated with existing or expired leases. On the January 1, 2019 adoption date, the Company recorded a right-of-use asset of approximately $7.3 million and corresponding lease liability of $16.9 million representing the present value of its future operating lease payments. Upon the adoption of Topic 842, lease incentives are presented as a reduction to the right-of-use asset resulting in the difference between the right-of-use asset and lease liability. Adoption of this standard did not require an adjustment to retained earnings and did not impact the condensed consolidated statements of operations, condensed consolidated statements of cash flows or condensed consolidated statements of changes in stockholders’ equity. See Note 4 – Leases for further information.

Note 2 — Acquisitions

Asset Acquisitions

Each of the acquisitions below qualified as an asset acquisition that requires, among other items, that the cost of the assets acquired and liabilities assumed be recognized on the balance sheet by allocating the asset cost on a relative fair value basis. The fair value measurements of the oil and natural gas properties acquired and asset retirement obligations assumed were derived utilizing an income approach and based, in part, on significant inputs not observable in the market. These inputs represent Level 3 measurements in the fair value hierarchy and include, but are not limited to, estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and appropriate discount rates. These inputs required significant judgments and estimates by the Company’s management at the time of the valuation. Transaction costs incurred on an asset acquisition are capitalized as a component of the assets acquired and any contingent consideration is recognized as the contingency is resolved.

Acquisition of Gunflint Field

On January 11, 2019, the Company completed the acquisition of an approximate 9.6% non-operated working interest in the Gunflint Field located in the Mississippi Canyon area (the “Gunflint Acquisition”) from Samson Offshore Mapleleaf, LLC for $29.6 million ($27.9 million after customary purchase price adjustments).

The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on January 11, 2019 (in thousands):

Property and equipment	$	28,912
Asset retirement obligations		(996	)
Allocated purchase price	$	27,916

Acquisition of Whistler Energy II, LLC

On August 31, 2018, the Company completed the acquisition of all the issued and outstanding membership interests of Whistler Energy II, LLC (“Whistler”) from Whistler Energy II Holdco, LLC, an affiliate of Apollo Funds (the “Whistler Acquisition”), for $52.6 million ($14.8 million, net of $37.8 million of cash acquired). The $37.8 million of cash acquired consists of $30.8 million of cash collateral posted by Whistler and released by third party surety companies at closing and $7.0 million of cash on hand for working capital purposes. Through the acquisition, the Company acquired and assumed all of Whistler’s oil and natural gas assets and the associated asset retirement obligations for interests located in Green Canyon Block 18, Green Canyon Block 60 and Ewing Bank Blocks 944 and 988, including a fixed production platform on Green Canyon Block 18.

The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on August 31, 2018 (in thousands):

Current assets⁽¹⁾	$	45,337
Property and equipment		35,344
Other long-term assets		66
Current liabilities		(4,261	)
Other long-term liabilities		(23,862	)
Allocated purchase price	$	52,624

⁽¹⁾	Includes $37.8 million of cash acquired and trade receivables of $3.2 million, which the Company expects all to be realizable.

Business Combinations

Acquisitions qualifying as a business combination are accounted for under the acquisition method of accounting, which requires, among other items, that assets acquired and liabilities assumed be recognized on the condensed consolidated balance sheet at their fair values as of the acquisition date. The fair value measurements of the oil and natural gas properties acquired and asset retirement obligations assumed were derived utilizing an income approach and based, in part, on significant inputs not observable in the market. These inputs represent Level 3 measurements in the fair value hierarchy and include, but are not limited to, estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and appropriate discount rates. These inputs required significant judgments and estimates at the time of the valuation.

Combination between Talos Energy LLC and Stone Energy Corporation

On May 10, 2018, the Company consummated the transactions contemplated by the Transaction Agreement and the Exchange Agreement, pursuant to which, among other things, Talos Energy LLC and Stone became wholly-owned subsidiaries of the Company. The combination was executed as an all-stock transaction whereby the former stakeholders of Talos Energy LLC held approximately 63% of the Company’s outstanding common stock and the former stockholders of Stone held approximately 37% of the Company’s outstanding common stock as of the Closing Date.

The purchase price of $732.0 million is based on the closing price of Stone common stock and common warrants immediately prior to closing. The following table summarizes the purchase price (in thousands, except per share data):

Stone common stock - issued and outstanding as of May 9, 2018		20,038
Stone common stock price	$	35.49
Common stock value	$	711,149

Stone common stock warrants - issued and outstanding as of May 9, 2018		3,528
Stone common stock warrants price	$	5.90
Common stock warrants value	$	20,815
Total purchase price	$	731,964

The following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed, based on their fair values on May 10, 2018 (in thousands):


Current assets⁽¹⁾	$	372,963
Property and equipment		886,406
Other long-term assets		19,494
Current liabilities		(132,846	)
Long-term debt		(235,416	)
Other long-term liabilities		(178,637	)
Allocated purchase price	$	731,964

⁽¹⁾	Includes $293.0 million of cash acquired. The fair values of current assets acquired includes trade receivables and joint interest receivables of $43.3 million and $3.5 million, respectively, which the Company expects all to be realizable.

The following table presents revenue and net income attributable to the assets acquired in the Stone Combination for the three and nine months ended September 30, 2019 and 2018:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Revenue	$	97,213	$	134,989	$	313,335	$	204,298
Net income	$	40,775	$	75,968	$	147,186	$	120,390

Pro Forma Financial Information (Unaudited)

The following supplemental pro forma information (in thousands, except per common share amounts), presents the condensed consolidated statements of operations for the three and nine months ended September 30, 2018 as if the Stone Combination had occurred on January 1, 2018. The unaudited pro forma information was derived from historical combined statements of operations of the Company and Stone and adjusted to include (i) depletion and accretion expense applied to the adjusted basis of the oil and natural gas properties acquired, (ii) interest expense to reflect the debt transactions contemplated by the Exchange Agreement and (iii) general and administrative expense adjusted for transaction related costs incurred. This information does not purport to be indicative of results of operations that would have occurred had the Stone Combination occurred on January 1, 2018, nor is such information indicative of any expected future results of operations.

	Three Months Ended September 30, 2018		Nine Months Ended September 30, 2018
Revenue	$	282,868	$	754,520
Net income (loss)	$	20,566	$	(30,645	)
Basic net income (loss) per common share	$	0.38	$	(0.71	)
Diluted net income (loss) per common share	$	0.38	$	(0.71	)

Note 3 — Property, Plant and Equipment

Proved Properties. The Company’s interests in proved oil and natural gas properties are located in the U.S., primarily in the Gulf of Mexico deep and shallow waters. The Company follows the full cost method of accounting for its oil and natural gas exploration and development activities.

At September 30, 2019, the Company’s ceiling test computation of its U.S. oil and natural gas properties was based on SEC pricing of $63.88 per Bbl of oil, $2.81 per Mcf of natural gas and $24.26 per Bbl of NGLs. During the three and nine months ended September 30, 2019 and 2018, the Company’s ceiling test computation did not result in a write-down of its U.S. oil and natural gas properties.

Unproved Properties. Unproved capitalized costs of oil and natural gas properties excluded from amortization relate to unevaluated properties associated with acquisitions, leases awarded in the U.S. Gulf of Mexico federal lease sales, certain geological and geophysical costs, costs associated with certain exploratory wells in progress and capitalized interest. Unproved properties also include costs associated with the two blocks (Block 2 and Block 7) awarded on September 4, 2015 to the Company together with Sierra Oil & Gas S. de R.L de C.V. (“Sierra”) and Premier Oil Plc (“Premier” and collectively, the “Consortium”), located in the shallow waters off the coast of Mexico’s Veracruz and Tabasco states, by the National Hydrocarbons Commission (“CNH”), Mexico’s upstream regulator. On September 4, 2019, the CNH granted a two-year extension under the Consortium’s production sharing contract for Block 7. During any period in which unproved properties are assessed as proved or impaired, the associated costs are transferred to the full cost pool and are subject to amortization.

In September 2018, the Company entered into a transaction (the “Hokchi Cross Assignment”) with Hokchi Energy, S.A. de C.V. (“Hokchi”), a subsidiary of Pan American Energy LLC (“PAE”), to cross assign 25% participation interests (“PI”) in each of Block 2 and Block 31. The Company’s assignment of a 25% PI in Block 2 to Hokchi closed on December 21, 2018, and Hokchi’s assignment to the Company closed on May 22, 2019. In addition, Premier exercised its option to reduce its PI in Block 2 to zero and assigned a 5% PI to each of Sierra and Talos. Following the completion of the Hokchi Cross Assignment, Talos owns a 25% PI in each of Block 2 and Block 31, and Hokchi is the operator of the blocks.

As a result of the Company’s evaluation of unproved property located in Block 2 offshore Mexico, specifically future exploratory drilling opportunities, results from exploratory wells drilled and the Block 2 production sharing contract’s expiration date, the Company recorded a $1.4 million and $13.8 million non-cash impairment expense for the three and nine months ended September 30, 2019, respectively, presented as “Write-down of oil and natural gas properties” on the condensed consolidated statements of operations.

Capitalized Overhead. General and administrative expense in the Company’s financial statements is reflected net of capitalized overhead. The Company capitalizes overhead costs directly related to exploration, acquisition and development activities. Capitalized overhead for the three and nine months ended September 30, 2019 was $7.4 million and $21.4 million, respectively. Capitalized overhead for the three and nine months ended September 30, 2018 was $8.7 million and $16.2 million, respectively.

Asset Retirement Obligations. The discounted asset retirement obligations included “Current portion of asset retirement obligations” and “Asset retirement obligations” on the condensed consolidated balance sheets and the changes to that liability during the nine months ended September 30, 2019 were as follows (in thousands):


Asset retirement obligations at December 31, 2018	$	382,817
Fair value of asset retirement obligations assumed		5,047
Obligations settled		(54,406	)
Fair value of asset retirement obligations divested		(5,450	)
Accretion expense		26,868
Obligations incurred		4,111
Changes in estimate		26,225
Asset retirement obligations at September 30, 2019	$	385,212
Less: Current portion		63,404
Long-term portion	$	321,808

Note 4 — Leases

The Company enters into service contracts and other contractual arrangements for the use of office space, drilling, completion and abandonment equipment (e.g., drilling rigs), production related equipment (e.g., compressors) and other equipment from third-party lessors to support its operations. The Company’s leasing activities as a lessor are negligible. At inception, contracts are reviewed to determine whether the agreement contains a lease. Contracts are considered a lease when the arrangement either explicitly or implicitly conveys the right to control the use of the identified property, plant or equipment for a period of time in exchange for consideration. In order to obtain control, the lessee must obtain substantially all of the economic benefits for the use of the identified asset and have the right to direct the use of the identified asset. To the extent an arrangement is determined to include a lease, it is classified as either an operating or a finance lease, which dictates the pattern of expense recognition in the income statement. The Company has elected to not apply the recognition requirements of Topic 842 to leases with durations of twelve months or less (i.e. short-term).

Upon commencement of a lease, a right-of-use asset and corresponding lease liability are recorded on the consolidated balance sheet for all leases, regardless of classification. The right-of-use asset is initially measured as the lease liability adjusted for any payments made prior to commencement, including any initial direct costs incurred and incentives received. Lease liabilities are initially measured at the present value of future minimum lease payments, excluding variable lease payments, over the lease term. Variable lease payments include changes in index rates, mobilization and demobilization costs related to oil and natural gas equipment and certain reimbursable costs associated with office and building leases that are recognized when incurred. The discount rate used to determine present value is the rate implicit in the lease unless the rate cannot be determined, in which case the incremental borrowing rate is used. The incremental borrowing rate reflects the estimated rate of interest the Company would pay to borrow over a similar term an amount equal to the lease payments on a collateralized basis in a similar economic environment.

The Company has elected to account for lease and non-lease components in its contracts as a single lease component for all asset classes. Lease agreements may include options to renew the lease, terminate the lease or purchase the underlying asset. The Company determines the lease term at lease commencement date as the non-cancelable period of the lease, including options to extend or terminate the lease when such an option is reasonably certain to be exercised. Factors used to assess reasonable certainty of rights to extend or terminate a lease include current and forecasted drillings plans, anticipated changes in development strategies, historical practice in extending similar contracts and current market conditions.

On August 2, 2016, the Company executed a seven-year lease agreement for the use of the Helix Producer 1 (“HP-I”), a dynamically positioned floating production facility that interconnects with the Phoenix Field through a production buoy. Under the terms of the agreement, the Company agreed to pay a $49.0 million annual fixed demand charge for each of the first two years and $45.0 million for each of the five years thereafter.

Prior to implementation, the HP-I lease was accounted for as a capital lease under previous lease accounting treatments. The Company initially recorded a capital lease asset and liability of $124.3 million on its consolidated balance sheet at lease inception. As the HP-I is utilized in the Company’s oil and natural gas development activities, the capital lease asset was included within proved property and depleted as part of the full cost pool. As of December 31, 2018, the balance of the capital lease obligation on the consolidated balance sheet was $93.6 million, of which $14.1 million is included in other current liabilities and $79.5 million is included in other long-term liabilities. Upon adoption of Topic 842, the HP-I capital lease was classified as a finance lease resulting in no change to the amounts recognized on the condensed consolidated balance sheet.

The Company has operating leases expiring at various dates, principally for office space, drilling rigs, compressors and other equipment necessary to support the Company’s operations. Operating leases are reflected as operating lease assets, current portion of operating lease liabilities and operating lease liabilities on the condensed consolidated balance sheet. The Company’s operating lease liabilities recognized on the balance sheet as of September 30, 2019 was $18.7 million. Costs associated with the Company’s operating leases are either expensed or capitalized depending on how the underlying asset is utilized.

Presented below are disclosures required by Topic 842. The amounts disclosed herein primarily represent costs associated with properties operated by the Company that are presented on a gross basis and do not reflect the Company’s net proportionate share of such amounts. A portion of these costs have been or will be billed to other working interest owners. The Company’s share of these costs is included in property and equipment, lease operating expense or general and administrative expense, as applicable. The components of lease costs were as follows (in thousands):

	Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
Finance lease cost - interest on lease liabilities⁽¹⁾	$	4,728	$	14,589
Operating lease cost, excluding short-term leases⁽²⁾		822		2,348
Short-term lease cost⁽³⁾		17,658		81,897
Variable lease cost⁽⁴⁾		3		8
Total lease cost	$	23,211	$	98,842

⁽¹⁾

The HP-I is utilized in the Company’s oil and natural gas development activities and the right-of-use asset was capitalized and included in proved property and depleted as part of the full cost pool. Once items are included in the full cost pool, they are indistinguishable from other proved properties. The capitalized costs within the full cost pool are amortized over the life of the total proved reserved using the unit-of-production method, computed quarterly.

⁽²⁾	Operating lease cost reflect a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis.

⁽³⁾	Short-term lease costs are reported at gross amounts and primarily represent costs incurred for drilling rigs, most of which are short-term contracts not recognized as a right-of-use asset and lease liability on the balance sheet.

⁽⁴⁾	Variable lease costs primarily represent differences between minimum payment obligations and actual operating charges incurred by the Company related to its long-term leases.

The present value of the fixed lease payments recorded as the Company’s right-of-use asset and liability, adjusted for initial direct costs and incentives are as follows (in thousands):

	September 30, 2019
Operating leases:
Operating lease assets	$	8,082

Current portion of operating leases	$	1,416
Operating lease liabilities		17,249
Total operating lease liabilities	$	18,665

Finance leases:
Proved property ⁽¹⁾	$	124,299

Other current liabilities	$	16,578
Other long-term liabilities		66,746
Total finance lease liabilities	$	83,324

⁽¹⁾

The HP-I is utilized in the Company’s oil and natural gas development activities and the right-of-use asset was capitalized and included in proved property and depleted as part of the full cost pool. Once items are included in the full cost pool, they are indistinguishable from other proved properties. The capitalized costs within the full cost pool are amortized over the life of the total proved reserves using the unit-of-production method, computed quarterly.

Minimum future commitments by year for the Company’s leases as of September 30, 2019 are presented in the table below (in thousands). Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet.

	Operating Leases			Finance Leases
2019 (excluding the nine months ended September 30, 2019)	$	453		$	8,314
2020		2,746			33,257
2021		4,079			33,257
2022		4,302			33,257
2023		4,237			13,858
Thereafter		19,105			—
Total lease payments	$	34,922		$	121,943
Imputed interest		(16,257	)		(38,619	)
Total	$	18,665		$	83,324

	September 30, 2019
Weighted average remaining lease term:
Operating leases	9 years
Finance leases	4 years
Weighted average discount rate:
Operating leases		10.2	%
Finance leases		21.9	%

The table below presents the supplemental cash flow information related to leases for the nine months ended September 30, 2019 (in thousands):

Operating cash outflow from finance leases	$	14,589
Financing cash outflow from finance leases	$	10,344
Operating cash outflow from operating leases	$	1,358

Right-of-use assets obtained in exchange for new finance lease liabilities	$	—
Right-of-use assets obtained in exchange for new operating lease liabilities	$	2,225

Note 5 — Financial Instruments

The following table presents the carrying amounts and estimated fair values of financial instruments (in thousands):

	September 30, 2019				December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
11.00% Second-Priority Senior Secured Notes – due April 2022⁽¹⁾	$	383,186	$	398,685	$	381,229	$	362,168
7.50% Senior Secured Notes – due May 2022	$	6,060	$	5,272	$	6,060	$	5,151
Bank Credit Facility – due May 2022⁽¹⁾	$	307,946	$	315,000	$	257,448	$	265,000
Oil and Natural Gas Derivatives	$	46,296	$	46,296	$	74,923	$	74,923

⁽¹⁾	The carrying amounts are net of discount and deferred financing costs.

As of September 30, 2019 and December 31, 2018, the carrying amounts of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximate their fair values due to the short-term nature of these instruments.

11.00% Second-Priority Senior Secured Notes – due April 2022. The $390.9 million aggregate principal amount of 11.00% Senior Secured Notes are reported on the condensed consolidated balance sheet as of September 30, 2019 at their carrying value, net of original issue discount and deferred financing costs (see Note 6 – Debt). The fair value of the 11.00% Senior Secured Notes are estimated (representing a Level 1 fair value measurement) using quoted secondary market trading prices.

7.50% Senior Secured Notes – due May 2022. The $6.1 million aggregate principal amount of 7.50% Stone Senior Notes are reported on the condensed consolidated balance sheet as of September 30, 2019 at their carrying value (see Note 6 – Debt). The fair value of the 7.50% Stone Senior Notes are estimated (representing a Level 1 fair value measurement) using quoted secondary market trading prices.

Bank Credit Facility – due May 2022. In May 2018, in conjunction with the Stone Combination, the Company and Talos Production LLC, our wholly-owned subsidiary, executed a new bank credit facility with an initial borrowing base of $600.0 million (the “Bank Credit Facility”) which is reported on the condensed consolidated balance sheet as of September 30, 2019 at its carrying value net of deferred financing costs (see Note 6 – Debt). The fair value of the Bank Credit Facility is estimated based on the outstanding borrowings under the Bank Credit Facility since it is secured by the Company’s reserves and the interest rates are variable and reflective of market rates (representing a Level 2 fair value measurement).

Oil and natural gas derivatives. The Company attempts to mitigate a portion of its commodity price risk and stabilize cash flows associated with sales of oil and natural gas production through the use of oil and natural gas swaps and costless collars. Swaps are contracts where the Company either receives or pays depending on whether the oil or natural gas floating market price is above or below the contracted fixed price. Costless collars consist of a purchased put option and a sold call option with no net premiums paid to or received from counterparties. Collar contracts typically require payments by the Company if the NYMEX average closing price is above the ceiling price or payments to the Company if the NYMEX average closing price is below the floor price.

The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, commodity derivatives are recorded on the condensed consolidated balance sheets at fair value with settlements of such contracts, and changes in the unrealized fair value, recorded as “Price risk management activities income (expense)” on the condensed consolidated statements of operations in each period.

The following table presents the impact that derivatives, not qualifying as hedging instruments, had on the Company’s condensed consolidated statements of operations (in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2019		2018			2019			2018
Net cash received (paid) on settled derivative instruments	$	5,360	$	(40,746	)	$	(7,202	)	$	(94,802	)
Unrealized gain (loss)		38,400		(12,584	)		(28,627	)		(101,680	)
Price risk management activities income (expense)	$	43,760	$	(53,330	)	$	(35,829	)	$	(196,482	)

The following table reflects the contracted volumes and weighted average prices the Company will receive under its derivative contracts as of September 30, 2019:

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	$	—	$	—

The Company’s commodity derivative instruments are measured at fair value based on third-party industry-standard models using various inputs substantially observable in active markets, including forward oil and natural gas price curves, and are therefore classified as Level 2 in the required fair value hierarchy for the periods presented. The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands):

	September 30, 2019
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas derivatives	$	—	$	50,878		$	—	$	50,878
Liabilities:
Oil and natural gas derivatives		—		(4,582	)		—		(4,582	)
Total net asset	$	—	$	46,296		$	—	$	46,296

	December 31, 2018
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas derivatives	$	—	$	75,473		$	—	$	75,473
Liabilities:
Oil and natural gas derivatives		—		(550	)		—		(550	)
Total net asset	$	—	$	74,923		$	—	$	74,923

Financial Statement Presentation. Derivatives are classified as either current or non-current assets or liabilities based on their anticipated settlement dates. Although the Company has master netting arrangements with its counterparties, the Company presents its derivative financial instruments on a gross basis on its condensed consolidated balance sheets. The following table presents the fair value of derivative financial instruments at September 30, 2019 and December 31, 2018 (in thousands):

	September 30, 2019				December 31, 2018
	Assets		Liabilities		Assets		Liabilities
Oil and natural gas derivatives:
Current	$	43,058	$	3,832	$	75,473	$	550
Non-current		7,820		750		—		—
Total	$	50,878	$	4,582	$	75,473	$	550

Credit Risk. The Company is subject to the risk of loss on its financial instruments as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. The Company entered into International Swaps and Derivative Association agreements with counterparties to mitigate this risk. The Company also maintains credit policies with regard to its counterparties to minimize overall credit risk. The Company’s assets and liabilities from commodity price risk management activities at September 30, 2019 represent derivative instruments from twelve counterparties; all of which are registered swap dealers that have an “investment grade” (minimum Standard & Poor’s rating of BBB- or better) credit rating, and ten of which are parties under the Company’s Bank Credit Facility. The Company enters into derivatives directly with these counterparties and, subject to the terms of the Company’s Bank Credit Facility, is not required to post collateral or other securities for credit risk in relation to the derivative activities.

Note 6 — Debt

A summary of the detail comprising the Company’s debt and the related book values for the respective periods presented is as follows (in thousands):

Description	September 30, 2019			December 31, 2018
11.00% Second-Priority Senior Secured Notes – due April 2022	$	390,868		$	390,868
7.50% Senior Secured Notes – due May 2022		6,060			6,060
Bank Credit Facility – due May 2022		315,000			265,000
4.20% Building Loan – due November 2030		—			10,567
Total debt, before discount and deferred financing cost		711,928			672,495
Discount and deferred financing cost		(14,736	)		(17,191	)
Total debt, net of discount and deferred financing cost	$	697,192		$	655,304
Less: current portion of long-term debt		—			(443	)
Long-term debt, net of discount and deferred financing costs	$	697,192		$	654,861

11.00% Second-Priority Senior Secured Notes – due April 2022. The 11.00% Senior Secured Notes were issued pursuant to an indenture dated May 10, 2018. The 11.00% Senior Secured Notes mature April 3, 2022 and have interest payable semi-annually each April 15 and October 15. Prior to May 10, 2020, the Company may, at its option, redeem all or a portion of the 11.00% Senior Secured Notes at 105.5% of the principal amount plus accrued and unpaid interest. Thereafter, the Company may redeem all or a portion of the 11.00% Senior Secured Notes at redemption prices decreasing annually from 102.75% to 100.0% plus accrued and unpaid interest.

The indenture governing the 11.00% Senior Secured Notes applies certain limitations on the Company’s ability and the ability of its subsidiaries to, among other things, (i) incur additional indebtedness or issue certain preferred shares; (ii) pay dividends and make certain other restricted payments; (iii) create restrictions on the payment of dividends or other distributions to the Company from its restricted subsidiaries; (iv) create liens on certain assets to secure debt; (v) make certain investments; (vi) engage in sales of assets and subsidiary stock; (vii) transfer all or substantially all of its assets or enter into merger or consolidation transactions; and (viii) engage in transactions with affiliates. The 11.00% Senior Secured Notes contain customary quarterly and annual reporting, financial and administrative covenants. The Company was in compliance with all debt covenants at September 30, 2019.

7.50% Senior Secured Notes – due May 2022. The 7.50% Stone Senior Notes represent the remaining $6.1 million of long-term debt assumed in the Stone Combination that were not exchanged for 11.00% Senior Secured Notes and thus remain outstanding. As a result, substantially all of the restrictive covenants relating to the 7.50% Stone Senior Notes have been removed and collateral securing the 7.50% Stone Senior Notes has been released. The 7.50% Stone Senior Notes mature May 31, 2022 and have interest payable semi-annually each May 31 and November 30. Prior to May 31, 2020, the Company may, at its option, redeem all or a portion of the 7.50% Stone Senior Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, the Company may redeem all or a portion of the 7.50% Stone Senior Notes at redemption prices decreasing annually from 105.625% to 100.0% plus accrued and unpaid interest.

Bank Credit Facility – due May 2022. The Company and Talos Production LLC, our wholly-owned subsidiary, executed the Bank Credit Facility in conjunction with the Stone Combination with a syndicate of financial institutions, with an initial borrowing base of $600.0 million. The Bank Credit Facility matures on May 10, 2022, provided that the Bank Credit Facility mandates a springing maturity that is 120 days prior to May 10, 2022, if greater than $25.0 million of the 11.00% Senior Secured Notes or any permitted refinancing indebtedness in resect thereof is outstanding on such date.

The Bank Credit Facility bears interest based on the borrowing base usage, at the applicable London InterBank Offered Rate, plus applicable margins ranging from 2.75% to 3.75% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 1.75% to 2.75%. In addition, the Company is obligated to pay a commitment fee of 0.50% on the unfunded portion of the commitments under the Bank Credit Facility. The Bank Credit Facility has certain debt covenants, the most restrictive of which is that the Company must maintain a total debt to EBITDAX Ratio (as defined in the Bank Credit Facility) of no greater than 3.00 to 1.00 each quarter. The Company must also maintain a current ratio no less than 1.00 to 1.00 each quarter. According to the Bank Credit Facility, undrawn commitments are included in current assets in the current ratio calculation. The Bank Credit Facility is secured by substantially all of the oil and natural gas assets of the Company. The Bank Credit Facility is fully and unconditionally guaranteed by the Company and certain of its wholly-owned subsidiaries.

The Bank Credit Facility provides for determination of the borrowing base based on the Company’s proved producing reserves and a portion of its proved undeveloped reserves. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter. On July 3, 2019, the Company and Talos Production LLC entered into a Joinder, First Amendment to Credit Agreement, and Borrowing Base Reaffirmation Agreement in which, (a) the $850.0 million borrowing base was reaffirmed, (b) the commitments were increased from $600.0 million to $850.0 million, (c) three additional financial institutions were joined as lenders to the syndicate and (d) certain other amendments were made to the Bank Credit Facility as more particularly described therein. The Company’s scheduled redetermination meeting was held October 30, 2019, with results expected in November 2019.

As of September 30, 2019, the Company’s borrowing base and commitments were $850.0 million, of which no more than $200 million can be used as letters of credit. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Bank Credit Facility. The Company was in compliance with all debt covenants at September 30, 2019. As of September 30, 2019, the Bank Credit Facility had approximately $521.4 million of undrawn commitments (taking into account $13.6 million letters of credit and $315.0 million drawn from the Bank Credit Facility).

Building Loan – due November 2030. In connection with the Stone Combination, the Company assumed Stone’s 4.20% term loan maturing on November 20, 2030 (the “Building Loan”). The Building Loan bears interest at a rate of 4.20% per annum and is to be repaid in 180 equal monthly installments of approximately $0.1 million. During June 2019, the Company repaid and discharged $10.4 million aggregate remaining principal, plus accrued interest, of the Building Loan using proceeds from the sale of an office building in Lafayette acquired in the Stone Combination and cash on hand. As of September 30, 2019, there is no outstanding balance under the Building Loan.

Note 7 — Employee Benefits Plans and Share-Based Compensation

Stone Severance Plans

The Company maintained the Stone Energy Corporation Executive Severance Plan and Stone Energy Corporation Employee Severance Plan, each a legacy plan of Talos Petroleum LLC (f/k/a Stone Energy Corporation). The plans provided for the payment of severance benefits to certain individuals who, prior to the Stone Combination, were executive officers or employees of Talos Petroleum LLC, in each case upon an involuntary termination within twelve months of the Closing Date. For the three and nine months ended September 30, 2019, the Company incurred nil and $0.2 million of severance expenses in relation to the Stone Combination, respectively. For the three and nine months ended September 30, 2018, the company incurred nil and $7.5 million of severance expenses in relation to the Stone Combination. Severance expenses are reflected in general and administrative expense on the consolidated statement of operations. As of September 30, 2019, the Company had no obligations outstanding related to the plans. The plans were terminated in July 2019.

Talos Energy Inc. Long Term Incentive Plan

Under the Talos Energy Inc. Long Term Incentive Plan (the “LTIP”), the Company may issue, subject to board approval, grants of options, stock appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based awards, cash awards, substitute awards or any combination of the foregoing to employees, directors and consultants. The LTIP authorizes the Company to grant awards of up to 5,415,576 shares of the Company’s common stock.

Restricted Stock Units. During the nine months ended September 30, 2019, the Company granted 732,771 restricted stock units (“RSUs”) under the LTIP to employees and non-employees. The following table summarizes RSU activity for the nine months ended September 30, 2019:

	Restricted Stock Units			Weighted Average Grant Date Fair Value
Unvested RSUs at December 31, 2018		138,704		$	33.85
Granted		732,771		$	24.39
Vested		(68,992	)	$	33.72
Forfeited		(48,518	)	$	25.43
Unvested RSUs at September 30, 2019		753,965		$	25.21

Performance Stock Units. During the nine months ended September 30, 2019, the Company granted 218,060 performance stock units (“PSUs”) under the LTIP to employees. The following table summarizes PSU activity for the nine months ended September 30, 2019:

	Performance Share Units			Weighted Average Grant Date Fair Value
Unvested PSUs at December 31, 2018		231,542		$	44.47
Granted		218,060		$	33.96
Vested		—		$	—
Forfeited		(26,358	)	$	39.72
Unvested PSUs at September 30, 2019		423,244		$	39.35

The grant date fair value of the PSUs granted during the nine months ended September 30, 2019, calculated using a Monte Carlo simulation, was $7.4 million. The following table summarizes the assumptions used to calculate the grant date fair value of the PSUs granted in the nine months ended September 30, 2019:

	Grant Date
	March 5, 2019			May 16, 2019
Number of simulations		100,000			100,000
Expected term (in years)		2.8			2.6
Expected volatility		46.9	%		44.8	%
Risk-free interest rate		2.5	%		2.1	%
Dividend yield		—	%		—	%

Share-based Compensation Expense, net.

Share-based compensation expense is reflected as “General administrative expense,” net amounts capitalized to oil and natural gas properties in the consolidated statement of operations. Because of the non-cash nature of share-based compensation, the expensed portion of share-based compensation is added back to net income in arriving at net cash used in or provided by operating activities in the condensed consolidated statement of cash flows. The following table summarizes the stock-based compensation expense for the three and nine months ended September 30, 2019 and 2018 (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Share based compensation	$	3,591		$	923		$	9,568		$	5,081
Capitalization		(1,647	)		(353	)		(4,404	)		(2,952	)
Share based compensation, net capitalization	$	1,944		$	570		$	5,164		$	2,129

Note 8 — Income Taxes

Prior to the Stone Combination, Talos Energy LLC was a partnership for U.S. federal income tax purposes and was not subject to U.S. federal income tax or state income tax (in most states) at the entity level. As such, Talos Energy LLC did not recognize U.S. federal income tax expense or state income tax expense in most states. Talos Energy LLC’s operations in the shallow waters off the coast of Mexico were conducted under a different legal form and are subject to foreign income taxes.

For the three months ended September 30, 2019, the Company recognized income tax expense of $0.8 million for an effective tax rate of 1.0%. The difference between the Company’s effective tax rate of 1.0% and federal statutory income tax rate of 21% is primarily due to a reduction to the Company’s valuation allowance. For the three months ended September 30, 2018, the Company’s effective tax rate of 0% differed from the federal statutory rate of 21% because the Company recorded a valuation allowance against its deferred tax assets.

For the nine months ended September 30, 2019, the Company recognized an income tax expense of $0.4 million for an effective tax rate of 0.7%. The difference between the Company’s effective tax rate of 0.7% and federal statutory income tax rate of 21% is primarily due to a reduction to the Company’s valuation allowance. For the nine months ended September 30, 2018, the Company’s effective tax rate of 0% differed from the federal statutory rate of 21% because the Company recorded a valuation allowance against its deferred tax assets.

The Company evaluates and updates the estimated annual effective income tax rate on a quarterly basis based on current and forecasted operating results and tax laws. Consequently, based upon the mix and timing of the Company’s actual earnings compared to annual projections, the effective tax rate may vary quarterly and may make quarterly comparisons not meaningful. The quarterly income tax provision is generally comprised of tax expense on income or benefit on loss at the most recent estimated annual effective tax rate. The tax effect of discrete items is recognized in the period in which they occur at the applicable statutory rate.

Deferred income tax assets and liabilities are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce deductions and income in the future. The realization of deferred tax assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or net operating losses are deductible. When assessing the need for a valuation allowance on deferred tax assets, the Company considers whether it is more likely than not that some portion or all of them will not be realized. As September 30, 2019, the Company had a valuation allowance related to federal, state and foreign deferred tax assets.

Note 9 — Income (Loss) Per Share

Basic earnings per share is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted earnings per share include the impact of RSUs, PSUs and outstanding warrants.

The following table presents the computation of basic and diluted earnings per share for Talos Energy Inc. (in thousands, except for per share amounts):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Net income (loss)	$	73,297	$	13,109	$	58,425	$	(84,746	)
Weighted average common shares outstanding — basic		54,200		54,156		54,178		43,329

Dilutive effect of securities		230		8		186		—
Weighted average common shares outstanding — diluted		54,430		54,164		54,364		43,329
Net income (loss) per common share:
Basic	$	1.35	$	0.24	$	1.08	$	(1.96	)
Diluted	$	1.35	$	0.24	$	1.07	$	(1.96	)
Anti-dilutive potentially issuable securities excluded from diluted common shares		4,250		3,538		4,282		3,891

For the periods prior to May 10, 2018, the Company retrospectively adjusted the weighted average shares used in determining earnings per share to reflect the number of shares Talos Energy LLC received in the Stone Combination.

Note 10 — Related Party Transactions

Whistler Acquisition. On August 31, 2018, the Company acquired certain properties from Whistler Energy II Holdco, LLC, an affiliate of the Apollo Funds, for $52.6 million ($14.8 million net of $37.8 million of cash acquired). Included in current assets acquired as of September 30, 2019 is $1.1 million in receivables from an affiliate of the Apollo Funds to reimburse the Company for certain payments made post-closing. See additional details in Note 2 – Acquisitions.

Equity Registration Rights Agreement. On the Closing Date, the Company entered into a Registration Rights Agreement (the “Equity Registration Rights Agreement”) with certain Apollo Funds and Riverstone Funds, certain funds controlled by Franklin Advisers, Inc. (“Franklin”) and certain clients of MacKay Shields LLC (“MacKay Shields”) relating to the registered resale of the Company’s common stock owned by such parties as of Closing. The Company will bear all of the expenses incurred in connection with any offer and sale, while the Apollo Funds, Riverstone Funds, Franklin and MacKay Shields will be responsible for paying underwriting fees, discounts and commissions or similar charges. Pursuant to the Equity Registration Rights Agreement, on June 4, 2019, the Company filed a registration statement on Form S-3 with the SEC registering the offering of shares of the Company’s common stock by the selling stockholders named therein, which was declared effective by the SEC on June 12, 2019. Fees incurred by the Company in conjunction with the Equity Registration Rights Agreement were nil and $0.7 million for the three and nine months ended September 30, 2019, respectively.

Legal Fees. The Company has engaged the law firm Vinson & Elkins L.L.P. to provide legal services. An immediate family member of William S. Moss III, our Executive Vice President and General Counsel and one of the Company’s executive officers, is a partner at Vinson & Elkins L.L.P. For the three and nine months ended September 30, 2019, we incurred fees of approximately $0.3 million and $1.9 million, respectively, of which $0.6 million remained payable for legal services performed by Vinson & Elkins L.L.P. as of September 30, 2019. For the three and nine months ended September 30, 2018, we incurred fees of approximately $5.0 million and $5.3 million, respectively.

Service Fee Agreement. Talos Energy LLC entered into service fee agreements with Apollo Funds and Riverstone Funds for the provision of certain management consulting and advisory services. Under each agreement, the Company paid a fee equal to the higher of (i) a certain percentage of earnings before interest, income taxes, depletion, depreciation and amortization and (ii) a fixed fee payable quarterly, provided, however, such fees did not exceed in each case $0.5 million, in aggregate, for any calendar year. For the three and nine months ended September 30, 2019, the Company did not incur expenses for these services. For the three and nine months ended September 30, 2018, the Company incurred approximately nil and $0.5 million, respectively. These fees are recognized in “General and administrative expense” on the condensed consolidated statements of operations. In connection with the Stone Combination, the service fee agreements were terminated.

Note 11 — Commitments and Contingencies

Performance Obligations

Regulations with respect to offshore operations govern, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells, removal of facilities and to guarantee the execution of the minimum work program under the Mexico production sharing contracts. As of September 30, 2019, the Company had secured performance bonds totaling approximately $637.3 million. As of September 30, 2019, the Company had $13.6 million in letters of credit issued under its Bank Credit Facility.

Legal Proceedings

The Company is named as a party in certain lawsuits and regulatory proceedings arising in the ordinary course of business. The Company does not expect that these matters, individually or in the aggregate, will have a material adverse effect on its financial condition.

Note 12 — Condensed Consolidating Financial Information

The Company owns no operating assets, has no operations independent of its subsidiaries and owns 100% of the Talos Issuers. The Talos Issuers issued 11.00% Senior Secured Notes on May 10, 2018, which are fully and unconditionally guaranteed, jointly and severally, by the Company and certain of its 100% owned subsidiaries (“Guarantors”) on a senior secured basis. Certain of the Company’s subsidiaries, which are accounted for on a consolidated basis, do not guarantee the 11.00% Senior Secured Notes (“Non-Guarantors”).

The following condensed consolidating financial information presents the financial information of the Company on an unconsolidated stand-alone basis and its combined subsidiary issuers, combined guarantor and combined non-guarantor subsidiaries as of and for the periods indicated. As described in Note 1 – Formation and Basis of Presentation, the Company retrospectively adjusted its consolidated equity to reflect the legal capital of the Company for all periods presented. Such financial information may not necessarily be indicative of the Company’s results of operations, cash flows or financial position had these subsidiaries operated as independent entities.

TALOS ENERGY INC.

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF SEPTEMBER 30, 2019

(In thousands)

(Unaudited)

	Talos		Talos Issuers			Guarantors			Non- Guarantors			Elimination			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	80,621		$	3,301		$	6,760		$	—		$	90,682
Restricted cash		—		—			—			—			—			—
Accounts receivable, net
Trade, net		—		—			108,354			—			—			108,354
Joint interest, net		—		—			17,124			438			—			17,562
Other		—		1,347			9,156			21,265			—			31,768
Assets from price risk management activities		—		43,058			—			—			—			43,058
Prepaid assets		—		1,993			37,358			27			—			39,378
Income tax receivable		—		—			—			—			—			—
Other current assets		—		—			1,952			—			—			1,952
Total current assets		—		127,019			177,245			28,490			—			332,754
Property and equipment:
Proved properties		—		—			4,012,100			—			—			4,012,100
Unproved properties, not subject to amortization		—		—			72,342			105,832			—			178,174
Other property and equipment		—		21,999			6,484			207			—			28,690
Total property and equipment		—		21,999			4,090,926			106,039			—			4,218,964
Accumulated depreciation, depletion and amortization		—		(10,302	)		(1,957,269	)		(39	)		—			(1,967,610	)
Total property and equipment, net		—		11,697			2,133,657			106,000			—			2,251,354
Other long-term assets:
Assets from price risk management activities		—		7,820			—			—			—			7,820
Other well equipment inventory		—		—			9,251			—			—			9,251
Leased assets		—		3,162			3,412			1,508			—			8,082
Investments in subsidiaries		1,078,993		1,663,746			—			—			(2,742,739	)		—
Other assets		54		364			2,140			66			—			2,624
Total assets	$	1,079,047	$	1,813,808		$	2,325,705		$	136,064		$	(2,742,739	)	$	2,611,885
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	279	$	2,758		$	89,617		$	3,083		$	—		$	95,737
Accrued liabilities		—		1,787			143,112			24,253			—			169,152
Accrued royalties		—		—			37,763			—			—			37,763
Current portion of long-term debt		—		—			—			—			—			—
Current portion of asset retirement obligations		—		—			63,404			—			—			63,404
Liabilities from price risk management activities		—		3,832			—			—			—			3,832
Accrued interest payable		—		20,906			152			—			—			21,058
Leases liabilities		—		70			798			548			—			1,416
Other current liabilities		—		—			18,993			—			—			18,993
Total current liabilities		279		29,353			353,839			27,884			—			411,355
Long-term debt, net of discount and deferred financing costs		—		691,132			6,060			—			—			697,192
Asset retirement obligations		—		—			321,808			—			—			321,808
Liabilities from price risk management activities		—		750			—			—			—			750
Long-term leased liabilities		—		13,580			2,629			1,040			—			17,249
Other long-term liabilities		3,944		—			84,620			143			—			88,707
Total liabilities		4,223		734,815			768,956			29,067			—			1,537,061
Commitments and Contingencies (Note 11)
Stockholders' equity		1,074,824		1,078,993			1,556,749			106,997			(2,742,739	)		1,074,824
Total liabilities and stockholders' equity	$	1,079,047	$	1,813,808		$	2,325,705		$	136,064		$	(2,742,739	)	$	2,611,885

TALOS ENERGY INC.

CONDENSED CONSOLIDATING BALANCE SHEET

AS OF DECEMBER 31, 2018

(In thousands)

	Talos		Talos Issuers			Guarantors			Non- Guarantors			Elimination			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	13,541		$	100,801		$	25,572		$	—		$	139,914
Restricted cash		—		—			1,248			—			—			1,248
Accounts receivable, net
Trade, net		—		—			103,025			—			—			103,025
Joint interest, net		—		—			15,870			4,374			—			20,244
Other		—		3,100			9,566			7,020			—			19,686
Assets from price risk management activities		—		75,473			—			—			—			75,473
Prepaid assets		—		1,225			37,639			47			—			38,911
Income tax receivable		—		—			10,701			—			—			10,701
Other current assets		—		—			7,644			—			—			7,644
Total current assets		—		93,339			286,494			37,013			—			416,846
Property and equipment:
Proved properties		—		—			3,629,430			—			—			3,629,430
Unproved properties, not subject to amortization		—		—			63,104			45,105			—			108,209
Other property and equipment		—		20,670			12,440			81			—			33,191
Total property and equipment		—		20,670			3,704,974			45,186			—			3,770,830
Accumulated depreciation, depletion and amortization		—		(8,310	)		(1,711,288	)		(11	)		—			(1,719,609	)
Total property and equipment, net		—		12,360			1,993,686			45,175			—			2,051,221
Other long-term assets:
Other well equipment inventory		—		—			9,224			—			—			9,224
Investments in subsidiaries		1,011,359		1,560,922			—			—			(2,572,281	)		—
Other assets		—		364			2,258			73			—			2,695
Total assets	$	1,011,359	$	1,666,985		$	2,291,662		$	82,261		$	(2,572,281	)	$	2,479,986
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	144	$	1,242		$	42,736		$	6,897		$	—		$	51,019
Accrued liabilities		—		4,995			159,491			24,164			—			188,650
Accrued royalties		—		—			38,520			—			—			38,520
Current portion of long-term debt		—		—			443			—			—			443
Current portion of asset retirement obligations		—		—			68,965			—			—			68,965
Liabilities from price risk management activities		—		550			—			—			—			550
Accrued interest payable		—		10,162			38			—			—			10,200
Other current liabilities		—		—			22,071			—			—			22,071
Total current liabilities		144		16,949			332,264			31,061			—			380,418
Long-term debt, net of discount and deferred financing costs		—		638,677			16,184			—			—			654,861
Asset retirement obligations		—		—			313,852			—			—			313,852
Other long-term liabilities		3,719		—			119,432			208			—			123,359
Total liabilities		3,863		655,626			781,732			31,269			—			1,472,490
Commitments and Contingencies (Note 11)
Stockholders' equity		1,007,496		1,011,359			1,509,930			50,992			(2,572,281	)		1,007,496
Total liabilities and stockholders' equity	$	1,011,359	$	1,666,985		$	2,291,662		$	82,261		$	(2,572,281	)	$	2,479,986

TALOS ENERGY INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2019

(In thousands)

(Unaudited)

	Talos			Talos Issuers			Guarantors			Non- Guarantors			Elimination			Consolidated
Revenues:
Oil revenue	$	—		$	—		$	211,690		$	209		$	—		$	211,899
Natural gas revenue		—			—			12,545			—			—			12,545
NGL revenue		—			—			3,384			—			—			3,384
Other revenue		—			—			1,029			—			—			1,029
Total revenue		—			—			228,648			209			—			228,857
Operating expenses:		—			—			—			—			—			—
Direct lease operating expense		—			—			43,439			—			—			43,439
Insurance		—			—			4,167			—			—			4,167
Production taxes		—			—			(21	)		—			—			(21	)
Total lease operating expense		—			—			47,585			—			—			47,585
Workover and maintenance expense		—			—			14,210			—			—			14,210
Depreciation, depletion and amortization		—			678			87,435			12			—			88,125
Write-down of oil and natural gas properties		—			—			—			1,417			—			1,417
Accretion expense		—			—			7,316			—			—			7,316
General and administrative expense		307			4,803			12,030			181			—			17,321
Total operating expenses		307			5,481			168,576			1,610			—			175,974
Operating income (loss)		(307	)		(5,481	)		60,072			(1,401	)		—			52,883
Interest expense		—			(16,734	)		(6,191	)		(198	)		—			(23,123	)
Price risk management activities income		—			43,760			—			—			—			43,760
Other income		—			491			6			70			—			567
Income tax (expense) benefit		(780	)		—			4			(14	)		—			(790	)
Equity earnings (loss) from subsidiaries		74,384			52,348			—			—			(126,732	)		—
Net income (loss)	$	73,297		$	74,384		$	53,891		$	(1,543	)	$	(126,732	)	$	73,297

TALOS ENERGY INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2019

(In thousands)

(Unaudited)

	Talos			Talos Issuers			Guarantors			Non- Guarantors			Elimination			Consolidated
Revenues:
Oil revenue	$	—		$	—		$	624,277		$	209		$	—		$	624,486
Natural gas revenue		—			—			41,738			—			—			41,738
NGL revenue		—			—			15,095			—			—			15,095
Other revenue								13,061									13,061
Total revenue		—			—			694,171			209			—			694,380
Operating expenses:
Direct lease operating expense		—			—			122,243			—			—			122,243
Insurance		—			—			12,462			—			—			12,462
Production taxes		—			—			1,067			—			—			1,067
Total lease operating expense		—			—			135,772			—			—			135,772
Workover and maintenance expense		—			—			49,525			—			—			49,525
Depreciation, depletion and amortization		—			1,992			246,499			27			—			248,518
Write-down of oil and natural gas properties		—			—			—			13,778			—			13,778
Accretion expense		—			—			26,868			—			—			26,868
General and administrative expense		692			21,035			31,439			629			—			53,795
Total operating expenses		692			23,027			490,103			14,434			—			528,256
Operating income (loss)		(692	)		(23,027	)		204,068			(14,225	)		—			166,124
Interest expense		—			(50,326	)		(22,428	)		(519	)		—			(73,273	)
Price risk management activities expense		—			(35,829	)		—			—			—			(35,829	)
Other income (expense)		—			678			1,242			(89	)		—			1,831
Income tax expense		(130	)		—			(292	)		(6	)		—			(428	)
Equity earnings (loss) from subsidiaries		59,247			167,751			—			—			(226,998	)		—
Net income (loss)	$	58,425		$	59,247		$	182,590		$	(14,839	)	$	(226,998	)	$	58,425

TALOS ENERGY INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2018

(In thousands)

(Unaudited)

	Talos		Talos Issuers			Guarantors			Non- Guarantors			Elimination			Consolidated
Revenues:
Oil revenue	$	—	$	—		$	248,100		$	—		$	—		$	248,100
Natural gas revenue		—		—			20,193			—			—			20,193
NGL revenue		—		—			14,575			—			—			14,575
Total revenue		—		—			282,868			—			—			282,868
Operating expenses:
Direct lease operating expense		—		—			42,090			—			—			42,090
Insurance		—		—			4,125			—			—			4,125
Production taxes		—		—			578			—			—			578
Total lease operating expense		—		—			46,793			—			—			46,793
Workover and maintenance expense		—		—			25,084			—			—			25,084
Depreciation, depletion and amortization		—		455			87,352			1			—			87,808
Accretion expense		—		—			10,162			—			—			10,162
General and administrative expense		—		12,942			8,274			444			—			21,660
Total operating expenses		—		13,397			177,665			445			—			191,507
Operating income (loss)		—		(13,397	)		105,203			(445	)		—			91,361
Interest expense		—		(15,580	)		(8,797	)		(460	)		—			(24,837	)
Price risk management activities expense		—		(47,656	)		(5,674	)		—			—			(53,330	)
Other income (expense)		—		(356	)		310			(39	)		—			(85	)
Equity earnings from subsidiaries		13,109		90,098			—			—			(103,207	)		—
Net income (loss)	$	13,109	$	13,109		$	91,042		$	(944	)	$	(103,207	)	$	13,109

TALOS ENERGY INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2018

(In thousands)

(Unaudited)

	Talos			Talos Issuers			Guarantors			Non- Guarantors			Elimination			Consolidated
Revenues:
Oil revenue	$	—		$	—		$	555,954		$	—		$	—		$	555,954
Natural gas revenue		—			—			49,364			—			—			49,364
NGL revenue		—			—			27,306			—			—			27,306
Total revenue		—			—			632,624			—			—			632,624
Operating expenses:
Direct lease operating expense		—			—			101,065			—			—			101,065
Insurance		—			—			11,059			—			—			11,059
Production taxes		—			—			1,533			—			—			1,533
Total lease operating expense		—			—			113,657			—			—			113,657
Workover and maintenance expense		—			—			49,703			—			—			49,703
Depreciation, depletion and amortization		—			1,180			203,391			3			—			204,574
Accretion expense		—			—			24,414			—			—			24,414
General and administrative expense		—			31,340			28,841			939			—			61,120
Total operating expenses		—			32,520			420,006			942			—			453,468
Operating income (loss)		—			(32,520	)		212,618			(942	)		—			179,156
Interest expense		—			(42,207	)		(22,754	)		(1,296	)		—			(66,257	)
Price risk management activities expense		—			(186,873	)		(9,609	)		—			—			(196,482	)
Other income (expense)		—			(1,564	)		395			6			—			(1,163	)
Equity earnings (loss) from subsidiaries		(84,746	)		178,418			—			—			(93,672	)		—
Net income (loss)	$	(84,746	)	$	(84,746	)	$	180,650		$	(2,232	)	$	(93,672	)	$	(84,746	)

TALOS ENERGY INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2019

(In thousands)

(Unaudited)

	Talos			Talos Issuers			Guarantors			Non- Guarantors			Elimination			Consolidated
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	(558	)	$	(64,050	)	$	412,445		$	(15,424	)	$	—		$	332,413
Cash flows from investing activities:
Exploration, development, and other capital expenditures		—			(1,577	)		(301,603	)		(69,740	)		—			(372,920	)
Cash paid for in acquisitions		—			—			(32,916	)		—			—			(32,916	)
Proceeds from sales of property								5,369									5,369
Investments in subsidiaries		—			(1,119,219	)		—			—			1,119,219			—
Distributions from subsidiaries		—			1,203,194			—			—			(1,203,194	)		—
Net cash provided by (used in) investing activities		—			82,398			(329,150	)		(69,740	)		(83,975	)		(400,467	)
Cash flows from financing activities:
Redemption of Senior Notes and other long-term debt		—			—			(10,567	)		—			—			(10,567	)
Proceeds from Bank Credit Facility		—			75,000			—			—			—			75,000
Repayment of Bank Credit Facility		—			(25,000	)		—			—			—			(25,000	)
Deferred financing costs		—			(1,268	)		—			—			—			(1,268	)
Other deferred payments		—			—			(9,921	)		—			—			(9,921	)
Payments of capital lease		—			—			(10,344	)		—			—			(10,344	)
Capital contributions		558			—			1,051,661			67,000			(1,119,219	)		—
Employee stock transaction		—			—			(326	)		—			—			(326	)
Distributions to subsidiary issuer		—			—			(1,202,546	)		(648	)		1,203,194			—
Net cash provided by (used in) financing activities		558			48,732			(182,043	)		66,352			83,975			17,574

Net increase (decrease) in cash, cash equivalents and restricted cash		—			67,080			(98,748	)		(18,812	)		—			(50,480	)
Cash, cash equivalents and restricted cash:
Balance, beginning of period		—			13,541			102,049			25,572			—			141,162
Balance, end of period	$	—		$	80,621		$	3,301		$	6,760		$	—		$	90,682

TALOS ENERGY INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2018

(In thousands)

(Unaudited)

	Talos		Talos Issuers			Guarantors			Non- Guarantors			Elimination			Consolidated
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	—	$	(126,105	)	$	269,841		$	(49	)	$	—		$	143,687
Cash flows from investing activities:
Exploration, development, and other capital expenditures		—		(12,966	)		(159,368	)		(2,015	)		—			(174,349	)
Cash acquired in acquisitions		—		—			278,409			—			—			278,409
Investments in subsidiaries		—		(778,148	)		—			—			778,148			—
Distributions from subsidiaries		—		1,097,505			(9	)		—			(1,097,496	)		—
Net cash provided by (used in) investing activities		—		306,391			119,032			(2,015	)		(319,348	)		104,060
Cash flows from financing activities:
Redemption of Senior Notes and other long-term debt		—		(24,977	)		(174	)		—			—			(25,151	)
Proceeds from Bank Credit Facility		—		319,000			—			—			—			319,000
Repayment of Bank Credit Facility		—		(54,000	)		—			—			—			(54,000	)
Repayment of LLC Credit Facility		—		(403,000	)		—			—			—			(403,000	)
Deferred financing costs		—		(16,990	)		—			—			—			(16,990	)
Payments of capital lease		—		—			(9,874	)		—			—			(9,874	)
Capital contributions		—		—			770,436			7,712			(778,148	)		—
Distributions to subsidiaries		—		—			(1,095,165	)		(2,331	)		1,097,496			—
Net cash provided by (used in) financing activities		—		(179,967	)		(334,777	)		5,381			319,348			(190,015	)

Net increase in cash, cash equivalents and restricted cash		—		319			54,096			3,317			—			57,732
Cash, cash equivalents and restricted cash:
Balance, beginning of period		—		22,315			9,048			2,070			—			33,433
Balance, end of period	$	—	$	22,634		$	63,144		$	5,387		$	—		$	91,165

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview

Our Business

The following management’s discussion and analysis should be read in conjunction with our Condensed Consolidated Financial Statements and notes thereto in Part I, Item 1 of this Quarterly Report, as well as our audited Consolidated Financial Statements and the notes thereto in our 2018 Annual Report and the related Management’s Discussion and Analysis of Financial Condition and Results of Operations included in “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2018 Annual Report.

We are a technically driven independent exploration and production company focused on safely and efficiently maximizing cash flows and long-term value through our operations, currently in the United States (“U.S.”) Gulf of Mexico and offshore Mexico. As one of the largest public independent producers in the U.S. Gulf of Mexico, we leverage decades of geology, geophysics and offshore operations expertise towards the acquisition, exploration, exploitation and development of deep and shallow water 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.

In order to determine the most attractive returns for our drilling program, we employ a disciplined portfolio management approach to stochastically evaluate all of our drilling prospects, whether they are generated organically from our existing acreage or are acquisition or joint venture opportunities. We add to and reevaluate our inventory in order to deploy our capital as efficiently as possible.

Unless otherwise indicated or the context otherwise requires, references in this report to “us,” “we,” “our” or the “Company” are to Talos Energy Inc. and its wholly-owned subsidiaries.

Factors Affecting the Comparability of our Financial Condition and Results of Operations

Stone Combination. On May 10, 2018 (the “Closing Date”), Stone Energy Corporation (“Stone”) and Talos Energy LLC became our wholly-owned subsidiaries (the “Stone Combination”). Prior to the Closing Date, Talos Energy Inc. had not conducted any material activities other than those incident to its formation. Talos Energy LLC is the acquirer of Stone for financial reporting and accounting purposes and considered the accounting acquirer in the Stone Combination under accounting principles generally accepted in the United States of America (“GAAP”). Accordingly, our historical financial and operating data, which covers periods prior to the Closing Date, reflects the assets, liabilities and results of operations of Talos Energy LLC prior to the Closing Date and does not reflect the assets, liabilities and results of operations of Stone prior to the Closing Date. See “Part I, Item 1. Condensed Consolidated Financial Statements – Note 2 – Acquisitions” for more information.

Whistler Acquisition. On August 31, 2018, we completed the acquisition of all the issued and outstanding membership interests of Whistler Energy II, LLC (“Whistler”) from Whistler Energy II Holdco, LLC, an affiliate of Apollo Management VII, L.P. and Apollo Commodities Management, L.P., with respect to Series I (“Apollo Funds”), (the “Whistler Acquisition”) for $52.6 million ($14.8 million net of $37.8 million of cash acquired). See “Part I, Item 1. Condensed Consolidated Financial Statements – Note 2 – Acquisitions” for more information.

Mexico Exchange. On September 11, 2018, we entered into a transaction (the “Hokchi Cross Assignment”) with Hokchi Energy, S.A. de C.V. (“Hokchi”), a subsidiary of Pan American Energy (“PAE”), to cross assign 25% participation interests (“PI”) in each of Block 2 and Block 31. Our assignment of a 25% PI in Block 2 to Hokchi closed on December 21, 2018, and Hokchi has assumed operator responsibilities with respect to Block 2. Hokchi’s assignment of Block 31 to us closed on May 22, 2019. In addition, Premier Oil Plc exercised its option to reduce its PI in Block 2 to zero and assigned a 5% PI to each of Sierra Oil & Gas S. de R.L. de C.V. (“Sierra”) and Talos. Following the completion of the Hokchi Cross Assignment, we own a 25% PI in each of Block 2 and Block 31, and Hokchi is the operator of both blocks.

Write-down of oil and natural gas properties. As a result of our evaluation of unproved property located in Block 2 offshore Mexico, specifically future exploratory drilling opportunities, results from exploratory wells drilled during the second quarter of 2019 and the Block 2 production sharing contract’s expiration date, for the three and nine months ended September 30, 2019 we recorded non-cash impairment expense of $1.4 million and $13.8 million, respectively, presented as “Write-down of oil and natural gas properties” on the condensed consolidated statements of operations.

Gunflint Acquisition. On January 11, 2019, pursuant to a Purchase Sale Agreement with Samson Offshore Mapleleaf, LLC, we acquired an approximate 9.6% non-operated working interest in the Gunflint Field located in the Mississippi Canyon area for $29.6 million ($27.9 million after customary purchase price adjustments). See “Part I, Item 1. Condensed Consolidated Financial Statements – Note 2 – Acquisitions” for more information.

Transaction Expenses. We incurred transaction and restructuring costs associated with the Stone Combination and the integration of the businesses of Stone and Talos Energy LLC that are not reflected in our comparative historical results of operations.

Income Tax Expenses. Prior to the Stone Combination, Talos Energy LLC was a partnership for U.S. federal income tax purposes and was not subject to U.S. federal income tax or state income tax (in most states) at the entity level. As such, Talos Energy LLC did not recognize U.S. federal income tax expense or state income tax expense in most states. Talos Energy LLC’s operations in the shallow waters off the coast of Mexico were conducted under a different legal form and are subject to foreign income taxes. In connection with the Stone Combination, Talos Energy LLC was contributed to us. We are subject to federal and state income taxes. We record current income taxes based on estimates of current taxable income and provide for deferred income taxes to reflect estimated future income tax payments and receipts.

Hurricane Barry. In July 2019, production from the U.S. Gulf of Mexico was impacted due to precautionary shut-ins of facilities and evacuations associated with Hurricane Barry. Although there was no major storm related damage to our facilities, the production impact to us spanned approximately one week. For the three and nine months ended September 30, 2019, we estimate deferred production related to Hurricane Barry was approximately 4.0 MBoepd and approximately 1.3 MBoepd, respectively, when comparing second quarter 2019 production to July 2019, the month during which Hurricane Barry temporarily affected our production.

Third Party Downtime. We are vulnerable to third party downtime events impacting the transportation, gathering or processing of production. Production from the Phoenix Field is processed through the Helix Producer I (“HP-I”), which is leased from and operated by Helix Energy Solutions Group, Inc. (“Helix”). Helix is required to disconnect and dry-dock the HP-I every two to three years for inspection as required by the United States Coast Guard, during which time we are unable to produce the Phoenix Field.

During the nine months ended September 30, 2019, Helix dry-docked the HP-I. After conducting sea trials, production resumed in late March 2019, resulting in a total shut-in period of 57 days. The shut-in resulted in deferred production of 4.4 MBoepd during the nine months ended September 30, 2019 when compared to the same period in 2018.

Known Trends and Uncertainties

Volatility in Oil, Natural Gas and NGL Prices. Historically, the markets for oil and natural gas have been volatile. Our revenue, profitability, access to capital and future rate of growth depends upon the price we receive for our sales of oil, natural gas and NGL production. Oil, natural gas and NGL prices are subject to wide fluctuations in response to relatively minor changes in supply and demand.

BOEM Bonding Requirements. In order to cover the various decommissioning obligations of lessees on the Outer Continental Shelf (“OCS”), the Bureau of Ocean Energy Management (“BOEM”) generally requires that lessees post some form of acceptable financial assurances that such obligations will be met, such as surety bonds. The cost of such bonds or other financial assurance can be substantial, and we can provide no assurance that we can continue to obtain bonds or other surety in all cases. As many BOEM regulations are being reviewed by the agency, we may be subject to additional financial assurance requirements in the future. For example, in July 2016, BOEM issued the NTL 2016-N01 (“the 2016 NTL”) to clarify the procedures and guidelines that BOEM Regional Directors use to determine if and when additional financial assurances may be required for OCS leases, right of ways (“ROWs”) and right of use easements (“RUEs”). The 2016 NTL became effective in September 2016, but BOEM subsequently postponed any implementation of the 2016 NTL and has indicated they will be issuing a modified or substitute NTL or a proposed rule. This extension for implementation currently remains in effect.

We remain in active discussions with government regulators and industry peers with regard to any future rulemaking and financial assurance requirements. Notwithstanding BOEM’s 2016 NTL, BOEM may also bolster its financial assurance requirements mandated by rule for all companies operating in federal waters. The future cost of compliance with respect to supplemental bonding, including the obligations imposed on us as a result of the 2016 NTL, to the extent implemented, as well as any other future BOEM directives, or any other changes to BOEM’s rules applicable to our or any of our subsidiaries’ properties, could materially and adversely affect our financial condition, cash flows and results of operations.

Deepwater Operations. We have interests in deepwater fields in the Gulf of Mexico. Operations in the deepwater can result in increased operational risks as has been demonstrated by the Deepwater Horizon disaster in 2010. Despite technological advances since this disaster, liabilities for environmental losses, personal injury and loss of life and significant regulatory fines in the event of a disaster could be well in excess of insured amounts and result in significant current losses on our statements of operations as well as going concern issues.

Oil Spill Response Plan. We maintain a Regional Oil Spill Response Plan that defines our response requirements, procedures and remediation plans in the event we have an oil spill. Oil Spill Response Plans are generally approved by the Bureau of Safety and Environmental Enforcement bi-annually, except when changes are required, in which case revised plans are required to be submitted for approval at the time changes are made. Additionally, these plans are tested and drills are conducted periodically at all levels.

Hurricanes. Since our operations are in the Gulf of Mexico, we are particularly vulnerable to the effects of hurricanes on production. Additionally, affordable insurance coverage for property damage to our facilities for hurricanes has become less effective due to rising retentions and limitations on named windstorm coverage and has been difficult to obtain at times in recent years. Significant hurricane impacts could include reductions and/or deferrals of future oil and natural gas production and revenues, increased lease operating expenses for evacuations and repairs and possible acceleration of plugging and abandonment costs.

Results of Operations

Revenue

The information below provides a discussion of, and an analysis of significant variances in, our oil, natural gas and NGL revenues, production volumes and sales prices for the three and nine months ended September 30, 2019 and 2018 (in thousands, unless otherwise stated):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Revenues:
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 revenue		1,029		—		13,061		—
Total revenue	$	228,857	$	282,868	$	694,380	$	632,624
Sales volume data:
Oil production volume (MBbls)		3,559		3,507		10,228		8,188
Oil production volume (MBblpd)		38.7		38.1		37.5		30.0
Natural gas production volume (MMcf)		5,909		6,783		17,101		16,548
Natural gas production volume (MMcfpd)		64.2		73.7		62.6		60.6
NGL production volume (MBbls)		299		414		915		886
NGL production volume (MBblpd)		3.2		4.5		3.4		3.2
Total production volume (MBoe)		4,843		5,052		13,993		11,832
Total production volume (MBoepd)		52.6		54.9		51.3		43.3
Average sale price per unit:
Average oil sales price per Bbl	$	59.54	$	70.74	$	61.06	$	67.90
Average natural gas sale price per Mcf	$	2.12	$	2.98	$	2.44	$	2.98
Average NGL sale price per Bbl	$	11.32	$	35.21	$	16.50	$	30.82
Price per Boe	$	47.04	$	55.99	$	48.69	$	53.47
Price per Boe (including realized commodity derivatives)	$	48.15	$	47.93	$	48.18	$	45.45

Comparison of the Three Months Ended September 30, 2019 and 2018

Total revenue for the three months ended September 30, 2019 was $228.9 million compared to $282.9 million for the three months ended September 30, 2018, a decrease of approximately $54.0 million, or 19%.

Oil revenue decreased approximately $36.2 million, or 15%, during the three months ended September 30, 2019 compared to the corresponding period in 2018. The change was a result of a decrease of $39.9 million due to a $11.20 per Bbl lower price realization, partially offset by an increase of $3.7 million from a 0.6 MBblpd increase in production volumes. The increase in oil production volumes was primarily attributable to 3.3 MBblpd of production from the Tornado 3 well and Boris 3 well in the Phoenix Field, which were completed and commenced production during the second quarter of 2019, partially offset by approximately 3.0 MBblpd in deferred production primarily attributable to Hurricane Barry.

Natural gas revenue decreased approximately $7.6 million, or 38%, during the three months ended September 30, 2019 compared to the corresponding period in 2018. The change was a result of a decrease of $5.0 million due to a $0.86 per Mcf lower price realization, and a decrease of $2.6 million from a 9.5 MMcfpd decrease in production volumes. Natural gas production volumes decreased approximately 3.4 MMcfpd in deferred production primarily attributable to Hurricane Barry.

NGL revenue decreased approximately $11.2 million, or 77%, during the three months ended September 30, 2019 compared to the corresponding period in 2018. The change was a result of a decrease of $7.1 million due to $23.89 per Mcf lower price realization, and a decrease of $4.1 million due to a 1.3 MBoepd decrease in production volumes. NGL production volumes decreased approximately 0.4 MBblpd in deferred production primarily attributable to Hurricane Barry.

Other revenue increased $1.0 million as a result of a multi-year federal royalty refund claim.

Comparison of the Nine Months Ended September 30, 2019 and 2018

Total revenue for the nine months ended September 30, 2019 was $694.4 million compared to $632.6 million for the nine months ended September 30, 2018, an increase of approximately $61.8 million, or 10%.

Oil revenue increased approximately $68.5 million, or 12%, during the nine months ended September 30, 2019 compared to the corresponding period in 2018. The change was a result of an increase of $138.5 million from a 7.5 MBblpd increase in production volumes, partially offset by a decrease of $70.0 million due to a $6.84 per Bbl lower price realization. The increased oil production volumes were primarily attributable to an increase of 7.6 MBblpd attributable to the Stone Combination, 3.0 MBblpd attributable to the Tornado 3 well and Boris 3 well in the Phoenix Field that were completed and commenced production during the second quarter of 2019 and 1.8 MBblpd attributable to the Gunflint Acquisition and Whistler Acquisitions. The increase in oil production volumes was partially offset by a reduction of 3.4 MBblpd resulting from the shut-in of the HP-I for regulatory-mandated dry-dock and decreased approximately 1.0 MBblpd in deferred production primarily attributable to Hurricane Barry.

Natural gas revenue decreased approximately $7.6 million, or 15%, during the nine months ended September 30, 2019 compared to the corresponding period in 2018. The change was a result of a decrease of $9.2 million due to a $0.54 per Mcf lower price realization partially offset by an increase of $1.6 million from a 2.0 MMcfpd increase in volumes. The increased natural gas production volumes were primarily attributable to 5.9 MMcfpd of production from assets acquired in the Stone Combination and Whistler Acquisition partially offset by a reduction of 3.6 MMcfpd of production, resulting from the shut-in of the HP-I for regulatory-mandated dry-dock and decreased approximately 1.2 MMcfpd in deferred production primarily attributable to Hurricane Barry.

NGL revenue decreased approximately $12.2 million, or 45%, during the nine months ended September 30, 2019 compared to the corresponding period in 2018. The change was a result of a decrease of $13.1 million due to $14.32 per Bbl lower price realization, partially offset by an increase of $0.9 million from a 0.1 MBblpd increase in production volumes. NGL production volumes decreased approximately 0.1 MBblpd in deferred production primarily attributable to Hurricane Barry.

Other revenue increased $13.1 million as a result of a multi-year federal royalty refund claim.

Operating Expenses

The information below provides the details of our operating expenses for the three and nine months ended September 30, 2019 and 2018 (in thousands, except per Boe amounts):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2019			2018		2019		2018
Operating expenses:
Lease 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
Average cost per Boe:
Lease operating expenses:
Direct lease operating expense	$	8.97		$	8.33	$	8.73	$	8.54
Insurance		0.86			0.82		0.89		0.94
Production taxes		—			0.11		0.08		0.13
Total lease operating expenses		9.83			9.26		9.70		9.61
Workover and maintenance expense		2.93			4.97		3.54		4.20
Depreciation, depletion and amortization		18.20			17.38		17.76		17.29
Write-down of oil and natural gas properties		0.29			—		0.98		—
Accretion expense		1.51			2.01		1.92		2.06
General and administrative expense		3.58			4.29		3.85		5.17
Total operating expenses	$	36.34		$	37.91	$	37.75	$	38.33

Comparison of the Three Months Ended September 30, 2019 and 2018

Lease operating expense. Total lease operating expense for three months ended September 30, 2019 was $47.6 million compared to $46.8 million for the three months ended September 30, 2018, an increase of approximately $0.8 million, or 2%. This increase was primarily attributable to a $1.0 million increase in process and handling fees, primarily related to non-operated production from the Gunflint Acquisition. On a per unit basis, lease operating expense increased $0.57 per Boe.

Workover and maintenance expense. Workover and maintenance expense for the three months ended September 30, 2019 was $14.2 million compared to $25.1 million for the three months ended September 30, 2018, a decrease of approximately $10.9 million, or 43%. The decrease is primarily attributable to $3.0 million of work in preparation of the HP-I dry dock in the Phoenix Field, $2.3 million tank maintenance at the South Marsh Island 130 Field and $1.3 million for maintenance at Viosca Knoll 989 incurred in the three months ended September 30, 2018. The decreases are partially offset by $2.0 million in non-routine expense as a result of Hurricane Barry for the three months ended September 30, 2019.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense for the three months ended September 30, 2019 was $88.1 million compared to $87.8 million for the three months ended September 30, 2018, an increase of approximately $0.3 million, or 0%. The change is primarily attributable to a $0.81 increase in the depletion rate per Boe partially offset by a decrease of $3.6 million of depletion expense as a result of decreased production, primarily as a result of the impact of Hurricane Barry.

Write-down of oil and natural gas properties. During the three months ended September 30, 2019, we recorded a $1.4 million impairment. The impairment is a result of our evaluation of unproved property located in Block 2 offshore Mexico, specifically future exploratory drilling opportunities, results from exploratory wells drilled and demobilized during the second and third quarter of 2019 and the Block 2 production sharing contract’s expiration date.

General and administrative expense. General and administrative expense for the three months ended September 30, 2019 was $17.3 million compared to $21.7 million for the three months ended September 30, 2018, a decrease of approximately $4.4 million, or 20%. The change is primarily attributable to a decrease of $5.0 million in other contract service costs, the majority of which are attributable to expenses related to additional professional services, information technology and compliance that were incurred subsequent to the Stone Combination, partially offset by a $1.1 increase in other administrative costs. On a per unit basis, general and administrative expense decreased $0.71 per Boe.

Comparison of the Nine Months Ended September 30, 2019 and 2018

Lease operating expense. Total lease operating expense for nine months ended September 30, 2019 was $135.8 million compared to $113.7 million for the nine months ended September 30, 2018, an increase of approximately $22.1 million, or 19%. The increase was primarily related to $10.0 million of lease operating expense incurred in connection with assets acquired in the Stone Combination and $5.0 million in the Whistler Acquisition. Additionally, we incurred an increase of $4.2 million in process handling and non-operated expenses primarily attributable to the Gunflint Acquisition and received $1.7 million less in reimbursements under our production handling agreements resulting from the HP-I dry dock. On a per unit basis, lease operating expense increased $0.09 per Boe to $9.70 per Boe.

Workover and maintenance expense. Workover and maintenance expense for the nine months ended September 30, 2019 was $49.5 million compared to $49.7 million for the nine months ended September 30, 2018, a decrease of approximately $0.2 million, or 0%. Included in the workover and maintenance expense for the nine months ended September 30, 2019 is $2.0 million of non-routine expenses as a result of Hurricane Barry.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense for the nine months ended September 30, 2019 was $248.5 million compared to $204.6 million for the nine months ended September 30, 2018, an increase of approximately $43.9 million, or 21%. The change is primarily attributable to an increase of $37.0 million of depletion expense as a result of increased production from the Stone Combination and Whistler Acquisition, and a $0.42 increase in the depletion rate per Boe.

Write-down of oil and natural gas properties. During the nine months ended September 30, 2019, we recorded a $13.8 million impairment. The impairment is a result of our evaluation of unproved property located in Block 2 offshore Mexico, specifically future exploratory drilling opportunities, results from exploratory wells drilled and demobilized during the second and third quarter of 2019 and the Block 2 Production Sharing Contract’s expiration date.

General and administrative expense. General and administrative expense for the nine months ended September 30, 2019 was $53.8 million compared to $61.1 million for the nine months ended September 30, 2018, a decrease of approximately $7.3 million, or 12%. The change is attributable to a decrease of $24.6 million in transaction related costs primarily related to the Stone Combination, partially offset by an increase of $13.4 million in employee and contract related costs and $3.9 million in other administrative costs, the majority of which are attributable to expenses related to additional professional services, information technology and compliance that were incurred subsequent to the Stone Combination. On a per unit basis, general and administrative expense decreased $1.32 per Boe.

Other Expenses

The information below provides the details of our other expenses for the three and nine months ended September 30, 2019 and 2018 (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Other expenses:
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 (expenses)	$	567		$	(85	)	$	1,831		$	(1,163	)
Income tax expense	$	(790	)	$	—		$	(428	)	$	—

Comparison of the Three Months Ended September 30, 2019 and 2018

Price risk management activities. Price risk management activities for the three months ended September 30, 2019 resulted in $43.8 million of income compared to an expense of $53.3 million for the three months ended September 30, 2018. The income of $43.8 million for the three months ended September 30, 2019 consists of $5.4 million in cash settlement gains and $38.4 million in non-cash gains from the increase in the fair value of our open derivative contracts. The expense of $53.3 million for the three months ended September 30, 2018 consists of cash settlement losses of $40.7 million and a $12.6 million in non-cash losses from the decrease in the fair value of our open derivative contracts. These unrealized gains or losses on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on our condensed consolidated statements of operations at the end of each month.

Income Tax Effect. For the three months ended September 30, 2019, our effective tax rate was 1.0%. Our effective tax rate in 2019 differed from the statutory rate of 21% due to a reduction to the valuation allowance. For the three months ended September 30, 2018, our 0.0% effective tax rate differed from the federal statutory rate of 21% because the Company recorded a valuation allowance for its deferred tax assets.

Comparison of the Nine Months Ended September 30, 2019 and 2018

Price risk management activities. Price risk management activities for the nine months ended September 30, 2019 resulted in $35.8 million of expense compared to an expense of $196.5 million for the nine months ended September 30, 2018. The expense of $35.8 million for the nine months ended September 30, 2019 consists of $7.2 million in cash settlement losses and $28.6 million in non-cash losses from the decrease in the fair value of our open derivative contracts. The expense of $196.5 million for the nine months ended September 30, 2018 consists of cash settlement losses of $94.8 million and a $101.7 million in non-cash losses from the decrease in the fair value of our open derivative contracts. These unrealized gains or losses on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on our condensed consolidated statements of operations at the end of each month.

Income Tax Effect. For the nine months ended September 30, 2019, our effective tax rate was 0.7%. Our effective tax rate in 2019 differed from the statutory rate of 21% due to a reduction to the valuation allowance. For the nine months ended September 30, 2018, our 0.0% effective tax rate differed from the federal statutory rate of 21% because the Company recorded a valuation allowance for its deferred tax assets.

Supplemental Non-GAAP Measure

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, and non-cash equity-based compensation expense.

The following table presents a reconciliation of the GAAP financial measure of net income (loss) to Adjusted EBITDA for each of the periods indicated (in thousands, except for Boe data):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Reconciliation of net income (loss) to EBITDA and Adjusted EBITDA:
Net income (loss)	$	73,297		$	13,109		$	58,425		$	(84,746	)
Interest expense		23,123			24,837			73,273			66,257
Income tax expense		790			—			428			—
Depreciation, depletion and amortization		88,125			87,808			248,518			204,574
Accretion expense		7,316			10,162			26,868			24,414
EBITDA	$	192,651		$	135,916		$	407,512		$	210,499
Write-down of oil and natural gas properties		1,417			—			13,778			—
Loss on debt extinguishment		—			356			—			1,764
Transaction related costs		146			7,595			3,349			27,905
Derivative fair value (gain) loss⁽¹⁾		(43,760	)		53,330			35,829			196,482
Net cash receipts (payments) on settled derivative instruments⁽¹⁾		5,360			(40,746	)		(7,202	)		(94,802	)
Non-cash equity-based compensation expense		1,944			570			5,164			2,129
Adjusted EBITDA	$	157,758		$	157,021		$	458,430		$	343,977

⁽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. Thus, these adjustments result in reflecting commodity derivative gains and losses within Adjusted EBITDA on a cash basis during the period the derivatives settled.

Liquidity and Capital Resources

Overview

Our primary sources of liquidity are cash generated by our operations and borrowings under our Bank Credit Facility. Our primary uses of cash are for capital expenditures, working capital, debt service and for general corporate purposes. As of September 30, 2019, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $612.1 million.

As of September 30, 2019, total debt, net of discount and deferred financing costs, was approximately $697.2 million, comprised of our $383.2 million aggregate principal amount of the 11.00% Second-Priority Senior Secured Notes due 2022 (“11.00% Senior Secured Notes”), $6.1 million aggregate principal amount of our 7.50% Senior Secured Notes due 2022 issued by Stone (“7.50% Stone Senior Notes”) and $307.9 million outstanding under our Bank Credit Facility. During June, 2019, we repaid $10.4 million in aggregate remaining principal and accrued interest on the Stone 4.20% term loan maturing on November 20, 2030 (the “Building Loan”). We were in compliance with all debt covenants at September 30, 2019. For additional details on our debt, see “Part I, Item 1. Condensed Consolidated Financial Statements – Note 6 – Debt.”

Based on our current level of operations and available cash, we believe our cash flows from operations, combined with availability under the Bank Credit Facility provide sufficient liquidity to fund our 2019 capital spending budget of $540.0 million to $550.0 million. However, our ability to (i) generate sufficient cash flows from operations or obtain future borrowings under the Bank Credit Facility, and (ii) repay or refinance any of our indebtedness on commercially reasonable terms or at all for any potential future acquisitions, joint ventures or other similar transactions depends on operating and economic conditions, some of which are beyond our control. To the extent possible, we have attempted to mitigate certain of these risks (e.g. by entering into oil and natural gas derivative contracts to reduce the financial impact of downward commodity price movements on a substantial portion of our anticipated production), but we could be required to, or we or our affiliates may from time to time, take additional future actions on an opportunistic basis. To address further changes in the financial and/or commodity markets, future actions may include, without limitation, raising debt, including secured debt, or issuing equity to directly or independently repurchase or refinance our outstanding debt.

As of September 30, 2019, we had secured performance bonds primarily related to plugging and abandonment of wells and removal of facilities in the United States Gulf of Mexico and to guarantee the completion of the minimum work program under the Mexico production sharing contracts totaling approximately $637.3 million. In July 2016, the BOEM issued the 2016 NTL to clarify the procedures and guidelines the BOEM Regional Directors use to determine if and when additional financial assurances may be required for OCS leases, ROWs and RUEs to meet the BOEM’s estimate of the lessees’ decommissioning obligations. The 2016 NTL became effective in September 2016 and allows qualifying operators to self-insure for an amount up to 10% of their tangible net worth. The 2016 NTL also provides for operators to propose a tailored plan subject to BOEM approval that allows the posting of additional financial assurance over time. However, BOEM has indefinitely delayed beyond June 30, 2017 implementation of the 2016 NTL, except in certain circumstances where there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities, to allow BOEM time to reconsider a number of regulatory initiatives. We received notice from BOEM in late 2016 ordering us to provide additional financial assurances in the form of additional security in material amounts. We entered into discussions with BOEM regarding the requested security and submitted a proposed tailored plan for the posting of additional financial security to the agency for review. However, as noted, BOEM has indefinitely delayed implementation beyond June 30, 2017 of the 2016 NTL, has rescinded the late December 2016 orders while BOEM reviews its financial assurance program and, to date, has taken no action with respect to our previously submitted proposed tailored plan. We remain in active discussion with our government regulators and industry peers with regard to any future rule making and financial assurance requirements. Notwithstanding the 2016 NTL, BOEM may also increase its financial assurance requirements mandated by rule for all companies operating in federal waters. BOEM could also make new demands for additional financial security in material amounts in the event the agency chooses to implement the 2016 NTL, and such amounts may be material and exceed our capability to provide additional financial assurance. The future cost of compliance with our existing supplemental bonding requirements, including with respect to any tailored plan, the 2016 NTL, as well as any other future directives or any other changes to the BOEM’s rules applicable to us or our subsidiaries’ properties, could materially and adversely affect our financial condition, cash flows and results of operations.

Senior Notes

11.00% Second-Priority Senior Secured Notes – due April 2022. The 11.00% Senior Secured Notes were issued pursuant to an indenture dated May 10, 2018. The 11.00% Senior Secured Notes mature April 3, 2022 and have interest payable semi-annually each April 15 and October 15. Prior to May 10, 2020, we may, at our option, redeem all or a portion of the 11.00% Senior Secured Notes at 105.5% of the principal amount plus accrued and unpaid interest. Thereafter, we may redeem all or a portion of the 11.00% Senior Secured Notes at redemption prices decreasing annually from 102.75% to 100.0% plus accrued and unpaid interest.

7.50% Senior Secured Notes – due May 2022. The 7.50% Stone Senior Notes represent the remaining $6.1 million of long-term debt assumed in the Stone Combination that were not exchanged for 11.00% Senior Secured Notes and thus remain outstanding. As a result, substantially all of the restrictive covenants relating to the 7.50% Stone Senior Notes have been removed and collateral securing the 7.50% Stone Senior Notes has been released. The 7.50% Stone Senior Notes mature May 31, 2022 and have interest payable semi-annually each May 31 and November 30. Prior to May 31, 2020, we may, at our option, redeem all or a portion of the 7.50% Stone Senior Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, we may redeem all or a portion of the 7.50% Stone Senior Notes at redemption prices decreasing annually from 105.625% to 100.0% plus accrued and unpaid interest.

Bank Credit Facility

The Company and Talos Production LLC, our wholly-owned subsidiary, executed the Bank Credit Facility in conjunction with the Stone Combination with a syndicate of financial institutions, with an initial borrowing base of $600.0 million. The Bank Credit Facility matures on May 10, 2022, provided that the Bank Credit Facility mandates a springing maturity that is 120 days prior to May 10, 2022, if greater than $25.0 million of the 11.00% Senior Secured Notes or any permitted refinancing indebtedness in respect thereof is outstanding on such date.

The Bank Credit Facility provides for determination of the borrowing base based on our proved producing reserves and a portion of our proved undeveloped reserves. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter. On July 3, 2019, the Company and Talos Production LLC entered into a Joinder, First Amendment to Credit Agreement, and Borrowing Base Reaffirmation Agreement in which, (a) the $850.0 million borrowing base was reaffirmed, (b) the commitments were increased from $600.0 million to $850.0 million, (c) three additional financial institutions were joined as lenders to the syndicate and (d) certain other amendments were made to the Bank Credit Facility as more particularly described therein. The Company’s scheduled redetermination meeting was held October 30, 2019, with results expected in November 2019.

As of September 30, 2019, our borrowing base and commitments were $850.0 million, of which no more than $200 million can be used as letters of credit. The amount that we are able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Bank Credit Facility. We were in compliance with all debt covenants at September 30, 2019. As of September 30, 2019, the Bank Credit Facility had approximately $521.4 million of undrawn commitments (taking into account $13.6 million letters of credit and $315.0 million drawn from the Bank Credit Facility).

Building Loan. In connection with the Stone Combination, we assumed Stone’s Building Loan maturing on November 20, 2030. The Building Loan bears interest at a rate of 4.20% per annum and is to be repaid in 180 equal monthly installments of approximately $0.1 million. During June 2019, the Company repaid and discharged $10.5 million aggregate remaining principal, plus accrued interest, of the Building Loan using proceeds from the sale of an office building in Lafayette acquired in the Stone Combination and cash on hand. As of September 30, 2019, there is no outstanding balance under the Building Loan.

Overview of Cash Flow Activities

The following table summarizes cash flows provided by (used in) by type of activity, for the following periods (in thousands):

	Nine Months Ended September 30,
	2019			2018
Operating activities	$	332,413		$	143,687
Investing activities	$	(400,467	)	$	104,060
Financing activities	$	17,574		$	(190,015	)

Operating Activities. Net cash provided by operating activities increased $188.7 million in the nine months ended September 30, 2019 compared to the corresponding period in 2018 primarily attributable to an increase in revenue of $143.2 million and a decrease in settlements of asset retirement obligations of $31.3 million.

Investing Activities. Net cash provided by (used in) investing activities increased $504.5 million in the nine months ended September 30, 2019 compared to the corresponding period in 2018 primarily attributable to an increase in capital expenditures of $198.6 million. Additionally, we paid $32.9 million for acquisitions during the nine months ended September 30, 2019 versus receiving $278.4 million for cash acquired for acquisitions during the nine months ended September 30, 2018.

Financing Activities. Net cash provided by (used in) financing activities increased $207.6 million in the nine months ended September 30, 2019 compared to the corresponding period in 2018. The increase was primarily attributable to receiving net proceeds of approximately $40.1 million from the Bank Credit Facility and other obligations, partially offset by a $10.6 million repayment of the Building Loan for the nine months ended September 30, 2019 compared to net repayments of approximately $180.1 million for the comparative period in 2018.

Capital Expenditures. We fund exploration and development activities primarily through operating cash flows, cash on hand and through borrowings under our Bank Credit Facility, if necessary. Historically, we have funded significant property acquisitions through the issuance of senior notes, borrowings under the Bank Credit Facility and through additional equity transactions. We occasionally adjust our capital budget in response to changing operating cash flow forecasts and market conditions, including the prices of oil, natural gas and NGLs, acquisition opportunities and the results of our exploration and development activities.

The following is a table of our capital expenditures for the nine months ended September 30, 2019 (in thousands):

U.S. drilling & completions	$	236,687
Mexico appraisal & exploration		68,868
Asset management		49,052
Seismic and G&G, land, capitalized G&A and other		49,881
Total capital expenditures	$	404,488
Plugging & abandonment		54,406
Total capital expenditures and plugging & abandonment	$	458,894

Capital expenditures and plugging and abandonment for the remainder of 2019 are estimated to be approximately $80.0 million to $90.0 million, which we plan to fund through cash flows from operations and borrowings under our Bank Credit Facility.

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements as of September 30, 2019.

Critical Accounting Policies and Estimates

We consider accounting policies related to oil and natural gas properties, proved reserve estimates, fair value measure of financial instruments, asset retirement obligations, revenue recognition, imbalances and production handling fees, income taxes as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. There have been no changes to our critical accounting policies, which are summarized in the “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” section in our 2018 Annual Report.

Recently Adopted Accounting Standards

See “Part I, Item 1. Condensed Consolidated Financial Statements – Note 1 – Formation and Basis of Presentation” for accounting standards recently adopted by the Company.

Recently Issued Accounting Standards

See “Part I, Item 1. Condensed Consolidated Financial Statements – Note 1 – Formation and Basis of Presentation” for recently issued accounting standards applicable to the Company.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

For information regarding our exposures to certain market risks, refer to “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” in our 2018 Annual Report. Except as disclosed in this report, there have been no material changes from the disclosures presented in our 2018 Annual Report regarding our exposures to certain market risks.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, our principal executive officer and principal financial officer have evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to ensure that the information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and to ensure that the information we are required to disclose in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on such evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of September 30, 2019.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended September 30, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

There have been no material developments with respect to the information previously reported under Part I, Item 3 of our 2018 Annual Report.

Item 1A. Risk Factors

In addition to the other information set forth in this Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under the heading “Part I, Item 1A. Risk Factors” included in our 2018 Annual Report and the risk factors and other cautionary statements contained in our other SEC filings, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. There have been no material changes in our risk factors from those described in our 2018 Annual Report or our other SEC filings.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

Exhibit Number		Description

3.1		Amended and Restated Certificate of Incorporation of Talos Energy Inc. (incorporated by reference to Exhibit 3.1 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

3.2		Amended & Restated Bylaws of Talos Energy Inc. (incorporated by reference to Exhibit 3.2 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).

10.1		Joinder, First Amendment to Credit Agreement, and Borrowing Base Reaffirmation Agreement, dated as of July 3, 2019, by and among Talos Energy Inc., as holdings, Talos Production LLC, as borrower, each other credit party, JPMorgan Chase Bank, N.A., as administrative agent, each issuing bank, the swingline lender, and the lenders (including the new lenders) party thereto (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K filed with the SEC on July 10, 2019).

31.1*		Certification of Chief Executive Officer of Talos Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer of Talos Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1**		Certification of Chief Executive Officer and Chief Financial Officer of Talos Energy Inc. pursuant to 18 U.S.C. § 1350, as adopted pursuant to the Sarbanes-Oxley Act of 2002.

101.INS*		XBRL Instance Document – The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document

101.SCH*		Inline XBRL Taxonomy Extension Schema Document

101.CAL*		Inline XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF*		Inline XBRL Taxonomy Extension Definition Linkbase Document

101.LAB*		Inline XBRL Taxonomy Extension Label Linkbase Document

101.PRE*		Inline XBRL Taxonomy Extension Presentation Linkbase Document

Exhibit 104		Cover Page Interactive Date File – The cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document

*	Filed herewith.

**	Furnished herewith.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		TALOS ENERGY INC.

Date:	November 6, 2019	By:	/s/ Shannon E. Young III
			Shannon E. Young III

			Executive Vice President and Chief Financial Officer

			(Principal Financial Officer and Authorized Signatory)