TALOS ENERGY INC. - Quarter Report: 2020 September (Form 10-Q)

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, 2020

☐	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 October 28, 2020, the registrant had 73,029,989 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	24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	39
Item 4.	Controls and Procedures	39
	PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	40
Item 1A.	Risk Factors	40
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	46

GLOSSARY

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:

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.

MMBoe — One million barrels of oil equivalent.

MMBtu — One million British thermal units.

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.

NYMEX Henry Hub — Henry Hub is the major exchange for pricing natural gas futures on the New York Mercantile Exchange. It is frequently referred to as the Henry Hub index.

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.

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 SEC 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.

WTI or West Texas Intermediate — A light crude oil produced in the United States with an American Petroleum Institute gravity of approximately 38-40 and the sulfur content is approximately 0.3%.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (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, including as a result of the upcoming presidential and congressional elections in the U.S.;

•

our ability to obtain permits and governmental approvals, including with respect to repairs to the Ram Powell facility;

•

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, including the sharp decline in oil prices beginning in March 2020, the impact of the coronavirus disease 2019 (“COVID-19”) and governmental measures related thereto on global demand for oil and natural gas and on the operations of our business; the ability or willingness of the Organization of Petroleum Exporting Countries (“OPEC”) and non-OPEC countries, such as Saudi Arabia and Russia, to set and maintain oil production levels; the impact of any such actions, lack of transportation and storage capacity as a result of oversupply, government regulations and actions or other factors; lack of availability of drilling and production equipment and services; inflation; 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; potential adverse reactions or competitive responses to our acquisitions and other transactions; the possibility that the anticipated benefits of our business combination are not realized when expected or at all, including as a result of the impact of, or problems arising from, the integration of acquired assets and operations; and the other risks discussed in Part I, Item 1A, “Risk Factors” of Talos Energy Inc.’s Annual Report on Form 10-K for the year ended December 31, 2019 (the “2019 Annual Report”) and Part II, Item 1A. “Risk Factors” of this Quarterly Report on Form 10-Q (this “Quarterly Report”).

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. 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 Quarterly Report.

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

TALOS ENERGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share amounts)

	September 30, 2020			December 31, 2019
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	32,377		$	87,022
Accounts receivable
Trade, net		64,948			107,842
Joint interest, net		61,054			16,552
Other		13,396			6,346
Assets from price risk management activities		38,716			8,393
Prepaid assets		44,148			65,877
Other current assets		1,802			1,952
Total current assets		256,441			293,984
Property and equipment:
Proved properties		4,855,152			4,066,260
Unproved properties, not subject to amortization		254,243			194,532
Other property and equipment		32,323			29,843
Total property and equipment		5,141,718			4,290,635
Accumulated depreciation, depletion and amortization		(2,327,556	)		(2,065,023	)
Total property and equipment, net		2,814,162			2,225,612
Other long-term assets:
Assets from price risk management activities		4,458			—
Other well equipment inventory		14,478			7,732
Operating lease assets		7,060			7,779
Other assets		75,682			54,375
Total assets	$	3,172,281		$	2,589,482
LIABILITIES AND STOCKHOLDERSʼ EQUITY
Current liabilities:
Accounts payable	$	110,895		$	71,357
Accrued liabilities		172,741			154,816
Accrued royalties		18,464			31,729
Current portion of asset retirement obligations		53,976			61,051
Liabilities from price risk management activities		33,443			19,476
Accrued interest payable		20,088			10,249
Current portion of operating lease liabilities		1,713			1,594
Other current liabilities		23,104			20,180
Total current liabilities		434,424			370,452
Long-term liabilities:
Long-term debt, net of discount and deferred financing costs		994,748			732,981
Asset retirement obligations		377,160			308,427
Liabilities from price risk management activities		8,201			511
Operating lease liabilities		18,998			17,239
Other long-term liabilities		56,474			81,595
Total liabilities		1,890,005			1,511,205
Commitments and contingencies (Note 11)
Stockholdersʼ Equity:
Preferred stock, $0.01 par value; 30,000,000 shares authorized and no shares issued or outstanding as of September 30, 2020 and December 31, 2019		—			—
Common stock $0.01 par value; 270,000,000 shares authorized; 73,029,989 and 54,197,004 shares issued and outstanding as of September 30, 2020 and December 31, 2019, respectively		730			542
Additional paid-in capital		1,584,815			1,346,142
Accumulated deficit		(303,269	)		(268,407	)
Total stockholdersʼ equity		1,282,276			1,078,277
Total liabilities and stockholdersʼ equity	$	3,172,281		$	2,589,482

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

TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except share amounts)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2020			2019			2020			2019
Revenues:
Oil revenue	$	117,190		$	211,899		$	358,285		$	624,486
Natural gas revenue		12,337			12,545			35,375			41,738
NGL revenue		3,409			3,384			9,674			15,095
Other		2,201			1,029			8,441			13,061
Total revenue		135,137			228,857			411,775			694,380
Operating expenses:
Lease operating expense		62,064			61,816			184,187			184,230
Production taxes		225			(21	)		640			1,067
Depreciation, depletion and amortization		80,547			88,125			262,533			248,518
Write-down of oil and natural gas properties		—			1,417			57			13,778
Accretion expense		11,537			7,316			37,748			26,868
General and administrative expense		17,823			17,321			62,484			53,795
Total operating expenses		172,196			175,974			547,649			528,256
Operating income (expense)		(37,059	)		52,883			(135,874	)		166,124
Interest expense		(24,124	)		(23,123	)		(76,164	)		(73,273	)
Price risk management activities income (expense)		(19,882	)		43,760			154,653			(35,829	)
Other income		813			567			139			1,831
Net income (loss) before income taxes		(80,252	)		74,087			(57,246	)		58,853
Income tax benefit (expense)		28,252			(790	)		22,384			(428	)
Net income (loss)	$	(52,000	)	$	73,297		$	(34,862	)	$	58,425

Net income (loss) per common share:
Basic	$	(0.73	)	$	1.35		$	(0.54	)	$	1.08
Diluted	$	(0.73	)	$	1.35		$	(0.54	)	$	1.07
Weighted average common shares outstanding:
Basic		71,286			54,200			65,134			54,178
Diluted		71,286			54,430			65,134			54,364

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

TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

STOCKHOLDERS’ EQUITY

(In thousands, except share amounts)

(Unaudited)

	Shares					Par Value				Additional						Total
	Common Stock			Preferred Stock		Common Stock		Preferred Stock		Paid- In Capital			Accumulated Deficit			Stockholdersʼ Equity
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

Balance at June 30, 2020		68,414,782			—	$	684	$	—	$	1,545,138		$	(251,269	)	$	1,294,553
Equity based compensation		17,879			—		—		—		4,366			—			4,366
Shares withheld for taxes on equity transactions		(5,132	)		—		—		—		(36	)		—			(36	)
Issuance of common stock		4,602,460			—		46		—		35,347			—			35,393
Net loss		—			—		—		—		—			(52,000	)		(52,000	)
Balance at September 30, 2020		73,029,989			—	$	730	$	—	$	1,584,815		$	(303,269	)	$	1,282,276

	Shares						Par Value						Additional						Total
	Common Stock			Preferred Stock			Common Stock			Preferred Stock			Paid- In Capital			Accumulated Deficit			Stockholdersʼ Equity
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

Balance at December 31, 2019		54,197,004			—		$	542		$	—		$	1,346,142		$	(268,407	)	$	1,078,277
Equity based compensation		248,357			—			2			—			12,133			—			12,135
Shares withheld for taxes on equity transactions		(67,832	)		—			(1	)		—			(826	)		—			(827	)
Issuances of preferred shares		—			110,000			—			1			156,199			—			156,200
Conversion of preferred shares into common shares		11,000,000			(110,000	)		110			(1	)		(109	)		—			—
Issuance of common stock		7,652,460			—			77			—			71,276			—			71,353
Net loss		—			—			—			—			—			(34,862	)		(34,862	)
Balance at September 30, 2020		73,029,989			—		$	730		$	—		$	1,584,815		$	(303,269	)	$	1,282,276

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,
	2020			2019
Cash flows from operating activities:
Net income (loss)	$	(34,862	)	$	58,425
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion, amortization and accretion expense		300,281			275,386
Write-down of oil and natural gas properties and other well inventory		190			13,778
Amortization of deferred financing costs and original issue discount		5,393			3,723
Equity based compensation, net of amounts capitalized		6,321			5,164
Price risk management activities expense (income)		(154,653	)		35,829
Net cash received (paid) on settled derivative instruments		141,529			(7,202	)
Gain on extinguishment of debt		(1,644	)		—
Settlement of asset retirement obligations		(34,502	)		(54,406	)
Changes in operating assets and liabilities:
Accounts receivable		(1,729	)		(14,729	)
Other current assets		21,835			11,384
Accounts payable		23,500			32,541
Other current liabilities		31,826			(26,753	)
Other non-current assets and liabilities, net		(41,418	)		(727	)
Net cash provided by operating activities		262,067			332,413
Cash flows from investing activities:
Exploration, development and other capital expenditures		(280,273	)		(372,920	)
Cash paid for acquisitions, net of cash acquired		(304,879	)		(32,916	)
Proceeds from sale of other property and equipment		—			5,369
Net cash used in investing activities		(585,152	)		(400,467	)
Cash flows from financing activities:
Redemption of Senior Notes and other long-term debt		(4,735	)		(10,567	)
Proceeds from Bank Credit Facility		300,000			75,000
Repayment of Bank Credit Facility		—			(25,000	)
Deferred financing costs		(1,287	)		(1,268	)
Other deferred payments		(11,921	)		(9,921	)
Payments of finance lease		(12,790	)		(10,344	)
Employee stock transactions		(827	)		(326	)
Net cash provided by financing activities		268,440			17,574

Net decrease in cash, cash equivalents and restricted cash		(54,645	)		(50,480	)
Cash, cash equivalents and restricted cash:
Balance, beginning of period		87,022			141,162
Balance, end of period	$	32,377		$	90,682

Supplemental Non-Cash Transactions:
Capital expenditures included in accounts payable and accrued liabilities	$	97,517		$	24,622
Debt exchanged for common stock	$	35,960		$	—
Supplemental Cash Flow Information:
Interest paid, net of amounts capitalized	$	41,188		$	36,011

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

TALOS ENERGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2020

(Unaudited)

Note 1 — Formation and Basis of Presentation

Formation and Nature of Business

Talos Energy Inc. (“Talos” or the “Company”) is a technically driven independent exploration and production company focused on safely and efficiently maximizing value through its operations, currently in the United States (“U.S.”) Gulf of Mexico and offshore Mexico. The Company leverages decades of geology, geophysics and offshore operations expertise towards the acquisition, exploration, exploitation and development of assets in key geological trends that are present in many offshore basins around the world.

Talos was formed in connection with the previously disclosed 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 (the “Stone Combination”). Talos Energy LLC was formed in 2011 and commenced commercial operations on February 6, 2013. Prior to February 6, 2013, Talos Energy LLC had 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 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, together with the Apollo Funds, the “Sponsors”) and members of management pursuant to which the Company received a private equity capital commitment.

Basis of Presentation and Consolidation

The condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the 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 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, 2019.

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.

As discussed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2019, operating expenses previously presented as “Direct lease operating expense,” “Insurance” and “Workover and maintenance expense” have been combined and presented as “Lease operating expense” on the Company’s condensed consolidated statements of operations. Such reclassification had no effect on the Company’s results of operations, financial position or cash flows.

The Company has one reportable segment, which is the exploration and production of oil and natural gas. Substantially all the Company’s long-lived assets, proved reserves and production sales are related to the Company’s operations in the United States.

Recently Adopted Accounting Standards

Credit Risk Losses — In June 2016, the Financial Accounting Standards Board issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which changes accounting requirements for the recognition of credit losses from an incurred or probable impairment methodology to a current expected credit losses (“CECL”) methodology. The CECL model is applicable to the measurement of credit losses on financial assets measured at amortized cost, including but not limited to trade receivables. The guidance was adopted on January 1, 2020 using a modified retrospective approach. The adoption of this guidance did not have a material effect on the Company’s condensed consolidated financial statements or related disclosures.

Accounts receivable resulting from the sale of crude oil, NGL and natural gas production and joint interest billings to our partners for their share of expenses on joint venture projects for which we are the operator are the primary financial assets within the scope of the standard. Although these receivables are from a diverse group of companies, including major energy companies, pipeline companies and joint interest owners, they are concentrated in the oil and gas industry. This concentration has the potential to impact our overall exposure to credit risk in that these companies may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. A loss-rate methodology is used to estimate the allowance for expected credit losses to be accrued on material receivables to reflect the net amount to be collected. At each reporting period the loss-rate is determined utilizing historical data, current market conditions and reasonable and supported forecast of future economic conditions. Our allowance for uncollectable receivables was $9.3 million at September 30, 2020 and $9.9 million at December 31, 2019.

Guarantor Financial Information — In March 2020, the SEC adopted final rules that simplify the disclosure requirements related to certain registered securities under SEC Regulation S-X, Rules 3-10 and 3-16, permitting registrants to provide certain alternative financial disclosures and non-financial disclosures in lieu of separate consolidated financial statements for subsidiary issuers and guarantors of registered debt securities (which we previously included within the notes to our financial statements included in our Annual Report on Form 10-K and Quarterly Reports on Form 10-Q) if certain conditions are met. The disclosure requirements, as amended, are now located in newly created Rules 13-01 and 13-02 of Regulation S-X and are generally effective for filings on or after January 4, 2021, with early adoption permitted. We early adopted the new disclosure requirements effective as of July 1, 2020 and are providing the summarized financial information and related disclosures in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Form 10-Q.

Note 2 — Acquisitions

Asset Acquisitions

Acquisitions qualifying as an asset acquisition requires, among other items, that the cost of the assets acquired and liabilities assumed be recognized on the condensed consolidated 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 Castex Energy 2005 — On August 5, 2020, the Company completed the acquisition of select oil and natural gas assets from affiliates of Castex Energy 2005 Holdco, LLC with an effective date of April 1, 2020 (the “Castex Energy 2005 Acquisition”). The oil and natural gas assets consist of 16 properties in the U.S. Gulf of Mexico shelf and Gulf Coast core area. The Castex Energy 2005 Acquisition was consummated pursuant to a Purchase and Sale Agreement dated June 19, 2020 for consideration consisting of (i) $6.5 million in cash, (ii) $35.4 million in 4.6 million shares of the Company’s common stock and $1.4 million in transaction related expenses, inclusive of customary closing adjustments.

The following table summarizes the purchase price, inclusive of customary closing adjustments (in thousands except share and per share data):

Talos common stock		4,602,460
Talos common stock price per share⁽¹⁾	$	7.69
Talos common stock value	$	35,393

Cash consideration	$	6,500
Transaction cost	$	1,413

Total purchase price	$	43,306

⁽¹⁾	Represents the closing price of the Company’s common stock on August 5, 2020, the date of the closing of the Castex Energy 2005 Acquisition.

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 5, 2020 (in thousands):

Property and equipment	$	46,626
Asset retirement obligations		(3,320	)
Allocated purchase price	$	43,306

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

Business Combination

Acquisitions qualifying as business combinations 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.

ILX and Castex Acquisition — On February 28, 2020, the Company acquired the outstanding limited liability interests in certain wholly owned subsidiaries of ILX Holdings, LLC, ILX Holdings II, LLC, ILX Holdings III LLC and Castex Energy 2014, LLC, each a related party and an affiliate of the Riverstone Funds (the “Riverstone Sellers”), and Castex Energy 2016, LP (together with the Riverstone Sellers, the “Sellers”) with an effective date of July 1, 2019 (collectively, the “ILX and Castex Acquisition”). The ILX and Castex Acquisition was consummated pursuant to separate Purchase and Sale Agreements, dated December 10, 2019 (as amended from time to time, the “Purchase Agreements”) for aggregate consideration consisting of (i) $385.0 million in cash subject to customary closing adjustments and (ii) an aggregate 110,000 shares (the “Preferred Shares”) of a series of the Company’s preferred stock designated as “Series A Convertible Preferred Stock” which subsequently converted to 11.0 million shares of the Company’s common stock on March 30, 2020 (such common stock, the “Conversion Stock”). The cash payment and escrow deposit were funded with borrowings under the Bank Credit Facility (as defined below).

The following table summarizes the purchase price, subject to customary post-closing adjustments (in thousands except per share data):

Talos Conversion Stock		11,000
Talos common stock price per share⁽¹⁾	$	14.20
Conversion Stock value	$	156,200

Cash consideration	$	385,000
Customary closing adjustments		(88,034	)
Net cash consideration paid at closing	$	296,966

Total purchase price	$	453,166

⁽¹⁾

Represents the closing price of the Company’s common stock on February 28, 2020, the date of the closing of the ILX and Castex Acquisition. The purchase price was based on the value of the Conversion Stock as the value approximates the value of the Preferred Shares as a result of the automatic conversion and dividend rights described in that certain Certificate of Designation, Preferences, Rights and Limitations.

While the Company has substantially completed the determination of the fair values of the assets acquired and liabilities assumed, the Company is still finalizing the fair value analysis related to the oil and natural gas properties acquired and asset retirement obligations assumed. The Company anticipates finalizing the determination of fair values by December 31, 2020.

The following table presents the preliminary allocation of the purchase price to the assets acquired and liabilities assumed, based on their fair values on February 28, 2020 and September 30, 2020, including the associated measurement period adjustments (in thousands):

	February 28, 2020			Adjustments			September 30, 2020
Current assets⁽¹⁾	$	10,969		$	(1,230	)	$	9,739
Property and equipment		489,796			720			490,516
Other long-term assets		148			—			148
Current liabilities		(7,129	)		(7,907	)		(15,036	)
Other long-term liabilities		(44,489	)		12,288			(32,201	)
Allocated purchase price	$	449,295		$	3,871		$	453,166

⁽¹⁾	Includes trade and other receivables of $6.9 million, which the Company expects all to be realizable.

The Company incurred approximately $12.1 million of transaction related costs, of which $0.4 million and $8.7 million was recognized in the three and nine months ended September 30, 2020, respectively, and $3.4 million was recognized in the fourth quarter of 2019. These costs have been reflected in “General and administrative expense” on the condensed consolidated statements of operations.

The following table presents revenue and net income attributable to the assets acquired in the ILX and Castex Acquisition for the three and nine months ended September 30, 2020:

	Three Months Ended September 30, 2020			Nine Months Ended September 30, 2020
Revenue	$	37,538		$	77,729
Net loss	$	(1,131	)	$	(13,083	)

Pro Forma Financial Information (Unaudited) — The following supplemental pro forma financial information (in thousands, except per common share amounts), presents the condensed consolidated results of operations for the three months ended September 30, 2019 and nine months ended September 30, 2020 and 2019 as if the ILX and Castex Acquisition had occurred on January 1, 2019. The unaudited pro forma information was derived from historical statements of operations of the Company and the Sellers adjusted to (i) include depletion expense applied to the adjusted basis of the oil and natural gas properties acquired, (ii) include interest expense to reflect borrowings under the Bank Credit Facility, (iii) eliminate the write-down of oil and natural gas properties on the assets acquired to reflect the pro-forma ceiling test calculation and (iv) include weighted average basic and diluted shares of common stock outstanding, which was calculated assuming the 11.0 million shares of Conversion Stock were issued to the Sellers. This information does not purport to be indicative of results of operations that would have occurred had the ILX and Castex Acquisition occurred on January 1, 2019, nor is such information indicative of any expected future results of operations.

	Three Months Ended September 30,		Nine Months Ended September 30,
	2019		2020			2019
Revenue	$	306,839	$	459,210		$	940,272
Net income (loss)	$	98,862	$	(22,799	)	$	150,129
Basic net income (loss) per common share	$	1.52	$	(0.34	)	$	2.30
Diluted net income (loss) per common share	$	1.51	$	(0.34	)	$	2.30

Note 3 — Property, Plant and Equipment

Proved Properties

The Company’s interests in oil and natural gas proved properties are located in the United States, 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.

During the three and nine months ended September 30, 2020 and 2019, the Company’s ceiling test computation did not result in a write-down of its U.S. oil and natural gas properties. At September 30, 2020, the Company’s ceiling test computation was based on SEC pricing, adjusted for differentials, of $44.31 per Bbl of oil, $1.97 per Mcf of natural gas and $10.89 per Bbl of NGLs.

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, expenditures associated with certain exploratory wells in progress and capitalized interest. Unproved properties also include expenditures associated with exploration and appraisal activities in Block 7 and Block 31 located in the shallow waters off the coast of Mexico’s Veracruz and Tabasco states.

The Company’s 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 resulted in the Company recording a non-cash impairment presented as “Write-down of oil and natural gas properties” on the condensed consolidated statements of operations. For the three and nine months ended September 30, 2020, the Company recorded an impairment of nil and $0.1 million, respectively. Unproved property impairment for the three and nine months ended September 30, 2019 was $1.4 million and $13.8 million, respectively.

Asset Retirement Obligations

The discounted asset retirement obligations included in the condensed consolidated balance sheets in current and non-current liabilities, and the changes in that liability during the nine months ended September 30, 2020 were as follows (in thousands):

Asset retirement obligations at January 1	$	369,478
Fair value of asset retirement obligations acquired⁽¹⁾		40,078
Obligations settled		(34,502	)
Fair value of asset retirement obligations divested		(185	)
Accretion expense		37,748
Obligations incurred		1,337
Changes in estimate		17,182
Asset retirement obligations at September 30	$	431,136
Less: Current portion		(53,976	)
Long-term portion	$	377,160

⁽¹⁾	Nine months ended September 30, 2020 includes $35.3 million and $3.3 million of asset retirement obligations assumed in the ILX and Castex Acquisition and Castex Energy 2005 Acquisition, respectively.

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. 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 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 depending on how the leased asset is utilized. The components of lease costs were as follows (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Finance lease cost - interest on lease liabilities⁽¹⁾	$	3,848	$	4,728	$	12,153	$	14,589
Operating lease cost, excluding short-term leases⁽²⁾		815		822		2,547		2,348
Short-term lease cost⁽³⁾		21,845		17,658		41,128		81,897
Variable lease cost⁽⁴⁾		215		3		221		8
Total lease cost	$	26,723	$	23,211	$	56,049	$	98,842

⁽¹⁾

The Helix Producer I (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, 2020		December 31, 2019
Operating leases:
Operating lease assets	$	7,060	$	7,779

Current portion of operating lease liabilities	$	1,713	$	1,594
Operating lease liabilities		18,998		17,239
Total operating lease liabilities	$	20,711	$	18,833

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

Other current liabilities	$	20,645	$	17,509
Other long-term liabilities		46,101		62,026
Total finance lease liabilities	$	66,746	$	79,535

⁽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.

The table below presents the lease maturity by year as of September 30, 2020 (in thousands). Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the condensed consolidated balance sheet.

	Operating Leases			Finance Leases
2020 (excluding the nine months ended September 30, 2020)	$	981		$	8,315
2021		4,079			33,257
2022		4,302			33,257
2023		4,239			13,857
2024		3,315			—
Thereafter		15,790			—
Total lease payments	$	32,706		$	88,686
Imputed interest		(11,995	)		(21,940	)
Total	$	20,711		$	66,746

The table below presents the weighted average remaining lease term and discount rate related to leases for the nine months ended September 30, 2020 and 2019:

	Nine Months Ended September 30,
	2020			2019
Weighted average remaining lease term:
Operating leases	8.0 years			8.6 years
Finance leases	2.7 years			3.7 years
Weighted average discount rate:
Operating leases		10.3	%		10.2	%
Finance leases		21.9	%		21.9	%

The table below presents the supplemental cash flow information related to leases for the nine months ended September 30, 2020 and 2019 (in thousands):

	Nine Months Ended September 30,
	2020		2019
Operating cash outflow from finance leases	$	12,153	$	14,589
Financing cash outflow from finance leases	$	12,790	$	10,344
Operating cash outflow from operating leases	$	1,666	$	1,358

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 the Company’s financial instruments (in thousands):

	September 30, 2020				December 31, 2019
	Carrying Amount		Fair Value		Carrying Amount			Fair Value
11.00% Second-Priority Senior Secured Notes – due April 2022⁽¹⁾	$	343,582	$	327,381	$	383,871		$	401,128
7.50% Senior Notes – due May 2022	$	6,060	$	4,560	$	6,060		$	5,030
Bank Credit Facility – matures May 2022⁽¹⁾	$	645,106	$	650,000	$	343,050		$	350,000
Oil and Natural Gas Derivatives	$	1,530	$	1,530	$	(11,594	)	$	(11,594	)

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

As of September 30, 2020 and December 31, 2019, the carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair values because of the short-term nature of these instruments.

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

The $347.9 million aggregate principal amount of 11.00% Second-Priority Senior Secured Notes (the “11.00% Notes”) is reported on the condensed consolidated balance sheet as of September 30, 2020 at its carrying value, net of original issue discount and deferred financing costs, see Note 6 — Debt. The fair value of the 11.00% Notes is estimated (representing a Level 1 fair value measurement) using quoted secondary market trading prices.

7.50% Senior Notes – due May 2022

The $6.1 million aggregate principal amount of 7.50% Senior Notes (the “7.50% Notes”) is reported on the condensed consolidated balance sheet as of September 30, 2020 at its carrying value, see Note 6 — Debt. The fair value of the 7.50% Notes is estimated (representing a Level 1 fair value measurement) using quoted secondary market trading prices.

Bank Credit Facility – matures May 2022

The Company and Talos Production Inc., a wholly-owned subsidiary that was formerly known as Talos Production LLC, maintains a bank credit facility with a borrowing base of $985.0 million at September 30, 2020 (the “Bank Credit Facility”), which is reported on the condensed consolidated balance sheet as of September 30, 2020 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 sheet 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 its condensed consolidated statements of operations (in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2020			2019		2020		2019
Net cash received (paid) on settled derivative instruments	$	19,030		$	5,360	$	141,529	$	(7,202	)
Unrealized gain (loss)		(38,912	)		38,400		13,124		(28,627	)
Price risk management activities income (expense)	$	(19,882	)	$	43,760	$	154,653	$	(35,829	)

The following table reflects the contracted volumes and weighted average prices the Company will receive under the terms of its derivative contracts as of September 30, 2020:

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)
October 2020 – December 2020	Swap		31,315	$	43.29	$	—	$	—
October 2020 – December 2020	Collar		5,000	$	—	$	50.00	$	57.09
January 2021 – December 2021	Swap		16,945	$	42.77	$	—	$	—
January 2021 – December 2021	Collar		1,000	$	—	$	30.00	$	40.00
January 2022 – December 2022	Swap		9,723	$	44.59	$	—	$	—
Crude Oil – LLS:		(Bbls)		(per Bbl)		(per Bbl)		(per Bbl)
January 2021 – December 2021	Swap		3,000	$	38.83	$	—	$	—
Natural Gas – NYMEX Henry Hub:		(MMBtu)		(per MMBtu)		(per MMBtu)		(per MMBtu)
October 2020 – December 2020	Swaps		71,815	$	2.29	$	—	$	—
January 2021 – December 2021	Swaps		53,934	$	2.52	$	—	$	—
January 2021 – December 2021	Collar		5,000	$	—	$	2.50	$	3.10
January 2022 – December 2022	Swaps		19,197	$	2.52	$	—	$	—

The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands):

	September 30, 2020
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas swaps and costless collars	$	—	$	43,174		$	—	$	43,174
Liabilities:
Oil and natural gas swaps and costless collars		—		(41,644	)		—		(41,644	)
Total net asset	$	—	$	1,530		$	—	$	1,530

	December 31, 2019
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas swaps and costless collars	$	—	$	8,393		$	—	$	8,393
Liabilities:
Oil and natural gas swaps and costless collars		—		(19,987	)		—		(19,987	)
Total net liability	$	—	$	(11,594	)	$	—	$	(11,594	)

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 in its condensed consolidated balance sheets. On derivative contracts recorded as “Assets” in the table below, the Company is exposed to the risk the counterparties may not perform. The following table presents the fair value of derivative financial instruments at September 30, 2020 and December 31, 2019 (in thousands):

	September 30, 2020				December 31, 2019
	Assets		Liabilities		Assets		Liabilities
Oil and natural gas derivatives:
Current	$	38,716	$	33,443	$	8,393	$	19,476
Non-current		4,458		8,201		—		511
Total	$	43,174	$	41,644	$	8,393	$	19,987

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. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the regular monitoring of counterparties’ credit exposures; (iii) the use of contract language that affords the Company netting or set off opportunities to mitigate exposure risk; and (iv) potentially requiring counterparties to post cash collateral, parent guarantees, or letters of credit to minimize credit risk. The Company’s assets and liabilities from commodity price risk management activities at September 30, 2020 represent derivative instruments from eleven 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 all 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):

	September 30, 2020			December 31, 2019
11.00% Second-Priority Senior Secured Notes – due April 2022	$	347,908		$	390,868
7.50% Senior Notes – due May 2022		6,060			6,060
Bank Credit Facility – matures May 2022⁽¹⁾		650,000			350,000
Total debt, before discount and deferred financing cost		1,003,968			746,928
Discount and deferred financing cost		(9,220	)		(13,947	)
Total debt, net of discount and deferred financing costs	$	994,748		$	732,981

⁽¹⁾

The Bank Credit Facility contains a springing maturity that is 120 days prior to the maturity date of the 11.00% Notes (such 120 days prior being December 4, 2021) if greater than $25.0 million of the 11.00% Notes or any permitted refinancing indebtedness in respect thereof is outstanding on such date.

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

The 11.00% Notes were issued pursuant to an indenture dated May 10, 2018, between Talos Production Inc. (formerly Talos Production LLC) and Talos Production Finance Inc., the subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent. The 11.00% Notes mature April 3, 2022 and have interest payable semi-annually each April 15 and October 15. Prior to May 10, 2021, the Company may, at its option, redeem all or a portion of the 11.00% Notes at 102.75% of the principal amount plus accrued and unpaid interest. Thereafter, the Company may redeem all or a portion of the 11.00% Notes at redemption prices decreasing annually at May 10 from 102.75% to 100.0% plus accrued and unpaid interest.

The indenture governing the 11.00% 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% Notes contain customary quarterly and annual reporting, financial and administrative covenants. The Company was in compliance with all debt covenants at September 30, 2020.

On June 15, 2020, the Company entered into an exchange agreement pursuant to which the Company agreed to exchange $37.2 million aggregate principal amount of the 11.00% Notes from certain holders in exchange for 3.1 million shares of the Company’s common stock plus cash in an amount equal to accrued interest up to the June 18, 2020 settlement date. Additionally, during the nine months ended September 30, 2020, the Company repurchased $5.8 million of the 11.00% Notes. The exchange agreement and debt repurchases resulted in a gain on extinguishment of debt for the three and nine months ended September 30, 2020 of $0.2 million and $1.7 million, respectively, which is presented as “Other income (expense)” on the condensed consolidated statements of operations.

7.50% Senior Notes – due May 2022

The 7.50% Notes represent the remaining $6.1 million of long-term debt assumed in the Stone Combination that were not exchanged for 11.00% Notes pursuant to the exchange offer and consent solicitation, and thus remain outstanding. As a result of the exchange offer and consent solicitation, substantially all of the restrictive covenants relating to the 7.50% Notes have been removed and collateral securing the 7.50% Notes has been released. The 7.50% Notes mature May 31, 2022 and have interest payable semi-annually each May 31 and November 30. Prior to May 31, 2021, the Company may, at its option, redeem all of the 7.50% Notes at 105.63% of the principal amount plus accrued and unpaid interest. Thereafter, the Company may redeem all or a portion of the 7.50% Notes at redemption prices decreasing annually at May 31 from 105.63% to 100.0% plus accrued and unpaid interest.

Bank Credit Facility – matures May 2022

The Company and Talos Production Inc. maintain a Bank Credit Facility with a syndicate of financial institutions, with a borrowing base of $985.0 million as of September 30, 2020. The borrowing base requires certain lender approval to access the last $25.0 million of capacity. 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 the maturity date of the 11.00% Notes (such 120 days prior being December 4, 2021), if greater than $25.0 million of the 11.00% Notes or any permitted refinancing indebtedness in respect 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 3.00% to 4.00% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 2.00% to 3.00%. In addition, the Company is obligated to pay a commitment fee of 0.50% on the unutilized portion of the commitments. 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 calculated each quarter utilizing the most recent twelve months to determine EBITDAX. The Company must also maintain a current ratio no less than 1.00 to 1.00 each quarter. According to the Bank Credit Facility, unutilized 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 each year. Upon closing of the ILX and Castex Acquisition on February 28, 2020, the maximum borrowing base and commitments were increased from $950.0 million to $1.15 billion. On June 19, 2020, the borrowing base was redetermined by the lenders and decreased from $1.15 billion to $985.0 million. The June 19, 2020 redetermination also requires certain lender approval to access the last $25.0 million. The next scheduled redetermination meeting will be during the fourth quarter of 2020.

As of September 30, 2020, no more than $200.0 million of the Company’s borrowing base 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, 2020. As of September 30, 2020, the Company has $650.0 million of outstanding borrowings and $13.6 million in letters of credit issued under the Bank Credit Facility.

Subsequent event — During October 2020, the Company borrowed $25.0 million under the Bank Credit Facility for general corporate purposes.

Note 7 — Employee Benefits Plans and Share-Based Compensation

Talos Energy Inc. Long Term Incentive Plan

Under the Talos Energy Inc. Long Term Incentive Plan (the “LTIP”), the Company may issue, subject to approval by the Talos board of directors, grants of options (including incentive stock 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 (“RSUs”) — The following table summarizes RSU activity for the nine months ended September 30, 2020:

	RSUs			Weighted Average Grant Date Fair Value
Unvested RSUs at December 31, 2019		733,777		$	25.20
Granted		1,284,797		$	10.02
Vested		(273,787	)	$	25.09
Forfeited		(89,234	)	$	19.95
Unvested RSUs at September 30, 2020		1,655,553		$	13.72

Performance Share Units (“PSUs”) — The following table summarizes PSU activity for the nine months ended September 30, 2020:

	PSUs			Weighted Average Grant Date Fair Value
Unvested PSUs at December 31, 2019		417,831		$	39.31
Granted		441,642		$	13.05
Vested		—		$	—
Forfeited		(25,301	)	$	37.67
Unvested PSUs at September 30, 2020		834,172		$	25.46

The grant date fair value of the PSUs granted during the nine months ended September 30, 2020, calculated using a Monte Carlo simulation, was $5.8 million. The following table summarizes the assumptions used to calculate the grant date fair value of the PSUs granted for the nine months ended September 30, 2020:

	2020 Grant Date
	March 5, 2020
Number of simulations		100,000
Expected term (in years)		2.8
Expected volatility		48.8	%
Risk-free interest rate		0.6	%
Dividend yield		—	%

Share-based Compensation Expense, net

Share-based compensation expense associated with RSUs, PSUs and Series B Units are reflected as “General and administrative expense,” in the condensed consolidated statements of operations, net amounts capitalized to “Proved Properties,” in the condensed consolidated balance sheet. 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 provided by operating activities” in the condensed consolidated statements of cash flows.

The Company recognized the following share-based compensation expense, net for the three and nine months ended September 30, 2020 and 2019 (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2020			2019			2020			2019
Share-based compensation expense	$	4,386		$	3,591		$	12,053		$	9,568
Less: amounts capitalized to oil and gas properties		(2,039	)		(1,647	)		(5,732	)		(4,404	)
Total share-based compensation expense, net	$	2,347		$	1,944		$	6,321		$	5,164

Note 8 — Income Taxes

The Company is a corporation that is subject to U.S. federal, state and foreign income taxes.

For the three months ended September 30, 2020, the Company recognized an income tax benefit of $28.3 million for an effective tax rate of 35.2%. The Company’s effective tax rate of 35.2% is higher than the U.S. federal statutory income tax rate of 21% primarily due to state income taxes and the income tax benefit from adopting the final regulations under section 163(j) of the Internal Revenue Code for tax years ended December 31, 2019 and 2020. Application of these final regulations to the tax year ended December 31, 2018 is complex and the Company will continue to analyze the impact. 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 the Company’s valuation allowance.

For the nine months ended September 30, 2020, the Company recognized an income tax benefit of $22.4 million for an effective tax rate of 39.1%. The Company’s effective tax rate of 39.1% is higher than the U.S. federal statutory income tax rate of 21% primarily due to state income taxes and the income tax benefit from adopting the final regulations under section 163(j) of the Internal Revenue Code for tax years ended December 31, 2019 and 2020. 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 the Company’s valuation allowance.

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 Company reduces deferred tax assets by a valuation allowance when, based on estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The deferred tax asset estimates are subject to revision, either up or down, in future periods based on new facts or circumstances. In evaluating the Company’s valuation allowance, the Company considers cumulative losses, the reversal of existing temporary differences, the existence of taxable income in carryback years, tax optimization planning and future taxable income for each of its taxable jurisdictions. The Company assesses the realizability of its deferred tax assets quarterly; changes to the Company’s assessment of its valuation allowance in future periods could materially impact its results of operations. As of September 30, 2020, the Company had a valuation allowance related to some state and foreign deferred tax assets.

Note 9 — Income (Loss) Per Share

Basic earnings per common 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 common share includes the impact of RSUs, PSUs and outstanding warrants.

The following table presents the computation of the Company’s basic and diluted income (loss) per share were as follows (in thousands, except for the per share amounts):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2020			2019		2020			2019
Net income (loss)	$	(52,000	)	$	73,297	$	(34,862	)	$	58,425
Weighted average common shares outstanding — basic		71,286			54,200		65,134			54,178

Dilutive effect of securities		—			230		—			186
Weighted average common shares outstanding — diluted		71,286			54,430		65,134			54,364
Net income (loss) per common share:
Basic	$	(0.73	)	$	1.35	$	(0.54	)	$	1.08
Diluted	$	(0.73	)	$	1.35	$	(0.54	)	$	1.07
Anti-dilutive potentially issuable securities excluded from diluted common shares		5,407			4,250		4,957			4,282

Note 10 — Related Party Transactions

ILX and Castex Acquisition

On February 28, 2020 the Company acquired assets and liabilities at fair value from sellers that include, the Riverstone Sellers, affiliates of the Riverstone Funds, for $453.2 million (comprised of $297.0 million in net cash paid and $156.2 million in Conversion Stock). See additional details in Note 2 — Acquisitions.

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, 2020 is $1.1 million in receivables from an affiliate of the Apollo Funds to reimburse the Company for certain payments made post-closing.

Equity Registration Rights Agreement

On May 10, 2018, the Company entered into a Registration Rights Agreement (the “Original Equity Registration Rights Agreement”) with certain of the Apollo Funds and the 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 the closing of the Stone Combination (the “Original Registrable Securities”).

The Company and the Riverstone Sellers (and their designated affiliates) agreed under the Purchase Agreements to enter into an amendment to the Original Equity Registration Rights Agreement (such amendment, the “Registration Rights Agreement Amendment,” and the Original Equity Registration Rights Agreement, as amended by the Registration Rights Agreement Amendment, the “Registration Rights Agreement”). The Registration Rights Agreement Amendment will add each of the Riverstone Sellers (or one or more of its designated affiliates) as parties to the Registration Rights Agreement and provide such parties with customary registration rights with respect to the Series A Convertible Preferred Stock (and Conversion Stock) that the Riverstone Sellers received at the closing of the ILX and Castex Acquisition (the “New Registrable Securities” and together with the Original Registrable Securities, the “Registrable Securities”). Under the Registration Rights Agreement, the Company is required to file a shelf registration statement within 30 days of the Company’s receipt of written request by a holder of Registrable Securities (a “Holder”). Each Holder will be limited to two demand registrations in any twelve-month period.

The Holders have the right to request that we initiate underwritten offerings of the Company’s common stock; provided, that the Apollo Funds and the Riverstone Funds will have the right to demand three underwritten offerings in any twelve-month period, and Franklin and MacKay Shields will only have the collective right to demand one underwritten offering. The Holders have customary piggyback rights with respect to any underwritten offering that we conduct for as long as the Holders and their respective affiliates own 5% of the Registrable Securities. Each Holder will agree to a lock up with underwriters in the event of an underwritten offering, provided that the lock up will not apply to any Holder who does not have a right to participate in such underwritten offering. The Registration Rights Agreement has terminated with respect to Franklin and will terminate with respect to MacKay Shields in the event that MacKay Shields ceases to beneficially own 5% or more of the then outstanding shares of the Company’s common stock. The Registration Rights Agreement will otherwise terminate at such time as there are no Registrable Securities outstanding.

In connection with the closing of the ILX and Castex Acquisition, and pursuant to the Purchase Agreements, as amended, the Company and ILX Holdings, LLC, ILX Holdings II, LLC, ILX Holdings III LLC and Riverstone V Castex 2014 Holdings, L.P., a Delaware limited partnership and designee of Castex Energy 2014, LLC, entered into the Registration Rights Agreement Amendment to the Registration Rights Agreement to, among other things, add each of the Riverstone Sellers (or one or more of its designated affiliates) as parties to the Registration Rights Agreement and provide such parties with customary registration rights with respect to the Company’s Series A Convertible Preferred Stock issued to the Riverstone Sellers at the closing of the ILX and Castex Acquisition.

The Company will bear all of the expenses incurred in connection with the offer and sale, while the Apollo Funds, the Riverstone Funds, Franklin and MacKay Shields will be responsible for paying underwriting fees, discounts and selling commissions. For the three and nine months ended September 30, 2020, fees incurred by the Company in conjunction with the Original Equity Registration Rights Agreement were nil and $0.2 million, respectively. For the three and nine months ended September 30, 2019, the Company incurred nil and $0.7 million, respectively.

Stockholders’ Agreement Amendment

On May 10, 2018, the Company entered into a Stockholders’ Agreement (the “Stockholders’ Agreement”) by and among the Company and the other parties thereto. On February 24, 2020, the Company and the other parties thereto amended the Stockholders’ Agreement (the “Stockholders’ Agreement Amendment”) to, among other things, add each of the Riverstone Sellers (or one or more of its designated affiliates) as parties to the Stockholders’ Agreement and provide that for purposes of determining whether the Riverstone Sellers and their affiliates continue to satisfy certain stock ownership requirements necessary to retain their rights to nominate directors to the board of directors, the Series A Convertible Preferred Stock owned by the Riverstone Sellers was, prior to the conversion thereof, counted towards such ownership requirements on an as converted basis at the closing of the ILX and Castex Acquisition. On March 30, 2020, all 110,000 shares of Series A Convertible Preferred Stock were converted into an aggregate 11.0 million shares of the Company’s common stock.

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, the Company’s Executive Vice President and General Counsel and one of its executive officers, is a partner at Vinson & Elkins L.L.P. For the three and nine months ended September 30, 2020, the Company incurred fees of approximately $0.6 million and $4.0 million, respectively, of which $2.2 million were payable for legal services performed by Vinson & Elkins L.L.P. as of September 30, 2020. For the three and nine months ended September 30, 2019, the Company 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.

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, 2020, the Company had secured performance bonds totaling approximately $659.3 million. As of September 30, 2020, the Company had $13.6 million in letters of credit issued under its Bank Credit Facility.

Legal Proceedings and Other Contingencies

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 —Subsequent Events

Debt

For additional information, see Note 6 – Debt.

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

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 2019 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 2019 Annual Report.

Our Business

We are a technically driven independent exploration and production company focused on safely and efficiently maximizing value through our operations, currently in the U.S. Gulf of Mexico and offshore Mexico. We leverage decades of geology, geophysics and offshore operations expertise towards the acquisition, exploration, exploitation and development of assets in key geological trends that are present in many offshore basins around the world.

We have historically focused our operations in the Gulf of Mexico because of our deep experience and technical expertise in the basin, which maintains favorable geologic and economic conditions, including multiple reservoir formations, comprehensive geologic and geophysical databases, extensive infrastructure and an attractive and robust asset acquisition market. Additionally, we have access to state-of-the-art three-dimensional seismic data, some of which is aided by new and enhanced reprocessing techniques that have not been previously applied to our current acreage position. We use our broad regional seismic database and our reprocessing efforts to generate a large and expanding inventory of high-quality prospects, which we believe greatly improves our development and exploration success. The application of our extensive seismic database, coupled with our ability to effectively reprocess this seismic data, allows us to both optimize our organic drilling program and better evaluate a wide range of business development opportunities, including acquisitions and joint venture opportunities, among others.

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, an acquisition or joint venture opportunities. We add to and reevaluate our inventory in order to deploy 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.

Outlook

The impact on our business of the COVID-19 outbreak are unprecedented. Please see Part II, Item 1A. “Risk Factors” in this Quarterly Report for additional information. We will continue to focus on maintaining safe and reliable operations, protecting our balance sheet and preserving long-term shareholder value.

COVID-19 — In the first quarter of 2020, the COVID-19 outbreak spread quickly across the globe. Federal, state and local governments mobilized to implement containment mechanisms and minimize impacts to their populations and economies. Various containment measures, such as stay-at-home orders, closures of restaurants and banning of group gatherings have resulted in a severe drop in general economic activity, as well as a corresponding decrease in global energy demand. During the third quarter of 2020, containment measures and responsive actions to the COVID-19 pandemic continue to result in severe declines in general economic activity and energy demand. As a result, the global economy has experienced a slowing of economic growth, disruption of global manufacturing supply chains, stagnation of crude oil and natural gas consumption and interference with workforce continuity. As cities, states and countries continue easing the confinement restrictions, the risk for the resurgence and recurrence of COVID-19 remains. The State of Texas has seen an increase in the number of COVID-19 positive cases, while state or local governments continue to lift stay-at-home and/or other similar orders, which had affected and continues to affect our personnel and operations at our headquarters, located in Houston, Texas. The reinstatement of the containment measures generally, across the globe, has led to an extended period of reduced demand for crude oil and natural gas commodities, as well as asserting further pressure on the global economy. Additionally, the risks associated with COVID-19 have impacted our workforce and the way we meet our business objectives.

Due to concerns over health and safety, we asked the vast majority of our corporate workforce to work remotely through the third quarter of 2020. We have begun the process of allowing employees to return to the office in phases during the fourth quarter of 2020. Our offshore employees have continued to work offshore with modified rotations. Working remotely has not significantly impacted our ability to maintain operations, or caused us to incur significant additional expenses; however, we are unable to predict the duration or ultimate impact of these measures. Further, the rapid and unprecedented decreases in energy demand have impacted certain elements of our distribution channels. Inventory surpluses have overwhelmed the United States’ storage capacity, leading to a further strain on the supply chain. The Company has evaluated the effect of these factors on the business and reduced the capital expenditure budget for the remainder of 2020, accelerated planned downtime maintenance projects, experienced production shut-ins from non-operated oil and gas properties and shut-in limited operated oil and gas properties. The Company continues to monitor the economic environment, U.S. global and political and economic developments, including the outcome of the U.S. presidential and congressional elections and resulting energy policies related thereto, and evaluate their continuing impact on the business.

Decline in Commodity Prices — In March 2020, OPEC and non-OPEC producers failed to agree to production cuts intended to stabilize and support commodity prices. With no agreement in place, Saudi Arabia, Russia and other producers committed to ramping up production in an attempt to protect, or increase, their global market share. This increased production has been coupled with significant demand declines caused by the global response to COVID-19, such as travel restrictions, business closures and the institution of quarantining which has contributed to a decrease in economic activity across the world. These extreme supply and demand dynamics have contributed to significant crude oil price declines. Although pricing has stabilized in the third quarter of 2020, the commodity price environment is expected to remain depressed based on over-supply, decreased demand and a potential global economic recession. In April 2020, Saudi Arabia, Russia and other crude oil-producing nations (“OPEC Plus”) came to an agreement to cut limited amounts of production by 9.7 million barrels per day in May and June 2020; however, in July 2020, OPEC Plus agreed to increase production by 1.6 million barrels per day starting in August 2020. OPEC Plus is scheduled to meet again in the fourth quarter of 2020 and it is possible OPEC Plus may agree to further production increases. As such, we cannot predict whether or when oil production and economic activities will return to normalized levels. The decline in commodity prices has adversely affected oil and natural gas exploration and production in the United States. In response, the Company has reduced its previously disclosed 2020 capital, operating and general and administrative expenses by a range of $213.0 million to $236.0 million. The Company’s 2020 revised capital program focuses on infrastructure-led, short-cycle projects that were previously committed to and that are focused on lowering the lifting cost structure of the Company’s assets by adding incremental barrels through existing fixed-cost offshore production facilities.

Global Economic Environment — COVID-19 and the numerous public and political responses thereto have contributed to equity market volatility and potentially the risk of a global recession. We expect the global equity market volatility experienced in the first half of 2020 to continue at least until the outbreak of COVID-19 stabilizes, if not longer. The response to the COVID-19 outbreak (such as stay-at-home orders, closures of restaurants and banning of group gatherings) and slowing of the global economy has contributed to increased unemployment rates. On March 27, 2020, the U.S. government passed the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”), the largest relief package in U.S. history. The CARES Act, a $2.2 trillion stimulus package, includes various provisions intended to provide relief to individuals and businesses in the form of tax law changes, loans and grants, among others. We have evaluated the potential impact of these measures, and we do not meet the criteria to participate.

FERC Regulatory Matters — On June 18, 2020, the Federal Energy Regulatory Commission (“FERC”) issued a Notice of Inquiry requesting comments on a proposed oil pipeline index using the Producer Price Index for Finished Goods (PPI-FG) plus 0.09% as the index level, and requested comments on whether and how the index should reflect changes to FERC’s policies regarding income tax costs and return on equity. The Notice of Inquiry is subject to a comment period, after which FERC will issue a final oil pipeline index for the five-year period commencing July 1, 2021. FERC’s final application of its indexing rate methodology for the next five-year term of index rates may impact our revenues associated with any transportation services we may provide pursuant to rates adjusted by the FERC oil pipeline index.

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

The following items affect the comparability of our financial condition and results of operations for periods presented herein and could potentially continue to affect our future financial condition and results of operations.

Acquisition of Castex Energy 2005 — On August 5, 2020, the Company completed the acquisition of select oil and natural gas assets from affiliates of Castex Energy 2005 Holdco, LLC, for $43.3 million (comprised of $6.5 million in cash, $35.4 million in 4.6 million shares of the Company’s common stock and $1.4 million in transaction related expenses). See additional details in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 2 — Acquisitions” for more information.

ILX and Castex Acquisition — On February 28, 2020 we acquired the outstanding limited liability interests in certain wholly owned subsidiaries of ILX Holdings, LLC, ILX Holdings II, LLC, ILX Holdings III LLC and Castex Energy 2014, LLC, each a related party and an affiliate of the Riverstone Funds ( the “Riverstone Sellers”), and Castex Energy 2016, LP (together with the Riverstone Sellers, the “Sellers”), for $453.2 million (comprised of $297.0 million in net cash paid and $156.2 million in 110,000 shares of a series of the Company’s preferred stock, which subsequently converted to an aggregate 11.0 million shares of our common stock). See additional details in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 2 — Acquisitions” for more information.

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 additional details in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 2 — Acquisitions” for more information.

Write-down of oil and natural gas properties — The Company’s 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 resulted in the Company recording a non-cash impairment presented as “Write-down of oil and natural gas properties” on the condensed consolidated statements of operations. For the three and nine months ended September 30, 2020, the Company recorded an impairment of nil and $0.1 million, respectively. Unproved property impairment for the three and nine months ended September 30, 2019 was $1.4 million and $13.8 million, respectively. See additional details in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 3 — Property, Plant and Equipment” for more information.

Transaction Expenses — We have incurred and will continue to incur transaction related and restructuring costs associated with our business development activities that may vary significantly in our comparative historical results of operations. See additional details in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 2 — Acquisitions” for more information.

Hurricanes and Tropical Storms — During 2020, production from the U.S. Gulf of Mexico was impacted due to precautionary shut-ins of facilities and evacuations associated with Hurricanes Hanna, Laura, Marco, Sally and Delta and Tropical Storms Cristobal and Beta. Although there was no major storm-related damage to our facilities, we incurred production downtime associated with the shut-ins for the storms. For the three and nine months ended September 30, 2020, we estimate deferred production related to these storms was approximately 8.6 MBoepd and approximately 3.3 MBoepd, respectively, when comparing the production of the affected month to a preceding month’s production.

Ram Powell Shut-In — Production at our Ram Powell facility was shut-in during the third quarter of 2020 while waiting on a repair of the platform’s oil export riser. We received final regulatory approvals and are in the process of repairing the export riser with production expected to resume in the first half of November 2020. During the three and nine months ended September 30, 2020, the Ram Powell facility shut-in resulted in deferred production of 4.9 MBoepd and 2.0 MBoepd, respectively.

Third Party Planned Downtime — Since our operations are offshore, we are vulnerable to third party downtime events impacting the transportation, gathering or processing of production. We produce the Phoenix Field through the Helix Producer I (“HP-I”) that is 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 first quarter of 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.

Known Trends and Uncertainties

Volatility in Oil, Natural Gas and NGL Prices — Historically, the markets for oil and natural gas have been volatile, and prices experienced a steep decline in March and April 2020. In March 2020, Saudi Arabia and Russia failed to reach a decision to cut production of oil and gas along with the OPEC countries. Subsequently, Saudi Arabia significantly reduced the prices at which it sells oil and announced plans to increase production. These events, combined with the continued outbreak of COVID-19, contributed to a sharp drop in prices for oil and gas during the nine months ended September 30, 2020. For example, from January 1, 2020 through September 30, 2020, the daily spot prices for NYMEX WTI crude oil ranged from a high of $63.27 per Bbl to a low of $(36.98) per Bbl and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $2.57 per MMBtu to a low of $1.33 per MMBtu. 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 supply and demand and we cannot predict whether or when oil production and economic activities will return to normalized levels.

Impairment of Oil and Natural Gas Properties — Under the full cost method of accounting that we use for our oil and gas operations, our capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. Any costs in excess of the ceiling are recognized as a non-cash “Write-down of oil and natural gas properties” on the condensed consolidated statements of operations and an increase to “Accumulated depreciation, depletion and amortization” on our condensed consolidated balance sheets. The expense may not be reversed in future periods, even though higher oil, natural gas and NGL prices may subsequently increase the ceiling. We perform this ceiling test calculation each quarter. In accordance with the SEC rules and regulations, we utilize SEC Pricing when performing the ceiling test. We also hold prices and costs constant over the life of the reserves, even though actual prices and costs of oil and natural gas are often volatile and may change from period to period. Although we experienced a significant decline in commodity prices during March 2020, future commodity prices remained relatively consistent in the undiscounted future cash flow estimate during the first nine months of 2020, particularly the commodity price as a result of the 12-month average SEC Pricing, and as such, we did not recognize impairment as of September 30, 2020. At September 30, 2020, the Company’s ceiling test computation was based on SEC pricing, adjusted for differentials, of $44.31 per Bbl of oil, $1.97 per Mcf of natural gas and $10.89 per Bbl of NGLs.

If the SEC pricing, adjusted for differentials, had been $40.31 per Bbl of oil, $2.00 per Mcf of natural gas and $9.90 per Bbl of NGLs, respectively, while all other factors remained constant, our oil and natural gas properties would have been impaired by approximately $181.1 million. The aforementioned prices, as estimated for the twelve month period January 2020 through December 2020, were calculated using a 12-month unweighted arithmetic average of oil and natural gas prices, which included the oil and natural gas prices on the first day of the month for the ten months ended October 2020, with the prices for November through December based on forward looking NYMEX and Henry Hub futures prices on October 1, 2020.

As part of our period end reserves estimation process for future periods, we expect changes in the key assumptions used, which could be significant, including updates to future pricing estimates and differentials, future production estimates to align with our anticipated five-year drilling plan and changes in our capital costs and operating expense assumptions, which we expect to decrease further as a result of sustained lower commodity prices. There is a significant degree of uncertainty with the assumptions used to estimate future undiscounted cash flows due to, but not limited to the risk factors referred to in Item 1A. “Risk Factors” included in our 2019 Annual Report and elsewhere in this Quarterly Report. Any decrease in pricing, negative change in price differentials, or increase in capital or operating costs could negatively impact the estimated undiscounted cash flows related to our proved oil and natural gas properties.

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 this extension for implementation currently remains in effect.

On October 16, 2020, the BOEM and the Bureau of Safety and Environmental Enforcement (“BSEE”), jointly published a proposed rule to clarify and provide greater transparency to decommissioning and related financial assurance requirements imposed on oil and gas lessees (record title owners), sublessees (operating rights owners) and RUE and ROW grant holders conducting operations on the federal OCS. In particular, the proposed rule would: (i) clarify the sequence for BSEE’s selection of predecessors who have accrued decommissioning obligations and are ordered to perform those obligations when the current lessee, sublessee or grant holder fails to do so, which sequence is generally in reverse chronological order through the chain-of-title of lessees or sublessees, although BSEE would reserve the right to deviate from this sequence in cases where previously ordered parties fail to pursue specified decommissioning activities, if an emergency condition is declared, or if such an order unreasonably delays decommissioning; (ii) seek to limit the circumstances under which BOEM would require supplemental bonding, with increased focus on a lessee’s or sublessee’s, as well as potentially a co-lessee’s or predecessor lessee’s, credit rating rather than relying primarily on a current lessee’s or sublessee’s net worth in determining whether additional supplemental bonding is necessary; (iii) relax certain third party guarantee requirements allowed by BOEM in lieu of lessee bonding; (iv) require the posting of bonds in an amount that BSEE determines would be adequate before that party may appeal a decommissioning order and (v) clarify that all RUE grant holders are jointly and severally liable for BSEE decommissioning obligations associated with RUE-related facilities. Comments on this proposed rule are due to BOEM (as to the BOEM portions of the proposed rule) and BSEE (as to the BSEE portions of the proposed rule) on or before December 15, 2020. We remain in active discussion with our industry peers with regard to this proposed rule. The future cost of compliance with respect to supplemental bonding, including the obligations imposed on us, whether as current or predecessor lessee or grant holder, as a result of the 2016 NTL, to the extent implemented, as well as to the provisions of any final rule published by BOEM and/or BSEE following the close of the comment period for the October 16, 2020 proposed rule, 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 U.S. 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 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 U.S. 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.

How We Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:

•

production volumes;

•

realized prices on the sale of oil, natural gas and NGLs, including the effect of our commodity derivative contracts;

•

lease operating expenses;

•

capital expenditures; and

•

Adjusted EBITDA, which is discussed under “—Supplemental Non-GAAP Measure” below.

Results of Operations

Revenue

The information below provides a discussion of, and an analysis of significant variance in, our oil, natural gas and NGL revenues, production volumes and sales prices for the three and nine months ended September 30, 2020 and 2019 (in thousands):

	Three Months Ended September 30,							Nine Months Ended September 30,
	2020		2019		Change			2020		2019		Change
Revenues:
Oil	$	117,190	$	211,899	$	(94,709	)	$	358,285	$	624,486	$	(266,201	)
Natural gas		12,337		12,545		(208	)		35,375		41,738		(6,363	)
NGL		3,409		3,384		25			9,674		15,095		(5,421	)
Other		2,201		1,029		1,172			8,441		13,061		(4,620	)
Total revenue	$	135,137	$	228,857	$	(93,720	)	$	411,775	$	694,380	$	(282,605	)

Total Production Volumes:
Oil (MBbls)		3,005		3,559		(554	)		10,010		10,228		(218	)
Natural gas (MMcf)		6,922		5,909		1,013			20,961		17,101		3,860
NGL (MBbls)		311		299		12			1,028		915		113
Total production volume (MBoe)		4,470		4,843		(373	)		14,532		13,993		539

Daily Production Volumes by Product:
Oil (MBblpd)		32.7		38.7		(6.0	)		36.5		37.5		(1.0	)
Natural gas (MMcfpd)		75.2		64.2		11.0			76.5		62.6		13.9
NGL (MBblpd)		3.4		3.2		0.2			3.8		3.4		0.4
Total production volume (MBoepd)		48.6		52.6		(4.0	)		53.0		51.3		1.7

Average sale price per unit:
Oil (per Bbl)	$	39.00	$	59.54	$	(20.54	)	$	35.79	$	61.06	$	(25.27	)
Natural gas (per Mcf)	$	1.78	$	2.12	$	(0.34	)	$	1.69	$	2.44	$	(0.75	)
NGL (per Bbl)	$	10.96	$	11.32	$	(0.36	)	$	9.41	$	16.50	$	(7.09	)
Price per Boe	$	29.74	$	47.04	$	(17.30	)	$	27.75	$	48.69	$	(20.94	)
Price per Boe (including realized commodity derivatives)	$	34.00	$	48.15	$	(14.15	)	$	37.49	$	48.18	$	(10.69	)

The information below provides an analysis of the change in our oil, natural gas and NGL revenues, due to changes in sales prices and production volumes for the three and nine months ended September 30, 2020 and 2019 (in thousands):

	Three Months Ended September 30, 2020 vs 2019									Nine Months Ended September 30, 2020 vs 2019
	Price			Volume			Total			Price			Volume			Total
Oil	$	(61,724	)		(32,985	)	$	(94,709	)	$	(252,890	)		(13,311	)	$	(266,201	)
Natural gas	$	(2,356	)		2,148		$	(208	)	$	(15,781	)		9,418		$	(6,363	)
NGL	$	(111	)		136		$	25		$	(7,286	)		1,865		$	(5,421	)
Total	$	(64,191	)		(30,701	)	$	(94,892	)	$	(275,957	)		(2,028	)	$	(277,985	)

Three Months Ended September 30, 2020 and 2019 Volumetric Analysis — Production volumes decreased by 4.0 MBoepd to 48.6 MBoepd. The decrease in production volumes includes 5.2 MBoepd from disruptions from weather events in the U.S. Gulf of Mexico, 4.9 MBoepd from temporary shut-ins for repairs and maintenance on the Ram Powell Field export riser and natural production declines and other miscellaneous shut-ins. The decrease in production volumes was partially offset by 16.8 MBoepd in production from the oil and natural gas assets acquired in the ILX and Castex Acquisition and Castex Energy 2005 Acquisition. The increase in production attributed to the ILX and Castex Acquisition and Castex Energy 2005 Acquisition includes the negative impact of 5.7 MBoepd in deferred production from non-operated temporary shut-ins and hurricane and tropical storm disruptions.

Nine Months Ended September 30, 2020 and 2019 Volumetric Analysis — Production volumes increased by 1.7 MBoepd to 53.0 MBoepd. The increase in production volumes was primarily attributable to 13.2 MBoepd in production from the oil and natural gas assets acquired in the ILX and Castex Acquisition and Castex Energy 2005 Acquisition and 4.3 MBoepd from third party downtime in the Phoenix Field during the first quarter of 2019 for the Helix HP-I dry-dock repairs and maintenance. The increase was partially offset by a decrease in production volumes including 6.4 MBoepd for deferred production for repairs and maintenance, 2.1 MBoepd from disruptions from weather events in the U.S. Gulf of Mexico and natural production decline and other miscellaneous shut-ins.

Expenses

Lease Operating Expense

The following table highlights lease operating expense items in total and on a cost per Boe production basis. The information below provides the financial results and an analysis of significant variances in these results for the three and nine months ended September 30, 2020 and 2019 (in thousands, except per Boe data):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Lease operating expenses	$	62,064	$	61,816	$	184,187	$	184,230
Lease operating expenses per Boe	$	13.88	$	12.76	$	12.67	$	13.17

Three Months Ended September 30, 2020 and 2019 — Total lease operating expense for the three months ended September 30, 2020 increased by approximately $0.2 million, or 0%. This increase was primarily related to lease operating expenses of $13.9 million incurred in connection with assets acquired in the ILX and Castex Acquisition. Additionally, there was an increase to workover and maintenance expenses of $3.4 million primarily related to the Ram Powell facility shut-in. This increase was offset by a reduction in costs of $16.7 million primarily related to a reduction of direct operating expenses and labor cost due to shuttering of certain shelf fields and cost cutting measures taken due to the current economic environment. On a per unit basis, lease operating expense increased $1.12 per Boe to $13.88 per Boe as a result of lower production due to present economic conditions.

Nine Months Ended September 30, 2020 and 2019 — Total lease operating expense for the nine months ended September 30, 2020, decreased by approximately $0.0 million, or 0%. This decrease was related to workover and maintenance expenses of $10.8 million primarily related to the HP-I dry-dock operation repairs and related workover expense within the Phoenix Field during the nine months ended September 30, 2019. Additionally, there was a reduction in contract labor costs and direct operating costs of $22.6 million when compared to the same period in 2019 as part of the cost cutting measures taken due to the current economic environment. The decrease was offset with an increase to lease operating expenses of $33.9 million incurred in connection with assets acquired in the ILX and Castex Acquisition. On a per unit basis, lease operating expense decreased $0.50 per Boe to $12.67 per Boe.

Depreciation, Depletion and Amortization

The following table highlights depreciation, depletion and amortization items in total and on a cost per Boe production basis. The information below provides the financial results and an analysis of significant variances in these results for the three and nine months ended September 30, 2020 and 2019 (in thousands, except per Boe data):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
Depreciation, depletion and amortization	$	80,547	$	88,125	$	262,533	$	248,518
Depreciation, depletion and amortization per Boe	$	18.02	$	18.20	$	18.07	$	17.76

Three Months Ended September 30, 2020 and 2019 — Depreciation, depletion and amortization expense for the three months ended September 30, 2020 decreased by approximately $7.6 million, or 9%. This decrease was primarily due to a decrease in production of 4.0 MBoepd as discussed above during the three months ended September 30, 2020 and a $0.23 per Boe, or 1%, decrease in the depletion rate on our proved oil and natural gas properties.

Nine Months Ended September 30, 2020 and 2019 —Depreciation, depletion and amortization expense for the nine months ended September 30, 2020 increased by approximately $14.0 million, or 6%. This increase was due to a $0.31 per Boe, or 2%, increase in the depletion rate on our proved oil and natural gas properties and an increase in production of 1.7 MBoepd as discussed above during the nine months ended September 30, 2020.

General and Administrative Expense

The following table highlights general and administrative expense items in total and on a cost per Boe production basis. The information below provides the financial results and an analysis of significant variances in these results for the three and nine months ended September 30, 2020 and 2019 (in thousands, except per Boe data):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
General and administrative expense	$	17,823	$	17,321	$	62,484	$	53,795
General and administrative expense per Boe	$	3.99	$	3.58	$	4.30	$	3.84

Three Months Ended September 30, 2020 and 2019 — General and administrative expense for the three months ended September 30, 2020, increased by approximately $0.5 million, or 3%. Transaction related costs were $1.6 million or $0.36 per Boe for the three months ended September 30, 2020, which is an increase of $1.5 million primarily due to the ILX and Castex Acquisition and the Castex Energy 2005 Acquisition. Non-cash equity based compensation was $2.3 million, or $0.53 per Boe for the three months ended September 30, 2020, which is an increase of $0.4 million. The increase was offset with the realized benefit of cost savings initiatives in the current economic environment primarily related to a reduction of employee and contract labor costs.

Nine Months Ended September 30, 2020 and 2019 — General and administrative expense for the nine months ended September 30, 2020, increased by approximately $8.7 million, or 16%. Transaction related costs were $12.9 million or $0.89 per Boe for the nine months ended September 30, 2020, which is an increase of $9.5 million primarily due to the ILX and Castex Acquisition and the Castex Energy 2005 Acquisition. Non-cash equity based compensation was $6.3 million, or $0.43 per Boe for the nine months ended September 30, 2020, which is an increase of $1.2 million. The increase was offset with the realized benefit of cost savings initiatives in the current economic environment, primarily related to a reduction of employee and contract labor costs.

Other Income and Expense

The following table highlights other income and expense items in total. The information below provides the financial results and an analysis of significant variances in these results for the three and nine months ended September 30, 2020 and 2019 (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2020			2019			2020		2019
Write-down of oil and natural gas properties	$	—		$	1,417		$	57	$	13,778
Accretion expense	$	11,537		$	7,316		$	37,748	$	26,868
Price risk management activities income (expense)	$	(19,882	)	$	43,760		$	154,653	$	(35,829	)
Income tax benefit (expense)	$	28,252		$	(790	)	$	22,384	$	(428	)

Three Months Ended September 30, 2020 and 2019 —

Price risk management activities — Price risk management activities for the three months ended September 30, 2020, decreased by approximately $63.6 million, or 145%. The expense of $19.9 million for the three months ended September 30, 2020 consists of $38.9 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $19.0 million in cash settlement gains. The income of $43.8 million for the three months ended September 30, 2019 consists of $38.4 million in non-cash gains from the increase in the fair value of our open derivative contracts and $5.4 million in cash settlement gains. These unrealized gains 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. As a result of the derivative contracts we have on our anticipated production volumes through 2021, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas.

Nine Months Ended September 30, 2020 and 2019 —

Price risk management activities — Price risk management activities for the nine months ended September 30, 2020, increased by approximately $190.5 million, or 532%. The income of $154.7 million for the nine months ended September 30, 2020 consists of $141.5 million in cash settlement gains and $13.2 million in non-cash gains from the increase in the fair value of our open derivative contracts. The expense of $35.8 million for the nine months ended September 30, 2019 consists of $28.6 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $7.2 million in cash settlement losses. These unrealized gains 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. As a result of the derivative contracts we have on our anticipated production volumes through 2021, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas.

Supplemental Non-GAAP Measure

EBITDA and Adjusted EBITDA

“EBITDA” and “Adjusted EBITDA” are non-GAAP financial measures used 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 accounting principles generally accepted in the United States of America (“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, the net change in the fair value of derivatives (mark to market effect, net of cash settlements and premiums related to these derivatives), non-cash (gain) loss on sale of assets, non-cash write-down of other well equipment inventory and non-cash equity based compensation expense.

The following tables present a reconciliation of the GAAP financial measure of net income (loss) to Adjusted EBITDA for each of the periods indicated (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2020			2019			2020			2019
Reconciliation of net income (loss) to Adjusted EBITDA:
Net income (loss)	$	(52,000	)	$	73,297		$	(34,862	)	$	58,425
Interest expense		24,124			23,123			76,164			73,273
Income tax expense (benefit)		(28,252	)		790			(22,384	)		428
Depreciation, depletion and amortization		80,547			88,125			262,533			248,518
Accretion expense		11,537			7,316			37,748			26,868
EBITDA		35,956			192,651			319,199			407,512
Write-down of oil and natural gas properties		—			1,417			57			13,778
Transaction and non-recurring expenses⁽¹⁾		1,607			146			12,863			3,349
Derivative fair value (gain) loss⁽²⁾		19,882			(43,760	)		(154,653	)		35,829
Net cash receipts (payments) on settled derivative instruments⁽²⁾		19,030			5,360			141,529			(7,202	)
Gain on extinguishment of debt		(174	)		—			(1,644	)		—
Non-cash write-down of other well equipment inventory		—			—			133			—
Non-cash equity-based compensation expense		2,347			1,944			6,321			5,164
Adjusted EBITDA	$	78,648		$	157,758		$	323,805		$	458,430

⁽¹⁾	Includes transaction related expenses, restructuring expenses and cost saving initiatives.

⁽²⁾

The adjustments for the derivative fair value (gains) losses and net cash receipts on settled commodity derivative instruments have the effect of adjusting net loss for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on a cash basis during the period the derivatives settled.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated by our operations and borrowings under our Bank Credit Facility (as defined below). Our primary uses of cash are for capital expenditures, working capital, debt service and for general corporate purposes. As of September 30, 2020, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $328.8 million, or $353.8 million inclusive of the $25.0 million requiring certain lender approval.

We fund exploration and development activities primarily through operating cash flows, cash on hand and through borrowings under the Bank Credit Facility, if necessary. Historically, we have funded significant property acquisitions with the issuance of senior notes, borrowings under the Bank Credit Facility and through additional equity issuances. 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.

Capital Expenditures — The following is a table of our capital expenditures, excluding acquisitions, for the nine months ended September 30, 2020 (in thousands):

U.S. drilling & completions	$	207,687
Mexico appraisal & exploration		406
Asset management		39,683
Seismic and G&G, land, capitalized G&A and other⁽¹⁾		52,226
Total capital expenditures		300,002
Plugging & abandonment		34,502
Total capital expenditures and plugging & abandonment	$	334,504

⁽¹⁾	Amount excludes $5.7 million of non-cash share-based awards.

Based on our current level of operations and available cash, inclusive of $213.0 million to $236.0 million of reductions in previously announced capital, operating and general and administrative expenses, we believe our cash flows from operations, combined with availability under the Bank Credit Facility, provide sufficient liquidity to fund our board approved 2020 capital spending program of $377.0 million to $397.0 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.

Guarantor Financial Information — Talos owns no operating assets and has no operations independent of its subsidiaries. Talos Production Inc. (formerly Talos Production LLC) and Talos Production Finance Inc. (together the “Issuers”) issued 11.00% Notes (as defined below) on May 10, 2018, which are fully and unconditionally guaranteed, jointly and severally, by Talos and certain 100% owned subsidiaries (the “Guarantors”) on a senior unsecured basis. Our non-domestic subsidiaries (the “Non-Guarantors”) are 100% owned by Talos but do not guarantee the 11.00% Notes issued on May 10, 2018.

In lieu of providing separate financial statements for Talos the Issuers and Guarantors, we have presented the accompanying supplemental summarized combined balance sheet and income statement information for Talos, the Issuers and Guarantors on a combined basis after elimination of intercompany transactions and amounts related to investment in any subsidiary that is a Non-Guarantor.

The following table presents the balance sheet information for the respective periods (in thousands):

	September 30, 2020		December 31, 2019
Current assets	$	238,960	$	281,008
Non-current assets		2,778,500		2,168,537
Total Assets	$	3,017,460	$	2,449,545

Current liabilities	$	423,170	$	357,893
Non-current liabilities		1,454,908		1,139,859
Talos Energy, Inc. stockholdersʼ equity		1,139,382		951,793
Total liabilities and stockholdersʼ equity	$	3,017,460	$	2,449,545

The following table presents the income statement information for the nine months ended September 30, 2020 (in thousands):

	Nine Months Ended September 30, 2020
Revenue	$	411,768
Cost and expenses		(442,364	)
Net Income	$	(30,596	)

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,
	2020			2019
Operating activities	$	262,067		$	332,413
Investing activities	$	(585,152	)	$	(400,467	)
Financing activities	$	268,440		$	17,574

Operating Activities — Net cash provided by operating activities decreased $70.3 million in the nine months ended September 30, 2020 compared to the corresponding period in 2019 primarily attributable to a decrease in revenues of $282.6 million. This decrease was partially offset by an increase in cash receipts on derivative instruments of $148.7 million and a decrease in settlement of asset retirement obligations of $19.9 million.

Investing Activities — Net cash used in investing activities increased $184.7 million in the nine months ended September 30, 2020 compared to the corresponding period in 2019 primarily due to an increase in payments for acquisitions of $272.0 million, which was offset by a decrease in capital expenditures of $92.6 million.

Financing Activities — Net cash provided by financing activities increased $250.9 million in the nine months ended September 30, 2020 compared to the corresponding period in 2019 primarily attributable to an increase in net proceeds of $250.0 million received from the Bank Credit Facility used primarily to fund the ILX and Castex Acquisition in the first quarter of 2020.

Bank Credit Facility – matures May 2022 — The Company maintains a Bank Credit Facility with a syndicate of financial institutions, with a borrowing base of $985.0 million (the “Bank Credit Facility”) as of September 30, 2020. The borrowing base requires certain lender approval to access the last $25.0 million of capacity. The Bank Credit Facility matures on May 10, 2022, provided that the Bank Credit Facility mandates a springing maturity that is prior to the maturity date of the 11.00% Notes (such 120 days prior being December 4, 2021), if greater than $25.0 million of the 11.00% Notes or any permitted refinancing indebtedness in respect thereof is outstanding on such date. We expect to refinance or extend the maturity of the 11.00% Notes prior to the springing maturity of the Bank Credit Facility, however, there can be no assurance that we will be able to execute this refinancing or extension or, if we are able to refinance or extend the 11.00% Notes maturity date, that the terms of such refinancing or extension would be as favorable as the terms of the existing 11.00% Notes.

The Bank Credit Facility bears interest based on the borrowing base usage, at the applicable London InterBank Offered Rate, plus applicable margins ranging from 3.00% to 4.00% or an alternate base rate based on the federal funds effective rate plus applicable margins ranging from 2.00% to 3.00%. In addition, we are obligated to pay a commitment fee of 0.50% on the unutilized portion of the commitments. The Bank Credit Facility has certain debt covenants, the most restrictive of which requires that we maintain a total debt to EBITDAX Ratio (as defined in the Bank Credit Facility) of no greater than 3.00 to 1.00 calculated each quarter utilizing the most recent twelve months to determine EBITDAX. We must also maintain a current ratio no less than 1.00 to 1.00 each quarter. According to the Bank Credit Facility, unutilized commitments are included in current assets in the current ratio calculation. The Bank Credit Facility is secured by substantially all of our oil and natural gas assets. The Bank Credit Facility is fully and unconditionally guaranteed by us and certain of our wholly-owned subsidiaries.

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 each year. Upon closing of the ILX and Castex Acquisition on February 28, 2020, the maximum borrowing base and commitments were increased from $950.0 million to $1.15 billion. On June 19, 2020, the borrowing base was redetermined by the lenders and decreased from $1.15 billion to $985.0 million. The June 19, 2020 redetermination also requires certain lender approval to access the last $25.0 million. The next scheduled redetermination meeting will be during the fourth quarter of 2020.

As of September 30, 2020, no more than $200.0 million of the borrowing base 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, 2020. As of September 30, 2020, the Company has $650.0 million of outstanding borrowings and $13.6 million in letters of credit issued under the Bank Credit Facility.

Subsequent event — During October 2020, the Company borrowed $25.0 million under the Bank Credit Facility for general corporate purposes.

11.00% Second-Priority Senior Secured Notes—due April 2022 — The 11.00% Second-Priority Senior Secured Notes (the “11.00% Notes”) were issued pursuant to an indenture dated May 10, 2018, between the Talos Issuers (as defined in that certain indenture), the subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent. The 11.00% Notes mature April 3, 2022 and have interest payable semi-annually each April 15 and October 15.

7.50% Senior Notes—due May 2022 — The 7.50% Senior Notes (the “7.50% Notes”) represent the remaining $6.1 million of long-term debt assumed in the Stone Combination that were not exchanged for 11.00% Notes pursuant to the exchange offer and consent solicitation, and thus remain outstanding. As a result of the exchange offer and consent solicitation, substantially all of the restrictive covenants relating to the 7.50% Notes have been removed and collateral securing the 7.50% Notes has been released. The 7.50% Notes mature May 31, 2022 and have interest payable semiannually each May 31 and November 30.

Performance Bonds — As of September 30, 2020, we had secured performance bonds primarily related to plugging and abandonment of wells and removal of facilities in the U.S. Gulf of Mexico and to guarantee the completion of the minimum work program under the Mexico production sharing contracts totaling approximately $659.3 million. In July 2016, BOEM issued the 2016 NTL to clarify the procedures and guidelines BOEM Regional Directors use to determine if and when additional financial assurances may be required for OCS leases, ROWs and RUEs to meet 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.

On October 16, 2020, the BOEM and BSEE, jointly published a proposed rule to clarify and provide greater transparency to decommissioning and related financial assurance requirements imposed on oil and gas lessees (record title owners), sublessees (operating rights owners) and RUE and ROW grant holders conducting operations on the federal OCS. In particular, the proposed rule would: (i) clarify the sequence for BSEE’s selection of predecessors who have accrued decommissioning obligations and are ordered to perform those obligations when the current lessee, sublessee or grant holder fails to do so, which sequence is generally in reverse chronological order through the chain-of-title of lessees or sublessees, although BSEE would reserve the right to deviate from this sequence in cases where previously ordered parties fail to pursue specified decommissioning activities, if an emergency condition is declared, or if such an order unreasonably delays decommissioning; (ii) seek to limit the circumstances under which BOEM would require supplemental bonding, with increased focus on a lessee’s or sublessee’s, as well as potentially a co-lessee’s or predecessor lessee’s, credit rating rather than relying primarily on a current lessee’s or sublessee’s net worth in determining whether additional supplemental bonding is necessary; (iii) relax certain third party guarantee requirements allowed by BOEM in lieu of lessee bonding; (iv) require the posting of bonds in an amount that BSEE determines would be adequate before that party may appeal a decommissioning order and (v) clarify that all RUE grant holders are jointly and severally liable for BSEE decommissioning obligations associated with RUE-related facilities. Comments on this proposed rule are due to BOEM (as to the BOEM portions of the proposed rule) and BSEE (as to the BSEE portions of the proposed rule) on or before December 15, 2020. We remain in active discussion with our industry peers with regard to this proposed rule. BOEM could make new demands for additional financial security in material amounts in the event the agency chooses to implement the 2016 NTL, or as a result of the provisions of any final rule published by BOEM and/or BSEE following the close of the comment period for the October 16, 2020 proposed rule, 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 BOEM’s rules applicable to our or our subsidiaries’ properties, could materially and adversely affect our financial condition, cash flows and results of operations.

Off Balance Sheet Arrangements

We did not have any off balance sheet arrangements as of September 30, 2020.

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 2019 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 accounting standards recently adopted by 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 2019 Annual Report. Except as disclosed in this Quarterly Report, there have been no material changes from the disclosures presented in our 2019 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, 2020.

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, 2020 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 2019 Annual Report, other than as set forth below.

On May 29, 2020, a lawsuit was filed in a Delaware Chancery Court asserting derivative and class action claims against us relating to the ILX and Castex Acquisition. Specifically, the lawsuit relates to the fairness of the consideration paid for such acquisitions in light of the fact that certain of the sellers are our affiliates. We disagree with the claims made in the lawsuit and we have filed for dismissal. We cannot currently predict the manner and timing of the resolution of this matter and are currently unable to estimate a range of possible losses from such matter.

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 2019 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. The risks and uncertainties described below should be read together with those disclosed in our 2019 Annual Report and our other SEC filings.

Oil and natural gas prices are volatile. Sustained periods of low, or further declines in, commodity prices adversely affect our financial condition and results of operations, cash flows, access to the capital markets, and ability to grow.

Our revenues, cash flows, profitability and future rate of growth substantially depend upon the market prices of oil and natural gas. The markets for oil and natural gas have been volatile historically and are likely to remain volatile in the future. For example, during the period from January 1, 2018 through September 30, 2020, the daily NYMEX WTI crude oil price per Bbl ranged from a low of $(36.98) to a high of $77.41, and the daily NYMEX Henry Hub natural gas price per MMBtu ranged from a low of $1.33 to a high of $6.24. Subsequent to September 30, 2020, NYMEX WTI crude oil and NYMEX Henry Hub natural gas prices recorded daily lows of $36.90 per Bbl and $1.41 per MMBtu, respectively. In April 2020, extreme shortages of transportation and storage capacity caused the NYMEX WTI front month oil futures price to go negative for the first time. We believe negative pricing resulted from the holders of expiring May 2020 oil purchase contracts being unable or unwilling to take physical delivery of crude oil and accordingly forced to make payments to purchasers of such contracts in order to transfer the corresponding purchase obligations.

Prices affect our cash flows available for capital expenditures and our ability to access funds under our Bank Credit Facility and through the capital markets. The amount available for borrowing under our Bank Credit Facility is subject to a borrowing base, which is determined by the lenders taking into account our estimated proved reserves, and is subject to periodic redeterminations based on pricing models to be determined by the lenders at such time. Further, because we use the full cost method of accounting for our oil and gas operations, we perform a ceiling test each quarter, which is impacted by declining prices. Significant price declines could cause us to take ceiling test write-downs, which would be reflected as non-cash charges against current earnings. See the Risk Factor entitled “Lower oil and natural gas prices and other factors in the future may result in ceiling test write-downs and other impairments of our asset carrying values” for further discussion. In addition, significant or extended price declines may also adversely affect the amount of oil and natural gas that we can produce economically. A reduction in production could result in a shortfall in our expected cash flows and require us to reduce our capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively impact our ability to replace our production and our future rate of growth.

The prices we receive for our oil and natural gas depend upon many factors beyond our control, including, among others:

•

changes in the supply of and demand for oil and natural gas;

•

market uncertainty;

•

level of consumer product demands;

•

hurricanes and other adverse weather conditions;

•

the impact of applicable market differentials, including those relating to quality, transportation, fees, energy content and regional pricing;

•

domestic and foreign governmental actions, regulations and taxes;

•

price and availability of alternative fuels;

•

political and economic conditions in oil-producing countries, particularly those in the Middle East, Russia, South America and Africa;

•

the occurrence or threat of epidemic or pandemic diseases, such as the recent outbreak of COVID-19, or any government response to such occurrence or threat;

•

actions by the OPEC and other state-controlled oil companies relating to oil and natural gas price and production controls;

•

U.S. and foreign supply of oil and natural gas;

•

price and quantity of oil and natural gas imports and exports;

•

the level of global oil and natural gas exploration and production;

•

the level of global oil and natural gas inventories;

•

localized supply and demand fundamentals and transportation availability;

•

capacity of processing, gathering, storage and transportation facilities;

•

speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;

•

price and availability of competitors’ supplies of oil and natural gas;

•

technological advances affecting energy consumption; and

•

overall domestic and foreign economic conditions.

These factors make it very difficult to predict future commodity price movements with any certainty. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices and are not long-term fixed price contracts. Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other. Because oil, natural gas and NGLs accounted for approximately 68%, 25%, and 7%, respectively, of our estimated proved reserves as of September 30, 2020, and approximately 69%, 24%, and 7%, respectively, of our production on an MBoe basis as of September 30, 2020, our financial results are sensitive to movements in oil, natural gas and NGL prices.

A financial crisis may impact our business, financial condition and cash flows and may adversely impact our ability to obtain funding under our Bank Credit Facility or in the capital markets.

We use our cash flows from operating activities and borrowings under our Bank Credit Facility to fund our capital expenditures, and we rely on the capital markets and asset monetization transactions to provide us with additional capital for large or exceptional transactions. However, COVID-19 and numerous public and political responses thereto have contributed to equity market volatility and the potential risk of a global recession, and we expect this global equity market volatility to continue at least until the outbreak of COVID-19 stabilizes, if not longer. As such, we may not be able to access adequate funding under our Bank Credit Facility as a result of (i) a decrease in our borrowing base due to the outcome of a borrowing base redetermination or a breach or default under our Bank Credit Facility, including a breach of a financial covenant or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. We may also face limitations on our ability to access the debt and equity capital markets and complete asset sales, increased counterparty credit risk on our derivatives contracts, and requirements by our contractual counterparties to post collateral guaranteeing performance.

In addition, from time to time, we could be required to, or we or our affiliates may seek to, retire or purchase our outstanding debt through cash purchases and/or exchanges for equity or debt, open-market purchases, privately negotiated transactions or other transactions. Such debt repurchase or exchange transactions, if any, will be upon such terms and at such prices as we may determine, and will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. Such transactions may give rise to taxable cancellation of indebtedness income (to the extent the fair market value of the property exchanged, or the amount of cash paid to acquire the outstanding debt, is less than the adjusted issue price of the outstanding debt) and adversely impact our ability to deduct interest expenses in respect of our debt against our taxable income in the future. This could result in a current or future tax liability, which could adversely affect our financial condition and cash flows.

Lower oil and natural gas prices and other factors in the future may result in ceiling test write-downs and other impairments of our asset carrying values.

We use the full cost method of accounting for our oil and gas operations. Accordingly, we capitalize the costs to acquire, explore for and develop oil and gas properties. Under the full cost method of accounting, our capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. Any costs in excess of the ceiling are recognized as a non-cash “Write-down of oil and natural gas properties” on the condensed consolidated statements of operations and an increase to “Accumulated depreciation, depletion and amortization” on our condensed consolidated balance sheets. A write-down of oil and gas properties does not impact cash flows from operating activities, but does reduce net income. The risk that we are required to write-down the carrying value of oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our undeveloped property values, or if estimated future development costs increase. Volatility in commodity prices, poor conditions in the global economic markets and other factors could cause us to record additional write-downs of our oil and natural gas properties and other assets in the future, and incur additional charges against future earnings. For the three and nine months ended September 30, 2020, the Company recorded an impairment of nil and $0.1 million, respectively. Any required write-downs or impairments could materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

Our business depends on access to oil and natural gas processing, gathering, storage and transportation systems and facilities.

The marketability of our oil and natural gas production depends in large part on the operation, availability, proximity, capacity and expansion of processing, gathering and transportation facilities, including storage capacity, owned by third parties. In April 2020, extreme shortages of transportation and storage capacity caused the NYMEX WTI front month oil futures price to go negative for the first time. This negative pricing resulted from the holders of expiring May 2020 oil purchase contracts being unable or unwilling to take physical delivery of crude oil, due to the severe lack of storage capacity, and accordingly were forced to make payments to purchasers of such contracts in order to transfer the corresponding purchase obligations. As such, we can provide no assurance that sufficient processing, gathering, storage and/or transportation capacity exists or that we will be able to obtain sufficient processing, gathering, storage and/or transportation capacity on economic terms. A lack of available capacity on processing, gathering, storage and transportation facilities or delays in their planned expansions could result in the shut-in of producing wells or the delay or discontinuance of drilling plans for properties. A lack of availability of these facilities for an extended period of time could negatively impact our revenues. In addition, we enter into contracts for firm transportation, and any failure to renew those contracts on the same or better commercial terms could increase our costs and our exposure to the risks described above. In addition, the rates charged for processing, gathering, storage and transportation services may increase over time.

If we are forced to shut in production, we will likely incur greater costs to bring the associated production back online, and will be unable to predict the production levels of such wells once brought back online.

The recent actions of foreign oil producers such as Saudi Arabia and Russia, coupled with the impact on global demand from the COVID-19 pandemic, have materially decreased global crude oil prices and generated a surplus of oil. This significant surplus has created a saturation of storage and caused crude storage constraints, which could lead to the shut-in of production of our wells due to lack of sufficient markets or lack of availability and capacity of processing, gathering, storing and transportation systems. If we are forced to shut in production we will likely incur greater costs to bring the associated production back online. Cost increases necessary to bring the associated wells back online may be significant enough that such wells would become uneconomic at low commodity price levels, which may lead to decreases in our proved reserve estimates and potential impairments and associated charges to our earnings. If we are able to bring wells back online, there is no assurance that such wells will be as productive following recommencement as they were prior to being shut in. Any shut in or curtailment of the oil, natural gas and NGLs produced from our fields could adversely affect our financial condition and results of operations.

The results of the November 3, 2020 election could impact the ability of the administration and/or Congress to enact rules and regulations that impose restrictions on our ability to acquire future federal OCS leases, as well as more onerous permitting and other detrimental requirements.

Although preliminary election results remain inconclusive, Democratic presidential candidate Joe Biden’s campaign website states that, if elected, on day one as President, he will issue Executive Orders to permanently protect the Arctic National Wildlife Refuge and other federal lands and waters, establish monuments and ban new oil and gas permitting on public lands and waters and modify royalties to account for climate costs. In addition, Mr. Biden promises to require aggressive methane pollution limits for new and existing oil and gas operations. These efforts, among others, support Mr. Biden’s overall goal of achieving net-zero emissions no later than 2050. In addition to these administrative actions, preliminary election results indicate that a Democratic-controlled Senate, together with a Democratic-controlled House of Representatives, could enact legislation that could permanently withdraw most, if not all of the OCS from future leasing, which would restrict our ability to acquire new leases for future exploration and development. Other potential actions of a Democratic-controlled Congress include imposing more restrictive laws and regulations pertaining to permitting, limitations on greenhouse gas emissions, increased requirements for financial assurance and bonding for decommissioning liabilities and carbon taxes. Any of these administrative or congressional actions could adversely affect our financial condition and results of operations. In addition, any extended uncertainty as to the outcome of the presidential election could lead to market uncertainty, civil unrest or general economic volatility. Any such uncertainty, unrest or volatility could adversely affect the macroeconomic environment, and accordingly, our financial condition and results of operations.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

None.

Item 5. Other Information

None.

Item 6. Exhibits

Exhibit Number		Description

2.1#		Purchase and Sale Agreement, dated as of December 10, 2019, by and among Talos Energy Inc., Talos Production Inc. and ILX Holdings, LLC (incorporated by reference to Exhibit 2.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 16, 2019).

2.2		Amendment to Purchase and Sale Agreement, dated as of February 24, 2020, by and among Talos Energy Inc., Talos Production Inc. and ILX Holdings LLC (incorporated by reference to Exhibit 2.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 25, 2020).

2.3#		Purchase and Sale Agreement, dated as of December 10, 2019, by and among Talos Energy Inc., Talos Production Inc. and ILX Holdings II, LLC (incorporated by reference to Exhibit 2.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 16, 2019).

2.4		Amendment to Purchase and Sale Agreement, dated as of February 24, 2020, by and among Talos Energy Inc., Talos Production Inc. and ILX Holdings II LLC (incorporated by reference to Exhibit 2.4 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 25, 2020).

2.5#		Purchase and Sale Agreement, dated as of December 10, 2019, by and among Talos Energy Inc., Talos Production Inc. and ILX Holdings III LLC (incorporated by reference to Exhibit 2.3 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 16, 2019).

2.6		Amendment to Purchase and Sale Agreement, dated as of February 24, 2020, by and among Talos Energy Inc., Talos Production Inc. and ILX Holdings III LLC (incorporated by reference to Exhibit 2.6 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 25, 2020).

2.7#		Purchase and Sale Agreement, dated as of December 10, 2019, by and among Talos Energy Inc., Talos Production Inc. and Castex Energy 2014, LLC (incorporated by reference to Exhibit 2.4 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 16, 2019).

2.8		Amendment to Purchase and Sale Agreement, dated as of February 24, 2020, by and among Talos Energy Inc., Talos Production Inc. and Castex Energy 2014, LLC (incorporated by reference to Exhibit 2.8 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 25, 2020).

2.9#		Purchase and Sale Agreement, dated as of December 10, 2019, by and among Talos Energy Inc., Talos Production Inc. and Castex Energy 2016, LP (incorporated by reference to Exhibit 2.5 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 16, 2019).

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 and 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).

3.3		Certificate of Designation, dated as of February 27, 2020 (incorporated by reference to Exhibit 3.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on March 2, 2020).

10.1		Talos Energy Operating Company LLC Amended and Restated Executive Severance Plan (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on October 26, 2020).

10.2		Form of Participation Agreement pursuant to Talos Energy Operating Company LLC Amended and Restated Executive Severance Plan (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on October 26, 2020).

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*		Inline XBRL Instance.

101.SCH*		Inline XBRL Taxonomy Extension Schema.

101.CAL*		Inline XBRL Taxonomy Extension Calculation.

101.DEF*		Inline XBRL Taxonomy Extension Definition.

101.LAB*		Inline XBRL Taxonomy Extension Label.

101.PRE*		Inline XBRL Taxonomy Extension Presentation.

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.

†	Identifies management contracts and compensatory plans or arrangements.

#	Certain schedules, annexes or exhibits have been omitted pursuant to Item 601(a)(5) of Regulation S-K, but will be furnished supplementally to the SEC upon request.

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 4, 2020	By:	/s/ Shannon E. Young III
			Shannon E. Young III
			Executive Vice President and Chief Financial Officer