UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM
(Mark One)
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended
OR
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:
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(I.R.S. Employer Identification No.) |
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Registrant’s telephone number, including area code: (
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class |
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Trading Symbol(s) |
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Name of Each Exchange on Which Registered |
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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.
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).
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 |
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Non-accelerated filer |
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Smaller reporting company |
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Emerging growth company |
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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
As of October 27, 2021, the registrant had
TABLE OF CONTENTS
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Item 1. |
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Condensed Consolidated Statements of Changes in Stockholders' Equity |
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Note 7 — Employee Benefits Plans and Share-Based Compensation |
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Item 2. |
Management’s Discussion and Analysis of Financial Condition and Results of Operations |
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Item 3. |
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Item 4. |
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Item 1. |
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Item 1A. |
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Item 2. |
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Item 3. |
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Item 4. |
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Item 5. |
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Item 6. |
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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.
BOEM — Bureau of Ocean Energy Management.
BSEE — Bureau of Safety and Environmental Enforcement.
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.
GAAP — Accounting principles generally accepted in the United States of America.
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.
OPEC — Organization of Petroleum Exporting Countries.
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.
1
Proved undeveloped reserves — In general, proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. The SEC provides a complete definition of undeveloped oil and gas reserves in Rule 4-10(a)(31) of Regulation S-K.
SEC — The U.S. 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).
Shelf — Water depths of up to 600 feet.
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%.
2
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
The information in this Quarterly Report on Form 10-Q (this "Quarterly 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:
3
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 due to the continued impact of the coronavirus disease 2019 (“COVID-19”), including any new strains or variants, 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 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 and regulations; lack of availability of drilling and production equipment and services; adverse weather events, including tropical storms, hurricanes, and winter storms; cybersecurity threats; 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 acquisitions 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, 2020 filed with the SEC on March 11, 2021 (the “2020 Annual 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 Quarterly 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.
4
PART I—FINANCIAL INFORMATION
Item 1. Financial Statements
TALOS ENERGY INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)
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September 30, 2021 |
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December 31, 2020 |
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(Unaudited) |
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ASSETS |
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Current assets: |
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Cash and cash equivalents |
$ |
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$ |
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Accounts receivable: |
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Trade, net |
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Joint interest, net |
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Other |
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Assets from price risk management activities |
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Prepaid assets |
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Other current assets |
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Total current assets |
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Property and equipment: |
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Proved properties |
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Unproved properties, not subject to amortization |
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Other property and equipment |
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Total property and equipment |
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Accumulated depreciation, depletion and amortization |
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Total property and equipment, net |
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Other long-term assets: |
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Assets from price risk management activities |
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Other well equipment inventory |
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Operating lease assets |
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Other assets |
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Total assets |
$ |
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$ |
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LIABILITIES AND STOCKHOLDERSʼ EQUITY |
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Current liabilities: |
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Accounts payable |
$ |
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$ |
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Accrued liabilities |
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Accrued royalties |
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Current portion of long-term debt |
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Current portion of asset retirement obligations |
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Liabilities from price risk management activities |
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Accrued interest payable |
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Current portion of operating lease liabilities |
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Other current liabilities |
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Total current liabilities |
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Long-term liabilities: |
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Long-term debt, net of discount and deferred financing costs |
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Asset retirement obligations |
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Liabilities from price risk management activities |
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Operating lease liabilities |
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Other long-term liabilities |
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Total liabilities |
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Stockholdersʼ equity: |
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Preferred stock, $ |
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Common stock $ |
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Additional paid-in capital |
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Accumulated deficit |
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( |
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( |
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Total stockholdersʼ equity |
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Total liabilities and stockholdersʼ equity |
$ |
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$ |
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See accompanying notes.
5
TALOS ENERGY INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except share amounts)
(Unaudited)
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Three Months Ended September 30, |
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Nine Months Ended September 30, |
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2021 |
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2020 |
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2021 |
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2020 |
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Revenues and other: |
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Oil |
$ |
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$ |
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$ |
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$ |
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Natural gas |
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NGL |
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Other |
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Total revenues and other |
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Operating expenses: |
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Lease operating expense |
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Production taxes |
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Depreciation, depletion and amortization |
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Write-down of oil and natural gas properties |
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Accretion expense |
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General and administrative expense |
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Other operating expense |
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Total operating expenses |
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Operating income (expense) |
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( |
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( |
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Interest expense |
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( |
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( |
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( |
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( |
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Price risk management activities income (expense) |
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( |
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( |
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( |
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Other income (expense) |
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( |
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Net loss before income taxes |
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( |
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( |
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( |
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( |
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Income tax benefit (expense) |
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( |
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Net loss |
$ |
( |
) |
$ |
( |
) |
$ |
( |
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$ |
( |
) |
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Net loss per common share: |
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Basic |
$ |
( |
) |
$ |
( |
) |
$ |
( |
) |
$ |
( |
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Diluted |
$ |
( |
) |
$ |
( |
) |
$ |
( |
) |
$ |
( |
) |
Weighted average common shares outstanding: |
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Basic |
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Diluted |
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See accompanying notes.
6
TALOS ENERGY INC.
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
STOCKHOLDERS’ EQUITY
(In thousands, except share amounts)
(Unaudited)
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Shares |
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Par Value |
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Additional |
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Total |
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Common Stock |
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Preferred Stock |
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Common Stock |
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Preferred Stock |
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Paid-In Capital |
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Accumulated Deficit |
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Stockholders' Equity |
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Balance at June 30, 2020 |
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— |
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$ |
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$ |
— |
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$ |
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$ |
( |
) |
$ |
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Equity-based compensation |
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— |
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— |
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— |
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— |
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— |
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Equity-based compensation |
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— |
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— |
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— |
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— |
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( |
) |
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— |
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( |
) |
Equity-based compensation |
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— |
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— |
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— |
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— |
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— |
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— |
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Issuance of common stock for |
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— |
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— |
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— |
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Net loss |
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— |
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— |
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— |
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— |
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— |
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( |
) |
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( |
) |
Balance at September 30, 2020 |
|
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— |
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$ |
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$ |
— |
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$ |
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$ |
( |
) |
$ |
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Balance at June 30, 2021 |
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— |
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$ |
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$ |
— |
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$ |
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$ |
( |
) |
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||||
Equity-based compensation |
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— |
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— |
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— |
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— |
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— |
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Equity-based compensation |
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— |
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— |
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— |
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— |
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( |
) |
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— |
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( |
) |
Equity-based compensation |
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— |
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— |
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— |
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— |
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— |
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— |
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Net loss |
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— |
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— |
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— |
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— |
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— |
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( |
) |
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( |
) |
Balance at September 30, 2021 |
|
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— |
|
$ |
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$ |
— |
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$ |
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$ |
( |
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$ |
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Shares |
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Par Value |
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Additional |
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Total |
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Common Stock |
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Preferred Stock |
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Common Stock |
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Preferred Stock |
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Paid-In Capital |
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Accumulated Deficit |
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Stockholders' Equity |
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Balance at December 31, 2019 |
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— |
|
$ |
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$ |
— |
|
$ |
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$ |
( |
) |
$ |
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||||
Equity-based compensation |
|
— |
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— |
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— |
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— |
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— |
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Equity-based compensation |
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— |
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— |
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— |
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— |
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( |
) |
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— |
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( |
) |
Equity-based compensation |
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— |
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— |
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( |
) |
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— |
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Issuance of preferred stock |
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— |
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— |
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— |
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Conversion of preferred |
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( |
) |
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( |
) |
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( |
) |
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— |
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— |
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Issuance of common stock for |
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— |
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— |
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— |
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Issuance of common stock for |
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— |
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— |
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— |
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Net loss |
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— |
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— |
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— |
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— |
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|
— |
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|
( |
) |
|
( |
) |
Balance at September 30, 2020 |
|
|
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— |
|
$ |
|
$ |
— |
|
$ |
|
$ |
( |
) |
$ |
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||||
|
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|||||||
Balance at December 31, 2020 |
|
|
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— |
|
$ |
|
$ |
— |
|
$ |
|
$ |
( |
) |
$ |
|
||||
Equity-based compensation |
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— |
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— |
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— |
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— |
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— |
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Equity-based compensation |
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— |
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— |
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— |
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— |
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( |
) |
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— |
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( |
) |
Equity-based compensation |
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— |
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— |
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( |
) |
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— |
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Net loss |
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— |
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— |
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— |
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|
— |
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|
— |
|
|
( |
) |
|
( |
) |
Balance at September 30, 2021 |
|
|
|
— |
|
$ |
|
$ |
— |
|
$ |
|
$ |
( |
) |
$ |
|
||||
See accompanying notes.
7
TALOS ENERGY INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
|
Nine Months Ended September 30, |
|
||||
|
2021 |
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2020 |
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Cash flows from operating activities: |
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Net loss |
$ |
( |
) |
$ |
( |
) |
Adjustments to reconcile net loss to net cash |
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Depreciation, depletion, amortization and accretion expense |
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|
||
Write-down of oil and natural gas properties and other well inventory |
|
|
|
|
||
Amortization of deferred financing costs and original issue discount |
|
|
|
|
||
Equity-based compensation, net of amounts capitalized |
|
|
|
|
||
Price risk management activities expense (income) |
|
|
|
( |
) |
|
Net cash received (paid) on settled derivative instruments |
|
( |
) |
|
|
|
Loss (gain) on extinguishment of debt |
|
|
|
( |
) |
|
Settlement of asset retirement obligations |
|
( |
) |
|
( |
) |
Gain on sale of assets |
|
( |
) |
|
|
|
Changes in operating assets and liabilities: |
|
|
|
|
||
Accounts receivable |
|
|
|
( |
) |
|
Other current assets |
|
( |
) |
|
|
|
Accounts payable |
|
( |
) |
|
|
|
Other current liabilities |
|
|
|
|
||
Other non-current assets and liabilities, net |
|
|
|
( |
) |
|
Net cash provided by operating activities |
|
|
|
|
||
Cash flows from investing activities: |
|
|
|
|
||
Exploration, development and other capital expenditures |
|
( |
) |
|
( |
) |
Cash paid for acquisitions, net of cash acquired |
|
( |
) |
|
( |
) |
Proceeds from sale of property and equipment, net |
|
|
|
|
||
Net cash used in investing activities |
|
( |
) |
|
( |
) |
Cash flows from financing activities: |
|
|
|
|
||
Issuance of senior notes |
|
|
|
|
||
Redemption of senior notes and other long-term debt |
|
( |
) |
|
( |
) |
Proceeds from Bank Credit Facility |
|
|
|
|
||
Repayment of Bank Credit Facility |
|
( |
) |
|
|
|
Deferred financing costs |
|
( |
) |
|
( |
) |
Other deferred payments |
|
( |
) |
|
( |
) |
Payments of finance lease |
|
( |
) |
|
( |
) |
Employee stock awards tax withholdings |
|
( |
) |
|
( |
) |
Net cash provided by (used in) financing activities |
|
( |
) |
|
|
|
|
|
|
|
|
||
Net increase (decrease) in cash and cash equivalents |
|
|
|
( |
) |
|
Cash and cash equivalents: |
|
|
|
|
||
Balance, beginning of period |
|
|
|
|
||
Balance, end of period |
$ |
|
$ |
|
||
|
|
|
|
|
||
Supplemental non-cash transactions: |
|
|
|
|
||
Capital expenditures included in accounts payable and accrued liabilities |
$ |
|
$ |
|
||
Debt exchanged for common stock |
$ |
|
$ |
|
||
Supplemental cash flow information: |
|
|
|
|
||
Interest paid, net of amounts capitalized |
$ |
|
$ |
|
||
See accompanying notes.
8
TALOS ENERGY INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2021
(Unaudited)
Note 1 — Nature of Business and Basis of Presentation
Nature of Business
Talos Energy Inc. (including its subsidiaries, collectively “Talos” or the “Company”) is a technically driven independent exploration and production company focused on safely and efficiently maximizing long-term value through its operations, currently in the United States (“U.S.”) Gulf of Mexico and offshore Mexico both upstream through oil and gas exploration and production and downstream through the development of future carbon capture and storage opportunities. The Company leverages decades of technical and offshore operational expertise towards the acquisition, exploration and development of assets in key geological trends that are present in many offshore basins around the world. With a focus on environmental stewardship, the Company also utilizes its expertise to explore opportunities to reduce industrial emissions through the Company's carbon capture and storage collaborative arrangements along the U.S. Gulf Coast and Gulf of Mexico.
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 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 unaudited financial statements and related notes included in this Quarterly Report should be read in conjunction with the Company’s audited Consolidated Financial Statements and accompanying notes included in the 2020 Annual Report.
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from those estimates.
The Company has
Note 2 — Acquisitions
Asset Acquisition
The following acquisition was accounted for as an asset acquisition whereby the cost of the acquisition, including transaction costs, was allocated to the assets acquired on the basis of their relative fair values.
Acquisition of Castex Energy 2005 — On
9
The following table summarizes the purchase price, inclusive of customary closing adjustments (in thousands except share and per share data):
Talos common stock |
|
|
||
Talos common stock price per share(1) |
$ |
|
||
Talos common stock value |
$ |
|
||
|
|
|
||
Cash consideration |
$ |
|
||
Transaction cost |
$ |
|
||
|
|
|
||
Total purchase price |
$ |
|
||
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 |
$ |
|
|
Asset retirement obligations |
|
( |
) |
Allocated purchase price |
$ |
|
Business Combination
The following acquisition was accounted for as a business combination whereby the Company recorded the assets acquired and liabilities assumed at their respective fair values as of the acquisition date.
ILX and Castex Acquisition — On
The following table summarizes the purchase price (in thousands except share and per share data):
Talos Conversion Stock |
|
|
||
Talos common stock price per share(1) |
$ |
|
||
Conversion Stock value |
$ |
|
||
|
|
|
||
Cash consideration |
$ |
|
||
Customary closing and post-closing adjustments |
|
( |
) |
|
Net cash consideration |
$ |
|
||
|
|
|
||
Total purchase price |
$ |
|
||
10
The following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed, based on their fair values on February 28, 2020 (in thousands):
Current assets(1) |
$ |
|
|
Property and equipment |
|
|
|
Other long-term assets |
|
|
|
Current liabilities |
|
( |
) |
Other long-term liabilities |
|
( |
) |
Allocated purchase price |
$ |
|
The Company incurred a total of $
The following table presents revenue and net income attributable to the assets acquired in the ILX and Castex Acquisition:
|
Three Months Ended September 30, 2020 |
|
Nine Months Ended September 30, 2020 |
|
||
Revenue |
$ |
|
$ |
|
||
Net loss |
$ |
( |
) |
$ |
( |
) |
Pro Forma Financial Information (Unaudited) —
|
Nine Months Ended September 30, 2020 |
|
|
Revenue |
$ |
|
|
Net loss |
$ |
( |
) |
Basic net loss per common share |
$ |
( |
) |
Diluted net loss per common share |
$ |
( |
) |
Note 3 — Property, Plant and Equipment
Ceiling Test
During the three and nine months ended September 30, 2021 and 2020, the Company’s ceiling test computations did
11
Asset Retirement Obligations
The asset retirement obligations included in the Condensed Consolidated Balance Sheets in current and non-current liabilities, and the changes in that liability were as follows (in thousands):
|
Asset Retirement Obligations |
|
|
Asset retirement obligations at December 31, 2020 |
$ |
|
|
Obligations acquired |
|
|
|
Obligations incurred |
|
|
|
Obligations settled |
|
( |
) |
Obligations divested |
|
( |
) |
Accretion expense |
|
|
|
Changes in estimate |
|
|
|
Asset retirement obligations at September 30, 2021 |
$ |
|
|
Less: Current portion at September 30, 2021 |
|
|
|
Long-term portion at September 30, 2021 |
$ |
|
|
Note 4 — Leases
The Company has operating leases principally for office space, drilling rigs, compressors and other equipment necessary to support the Company’s operations. Additionally, the Company has a finance lease related to the use of the Helix Producer I (the “HP-I”), a dynamically positioned floating production facility that interconnects with the Phoenix Field through a production buoy. 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. Costs associated with the Company’s leases are either expensed or capitalized depending on how the underlying asset is utilized.
The lease costs described below are presented on a gross basis and do not represent the Company’s net proportionate share of such amounts. A portion of these costs have been or may be billed to other working interest owners. The Company’s share of these costs is included in property and equipment, lease operating expense or general and administrative expense, as applicable.
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
|
||||||||
|
2021 |
|
2020 |
|
2021 |
|
2020 |
|
||||
Finance lease cost - interest on lease liabilities |
$ |
|
$ |
|
$ |
|
$ |
|
||||
Operating lease cost, excluding short-term |
|
|
|
|
|
|
|
|
||||
Short-term lease cost(2) |
|
|
|
|
|
|
|
|
||||
Variable lease cost(3) |
|
|
|
|
|
|
|
|
||||
Total lease cost |
$ |
|
$ |
|
$ |
|
$ |
|
||||
12
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 were as follows (in thousands):
|
September 30, 2021 |
|
December 31, 2020 |
|
||
Operating leases: |
|
|
|
|
||
Operating lease assets |
$ |
|
$ |
|
||
|
|
|
|
|
||
$ |
|
$ |
|
|||
Operating lease liabilities |
|
|
|
|
||
Total operating lease liabilities |
$ |
|
$ |
|
||
|
|
|
|
|
||
Finance leases: |
|
|
|
|
||
Proved property |
$ |
|
$ |
|
||
|
|
|
|
|
||
Other current liabilities |
$ |
|
$ |
|
||
Other long-term liabilities |
|
|
|
|
||
Total finance lease liabilities |
$ |
|
$ |
|
||
The table below presents the supplemental cash flow information related to leases (in thousands):
|
Nine Months Ended September 30, |
|
||||
|
2021 |
|
2020 |
|
||
Operating cash outflow from finance leases |
$ |
|
$ |
|
||
Operating cash outflow from operating leases |
$ |
|
$ |
|
||
|
|
|
|
|
||
Right-of-use assets obtained in exchange for new operating lease |
$ |
|
$ |
|
||
N
As of September 30, 2021 and December 31, 2020, 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.
Debt Instruments
The following table presents the carrying amounts, net of discount and deferred financing costs, and estimated fair values of the Company’s debt instruments (in thousands):
|
September 30, 2021 |
|
December 31, 2020 |
|
||||||||
|
Carrying |
|
Fair |
|
Carrying |
|
Fair |
|
||||
12.00% Second-Priority Senior Secured Notes – |
$ |
|
$ |
|
$ |
— |
|
$ |
— |
|
||
11.00% Second-Priority Senior Secured Notes – |
$ |
— |
|
$ |
— |
|
$ |
|
$ |
|
||
7.50% Senior Notes – due May 2022 |
$ |
|
$ |
|
$ |
|
$ |
|
||||
Bank Credit Facility – matures November 2024 |
$ |
|
$ |
|
$ |
|
$ |
|
||||
The carrying value of the senior notes are presented net of the original issue discount and deferred financing costs. Fair value is estimated (representing a Level 1 fair value measurement) using quoted secondary market trading prices.
The carrying amount of the Company’s bank credit facility, as amended and restated (the “Bank Credit Facility”), is presented net of deferred financing costs. 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).
13
Oil and Natural Gas Derivatives
The Company attempts to mitigate a portion of its commodity price risk and stabilize cash flows associated with sales of oil and natural gas production through the use of oil and natural gas swaps and costless collars. Swaps are contracts where the Company either receives or pays depending on whether the oil or natural gas floating market price is above or below the contracted fixed price. Costless collars consist of a purchased put option and a sold call option with no net premiums paid to or received from counterparties. Collar contracts typically require payments by the Company if the NYMEX average closing price is above the ceiling price or payments to the Company if the NYMEX average closing price is below the floor price.
The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, commodity derivatives are recorded on the Condensed Consolidated Balance Sheets at fair value with settlements of such contracts, and changes in the unrealized fair value, recorded as “Price risk management activities income (expense)” on the Condensed Consolidated Statements of Operations in each period.
The following table presents the impact that derivatives, not designated as hedging instruments, had on its Condensed Consolidated Statements of Operations (in thousands):
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
|
||||||||
|
2021 |
|
2020 |
|
2021 |
|
2020 |
|
||||
Net cash received (paid) on settled derivative |
$ |
( |
) |
$ |
|
$ |
( |
) |
$ |
|
||
Unrealized gain (loss) |
|
( |
) |
|
( |
) |
|
( |
) |
|
|
|
Price risk management activities income |
$ |
( |
) |
$ |
( |
) |
$ |
( |
) |
$ |
|
|
The following tables reflect the contracted volumes and weighted average prices under the terms of the Company's derivative contracts as of September 30, 2021:
Swap Contracts |
|
||||||
Production Period |
Settlement Index |
Average |
|
Weighted |
|
||
Crude oil: |
|
(Bbls) |
|
(per Bbl) |
|
||
October 2021 – December 2021 |
|
|
$ |
|
|||
January 2022 – December 2022 |
|
|
$ |
|
|||
January 2023 – June 2023 |
|
|
$ |
|
|||
October 2021 – December 2021 |
|
|
$ |
|
|||
Natural gas: |
|
(MMBtu) |
|
(per MMBtu) |
|
||
October 2021 – December 2021 |
|
|
$ |
|
|||
January 2022 – December 2022 |
|
|
$ |
|
|||
January 2023 – June 2023 |
|
|
$ |
|
|||
Collar Contracts |
|
|||||||||
Production Period |
Settlement Index |
Average |
|
Weighted |
|
Weighted |
|
|||
Crude oil: |
|
(Bbls) |
|
(per Bbl) |
|
(per Bbl) |
|
|||
October 2021 – December 2021 |
|
|
$ |
|
$ |
|
||||
Natural gas: |
|
(MMBtu) |
|
(per MMBtu) |
|
(per MMBtu) |
|
|||
October 2021 – December 2021 |
|
|
$ |
|
$ |
|
||||
14
The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands):
|
September 30, 2021 |
|
||||||||||
|
Level 1 |
|
Level 2 |
|
Level 3 |
|
Total |
|
||||
Assets: |
|
|
|
|
|
|
|
|
||||
Oil and natural gas swaps and costless collars |
$ |
|
$ |
|
$ |
|
$ |
|
||||
Liabilities: |
|
|
|
|
|
|
|
|
||||
Oil and natural gas swaps and costless collars |
|
|
|
( |
) |
|
|
|
( |
) |
||
Total net liability |
$ |
|
$ |
( |
) |
$ |
|
$ |
( |
) |
||
|
December 31, 2020 |
|
||||||||||
|
Level 1 |
|
Level 2 |
|
Level 3 |
|
Total |
|
||||
Assets: |
|
|
|
|
|
|
|
|
||||
Oil and natural gas swaps and costless collars |
$ |
|
$ |
|
$ |
|
$ |
|
||||
Liabilities: |
|
|
|
|
|
|
|
|
||||
Oil and natural gas swaps and costless collars |
|
|
|
( |
) |
|
|
|
( |
) |
||
Total net liability |
$ |
|
$ |
( |
) |
$ |
|
$ |
( |
) |
||
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.
|
September 30, 2021 |
|
December 31, 2020 |
|
||||||||
|
Assets |
|
Liabilities |
|
Assets |
|
Liabilities |
|
||||
Oil and natural gas derivatives: |
|
|
|
|
|
|
|
|
||||
Current |
$ |
|
$ |
|
$ |
|
$ |
|
||||
Non-current |
|
|
|
|
|
|
|
|
||||
Total gross amounts presented on balance sheet |
|
|
|
|
|
|
|
|
||||
Less: Gross amounts not offset on the balance sheet |
|
|
|
|
|
|
|
|
||||
Net amounts |
$ |
|
$ |
|
$ |
|
$ |
|
||||
Credit Risk
15
N
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, 2021 |
|
December 31, 2020 |
|
||
$ |
|
$ |
|
|||
|
|
|
|
|||
|
|
|
|
|||
Bank Credit Facility – matures |
|
|
|
|
||
Total debt, before discount and deferred financing cost |
|
|
|
|
||
Discount and deferred financing cost |
|
( |
) |
|
( |
) |
Total debt, net of discount and deferred financing costs |
|
|
|
|
||
Less: Current portion of long-term debt |
|
|
|
|
||
Long-term debt, net of discount and deferred financing costs |
$ |
|
$ |
|
||
12.00% Second-Priority Senior Notes
The 12.00% Second-Priority Senior Secured Notes due 2026 (the “
Period |
|
Redemption Price |
|
|
2023 |
|
|
% |
|
2024 |
|
|
% |
|
2025 |
|
|
% |
|
The indenture governing the 12.00% Notes applies certain limitations on the Company’s ability and the ability of its subsidiaries to, among other things, (i) incur, assume or guarantee additional indebtedness or issue certain convertible or redeemable equity securities; (ii) create liens to secure indebtedness; (iii) pay distributions on equity interests, repurchase equity securities or redeem junior lien, unsecured or subordinated indebtedness; (iv) make investments; (v) restrict distributions, loans or other asset transfers from Talos Production Inc.’s restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of Talos Production Inc.’s properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiliates. The
11.00% Second-Priority Senior Secured Notes
On January 13, 2021, the Company redeemed $
16
On June 15, 2020, the Company entered into an exchange agreement pursuant to which the Company agreed to exchange $
Bank Credit Facility
The Company maintains a Bank Credit Facility with a syndicate of financial institutions.
The Bank Credit Facility sets the interest rate at either (at the Company’s option) an alternative base rate plus a specified percentage, or London Interbank Offered Rate (“LIBOR”) plus a specified percentage. The specified percentage is referred to as the applicable margin, which varies based on the borrowing base utilization percentage.
As of September 30, 2021, the Company's borrowing base was $
Note 7 — Employee Benefits Plans and Share-Based Compensation
Long Term Incentive Plans
On May 11, 2021, the Company’s stockholders approved the Talos Energy Inc. 2021 Long Term Incentive Plan (the “2021 LTIP”), which had previously been approved by the board of directors of the Company. No further awards will be granted under the Talos Energy Inc. Long Term Incentive Plan (the “2018 LTIP”).
The 2021 LTIP provides for potential grants of: (i) incentive stock options qualified as such under U.S. federal income tax laws (“ISOs”), (ii) stock options that do not qualify as ISOs (together with ISOs, “Options”), (iii) stock appreciation rights, (iv) restricted stock awards, (v) restricted stock units (the “RSUs”), (vi) awards of vested stock, (vii) dividend equivalents, (viii) other stock-based or cash awards and (ix) substitute awards (collectively, the “Awards”). Employees, non-employee directors and consultants of the Company and its affiliates are eligible to receive awards under the 2021 LTIP. The 2021 LTIP authorizes the Company to grant awards of up to
Restricted Stock Units —
|
RSUs |
|
Weighted Average |
|
||
Unvested RSUs at December 31, 2020 |
|
|
$ |
|
||
Granted |
|
|
$ |
|
||
Vested |
|
( |
) |
$ |
|
|
Forfeited |
|
( |
) |
$ |
|
|
Unvested RSUs at September 30, 2021(1) |
|
|
$ |
|
||
17
The Company considers its intent and ability to settle awards in cash or shares in determining whether to classify the awards as equity or as a liability. Certain awards granted during the nine months ended September 30, 2021 were originally classified as liability awards; however, these awards became equity-classified awards upon stockholder approval of the 2021 LTIP. The aggregate amount of compensation cost related to these awards is determined by the fair value of the award on the modification date.
Performance Share Units (“PSUs”) —
|
PSUs |
|
Weighted Average |
|
||
Unvested PSUs at December 31, 2020 |
|
|
$ |
|
||
Granted |
|
|
$ |
|
||
Vested |
|
( |
) |
$ |
|
|
Forfeited |
|
( |
) |
$ |
|
|
Unvested PSUs at September 30, 2021 |
|
|
$ |
|
||
|
Modification Date |
|
Grant Date |
|
||
|
May 11, 2021 |
|
March 8, 2021 |
|
||
Expected term (in years) |
|
|
|
|
||
Expected volatility |
|
% |
|
% |
||
Risk-free interest rate |
|
% |
|
% |
||
Dividend yield |
|
% |
|
% |
||
Fair value (in thousands) |
$ |
|
$ |
|
||
Share-based Compensation Costs
Share-based compensation costs associated with RSUs, PSUs and other awards 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 Sheets. 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 following table presents the amount of cost expensed and capitalized
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
|
||||||||
|
2021 |
|
2020 |
|
2021 |
|
2020 |
|
||||
Share-based compensation costs |
$ |
|
$ |
|
$ |
|
$ |
|
||||
Less: Amounts capitalized to oil and gas |
|
|
|
|
|
|
|
|
||||
Total share-based compensation expense |
$ |
|
$ |
|
$ |
|
$ |
|
||||
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, 2021, the Company recognized an income tax benefit of $
18
For the nine months ended September 30, 2021, the Company recognized income tax expense of $
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, 2021, the Company maintains a full valuation allowance for U.S. federal, state and foreign net 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 warrants expired unexercised on February 28, 2021.
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, |
|
||||||||
|
2021 |
|
2020 |
|
2021 |
|
2020 |
|
||||
Net loss |
$ |
( |
) |
$ |
( |
) |
$ |
( |
) |
$ |
( |
) |
|
|
|
|
|
|
|
|
|
||||
Weighted average common shares |
|
|
|
|
|
|
|
|
||||
Dilutive effect of securities |
|
|
|
|
|
|
|
|
||||
Weighted average common shares |
|
|
|
|
|
|
|
|
||||
|
|
|
|
|
|
|
|
|
||||
Net loss per common share: |
|
|
|
|
|
|
|
|
||||
Basic |
$ |
( |
) |
$ |
( |
) |
$ |
( |
) |
$ |
( |
) |
Diluted |
$ |
( |
) |
$ |
( |
) |
$ |
( |
) |
$ |
( |
) |
Anti-dilutive potentially issuable securities |
|
|
|
|
|
|
|
|
||||
19
N
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. Collectively, the Sponsors held
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. See additional details in Note 2 — Acquisitions.
Whistler Acquisition
On
Subsequent Event — During October 2021, the Company received the payment from an affiliate of Apollo Funds to satisfy the outstanding $
Equity Registration Rights Agreement
The Sponsors and Riverstone Sellers are parties to an amended registration rights agreement relating to the registered resale of the Company’s common stock owned by such parties, a discussion of which is included in the Notes to the Consolidated Financial Statements in the 2020 Annual Report.
The Company will bear all of the expenses incurred in connection with the offer and sale, while the selling stockholders will be responsible for paying underwriting fees, discounts and selling commissions. For the three and nine months ended September 30, 2021, fees incurred by the Company were
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”). A discussion of the Stockholders’ Agreement Amendment is included in the Notes to Consolidated Financial Statements in the 2020 Annual Report.
Legal Fees
The Company has engaged the law firm Vinson & Elkins L.L.P. ("V&E") 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 V&E. For the three and nine months ended September 30, 2021, the Company incurred fees of approximately $
20
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, 2021, the Company had secured performance bonds totaling approximately $
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.
Decommissioning Obligations
The Company has divested various leases, wells and facilities located in the U.S. Gulf of Mexico where the purchasers typically assume all abandonment obligations acquired. Certain of these counterparties in these divestiture transactions or third parties in existing leases have filed for bankruptcy protection or undergone associated reorganizations and may not be able to perform required abandonment obligations. Under certain circumstances, regulations or federal laws could require the Company to assume such obligations. During the three and nine months ended September 30, 2021, the Company recorded $
Although it is reasonably possible that the Company could receive state or federal decommissioning orders in the future or be notified of defaulting third parties in existing leases, the Company cannot predict with certainty, if, how or when such orders or notices will be resolved or estimate a possible loss or range of loss that may result from such orders. However, we could incur judgments, enter into settlements, or revise our opinion regarding the outcome of certain notices or matters, and such developments could have a material adverse effect on our results of operations in the period in which the amounts are accrued and our cash flows in the period in which the amounts are paid.
Note 12 — Subsequent Events
Whistler Acquisition
For additional information, see Note 10 — Related Party Transactions.
21
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. “Condensed Consolidated Financial Statements” of this Quarterly Report, as well as our audited Consolidated Financial Statements and the notes thereto in our 2020 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 2020 Annual Report.
Unless otherwise indicated or the context otherwise requires, references in this Quarterly Report to “us,” “we,” “our” or the “Company” are to Talos Energy Inc. and its wholly-owned subsidiaries.
Our Business
We are a technically driven independent exploration and production company focused on safely and efficiently maximizing long-term value through our operations, currently in the United States (“U.S.”) Gulf of Mexico and offshore Mexico both upstream through oil and gas exploration and production and downstream through the development of future carbon capture and storage opportunities. We leverage decades of technical and offshore operational expertise towards the acquisition, exploration and development of assets in key geological trends that are present in many offshore basins around the world. With a focus on environmental stewardship, we are also utilizing our expertise to explore opportunities to reduce industrial emissions through our carbon capture and storage collaborative arrangements along the U.S. Gulf Coast and Gulf of Mexico.
We have historically focused our operations in the U.S. 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.
Outlook
COVID-19 and Global Economic Environment — The ongoing COVID-19 pandemic that emerged at the beginning of 2020 has resulted in the reimplementation of travel and social distancing restrictions as well as border and office closures in the various countries in which we operate, and continues to impact some of our business operations. On March 11, 2021, President Biden signed the American Rescue Plan Act of 2021, which is the latest stimulus package aimed at mitigating the financial impact of the pandemic. Beginning June 1, 2021, based on the high vaccination rate of our employees, our entire corporate workforce returned to the office and our offshore employees returned to normal offshore rotations; however, we continue to actively monitor the ongoing situation with respect to any future containment measures which may result from the emergence of new strains or variants of COVID-19 and promote the safety and wellbeing of our employees. Working remotely did not significantly impact our ability to maintain operations, or caused us to incur significant additional expenses; however, we continue to evaluate the effect of COVID-19 on our business by, amongst other things, focusing on lower risk in-field drilling and development.
22
FERC Regulatory Matters — The Federal Energy Regulatory Commission (“FERC”) issued its Five-Year Review of the Oil Pipeline Index establishing an index level of Producer Price Index for Finished Goods ("PPI-FG") plus 0.78% on December 17, 2020 for the five-year period commencing July 1, 2021 ("December 2020 Order"). A number of parties requested rehearing of the December 2020 Order and these requests remain pending as a result of FERC’s February 18, 2021 order granting rehearing for further consideration. FERC published a revised oil pricing index factor on May 14, 2021, utilizing the pricing index factor established in the December 2020 Order, resulting in a negative percent change for the index year July 1, 2021 through June 30, 2022. A negative percent changes means that the ceiling level for certain oil pipelines’ rates may decrease and, if the actual transportation rate would be above such ceiling level, the rate also must decrease to be equal to or less than the applicable ceiling. Accordingly, on June 15, 2021, SP 49 Pipeline filed to reduce certain of its rates, effective July 1, 2021. FERC’s final application of its indexing rate methodology for the next five-year term of index rates will be determined based on the outcome of these requests for rehearing, and any changes to FERC's index level may impact our revenues associated with any transportation services we may provide pursuant to rates adjusted by the FERC oil pipeline index.
Outer Continental Shelf Regulation — With regard to President Biden’s issuance of an executive order in January 2021 mandating the suspension of new leasing activities for oil and gas exploration and production on federal lands and offshore waters pending review and reconsideration of federal oil and gas permitting and leasing practices, in June 2021, a federal judge issued a nationwide temporary injunction in a lawsuit filed in federal district court in Louisiana that effectively halts the Biden Administration’s suspension on new leasing. The Biden Administration has announced that it will comply with the judge's order while the decision is appealed, and has separately scheduled a GOM lease sale for certain blocks to occur in November 2021. Several nongovernmental organizations have filed a lawsuit against the Department of the Interior challenging the proposed sale, which currently remains pending.
SEC Climate Change Regulation — The SEC's Division of Corporation Finance issued a sample letter on September 22, 2021 to highlight its increased focus on climate change-related disclosures. A climate change disclosure rulemaking is on the SEC's near-term agenda, but no new rules have been proposed yet.
Recent Developments
Below is a cumulative list of significant developments that have occurred since the filing of our Quarterly Report on Form 10-Q for the period ended June 30, 2021.
TechnipFMC Strategic Alliance — In October 2021, we announced that we had entered into a long-term strategic alliance with TechnipFMC to develop and deliver technical and commercial solutions to Carbon Capture and Storage (“CCS”) projects along the United States Gulf Coast. Under the alliance, the companies intend to collaborate to progress CCS opportunities through the full lifecycle of storage site characterization, front-end engineering and design, and first injection through life of field operations.
Winning Bidder for Jefferson County Carbon Capture and Storage Site — In August 2021, we announced that, along with our partner Carbonvert, Inc., we were the successful bidder partnership for the Texas General Land Office's Jefferson County, Texas carbon storage site (the "Project Site") located near Beaumont and Port Arthur, Texas. The Project Site encompasses a total land area of over 40,000 gross acres and is located offshore in Texas state waters in the Gulf of Mexico. We expect it can ultimately sequester approximately 225 to 275 million metric tons of carbon dioxide from industrial sources in the area. The award provides us with a physical project site dedicated to carbon sequestration and storage. We are designated as the operator of this project.
Bank Credit Facility — On August 2, 2021, we announced the addition of a new lender to our Bank Credit Facility (as defined below under "Liquidity and Capital Resources — Overview of Debt Instruments"). See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 6 — Debt” for more information.
Zama Update — On July 2, 2021, we were notified by Mexico’s Ministry of Energy ("SENER") that it had designated Petróleos Mexicanos ("PEMEX") as the operator of the Zama unit, just three days after SENER received a letter directly from PEMEX arguing for operatorship. Such designation may potentially result in material delays, underperformance, insufficient access to capital or adverse consequences as compared to our expectations for such project should we have been designated as operator. The Block 7 partners and PEMEX had engaged a third-party reservoir engineering firm to evaluate initial tract participation within the Zama reservoir, which concluded that the Block 7 consortium led by us holds 49.6% of the gross interest in Zama and PEMEX holds 50.4%.
23
On September 3, 2021, we announced our submission of notices of dispute (the "Notices of Dispute") to the Government of Mexico over decisions taken by SENER, including the designation of PEMEX as the operator of a yet-to-be unitized asset. The actions taken by SENER constitute violations of the Agreement between the United States of America, the United Mexican States and Canada and the Bilateral Investment Treaty between the United Mexican States and the Belgo-Luxembourg Economic Union. We will continue to engage in good faith with the institutionally appointed representatives of the Government of Mexico by seeking to achieve a fair and mutually beneficial agreement.
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.
LLOG Properties Acquisition — On November 16, 2020, we completed the acquisition of select interests in oil and natural gas assets from LLOG Exploration & Production Company, LLC (the “LLOG Acquisition”). A discussion of the LLOG Acquisition is included the Notes to Consolidated Financial Statements in the 2020 Annual Report.
Castex Energy 2005 Acquisition — On August 5, 2020, we completed the acquisition of select oil and natural gas assets from affiliates of Castex Energy 2005 Holdco, LLC (the “Castex 2005 Acquisition”). See 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 with the entities controlled by or affiliated with Riverstone Energy Partners V, L.P. (the “Riverstone Sellers”), and Castex Energy 2016, LP (together with the Riverstone Sellers, the “Sellers” and collectively, the “ILX and Castex Acquisition”). See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 2 — Acquisitions” for more information.
Hurricanes and Tropical Storms — During the third quarter of 2021, production from the U.S. Gulf of Mexico was impacted due to Hurricane Ida. While our assets did not sustain significant damage, the storm impacted key third-party downstream infrastructure, which prevented us from restoring the majority of our production for several weeks. For the three and nine months ended September 30, 2021, we estimate that deferred production related to this storm was approximately 12.7 MBoepd and 4.3 MBoepd, respectively, based on production rates prior to the storm. As of October 31, 2021, we still have approximately 3.8 MBoepd of production offline due to the continued impact of Hurricane Ida.
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 3.3 MBoepd, respectively, based on production rates prior to the storms.
Ram Powell Shut-In — Production at our Ram Powell facility was shut-in in late June 2020 while waiting for the repair of the platform’s oil export riser. We received final regulatory approvals and completed the repair of the export riser. Production commenced on November 21, 2020. For 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.
Known Trends and Uncertainties
See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2020 Annual Report for a detailed discussion of known trends and uncertainties. The following carries forward or provides an update to known trends and uncertainties discussed in our 2020 Annual Report.
Volatility in Oil, Natural Gas and NGL Prices — Historically, the markets for oil and natural gas have been volatile. Oil, natural gas and NGL prices are subject to wide fluctuations in supply and demand. 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.
24
In 2020, OPEC and certain non-OPEC producers (“OPEC Plus”) agreed to production cuts intended to stabilize and support commodity prices, which resulted in cutting production by a record 9.7 million barrels per day starting on May 1, 2020 but was subsequently scaled back to 7.7 million barrels per day from August 1, 2020 through December 2020. On December 3, 2020, OPEC Plus agreed to increase production by 500,000 barrels per day beginning in January 2021 bringing the total production cuts to 7.2 million barrels per day. In January 2021, Saudi Arabia pledged 1.0 million barrels per day of voluntary cuts during February and March 2021. On March 4, 2021, OPEC Plus agreed to increase production by 150,000 barrels per day beginning in April 2021 and Saudi Arabia extended its one million barrels per day voluntary production cut into April 2021. At the April 1, 2021 meeting, OPEC Plus agreed to ease production cuts by 1.2 million barrels per day over a three month period starting May 1, 2021 through July 31, 2021, reducing the total production cuts to 5.8 million barrels per day. Moreover, Saudi Arabia decided to roll back its 1.0 million barrels per day of voluntary cuts over this same period. On July 18, 2021, OPEC Plus reached an agreement that will allow its members to collectively increase production by 400,000 barrels per day each month beginning August 2021 until phasing out the 5.8 million barrels per day and to reassess market developments in December 2021.
Oil prices have benefited from the continuation of coordinated production policies by OPEC Plus and capital discipline by oil and gas producers. Despite the recent upswing in oil prices, we believe that commodity prices will remain cyclical and volatile. We developed a flexible fiscal year 2021 capital spending budget that is within projected operating cash flows and does not require any long-term commitments. During January 1, 2021 through September 30, 2021, the daily spot prices for NYMEX WTI crude oil ranged from a high of $75.54 per Bbl to a low of $47.47 per Bbl and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $23.86 per MMBtu to a low of $2.43 per MMBtu. The spread between the high and low natural gas prices was caused by a severe winter storm that precipitated both an immediate constraint in the supply of and a significant increase in the demand for natural gas. Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of production. From time to time, we may hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 5 — Financial Instruments” for more additional information regarding our commodity derivative positions as of September 30, 2021.
Impairment of Oil and Natural Gas Properties — Under the full cost method of accounting, the “ceiling test” under SEC rules and regulations specifies that evaluated and unevaluated properties’ capitalized costs, less accumulated amortization and related deferred income taxes (the “Full Cost Pool”), should be compared to a formulaic limitation (the “Ceiling”) each quarter on a country-by-country basis. If the Full Cost Pool exceeds the Ceiling, an impairment must be recorded. For the three and nine months ended September 30, 2021 and 2020, we did not recognize an impairment based on the ceiling test computations. At September 30, 2021 our ceiling test computation was based on SEC pricing of $58.25 per Bbl of oil, $3.02 per Mcf of natural gas and $20.75 per Bbl of NGLs.
There is a significant degree of uncertainty with the assumptions used to estimate the present value of future net cash flows from estimated production of proved oil and gas reserves due to, but not limited to the risk factors referred to in Part I, Item 1A. “Risk Factors” included in our 2020 Annual Report. The discounted present value of our proved reserves is a major component of the Ceiling calculation. Any decrease in pricing, negative change in price differentials or increase in capital or operating costs could negatively impact the estimated future discounted net cash flows related to our proved oil and natural gas properties.
With respect to our operations in Mexico, our oil and natural gas properties are classified as unproved properties, not subject to amortization. The finalization of the Unitization and Unit Operating Agreement, which sets out the terms on which the reservoir will be jointly developed, and the outcome of the dispute with the Government of Mexico over decisions taken by SENER with respect to the Zama discovery could adversely affect the value of the oil and natural gas assets and result in an impairment of our unevaluated oil and gas properties prior to reaching a final investment decision or of our evaluated properties upon reaching a final investment decision.
Third Party Planned Downtime — Since our operations are offshore, we are vulnerable to third party downtime events impacting the transportation, gathering and processing of production. We produce the Phoenix Field through the Helix Producer I (the “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. The next dry-dock is scheduled for mid-2022 with an estimated shut-in lasting approximately 45 days.
25
BOEM Bonding Requirements — In 2016, the BOEM issued the 2016 Notice to Lessees and Operators (“NTL”), which bolstered supplemental bonding requirements. The NTL was not fully implemented as the BOEM under the Trump Administration first paused, and then in 2020 rescinded, this NTL. The BOEM and BSEE issued a jointly proposed rulemaking in October 2020 in which the BOEM proposed amendments to its financial assurance program. The proposed rule was significantly less stringent with respect to financial assurance than 2016 NTL. To date, however, a final rule has not issued.
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 implementation of a new NTL analogous to the 2016 NTL, or the October 2020 proposed rule, to the extent finalized, as well as to the provisions of any other new, more stringent NTLs or final rules on supplemental bonding published by the BOEM under the Biden Administration, could materially and adversely affect our financial condition, cash flows and results of operations. Moreover, the BOEM has the right to issue liability orders in the future, including if it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities and the Biden Administration may elect to pursue more stringent supplemental bonding requirements.
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 the BSEE 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 and Tropical Storms — Since our operations are in the U.S. Gulf of Mexico, we are particularly vulnerable to the effects of hurricanes and tropical storms on production and capital projects. Significant 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:
26
Results of Operations
Revenue and Other
The information below provides a discussion of, and an analysis of significant variances in, our oil, natural gas and NGL revenues, production volumes and sales prices (in thousands):
|
Three Months Ended September 30, |
|
|
|
Nine Months Ended September 30, |
|
|
|
||||||||||
|
2021 |
|
2020 |
|
Change |
|
2021 |
|
2020 |
|
Change |
|
||||||
Revenues and other: |
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Oil |
$ |
246,208 |
|
$ |
117,190 |
|
$ |
129,018 |
|
$ |
743,759 |
|
$ |
358,285 |
|
$ |
385,474 |
|
Natural gas |
|
31,723 |
|
|
12,337 |
|
|
19,386 |
|
|
86,088 |
|
|
35,375 |
|
|
50,713 |
|
NGL |
|
12,978 |
|
|
3,409 |
|
|
9,569 |
|
|
31,738 |
|
|
9,674 |
|
|
22,064 |
|
Other |
|
— |
|
|
2,201 |
|
|
(2,201 |
) |
|
1,000 |
|
|
8,441 |
|
|
(7,441 |
) |
Total revenues and other |
$ |
290,909 |
|
$ |
135,137 |
|
$ |
155,772 |
|
$ |
862,585 |
|
$ |
411,775 |
|
$ |
450,810 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Total Production Volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Oil (MBbls) |
|
3,609 |
|
|
3,005 |
|
|
604 |
|
|
11,827 |
|
|
10,010 |
|
|
1,817 |
|
Natural gas (MMcf) |
|
6,975 |
|
|
6,922 |
|
|
53 |
|
|
24,055 |
|
|
20,961 |
|
|
3,094 |
|
NGL (MBbls) |
|
429 |
|
|
311 |
|
|
118 |
|
|
1,344 |
|
|
1,028 |
|
|
316 |
|
Total production volume (MBoe) |
|
5,200 |
|
|
4,470 |
|
|
730 |
|
|
17,180 |
|
|
14,532 |
|
|
2,648 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Daily Production Volumes by |
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Oil (MBblpd) |
|
39.2 |
|
|
32.7 |
|
|
6.5 |
|
|
43.3 |
|
|
36.5 |
|
|
6.8 |
|
Natural gas (MMcfpd) |
|
75.8 |
|
|
75.2 |
|
|
0.6 |
|
|
88.1 |
|
|
76.5 |
|
|
11.6 |
|
NGL (MBblpd) |
|
4.7 |
|
|
3.4 |
|
|
1.3 |
|
|
4.9 |
|
|
3.8 |
|
|
1.1 |
|
Total production volume (MBoepd) |
|
56.5 |
|
|
48.6 |
|
|
7.9 |
|
|
62.9 |
|
|
53.0 |
|
|
9.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Average Sale Price Per Unit: |
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Oil (per Bbl) |
$ |
68.22 |
|
$ |
39.00 |
|
$ |
29.22 |
|
$ |
62.89 |
|
$ |
35.79 |
|
$ |
27.10 |
|
Natural gas (per Mcf) |
$ |
4.55 |
|
$ |
1.78 |
|
$ |
2.77 |
|
$ |
3.58 |
|
$ |
1.69 |
|
$ |
1.89 |
|
NGL (per Bbl) |
$ |
30.25 |
|
$ |
10.96 |
|
$ |
19.29 |
|
$ |
23.61 |
|
$ |
9.41 |
|
$ |
14.20 |
|
Price per Boe |
$ |
55.94 |
|
$ |
29.74 |
|
$ |
26.20 |
|
$ |
50.15 |
|
$ |
27.75 |
|
$ |
22.40 |
|
Price per Boe (including realized |
$ |
42.17 |
|
$ |
34.00 |
|
$ |
8.17 |
|
$ |
39.13 |
|
$ |
37.49 |
|
$ |
1.64 |
|
The information below provides an analysis of the change in our oil, natural gas and NGL revenues due to changes in sale prices and production volumes (in thousands):
|
Three Months Ended |
|
Nine Months Ended |
|
||||||||||||||
|
Price |
|
Volume |
|
Total |
|
Price |
|
Volume |
|
Total |
|
||||||
Oil |
$ |
105,462 |
|
$ |
23,556 |
|
$ |
129,018 |
|
$ |
320,444 |
|
$ |
65,030 |
|
$ |
385,474 |
|
Natural gas |
|
19,292 |
|
|
94 |
|
|
19,386 |
|
|
45,484 |
|
|
5,229 |
|
|
50,713 |
|
NGL |
|
8,276 |
|
|
1,293 |
|
|
9,569 |
|
|
19,090 |
|
|
2,974 |
|
|
22,064 |
|
Total revenues |
$ |
133,030 |
|
$ |
24,943 |
|
$ |
157,973 |
|
$ |
385,018 |
|
$ |
73,233 |
|
$ |
458,251 |
|
Three Months Ended September 30, 2021 and 2020 Volumetric Analysis — Production volumes increased by 7.9 MBoepd to 56.5 MBoepd. The increase in production volumes was an increase of 5.9 MBoepd from the Green Canyon 18 Field, primarily due to the Kaleidoscope and Tokum wells drilled as part of the Green Canyon 18 Field platform rig program. Additionally, production volumes increased 4.9 MBoepd from temporary shut-ins for repairs and maintenance on the Ram Powell Field export riser during the third quarter of 2020. The increase was partially offset by a decrease in production of 4.1 MBoepd from disruptions from weather events in the U.S. Gulf of Mexico when compared to the same period in 2020.
27
Nine Months Ended September 30, 2021 and 2020 Volumetric Analysis — Production volumes increased by 9.9 MBoepd to 62.9 MBoepd. The increase in production volumes was attributable to 6.4 MBoepd from temporary downtime as a result of repairs and maintenance that occurred in 2020 and 5.6 MBoepd from the Green Canyon 18 Field, primarily attributable to the Kaleidoscope and Tokum wells drilled as part of the Green Canyon 18 Field platform rig program. The increase was partially offset by a decrease in production of 1.0 MBoepd from disruptions from weather events in the U.S. Gulf of Mexico when compared to the same period in 2020.
Operating 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 (in thousands, except per Boe data):
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
|
||||||||
|
2021 |
|
2020 |
|
2021 |
|
2020 |
|
||||
Lease operating expenses |
$ |
70,034 |
|
$ |
62,064 |
|
$ |
208,675 |
|
$ |
184,187 |
|
Lease operating expenses per Boe |
$ |
13.47 |
|
$ |
13.88 |
|
$ |
12.15 |
|
$ |
12.67 |
|
Three Months Ended September 30, 2021 and 2020 — Total lease operating expense for the three months ended September 30, 2021 increased by approximately $8.0 million, or 13%. This increase was primarily related to an increase in lease operating expenses of $2.0 million incurred in connection with assets acquired in the Castex 2005 Acquisition and LLOG Acquisition when compared to the same period in 2020. Additionally, there was an overall increase in direct operating expenses and labor costs primarily due to the temporary shuttering of certain Shelf fields and cost cutting measures taken during third quarter of 2020 as a result of the economic environment caused by the COVID-19 pandemic. On a per unit basis, lease operating expense decreased $0.41 per Boe to $13.47 per Boe primarily as a result of higher production.
Nine Months Ended September 30, 2021 and 2020 — Total lease operating expense for the nine months ended September 30, 2021 increased by approximately $24.5 million, or 13%. This increase was primarily related to an increase in lease operating expenses of $11.6 million incurred in connection with assets acquired in the Castex 2005 Acquisition and LLOG Acquisition when compared to the same period in 2020. Hurricane related repairs increased $4.3 million due to Hurricane Ida and ongoing repairs for 2020 named storms in the first half of 2021. Further, there was an increase in workover expense of $10.6 million primarily related to South Marsh Island 130 Field, non-operated deepwater Marmalard Field and Amberjack Fields. On a per unit basis, lease operating expense decreased $0.52 per Boe to $12.15 per Boe primarily as a result of higher production.
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 (in thousands, except per Boe data):
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
|
||||||||
|
2021 |
|
2020 |
|
2021 |
|
2020 |
|
||||
Depreciation, depletion and amortization |
$ |
88,596 |
|
$ |
80,547 |
|
$ |
290,094 |
|
$ |
262,533 |
|
Depreciation, depletion and amortization per Boe |
$ |
17.04 |
|
$ |
18.02 |
|
$ |
16.89 |
|
$ |
18.07 |
|
Three Months Ended September 30, 2021 and 2020 — Depreciation, depletion and amortization expense for the three months ended September 30, 2021 increased by approximately $8.0 million, or 10%. This increase was primarily due to increased production of 7.9 MBoepd partially offset by a decrease of $0.91 per Boe, or 5% in the depletion rate on our proved oil and natural gas properties as a result of the impairment on oil and gas properties in the fourth quarter of 2020.
Nine Months Ended September 30, 2021 and 2020 — Depreciation, depletion and amortization expense for the nine months ended September 30, 2021 increased by approximately $27.6 million, or 10%. This increase was primarily due to increased production of 9.9 MBoepd offset by a decrease of $1.14 per Boe, or 6% in the depletion rate on our proved oil and natural gas properties as a result of the impairment on oil and gas properties in the fourth quarter of 2020.
28
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 (in thousands, except per Boe data):
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
|
||||||||
|
2021 |
|
2020 |
|
2021 |
|
2020 |
|
||||
General and administrative expense |
$ |
20,427 |
|
$ |
17,823 |
|
$ |
58,993 |
|
$ |
62,484 |
|
General and administrative expense per Boe |
$ |
3.93 |
|
$ |
3.99 |
|
$ |
3.43 |
|
$ |
4.30 |
|
Three Months Ended September 30, 2021 and 2020 — General and administrative expense for the three months ended September 30, 2021 increased by approximately $2.6 million, or 15%, which was primarily related to increased employee and contract labor costs.
Nine Months Ended September 30, 2021 and 2020 — General and administrative expense for the nine months ended September 30, 2021 decreased by approximately $3.5 million, or 6%. Transaction and non-recurring expenses were $4.8 million, or $0.28 per Boe, for the nine months ended September 30, 2021, which is a decrease of $8.1 million primarily due to the ILX and Castex Acquisition that occurred in the first quarter of 2020. This decrease was partially offset by increased employee and contract labor costs. General and administrative expense includes non-cash equity-based compensation of $8.3 million, or $0.48 per Boe, for the nine months ended September 30, 2021, which is an increase of $2.0 million.
Miscellaneous
The following table highlights miscellaneous items in total. The information below provides the financial results and an analysis of significant variances in these results (in thousands):
|
Three Months Ended September 30, |
|
Nine Months Ended September 30, |
|
||||||||
|
2021 |
|
2020 |
|
2021 |
|
2020 |
|
||||
Write-down of oil and natural gas properties |
$ |
— |
|
$ |
— |
|
$ |
— |
|
$ |
57 |
|
Accretion expense |
$ |
13,668 |
|
$ |
11,537 |
|
$ |
44,110 |
|
$ |
37,748 |
|
Other operating expense |
$ |
5,081 |
|
$ |
— |
|
$ |
7,864 |
|
$ |
— |
|
Interest expense |
$ |
32,390 |
|
$ |
24,124 |
|
$ |
100,036 |
|
$ |
76,164 |
|
Price risk management activities (income) |
$ |
81,479 |
|
$ |
19,882 |
|
$ |
405,604 |
|
$ |
(154,653 |
) |
Other (income) expense |
$ |
(4,475 |
) |
$ |
(813 |
) |
$ |
7,916 |
|
$ |
(139 |
) |
Income tax (benefit) expense |
$ |
(364 |
) |
$ |
(28,252 |
) |
$ |
718 |
|
$ |
(22,384 |
) |
Three Months Ended September 30, 2021 and 2020 —
Interest Expense — During the three months ended September 30, 2021, we recorded $32.4 million of interest expense compared to $24.1 million during the three months ended September 30, 2020. The change is primarily a result of the interest associated with the 12.00% Notes (as defined below under “Liquidity and Capital Resources — Overview of Debt Instruments”) issued in January 2021 with an aggregate principal amount of $650.0 million when compared to the interest on the 11.00% Notes (as defined below under “Liquidity and Capital Resources — Overview of Debt Instruments”) that were redeemed in January 2021. See further discussion in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 6 — Debt.”
Other operating expense — During the three months ended September 30, 2021, we recorded $4.1 million of estimated decommissioning obligations primarily as a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 11 — Commitments and Contingencies.”
29
Price risk management activities — Price risk management activities for the three months ended September 30, 2021 decreased by approximately $61.6 million, or 310%. The expense of $81.5 million for the three months ended September 30, 2021 consists of $71.6 million in cash settlement losses and $9.8 million in non-cash losses from the decrease in the fair value of our open derivative contracts. 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 partially offset by $19.0 million in cash settlement gains. These unrealized gains or losses on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on our Condensed Consolidated Statements of Operations at the end of each month. As a result of the derivative contracts we have on our anticipated production volumes through June 2023, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 5 — Financial Instruments.”
Other (income) expense — During the three months ended September 30, 2021 we recorded a $4.4 million gain as a result of the settlement related to the Whistler Acquisition that is further discussed in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 10 — Related Party Transactions.”
Income tax (benefit) expense — During the three months ended September 30, 2021, we recorded $0.4 million of income tax benefit compared to $28.3 million of income tax benefit during the three months ended September 30, 2020. The change is primarily a result of recording a valuation allowance on our deferred tax assets. The realization of our deferred tax asset depends on recognition of sufficient future taxable income in specific tax jurisdictions in which temporary differences or net operating losses relate. In assessing the need for a valuation allowance, we consider whether it is more likely than not that some portion of all of the deferred tax assets will not be realized. See additional information on the valuation allowance as described in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 8 — Income Taxes.”
Nine Months Ended September 30, 2021 and 2020 —
Interest Expense — During the nine months ended September 30, 2021, we recorded $100.0 million of interest expense compared to $76.2 million during the nine months ended September 30, 2020. The change is primarily a result of the interest associated with the 12.00% Notes issued in January 2021 with an aggregate principal amount of $650.0 million when compared to the interest on the 11.00% Notes that were redeemed in January 2021. See further discussion in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 6 — Debt.”
Other operating expense — During the nine months ended September 30, 2021, we recorded $6.9 million of estimated decommissioning obligations primarily as a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 11 — Commitments and Contingencies.”
Price risk management activities — Price risk management activities for the nine months ended September 30, 2021 decreased by approximately $560.3 million, or 362%. The expense of $405.6 million for the nine months ended September 30, 2021 consists of $216.4 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $189.3 million in cash settlement losses. 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. These unrealized gains or losses on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on our Condensed Consolidated Statements of Operations at the end of each month. As a result of the derivative contracts we have on our anticipated production volumes through June 2023, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 5 — Financial Instruments.”
Other (income) expense — During the nine months ended September 30, 2021, we recorded a $13.2 million loss on extinguishment of debt as a result of the redemption of the 11.00% Notes further discussed in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 6 — Debt.” This was partially offset by a $4.4 million gain as a result of the settlement related to the Whistler Acquisition that is further discussed in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 10 — Related Party Transactions.”
30
Income tax (benefit) expense — During the nine months ended September 30, 2021, we recorded $0.7 million of income tax expense compared to $22.4 million of income tax benefit during the nine months ended September 30, 2020. The change is primarily a result of recording a valuation allowance on our deferred tax assets as of December 31, 2020. The realization of our deferred tax asset depends on recognition of sufficient future taxable income in specific tax jurisdictions in which temporary differences or net operating losses relate. In assessing the need for a valuation allowance, we consider whether it is more likely than not that some portion of all of the deferred tax assets will not be realized. See additional information on the valuation allowance as described in Part I, Item 1. “Condensed Consolidated Financial Statements — Note 8 — Income Taxes.”
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 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:
31
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, |
|
||||||||
|
2021 |
|
2020 |
|
2021 |
|
2020 |
|
||||
Reconciliation of net loss to Adjusted EBITDA: |
|
|
|
|
|
|
|
|
||||
Net loss |
$ |
(16,691 |
) |
$ |
(52,000 |
) |
$ |
(263,964 |
) |
$ |
(34,862 |
) |
Interest expense |
|
32,390 |
|
|
24,124 |
|
|
100,036 |
|
|
76,164 |
|
Income tax (benefit) expense |
|
(364 |
) |
|
(28,252 |
) |
|
718 |
|
|
(22,384 |
) |
Depreciation, depletion and amortization |
|
88,596 |
|
|
80,547 |
|
|
290,094 |
|
|
262,533 |
|
Accretion expense |
|
13,668 |
|
|
11,537 |
|
|
44,110 |
|
|
37,748 |
|
EBITDA |
|
117,599 |
|
|
35,956 |
|
|
170,994 |
|
|
319,199 |
|
Write-down of oil and natural gas properties |
|
— |
|
|
— |
|
|
— |
|
|
57 |
|
Transaction and non-recurring expense(1) |
|
1,370 |
|
|
1,607 |
|
|
7,231 |
|
|
12,863 |
|
Derivative fair value (gain) loss(2) |
|
81,479 |
|
|
19,882 |
|
|
405,604 |
|
|
(154,653 |
) |
Net cash received (paid) on settled |
|
(71,634 |
) |
|
19,030 |
|
|
(189,252 |
) |
|
141,529 |
|
(Gain) loss on extinguishment of debt |
|
— |
|
|
(174 |
) |
|
13,225 |
|
|
(1,644 |
) |
Non-cash write-down of other well |
|
— |
|
|
— |
|
|
— |
|
|
133 |
|
Non-cash equity-based compensation |
|
2,613 |
|
|
2,347 |
|
|
8,294 |
|
|
6,321 |
|
Adjusted EBITDA |
$ |
131,427 |
|
$ |
78,648 |
|
$ |
416,096 |
|
$ |
323,805 |
|
Liquidity and Capital Resources
Our primary sources of liquidity are cash generated by our operations and borrowings under our Bank Credit Facility. Our primary uses of cash are for capital expenditures, working capital, debt service and for general corporate purposes. Our working capital deficit has increased since December 31, 2020 primarily due to an increase of $182.4 million in liabilities from price risk management activities. As of September 30, 2021, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $375.9 million.
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, 2021 (in thousands):
U.S. drilling & completions |
$ |
115,391 |
|
Mexico appraisal & exploration |
|
777 |
|
Asset management |
|
62,015 |
|
Seismic and G&G, land, capitalized G&A and other |
|
38,366 |
|
Total capital expenditures |
|
216,549 |
|
Plugging & abandonment |
|
58,001 |
|
Total capital expenditures and plugging & abandonment |
$ |
274,550 |
|
32
Based on our current level of operations and available cash, we believe our cash flows from operations, combined with availability under the Bank Credit Facility, provide sufficient liquidity to fund the remainder of our board approved 2021 capital spending program of $340.0 million to $370.0 million and our working capital deficit. 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.
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, |
|
||||
|
2021 |
|
2020 |
|
||
Operating activities |
$ |
287,648 |
|
$ |
262,067 |
|
Investing activities |
$ |
(212,153 |
) |
$ |
(585,152 |
) |
Financing activities |
$ |
(50,301 |
) |
$ |
268,440 |
|
Operating Activities — Net cash provided by operating activities increased $25.6 million in the nine months ended September 30, 2021 compared to the corresponding period in 2020 primarily attributable to an increase in revenues net of lease operating expense of $426.3 million. This was offset by an increase in cash payments on derivative instruments of $330.8 million, interest expense of $23.9 million and settlements of asset retirement obligations of $23.5 million.
Investing Activities — Net cash used in investing activities decreased $373.0 million in the nine months ended September 30, 2021 compared to the corresponding period in 2020 primarily due to a decrease in payments for acquisitions of $299.5 million and a decrease in capital expenditures of $68.7 million.
Financing Activities — Cash flow from financing activities decreased $318.7 million in the nine months ended September 30, 2021 compared to the corresponding period in 2020. During the nine months ended September 30, 2020, net proceeds of $300.0 million were received from the Bank Credit Facility and used primarily to fund the ILX and Castex Acquisition in the first quarter of 2020. During the nine months ended September 30, 2021, the issuance of the 12.00% Notes in January 2021 generated $579.4 million after original discount and deferred financing costs. The net proceeds from the 12.00% Notes funded the $356.8 million redemption of the 11.00% Notes and reduced the indebtedness under the Bank Credit Facility by $175.0 million in the first quarter of 2021. Indebtedness under the Bank Credit Facility was then further reduced by $65.0 million.
Overview of Debt Instruments
Bank Credit Facility — matures November 2024 — We maintain a Bank Credit Facility with a syndicate of financial institutions (the “Bank Credit Facility”). 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. On August 2, 2021, an additional lender was added to the syndicate which increased commitments from $655.0 million to $730.0 million. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 6 — Debt” for more information.
33
12.00% Second-Priority Senior Secured Notes—due January 2026 — The 12.00% Second-Priority Senior Secured Notes (the “12.00% Notes”) were issued pursuant to an indenture dated January 4, 2021 and the first supplemental indenture dated January 14, 2021 between Talos Energy Inc. (the "Parent Guarantor"), Talos Production Inc. (“Issuer”), and the Subsidiary Guarantors (as defined below) and Wilmington Trust, National Association, as trustee and collateral agent. The 12.00% Notes rank pari passu in right of payment and constitute a single class of securities for all purposes under the indentures. The 12.00% Notes are secured on a second-priority basis by liens on substantially the same collateral as the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 12.00% Notes mature on January 15, 2026 and have interest payable semi-annually each January 15 and July 15, commencing on July 15, 2021. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 6 — Debt” for more information.
Redemption of the 11.00% Second-Priority Senior Secured Notes—due April 2022 — On January 13, 2021, we redeemed the 11.00% Second-Priority Senior Secured Notes (the “11.00% Notes”) using the proceeds from the issuance of 12.00% Notes. See Part I, Item 1. “Condensed Consolidated Financial Statements — Note 6 — Debt” for more information.
Guarantor Financial Information — Talos owns no operating assets and has no operations independent of its subsidiaries. The 12.00% Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by the Parent Guarantor and on a second-priority senior secured basis by each of the Issuer’s present and future direct or indirect wholly owned material domestic subsidiaries (collectively, the “Subsidiary Guarantors” and, together with the Parent Guarantor, the “Guarantors”) that guarantees the Issuer’s senior reserve-based revolving credit facility. Our non-domestic subsidiaries (the “Non-Guarantors”) are 100% owned by Talos but do not guarantee the 12.00% Notes.
In lieu of providing separate financial statements for the Issuer and the Guarantors, we have presented the accompanying supplemental summarized combined balance sheet and income statement information for the Issuer and the 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, 2021 |
|
December 31, 2020 |
|
||
Current assets |
$ |
246,199 |
|
$ |
231,669 |
|
Non-current assets |
|
2,384,660 |
|
|
2,444,886 |
|
Total assets |
$ |
2,630,859 |
|
$ |
2,676,555 |
|
|
|
|
|
|
||
Current liabilities |
$ |
633,368 |
|
$ |
438,340 |
|
Non-current liabilities |
|
1,475,365 |
|
|
1,459,816 |
|
Talos Energy Inc. stockholdersʼ equity |
|
522,126 |
|
|
778,399 |
|
Total liabilities and stockholdersʼ equity |
$ |
2,630,859 |
|
$ |
2,676,555 |
|
The following table presents the income statement information (in thousands):
|
Nine Months Ended |
|
|
Revenues and other |
$ |
862,585 |
|
Costs and expenses |
|
(1,122,621 |
) |
Net loss |
$ |
(260,036 |
) |
34
Contractual Obligations
We have various contractual obligations in the normal course of our operations. There have been no material changes to our contractual obligations since those reported in our 2020 Annual Report except:
Performance Bonds — As of September 30, 2021, 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 $810.6 million.
See “Known Trends and Uncertainties — BOEM Bonding Requirements” under Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Quarterly Report for additional information on the future cost of compliance with respect to BOEM supplemental bonding requirements that could have a material adverse effect on our business, properties, results of operations and financial condition.
Off Balance Sheet Arrangements
We did not have any off-balance sheet arrangements as of September 30, 2021.
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 and 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 2020 Annual Report.
Recently Adopted Accounting Standards
None.
Recently Issued Accounting Standards
There was no recently issued accounting standards material to us.
35
Item 3. Quantitative and Qualitative Disclosures About Market Risk
For information regarding our exposures to certain market risks, refer to Part II, Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” in our 2020 Annual Report. Except as disclosed in this Quarterly Report, there have been no material changes from the disclosures presented in our 2020 Annual Report regarding our exposures to certain market risks.
Item 4. Controls and Procedures
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, 2021.
Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during the quarter ended September 30, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
36
PART II – OTHER INFORMATION
Item 1. Legal Proceedings
On May 29, 2020, a lawsuit was filed in the Delaware Court of Chancery asserting derivative and class action claims against us relating to the ILX and Castex Acquisition (as previously defined in this Quarterly Report). Specifically, the lawsuit, among other things, related to the fairness of the consideration paid for such acquisitions in light of the fact that certain of the sellers were affiliates of Riverstone Energy Partners V, L.P. The lawsuit was dismissed during the third quarter of 2021, and the plaintiffs have appealed the dismissal to the Delaware Supreme Court.
There have been no additional material developments with respect to the information previously reported under Part I, Item 3. “Legal Proceedings” of our 2020 Annual Report.
Item 1A. Risk Factors
In addition to the other information set forth in this Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under Part I, Item 1A. “Risk Factors” included in our 2020 Annual Report and the risk factors and other cautionary statements contained in our other SEC filings, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. There have been no material changes in our risk factors from those described in our 2020 Annual Report or our other SEC filings.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
Not applicable.
Item 5. Other Information
None.
37
Item 6. Exhibits
Exhibit Number |
|
Description |
|
|
|
2.1# |
|
|
|
|
|
2.2 |
|
|
|
|
|
2.3# |
|
|
|
|
|
2.4 |
|
|
|
|
|
2.5# |
|
|
|
|
|
2.6 |
|
|
|
|
|
2.7# |
|
|
|
|
|
2.8 |
|
|
|
|
|
2.9# |
|
|
|
|
|
3.1 |
|
|
|
|
|
3.2 |
|
|
|
|
|
3.3 |
|
|
|
|
|
4.1
|
|
|
|
|
|
4.2 |
|
|
|
|
|
38
4.3 |
|
|
|
|
|
10.1* |
|
|
|
|
|
22.1 |
|
|
|
|
|
31.1* |
|
|
|
|
|
31.2* |
|
|
|
|
|
32.1** |
|
|
|
|
|
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. |
|
|
|
104* |
|
Cover Page Interactive Date File (Embedded within the Inline XBRL document and included in Exhibit 101). |
|
|
|
* Filed herewith.
** Furnished herewith.
# 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.
39
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 3, 2021 |
By: |
/s/ Shannon E. Young III |
|
|
|
Shannon E. Young III |
|
|
|
Executive Vice President and Chief Financial Officer |
40