Talos Energy Announces First Quarter 2022 Operational and Financial Results and Increased Borrowing Base Under RBL Facility

Rhea-AI Summary

Talos Energy (NYSE: TALO) reported Q1 2022 results with production of 63.2 MBoe/d, generating $413.6 million in revenue. Despite experiencing 40 days of unplanned downtime, the company achieved a net loss of $66.4 million and adjusted net income of $64.0 million. Talos' adjusted EBITDA stood at $208.2 million. The company increased its borrowing base to $1.1 billion and maintained liquidity of $516.1 million. Talos aims to reduce net debt to 1.0x by year-end. The company also expanded its Carbon Capture ventures, including a partnership with Chevron.

Positive

• Increased production to 63.2 MBoe/d despite downtime.
• Reported free cash flow of $92 million in Q1.
• Successful semi-annual borrowing base increase to $1.1 billion.
• Significant expansion in Carbon Capture ventures, including partnership with Chevron.

Negative

• Net loss of $66.4 million for the quarter.
• Unplanned downtime of approximately 40 days impacted production.
• Expecting planned downtime of 4.5 - 5.0 MBoe/d in Q2 2022.

HOUSTON, May 4, 2022 /PRNewswire/ -- Talos Energy Inc. ("Talos" or the "Company") (NYSE: TALO) today announced its operational and financial results for the first quarter of 2022 and the increase of its borrowing base under the Company's reserves-based lending ("RBL") credit facility as part of its semi-annual redetermination process.

Key Highlights:

• Production of 63.2 thousand barrels of oil equivalent per day ("MBoe/d") (67% oil, 75% liquids), including the impact of approximately 4.7 MBoe/d resulting from approximately 40 cumulative shut-in days of third-party midstream downtime.
• Revenue of $413.6 million, driven by realized prices (excluding hedges) of $93.42 per barrel for oil, $36.54 per barrel for natural gas liquids ("NGLs") and $4.97 per thousand cubic feet ("Mcf") for natural gas.
• Net Loss of $66.4 million, or $0.81 Net Loss per diluted share, and Adjusted Net Income⁽¹⁾ of $64.0 million, or $0.77 Adjusted Net Income per diluted share.
• Adjusted EBITDA⁽¹⁾ of $208.2 million, or $36.61 Adjusted EBITDA per Boe; Adjusted EBITDA excluding hedges of $335.3 million, or $58.96 per Boe.
• Capital Expenditures of $84.7 million, inclusive of plugging and abandonment.
• Free Cash Flow⁽¹⁾ (before changes in working capital) of $92.0 million.
• Continued rapid debt reduction trend to 1.4x leverage and liquidity of approximately $516.1 million at quarter end.
• Extended deepwater rig contract from three to six projects for the Company's subsea tie-back drilling program, which is expected to begin in the third quarter of 2022 and extend into the 2023 capital program.
• Expanded the Bayou Bend CCS joint venture with Carbonvert Inc. ("Carbonvert") by entering into a memorandum of understanding with Chevron U.S.A., Inc. ("Chevron") in May.
• Increased RBL borrowing base from $950.0 million to $1,100.0 million and commitments from $791.3 million to $806.3 million as part of successful semi-annual redetermination process.

President and Chief Executive Officer Timothy S. Duncan commented: "We continue to believe Talos is one of the most compelling investment opportunities in the energy sector. In the first quarter of 2022 we generated over $92 million of free cash flow before working capital, despite unplanned third-party downtime and hedge losses. We continued to outperform our plan in the Upstream business while also significantly expanding our Carbon Capture venture. This strong performance contributed to our broader debt reduction priority, which has now reduced net debt by over $160 million in the last four quarters, allowing us to advance toward our de-leveraging goal of around 1.0x by year end 2022, if not sooner." 

Duncan continued: "On the operations front, we expect activity for our capital investment program to increase in late summer as we initiate our operated deepwater rig program. During the quarter we extended the contract for that rig into 2023, adding three additional operations to secure availability for our 2023 open water campaign, which reflects our strong conviction in our inventory of subsea tieback opportunities. We will execute a series of projects that we believe can add material reserves and production in 2023 and 2024. It was also a busy quarter for our growing CCS business. Not only did we move into two new markets in the Mississippi River and Corpus Christi industrial corridors, we also partnered with critical midstream infrastructure providers in each area to provide what we believe to be the best end-to-end CO₂ transportation and storage solution for future customers. Separately, we are excited to expand our Bayou Bend CCS project with the addition of Chevron to the partnership, which adds a significant partner committed to low-carbon investments and increases the potential impact this CCS hub can have. We are proud of our accomplishments in the quarter and hope to maintain the positive momentum for the remainder of 2022."

RECENT DEVELOPMENTS AND OPERATIONS UPDATE

Pompano Platform Rig Program: Activities related to the platform rig program at the Pompano field provided approximately 2.4 MBoe/d of incremental average production in March following first oil during the quarter. Talos spud the Seville exploitation well in late March 2022 and expects first production in the third quarter of 2022 if successful.

Operated Deepwater Rig Program: In the first quarter, Talos extended its contract for the Seadrill Sevan Louisiana by adding three additional consecutive rig operations, currently scheduled for early 2023. The Company expects the program to execute a total of six straight operated projects beginning in the second half of 2022 through the first half of 2023. The addition of the operations provides Talos with significant operational synergies that could reduce the total number of days required to drill and complete these projects if successful. Delivery of the rig is scheduled for early third quarter of 2022. These projects include three high-impact subsea tie-back projects with pre-drill resource estimates of 10-30 gross million barrels of oil equivalent gross per project.

Non-Operated Deepwater Rig Program: The Company separately expects to participate in three non-operated deepwater wells, all subsea tiebacks to existing infrastructure, with working interest ranges between 10-25%. Among these projects is the appraisal of the 2021 Puma West discovery, which is set to spud in the second half of 2022.

Carbon Capture (Talos Low Carbon Solutions): Talos has recently made numerous key announcements related to its rapidly emerging CCS business:

• River Bend CCS: In February, Talos announced the River Bend CCS site lease and associated memorandum of understanding with EnLink Midstream ("EnLink"). The agreements encompass approximately 26,000 acres with a total estimated storage capacity of more than 500 million metric tons of CO₂. The project will utilize significant portions of EnLink's existing regional pipeline infrastructure of approximately 4,000 miles in southeast Louisiana, thereby providing an integrated transportation and sequestration solution to potential customers.
• Coastal Bend CCS: In February, the Company also announced the execution of an option agreement with Howard Energy Partners ("Howard") and the Port of Corpus Christi Authority to evaluate CCS opportunities on-site at the Port of Corpus Christi. The agreement encompasses approximately 13,000 acres with a total estimated storage capacity of 50-100 million metric tons of CO₂. Howard's Javelina midstream system is directly connected to over half of the total regional emissions.
• Bayou Bend CCS: In March, the Company finalized its previously announced lease with the State of Texas General Land Office, the first ever major offshore CCS site in the United States. In May, Talos, along with partner Carbonvert, entered into a memorandum of understanding to add Chevron to the joint venture in exchange for a cash consideration and a capital carry through final investment decision ("FID").
• Alliance with Core Lab: In March, Talos established a strategic alliance with Core Laboratories N.V. ("Core Lab") to provide technical evaluation and assurance services for sequestration subsurface analysis, including the Company's upcoming 2022 stratigraphic evaluation wells, and joined a joint-industry CCS consortium as an inaugural member.

Successful Semi-Annual Borrowing Base Redetermination: Talos successfully completed its semi-annual borrowing base redetermination in accordance with its RBL credit facility. The borrowing base was increased to $1,100.0 million, from $950.0 million, and the total bank commitments increased to $806.3 million from $791.3 million.

Zama: Talos received the final Unitization Resolution ("UR") from Mexico's Ministry of Energy ("SENER") regarding the development of the Zama field in offshore Mexico, affirming the appointment of Petróleos Mexicanos ("Pemex") as operator of the unit. Talos will maintain a 17.35% participating interest in the Zama field, and the Company anticipates submission of a Unit Development Plan for approval by the working interest partners, a critical step before the parties can make an FID in 2023.

Unplanned and Planned Downtime: Talos experienced approximately 40 days of unplanned third-party downtime resulting from maintenance of the Eugene Island Pipeline System. The third-party pipeline shut-in resulted in a total production impact of approximately 4.7 MBoe/d for the first quarter of 2022 or 1.2 MBoe/d for the full year 2022. This impact is incorporated into the Company's 2022 operational and financial guidance. Separately, Talos experienced approximately 11 days of downtime from the acceleration of annual maintenance at the Delta House facility from the third quarter of 2022 into the first quarter of 2022, resulting in an impact of approximately 0.9 MBoe/d for the first quarter of 2022.

HP-1 Dry Dock and Second Quarter 2022 Planned Downtime: Talos expects to begin the dry-dock maintenance process for its HP-1 floating production unit during the month of June, which will defer production from the Company's Tornado and Phoenix fields for approximately 45-60 days. In addition to the HP-1 dry-dock, Talos expects other planned events to impact second quarter 2022 production. All of these events were already accounted for in the Company's annual guidance and are not incremental. Total planned downtime in the second quarter of 2022 is expected to be approximately 4.5 – 5.0 MBoe/d, as compared to a normalized quarterly production.

FIRST QUARTER 2022 RESULTS   Key Financial Highlights:
	Three Months Ended March 31, 2022
Period results ($ million):
Total Revenues	$	413.6
Net Loss	$	(66.4)
Net Loss per diluted share	$	(0.81)
Adjusted Net Income(1)	$	64.0
Adjusted Net Income per diluted share(1)	$	0.77
Adjusted EBITDA(1)	$	208.2
Adjusted EBITDA excluding hedges(1)	$	335.3
Capital Expenditures (including Plug & Abandonment)	$	84.7
Adjusted EBITDA Margin(1):
Adjusted EBITDA per Boe	$	36.61
Adjusted EBITDA excluding hedges per Boe	$	58.96

Production

Production for the quarter was 63.2 MBoe/d net, inclusive of unplanned downtime of 4.7 MBoe/d net.

		Three Months Ended March 31, 2022
Average net daily production volumes
Oil (MBbl/d)			42.1
Natural Gas (MMcf/d)			96.1
NGL (MBbl/d)			5.1
Total average net daily (MBoe/d)			63.2

 

	Three Months Ended March 31, 2022
	Production			% Oil			% Liquids			% Operated
Average net daily production volumes by Core Area (MBoe/d)
Green Canyon Area		20.0			82	%		89	%		98	%
Mississippi Canyon Area		27.0			74	%		83	%		58	%
Shelf and Gulf Coast		16.2			35	%		43	%		53	%
Total average net daily (MBoe/d)		63.2			67	%		75	%		70	%

 

Capital Expenditures

Capital expenditures for the quarter, including plugging and abandonment activities, totaled $84.7 million.

	Three Months Ended March 31, 2022
Capital Expenditures
U.S. Drilling & Completions	$	29.4
Mexico Appraisal & Exploration		0.1
Asset Management		20.3
Seismic and G&G / Land / Capitalized G&A / CCS and Other		14.9
Total Capital Expenditures		64.7
Plugging & Abandonment		20.0
Total Capital Expenditures and Plugging & Abandonment	$	84.7

Liquidity and Leverage

At quarter-end the Company had approximately $516.1 million of liquidity, with $451.3 million undrawn on its RBL facility and approximately $78.3 million in cash, less approximately $13.6 million in outstanding letters of credit. On March 31, 2022, Talos had $1,030.0 million in total debt, inclusive of $34.0 million related to the HP-I finance lease. Net Debt was $951.7 million⁽¹⁾. Net Debt to Credit Facility LTM Adjusted EBITDA⁽¹⁾, as determined in accordance with the Company's credit agreement, was 1.4x⁽¹⁾.

Footnotes:

(1)

Adjusted Net Income, Adjusted Net Income per diluted share, Adjusted EBITDA, Adjusted EBITDA excluding hedges, Adjusted EBITDA margin, Adjusted EBITDA margin excluding hedges, Credit Facility LTM Adjusted EBITDA, Net Debt, Net Debt to Credit Facility LTM Adjusted EBITDA and Free Cash Flow are non-GAAP financial measures. See "Supplemental Non-GAAP Information" below for additional detail and reconciliations of GAAP to non-GAAP measures.

HEDGES

The following table reflects contracted volumes and weighted average prices the Company will receive under the terms of its derivative contracts as of May 4, 2022 and includes contracts entered into after March 31, 2022:

 

		Instrument Type		Avg. Daily Volume		Weighted Avg. Swap Price
Crude – WTI				(Bbls)		(Per Bbl)
April - June 2022		Swaps		27,341		$52.38
July - September 2022		Swaps		18,000		$52.20
October - December 2022		Swaps		19,326		$55.05
January - March 2023		Swaps		23,000		$69.44
April - June 2023		Swaps		12,000		$62.48
July - September 2023		Swaps		9,000		$73.09
October - December 2023		Swaps		5,000		$67.44
January - March 2024		Swaps		4,000		$72.56
April - June 2024		Swaps		2,000		$69.85
Natural Gas – HH NYMEX				(MMBtu)		(Per MMBtu)
April - June 2022		Swaps		56,352		$3.00
July - September 2022		Swaps		31,000		$2.63
October - December 2022		Swaps		34,000		$2.72
January - March 2023		Swaps		42,000		$3.87
April - June 2023		Swaps		29,000		$3.17
July - September 2023		Swaps		15,000		$3.46
October - December 2023		Swaps		5,000		$3.39
January - March 2024		Swaps		10,000		$3.25
April - June 2024		Swaps		10,000		$3.25

CONFERENCE CALL AND WEBCAST INFORMATION

Talos will host a conference call, which will be broadcast live over the internet, on Thursday, May 5, 2022 at 10:00 AM Eastern Time (9:00 AM Central Time). Listeners can access the conference call through a webcast link on the Company's website at: https://www.talosenergy.com/investors. Alternatively, the conference call can be accessed by dialing (888) 348-8927 (U.S. toll free), (855) 669-9657 (Canada toll-free) or (412) 902-4263 (international). Please dial in approximately 15 minutes before the teleconference is scheduled to begin and ask to be joined into the Talos Energy call. A replay of the call will be available one hour after the conclusion of the conference until May 12, 2022 and can be accessed by dialing (877) 344-7529 and using access code 6364444.

ABOUT TALOS ENERGY

Talos Energy (NYSE: TALO) 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 and offshore Mexico, both upstream through oil and gas exploration and production and downstream through the development of carbon capture and sequestration opportunities. As one of the Gulf of Mexico's largest public independent producers, 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 sequestration initiatives along the U.S. Gulf Coast and Gulf of Mexico. For more information, visit www.talosenergy.com.

INVESTOR RELATIONS CONTACT

Sergio Maiworm
+1.713.328.3008
investor@talosenergy.com 

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

This communication may contain "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact included in this communication, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this communication, the words "will", "could," "believe," "anticipate," "intend," "estimate," "expect," "project," "forecast," "may," "objective," "plan" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.

We caution you that these forward-looking statements are subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility 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 other state-controlled oil companies ("OPEC Plus"), such as Saudi Arabia and Russia, to set and maintain oil production levels; the impact of any such actions; the lack of a resolution to the war in Ukraine and its impact on certain commodity markets; 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, 2021, filed with the SEC on February 25, 2022 and Talos Energy Inc's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2022, to be filed with the SEC subsequent to the issuance of this communication. Should one or more of these risks occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, to reflect events or circumstances after the date of this communication.

Estimates for our future production volumes are based on assumptions of capital expenditure levels and the assumption that market demand and prices for oil and gas will continue at levels that allow for economic production of these products. The production, transportation, marketing and storage of oil and gas are subject to disruption due to transportation, processing and storage availability, mechanical failure, human error, hurricanes and numerous other factors. Our estimates are based on certain other assumptions, such as well performance, which may vary significantly from those assumed. Therefore, we can give no assurance that our future production volumes will be as estimated.

 

Talos Energy Inc. Condensed Consolidated Balance Sheets (In thousands, except per share amounts)
	March 31, 2022			December 31, 2021
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	78,348		$	69,852
Accounts receivable:
Trade, net		242,303			173,241
Joint interest, net		23,999			28,165
Other, net		11,946			18,062
Assets from price risk management activities		—			967
Prepaid assets		43,402			48,042
Other current assets		1,808			1,674
Total current assets		401,806			340,003
Property and equipment:
Proved properties		5,304,468			5,232,479
Unproved properties, not subject to amortization		227,411			219,055
Other property and equipment		29,452			29,091
Total property and equipment		5,561,331			5,480,625
Accumulated depreciation, depletion and amortization		(3,190,383)			(3,092,043)
Total property and equipment, net		2,370,948			2,388,582
Other long-term assets:
Assets from price risk management activities		—			2,770
Equity method investments		2,665			—
Other well equipment inventory		17,650			17,449
Operating lease assets		5,649			5,714
Other assets		11,776			12,297
Total assets	$	2,810,494		$	2,766,815
LIABILITIES AND STOCKHOLDERSʼ EQUITY
Current liabilities:
Accounts payable	$	91,158		$	85,815
Accrued liabilities		126,838			130,459
Accrued royalties		68,134			59,037
Current portion of long-term debt		6,060			6,060
Current portion of asset retirement obligations		51,273			60,311
Liabilities from price risk management activities		308,402			186,526
Accrued interest payable		17,981			37,542
Current portion of operating lease liabilities		1,778			1,715
Other current liabilities		33,970			33,061
Total current liabilities		705,594			600,526
Long-term liabilities:
Long-term debt, net of discount and deferred financing costs		925,081			956,667
Asset retirement obligations		390,806			373,695
Liabilities from price risk management activities		42,458			13,938
Operating lease liabilities		15,853			16,330
Other long-term liabilities		35,577			45,006
Total liabilities		2,115,369			2,006,162
Commitments and contingencies (Note 10)
Stockholdersʼ equity:
Preferred stock, $0.01 par value; 30,000,000 shares authorized and   no shares issued or outstanding as of March 31, 2022 and December 31, 2021		—			—
Common stock $0.01 par value; 270,000,000 shares authorized;   82,535,186 and 81,881,477 shares issued and outstanding as of   March 31, 2022 and December 31, 2021, respectively		825			819
Additional paid-in capital		1,677,705			1,676,798
Accumulated deficit		(983,405)			(916,964)
Total stockholdersʼ equity		695,125			760,653
Total liabilities and stockholdersʼ equity	$	2,810,494		$	2,766,815

 

Talos Energy Inc. Condensed Consolidated Statements of Operations (In thousands, except per common share amounts)
	Three Months Ended March 31,
	2022			2021
Revenues:
Oil	$	353,886		$	229,561
Natural gas		42,981			28,234
NGL		16,699			9,113
Total revenues		413,566			266,908
Operating expenses:
Lease operating expense		59,814			66,628
Production taxes		851			822
Depreciation, depletion and amortization		98,340			101,657
Accretion expense		14,377			14,985
General and administrative expense		22,528			19,189
Other operating (income) expense		136			(1,000)
Total operating expenses		196,046			202,281
Operating income		217,520			64,627
Interest expense		(31,490)			(34,076)
Price risk management activities expense		(281,219)			(137,508)
Equity method investment income		142			—
Other income (expense)		28,134			(13,950)
Net loss before income taxes		(66,913)			(120,907)
Income tax benefit (expense)		472			(584)
Net loss	$	(66,441)		$	(121,491)
Net loss per common share:
Basic	$	(0.81)		$	(1.49)
Diluted	$	(0.81)		$	(1.49)
Weighted average common shares outstanding:
Basic		82,071			81,435
Diluted		82,071			81,435

 

Talos Energy Inc. Condensed Consolidated Statements of Cash Flows (In thousands)
	Three Months Ended March 31,
	2022			2021
Cash flows from operating activities:
Net loss	$	(66,441)		$	(121,491)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion expense		112,717			116,642
Amortization of deferred financing costs and original issue discount		3,415			3,142
Equity-based compensation expense		3,318			2,664
Price risk management activities expense		281,219			137,508
Net cash paid on settled derivative instruments		(127,086)			(48,381)
Equity method investment income		(142)			—
Loss on extinguishment of debt		—			13,225
Settlement of asset retirement obligations		(20,023)			(10,120)
Gain on sale of assets		—			(319)
Changes in operating assets and liabilities:
Accounts receivable		(56,817)			(17,108)
Other current assets		4,505			(3,350)
Accounts payable		9,381			(10,978)
Other current liabilities		(26,423)			5,328
Other non-current assets and liabilities, net		(4,013)			194
Net cash provided by operating activities		113,610			66,956
Cash flows from investing activities:
Exploration, development and other capital expenditures		(53,978)			(64,745)
Cash paid for acquisitions, net of cash acquired		(3,500)			(8,322)
Proceeds from sale of property and equipment, net		346			330
Contributions to equity method investees		(2,250)			—
Net cash used in investing activities		(59,382)			(72,737)
Cash flows from financing activities:
Issuance of senior notes		—			600,500
Redemption of senior notes and other long-term debt		—			(356,803)
Proceeds from Bank Credit Facility		35,000			—
Repayment of Bank Credit Facility		(70,000)			(175,000)
Deferred financing costs		—			(19,387)
Other deferred payments		—			(5,575)
Payments of finance lease		(6,256)			(5,058)
Employee stock awards tax withholdings		(4,476)			(2,150)
Net cash (used in) provided by financing activities		(45,732)			36,527
Net increase in cash and cash equivalents		8,496			30,746
Cash and cash equivalents:
Balance, beginning of period		69,852			34,233
Balance, end of period	$	78,348		$	64,979
Supplemental non-cash transactions:
Capital expenditures included in accounts payable and accrued liabilities	$	53,317		$	65,755
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	43,352		$	13,712

SUPPLEMENTAL NON-GAAP INFORMATION

Certain financial information included in our financial results are not measures of financial performance recognized by accounting principles generally accepted in the United States, or GAAP. These non-GAAP financial measures are "Adjusted Net Income (Loss)," "Adjusted Earnings per Share," "EBITDA," "Adjusted EBITDA," "Adjusted EBITDA excluding hedges," "Adjusted EBITDA Margin," "Adjusted EBITDA Margin excluding hedges," "Free Cash Flow," "Net Debt," "LTM Adjusted EBITDA," "Credit Facility LTM Adjusted EBITDA" and "Net Debt to Credit Facility LTM Adjusted EBITDA." These disclosures may not be viewed as a substitute for results determined in accordance with GAAP and are not necessarily comparable to non-GAAP measures which may be reported by other companies.

Reconciliation of Net Income (Loss) to EBITDA and Adjusted EBITDA

"EBITDA" and "Adjusted EBITDA" are to provide management and investors with (i) additional information to evaluate, with certain adjustments, items required or permitted in calculating covenant compliance under our debt agreements, (ii) important supplemental indicators of the operational performance of our business, (iii) additional criteria for evaluating our performance relative to our peers and (iv) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. EBITDA and Adjusted EBITDA have limitations as analytical tools and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP or as alternatives to net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP. We define these as the following:

EBITDA. Net income (loss) plus interest expense, income tax expense (benefit), depreciation, depletion and amortization and accretion expense.

Adjusted EBITDA. EBITDA plus non-cash write-down of oil and natural gas properties, transaction and non-recurring expenses, derivative fair value (gain) loss, net cash receipts (payments) on settled derivatives, (gain) loss on debt extinguishment, non-cash write-down of other well equipment inventory and non-cash equity-based compensation expense.

We also present Adjusted EBITDA excluding hedges and as a percentage of revenue to further analyze our business, which are outlined below:

Adjusted EBITDA Margin. EBITDA divided by Revenue, as a percentage. It is also defined as Adjusted EBITDA divided by the total production volume, expressed in Boe, in the period, and described as dollar per Boe. We believe the presentation of Adjusted EBITDA margin is important to provide management and investors with information about how much we retain in Adjusted EBITDA terms as compared to the revenue we generate and how much per barrel we generate after accounting for certain operational and corporate costs.

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

 

	Three Months Ended
($ thousands, except per Boe)	March 31, 2022			December 31, 2021			September 30, 2021			June 30, 2021
Reconciliation of net income (loss) to Adjusted EBITDA:
Net Income (loss)	$	(66,441)		$	81,012		$	(16,691)		$	(125,782)
Interest expense		31,490			33,102			32,390			33,570
Income tax expense (benefit)		(472)			(2,353)			(364)			498
Depreciation, depletion and amortization		98,340			105,900			88,596			99,841
Accretion expense		14,377			14,019			13,668			15,457
EBITDA		77,294			231,680			117,599			23,584
Write-down of oil and natural gas properties		—			18,123			—			—
Transaction and other (income) expenses(1)(4)		(26,532)			19,710			1,370			4,083
Derivative fair value loss(2)		281,219			13,473			81,479			186,617
Net cash payments on settled derivative    instruments(2)		(127,086)			(100,912)			(71,634)			(69,237)
Non-cash write-down of other well equipment   inventory		—			5,606			—			—
Non-cash equity-based compensation expense		3,318			2,698			2,613			3,017
Adjusted EBITDA		208,213			190,378			131,427			148,064
Add: Net cash payments on settled derivative    instruments(2)		127,086			100,912			71,634			69,237
Adjusted EBITDA excluding hedges	$	335,299		$	291,290		$	203,061		$	217,301
Production and Revenue:
Boe(3)		5,687			6,320			5,200			6,031
Revenue - Operations		413,566			382,955			290,909			303,768
Adjusted EBITDA margin and Adjusted EBITDA   excl hedges margin:
Adjusted EBITDA divided by Revenue -   Operations (%)		50	%		50	%		45	%		49	%
Adjusted EBITDA per Boe(3)	$	36.61		$	30.12		$	25.27		$	24.55
Adjusted EBITDA excl hedges divided by Revenue -   Operations (%)		81	%		76	%		70	%		72	%
Adjusted EBITDA excl hedges per Boe(3)	$	58.96		$	46.09		$	39.05		$	36.03

 

(1)	Includes transaction related expenses, restructuring expenses, cost saving initiatives and other miscellaneous income and expenses.
(2)	The adjustments for the derivative fair value (gain) loss and net cash receipts (payments) on settled derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled.
(3)	One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.
(4)	Includes $27.5 million gain as a result of the settlement agreement to resolve previously pending litigation that was filed in October 2017.

Reconciliation of Adjusted EBITDA to Free Cash Flow

"Free Cash Flow" before changes in working capital provides management and investors with (i) important supplemental indicators of the operational performance of our business, (ii) additional criteria for evaluating our performance relative to our peers and (iii) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. Free Cash Flow has limitations as an analytical tool 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:

Capital Expenditures and Plugging & Abandonment. Actual capital expenditures and plugging & abandonment recognized in the quarter, inclusive of accruals.

Interest Expense. Actual interest expense per the income statement.

Talos did not pay any cash taxes in the period, therefore cash taxes have no impact to the reported Free Cash Flow before changes in working capital number.

($ thousands, except per share amounts)	Three Months Ended March 31, 2022
Reconciliation of Adjusted EBITDA to Free Cash Flow (before changes in working capital)
Adjusted EBITDA	$	208,213
Less: Capital Expenditures and Plugging & Abandonment		(84,706)
Less: Interest Expense		(31,490)
Free Cash Flow (before changes in working capital)	$	92,017

Reconciliation of Net Income (Loss) to Adjusted Net Income (Loss) and Adjusted Earnings per Share

"Adjusted Net Income (Loss)" and "Adjusted Earnings per Share" are to provide management and investors with (i) important supplemental indicators of the operational performance of our business, (ii) additional criteria for evaluating our performance relative to our peers and (iii) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. Adjusted Net Income (Loss) and Adjusted Earnings per Share have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP or as an alternative to net income (loss), operating income (loss), earnings per share or any other measure of financial performance presented in accordance with GAAP.

Adjusted Net Income (Loss). Net income (loss) plus accretion expense, transaction related costs, derivative fair value (gain) loss, net cash receipts (payments) on settled derivative instruments and non-cash equity-based compensation expense.

Adjusted Earnings per Share. Adjusted Net Income (Loss) divided by the number of common shares.

 

($ thousands, except per share amounts)	Three Months Ended March 31, 2022
Reconciliation of Net Loss to Adjusted Net Income:
Net Loss	$	(66,441)
Transaction and other income(2)(3)	$	(26,532)
Derivative fair value loss(1)	$	281,219
Cash payments on settled derivative instruments(1)	$	(127,086)
Non-cash income tax expense	$	(472)
Non-cash equity-based compensation expense	$	3,318
Adjusted Net Income	$	64,006
Weighted average common shares outstanding at March 31, 2022:
Basic		82,071
Diluted		82,071
Diluted (non-GAAP)		82,826
Net Loss per common share:
Basic	$	(0.81)
Diluted	$	(0.81)
Adjusted Net Income per common share:
Basic	$	0.78
Diluted	$	0.77

 

(1)	The adjustments for the derivative fair value (gain) loss and net cash receipts (payments) on settled derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted Net Income (Loss) on an unrealized basis during the period the derivatives settled.
(2)	Includes transaction related expenses, restructuring expenses, cost saving initiatives and other miscellaneous income and expenses.
(3)	Includes $27.5 million gain as a result of the settlement agreement to resolve previously pending litigation that was filed in October 2017.

 

Reconciliation of Total Debt to Net Debt and Net Debt to LTM Adjusted EBITDA and Credit Facility LTM Adjusted EBITDA

We believe the presentation of Net Debt, LTM Adjusted EBITDA, Credit Facility LTM Adjusted EBITDA, Net Debt to LTM Adjusted EBITDA and Net Debt to Credit Facility LTM Adjusted EBITDA is important to provide management and investors with additional important information to evaluate our business. These measures are widely used by investors and ratings agencies in the valuation, comparison, rating and investment recommendations of companies

Net Debt. Total Debt principal of the Company plus the finance lease balance minus cash and cash equivalents.

Net Debt to LTM Adjusted EBITDA. Net Debt divided by the LTM Adjusted EBITDA.

Net Debt to Credit Facility LTM Adjusted EBITDA. Net Debt divided by the Credit Facility LTM Adjusted EBITDA.

Reconciliation of Net Debt ($ thousands) at March 31, 2022:
12.00% Second-Priority Senior Secured Notes – due January 2026	$	650,000
7.50% Senior Notes – due May 2022		6,060
Bank Credit Facility – matures November 2024		340,000
Finance lease		33,965
Total Debt		1,030,025
Less: Cash and cash equivalents		(78,348)
Net Debt	$	951,677
Calculation of LTM EBITDA:
Adjusted EBITDA for three months period ended June 30, 2021	$	148,064
Adjusted EBITDA for three months period ended September 30, 2021		131,427
Adjusted EBITDA for three months period ended December 31, 2021		190,378
Adjusted EBITDA for three months period ended March 31, 2022		208,213
LTM Adjusted EBITDA	$	678,082
Reconciliation of Net Debt to LTM Adjusted EBITDA:
Net Debt / LTM Adjusted EBITDA		1.4x

 

The Adjusted EBITDA information included in this communication provides additional relevant information to our investors and creditors. Talos needs to comply with a financial covenant included in its Bank Credit Facility that requires it to maintain a Net Debt to Credit Facility LTM Adjusted EBITDA ratio, as determined in accordance with the Company's credit agreement, equal to or lower than 3.0x. For purposes of covenant compliance, Credit Facility LTM Adjusted EBITDA, with certain adjustments, is calculated as the sum of quarterly Adjusted EBITDA for the 12-month period ended on that quarter, inclusive of revenue less direct operating expenditures of the Acquired Assets for periods prior to closing of the Transaction.

 

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SOURCE Talos Energy

FAQ

What were Talos Energy's Q1 2022 earnings results?

Talos Energy reported a net loss of $66.4 million and adjusted net income of $64 million in Q1 2022.

How much free cash flow did Talos Energy generate in Q1 2022?

Talos Energy generated $92 million of free cash flow before changes in working capital in Q1 2022.

What is Talos Energy's borrowing base after the recent redetermination?

Talos Energy's borrowing base increased to $1.1 billion after the semi-annual redetermination.

How does Talos Energy plan to address its debt?

Talos aims to reduce its net debt to approximately 1.0x by year-end 2022.