PR Newswire
HOUSTON
, Feb. 26, 2025 /PRNewswire/ — Talos Energy Inc. (“Talos” or the “Company”) (NYSE: TALO) today announced its operational and financial results for the three and twelve months ended December 31, 2024. Talos also announced its year-end 2024 reserves figures and 2025 operational and financial guidance.
Fourth Quarter 2024 and Recent Highlights
- Production of 98.7 thousand barrels of oil equivalent per day (“MBoe/d”) (70% oil, 79% liquids).
- Net Loss of $64.5 million, or $0.36 Net Loss per diluted share, and Adjusted Net Income* of $15.2 million, or $0.08 Adjusted Net Income per diluted share*.
- Adjusted EBITDA* of $361.8 million.
- Upstream capital expenditures of $133.2 million, excluding plugging and abandonment and settled decommissioning obligations.
- Net cash provided by operating activities of $349.3 million.
- Adjusted Free Cash Flow* of $164.0 million.
- Paid off the balance of Talos’s credit facility, bringing leverage to 0.8x (Net Debt / Pro Forma LTM Adjusted EBITDA)*.
- Successfully drilled Katmai West #2 well a month faster than expected and under budget.
Full Year 2024 Highlights
- Production of 92.6 MBoe/d (71% oil, 80% liquids).
- Net Loss of $76.4 million, or $0.44 Net Loss per diluted share, and Adjusted Net Loss* of $26.2 million, or $0.15 Adjusted Net Loss per diluted share*, excluding Talos’s Carbon Capture & Sequestration (“CCS”) business.
- Adjusted EBITDA* of $1,297.7 million, excluding CCS.
- Upstream capital expenditures of $489.5 million, excluding plugging and abandonment and settled decommissioning obligations.
- Net cash provided by operating activities of $962.6 million.
- Adjusted Free Cash Flow* of $511.2 million, excluding CCS.
- Year-end 2024 proved reserves of 194.2 million barrels of oil equivalent (“MMBoe”) with a PV-10 value* of $4.2 billion.
Talos Interim Chief Executive Officer, Co-President and General Counsel William Moss stated, “Talos had a strong fourth quarter and a solid finish to 2024, with our operations performing well and achieving key objectives for the year. We look forward to Paul Goodfellow joining Talos as our President, Chief Executive Officer and member of the Board in the next few days. The Talos Board is confident that Paul’s extensive expertise in oil and natural gas, especially in deepwater operations, combined with his strategic judgment and proven track record, will play a vital role in advancing Talos. Under Paul’s leadership, we expect to remain focused on leveraging our strengths in deepwater exploration and production to deliver value for all shareholders.”
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RECENT DEVELOPMENTS AND OPERATIONS UPDATE
Production Updates:
Katmai West: In December 2024, Katmai West #2 well was drilled under budget and a month faster than expected, encountering over 400 feet of gross hydrocarbon pay with excellent rock properties. First production is expected later in the second quarter 2025. The strong performance from Katmai West #1 well, and the successful appraisal from Katmai West #2 well, have nearly doubled the proved estimated ultimate recovery (“EUR” )1 of Katmai West field to approximately 50 MMBoe gross, which further affirms Talos’s estimated gross resource potential of approximately 100 MMBoe. The greater Katmai area is estimated to contain up to a total resource potential of 200 MMBoe. Talos, as operator, holds a 50% working interest (“W.I.”), with entities managed by Ridgewood Energy Corporation holding the other 50% in Katmai West field.
Sunspear Completion: Talos recently commenced completion operations on Sunspear with the West Vela deepwater drillship and expects first production late in the second quarter 2025. Talos projects production to be approximately 8-10 MBoe/d gross. Sunspear will be tied back to the Talos operated Prince platform. Talos holds a 48.0% W.I., an entity managed by Ridgewood Energy Corporation holds a 47.5% W.I., and an undisclosed partner holds a 4.5% W.I.
Exploitation and Exploration Updates:
Daenerys: Talos anticipates focusing on drilling operations on the Daenerys well in the second quarter 2025. Talos holds a 30% W.I.
Monument Discovery Farm-in: Talos recently agreed to increase its interest in the Monument discovery to a 29.76% W.I., up from 21.4% W.I. Monument is a large Wilcox oil discovery in Walker Ridge blocks 271, 272, 315, and 316. It will be developed as a subsea tie-back to the Shenandoah production facility in Walker Ridge. First production is expected between 20–30 MBoe/d gross by late 2026 under restricted flow due to facility rate constraints. There is an additional 25–35 MMBoe drilling location adjacent to the discovery that could extend the resource. Other partners include Beacon as operator with a 41.67% W.I. and Navitas Petroleum with a 28.57% W.I.
Other Business Developments
Chief Executive Officer Transition:
Paul Goodfellow will become Talos’s President and Chief Executive Officer and a member of the Talos Board of Directors, effective March 1, 2025. Mr. Goodfellow has over 30 years of domestic and international experience in the oil and natural gas industry, having led Shell’s global deepwater business and overseeing Shell’s internal audit function.
Sale of Mexico Interest: In December 2024, Talos entered into an agreement to sell an additional 30.1% interest in Talos Mexico to a subsidiary of Grupo Carso, S.A.B. de C.V. (“Carso”) for $49.7 million in cash, with an additional $33.1 million due upon first oil production from the Zama Field, for an aggregate price of $82.7 million (the “Pending Transaction”). Upon consummation of the sale, Talos Mexico will be owned 20.0% by Talos Energy and 80.0% by Carso. Talos Mexico holds a 17.4% interest in the Zama Field. The Pending Transaction is expected to close during 2025 upon satisfaction of customary closing conditions and the receipt of all regulatory approvals. Upon achievement of commercial production from the Zama Field, Talos anticipates receiving $82.9 million in cash contingent considerations, comprised of approximately $33.0 million relating to the Pending Transaction and $49.9 million from the sale of a 49.9% equity interest in Talos Mexico to Carso which occurred in September 2023.
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FOURTH QUARTER AND FULL YEAR 2024 RESULTS
Key Financial Highlights:
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||||
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Total revenues |
$ |
485,185 |
$ |
1,973,568 |
||
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Net Income (Loss) |
$ |
(64,508) |
$ |
(76,393) |
||
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Net Income (Loss) per diluted share |
$ |
(0.36) |
$ |
(0.44) |
||
|
Adjusted Net Income (Loss) excluding CCS* |
$ |
15,173 |
$ |
(26,198) |
||
|
Adjusted Net Income (Loss) excluding CCS per diluted share* |
$ |
0.08 |
$ |
(0.15) |
||
|
Adjusted EBITDA excluding CCS* |
$ |
361,814 |
$ |
1,297,705 |
||
|
Adjusted EBITDA excluding CCS and hedges* |
$ |
342,163 |
$ |
1,292,995 |
||
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Upstream Capital Expenditures |
$ |
133,249 |
$ |
489,529 |
||
Production
Production for the fourth quarter and full year 2024 was 98.7 MBoe/d ( 70% oil, 79% liquids) and 92.6 MBoe/d (71% oil, 80% liquids), respectively.
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Oil (MBbl/d) |
69.0 |
65.8 |
||||
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Natural Gas (MMcf/d) |
124.8 |
112.2 |
||||
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NGL (MBbl/d) |
8.9 |
8.1 |
||||
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Total average net daily (MBoe/d) |
98.7 |
92.6 |
||||
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||||||||||||
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|||||||||
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Deepwater |
85.6 |
72 |
% |
82 |
% |
83 |
% |
|||||
|
Shelf and Gulf Coast |
13.1 |
54 |
% |
62 |
% |
74 |
% |
|||||
|
Total average net daily (MBoe/d) |
98.7 |
70 |
% |
79 |
% |
82 |
% |
|||||
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||||||||||||
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|
|
|
|||||||||
|
Deepwater |
79.7 |
74 |
% |
83 |
% |
86 |
% |
|||||
|
Shelf and Gulf Coast |
12.9 |
50 |
% |
60 |
% |
70 |
% |
|||||
|
Total average net daily (MBoe/d) |
92.6 |
71 |
% |
80 |
% |
83 |
% |
|||||
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|||||
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Average realized prices (excluding hedges) |
||||||
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Oil ($/Bbl) |
$ |
69.03 |
$ |
75.01 |
||
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Natural Gas ($/Mcf) |
$ |
2.60 |
$ |
2.57 |
||
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NGL ($/Bbl) |
$ |
21.18 |
$ |
20.85 |
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Average realized price ($/Boe) |
$ |
53.43 |
$ |
58.23 |
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Average NYMEX prices |
||||||
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WTI ($/Bbl) |
$ |
70.73 |
$ |
76.59 |
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Henry Hub ($/MMBtu) |
$ |
2.44 |
$ |
2.19 |
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Lease Operating & General and Administrative Expenses
Total lease operating expenses for the fourth quarter and full year 2024, inclusive of workover, maintenance and insurance costs, were $110.2 million, or $12.14 per Boe, and $566.0 million, or $16.70 per Boe, respectively.
Adjusted General and Administrative expenses for the fourth quarter and full year 2024, adjusted to exclude CCS expenses, one-time transaction-related costs, and non-cash equity-based compensation, were $34.9 million, or $3.84 per Boe, and $130.7 million, or $3.86 per Boe, respectively.
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||||
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Lease Operating Expenses |
$ |
110,206 |
$ |
566,041 |
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Lease Operating Expenses per Boe |
$ |
12.14 |
$ |
16.70 |
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Adjusted General & Administrative Expenses excluding CCS* |
$ |
34,854 |
$ |
130,695 |
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Adjusted General & Administrative Expenses excluding CCS per Boe* |
$ |
3.84 |
$ |
3.86 |
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Upstream Capital Expenditures
Upstream capital expenditures for the fourth quarter and full year 2024, excluding plugging and abandonment and settled decommissioning obligations, totaled $133.2 million and $489.5 million, respectively.
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||||
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U.S. drilling & completions |
$ |
98,459 |
$ |
283,779 |
||
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Asset management(1) |
13,188 |
109,222 |
||||
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Seismic and G&G, land, capitalized G&A and other |
18,241 |
91,059 |
||||
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Total Upstream Capital Expenditures |
129,888 |
484,060 |
||||
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Investment in Mexico |
3,361 |
5,469 |
||||
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Total Upstream |
$ |
133,249 |
$ |
489,529 |
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_________________________ |
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(1) |
Asset management consists of capital expenditures for development-related activities primarily associated with recompletions and improvements to our facilities and infrastructure. |
Plugging & Abandonment Expenditures
Upstream capital expenditures for plugging and abandonment and settled decommissioning obligations for the fourth quarter and full year 2024 totaled $23.1 million, and $114.2 million, respectively.
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Plugging & Abandonment and Decommissioning Obligations Settled(1) |
$ |
23,069 |
$ |
114,236 |
||
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_________________________ |
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(1) |
Settlement of decommissioning obligations 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. |
Liquidity and Leverage
At December 31, 2024, Talos had a borrowing base of $925.0 million under its Bank Credit Facility, subject to a total availability cap of $800.0 million with approximately $42.4 million in outstanding letters of credit. Cash was $108.2 million, providing Talos approximately $865.8 million of liquidity. On December 31, 2024, Talos had $1,250.0 million in total debt. Net Debt* was $1,141.8 million, Net Debt to Pro Forma Last Twelve Months (“LTM”) Adjusted EBITDA* was 0.8x.
YEAR-END 2024 RESERVES
As of December 31, 2024, Talos had proved reserves of 194.2 MMBoe, comprised of 74% oil and 81% liquids. The Standardized Measure of Talos’s standalone reserves was approximately $3.6 billion and the PV-10 of Talos proved reserves(1)(2)(3) was approximately $4.2 billion. In addition to proved reserves, Talos’s probable reserves as of December 31, 2024 were 125.3 MMBoe with a corresponding PV-10(2)(3)(4) of approximately $3.0 billion. The proved and probable reserves are prepared by Netherland, Sewell & Associates, Inc. (“NSAI”). All figures are fully burdened by and net of all plugging and abandonment costs associated with the properties included in the reserves report. The following tables summarize proved reserves at December 31, 2024 based on SEC pricing of $76.32 per barrel of oil and $2.13 per MMBtu of natural gas, before differentials.
Proved Reserves
The following table presents Talos’s estimated proved reserves and PV-10 values as of December 31, 2024.
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Proved Developed Producing |
108,973 |
56 |
% |
76 |
% |
$ |
2,875,948 |
||||||||
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Proved Developed Non-Producing |
41,429 |
21 |
% |
62 |
% |
715,006 |
|||||||||
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Total Proved Developed |
150,402 |
77 |
% |
72 |
% |
3,590,954 |
|||||||||
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Proved Undeveloped |
43,840 |
23 |
% |
79 |
% |
609,770 |
|||||||||
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Total Proved |
194,242 |
100 |
% |
74 |
% |
$ |
3,546,204 |
$ |
4,200,724 |
||||||
Probable Reserves
The following table presents Talos’s estimated probable reserves and PV-10 value as of December 31, 2024.
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||||||
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Total Probable |
125,349 |
$ |
3,011,741 |
||||
Proved Reserves Sensitivities
The following table presents the PV-10 values of Talos’s proved reserves as of December 31, 2024, at various crude oil prices and natural gas prices.
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Proved Developed Producing |
$ |
2,242,411 |
$ |
2,576,158 |
$ |
2,875,948 |
$ |
3,200,295 |
$ |
3,489,138 |
|||||
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Proved Developed Non-Producing |
555,628 |
636,779 |
715,006 |
820,699 |
903,344 |
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Total Proved Developed |
2,798,039 |
3,212,937 |
3,590,954 |
4,020,994 |
4,392,481 |
||||||||||
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Proved Undeveloped |
400,834 |
477,701 |
609,770 |
705,896 |
816,690 |
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Total Proved |
$ |
3,198,873 |
$ |
3,690,637 |
$ |
4,200,724 |
$ |
4,726,890 |
$ |
5,209,171 |
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Probable Reserves Sensitivities
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Total Probable |
$ |
2,723,327 |
$ |
2,975,984 |
$ |
3,011,736 |
$ |
3,476,200 |
$ |
3,721,443 |
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_________________________ |
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(1) |
PV-10 is a non-GAAP financial measure and differs from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. See “Supplemental Non-GAAP Information” below for additional detail and a reconciliation of PV-10 of our proved reserves to the corresponding standardized measure of discounted future net cash flows at December 31, 2024. |
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(2) |
PV-10 is presented inclusive of the plugging and abandonment obligations and before hedges. |
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(3) |
SEC pricing of $76.32 per barrel of oil and $2.13 per MMBtu of natural gas, before differentials. |
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(4) |
Investors should be cautioned that estimates of PV-10 of probable reserves, as well as underlying volumetric estimates, are inherently more uncertain of being recovered and realized than comparable measures for proved reserves. Further, because estimates of probable reserve volumes have not been adjusted for risk due to this uncertainty of recovery, their summation may be of limited use. |
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(5) |
PV-10 for proved reserves cannot be reconciled to Standardized Measure for prices other than SEC pricing because GAAP does not prescribe any corresponding measure based on other pricing, and accordingly it is not practicable to prepare any such reconciliation. |
OPERATIONAL & FINANCIAL GUIDANCE UPDATES
Talos intends to prioritize free cash flow generation and the advancement of key drilling projects expected to drive future shareholder value creation in its 2025 operational and financial plan.
Production for the first quarter 2025 is estimated to be in the range from 99.0 to 101.0 MBoe/d, with 68% oil volumes.
Talos’s production guidance takes into account known and anticipated factors influencing the productive capacity between 100 Mboe/d and 105.0 MBoe/d, including expected planned downtime for facility and downstream maintenance activities. Key maintenance includes work scheduled for such assets as Katmai, Pompano, and Brutus, in addition to third-party pipeline maintenance. Furthermore, the guidance also considers potential expected but unplanned downtime due to unforeseen risks and weather-related disruptions.
Production for the full year 2025 is expected to range from 90.0 to 95.0 MBoe/d, consisting of 69% oil and 79% liquids.
The following summarizes Talos’s full-year 2025 operational and production guidance.
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|||||
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|
Oil (MMBbl) |
22.7 |
24.0 |
||||
|
Natural Gas (Bcf) |
41.9 |
44.3 |
|||||
|
NGL (MMBbl) |
3.1 |
3.3 |
|||||
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|
|
|||||
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|
|||||
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|
Cash Operating Expenses and Workovers(1)(2)(4)* |
$ |
580 |
$ |
610 |
||
|
G&A(2)(3)* |
$ |
120 |
$ |
130 |
|||
|
|
Capital Expenditures(5) |
$ |
500 |
$ |
540 |
||
|
|
P&A, Decommissioning |
$ |
100 |
$ |
120 |
||
|
|
Interest Expense(6) |
$ |
155 |
$ |
165 |
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_________________________ |
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|
(1) |
Includes Lease Operating Expenses and Maintenance. |
|
(2) |
Includes insurance costs. |
|
(3) |
Excludes non-cash equity-based compensation and transaction and other expenses. |
|
(4) |
Includes reimbursements under production handling agreements. |
|
(5) |
Excludes acquisitions. |
|
(6) |
Includes cash interest expense on debt and finance lease, surety charges and amortization of deferred financing costs and original issue discounts. |
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*Due to the forward-looking nature a reconciliation of Cash Operating Expenses and Workovers and G&A to the most directly comparable GAAP measure could not be reconciled without unreasonable efforts. |
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HEDGES
The following table reflects contracted volumes and weighted average prices the Company will receive under the terms of its derivative contracts as of February 20, 2025.
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January – March 2025 |
Fixed Swaps |
36,917 |
$ |
72.81 |
— |
— |
|||||||
|
Collar |
3,000 |
— |
$ |
65.00 |
$ |
84.35 |
|||||||
|
April – June 2025 |
Fixed Swaps |
38,000 |
$ |
73.45 |
— |
— |
|||||||
|
July – September 2025 |
Fixed Swaps |
20,685 |
$ |
71.81 |
— |
— |
|||||||
|
October – December 2025 |
Fixed Swaps |
18,326 |
$ |
72.33 |
— |
— |
|||||||
|
January – March 2026 |
Fixed Swaps |
11,000 |
$ |
66.45 |
— |
— |
|||||||
|
April – June 2026 |
Fixed Swaps |
10,000 |
$ |
65.47 |
— |
— |
|||||||
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|
|
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|
January – March 2025 |
Fixed Swaps |
75,000 |
$ |
3.61 |
— |
— |
|||||||
|
April – June 2025 |
Fixed Swaps |
65,000 |
$ |
3.38 |
— |
— |
|||||||
|
July – September 2025 |
Fixed Swaps |
50,000 |
$ |
3.47 |
— |
— |
|||||||
|
October – December 2025 |
Fixed Swaps |
40,000 |
$ |
3.53 |
— |
— |
|||||||
|
January – March 2026 |
Fixed Swaps |
20,000 |
$ |
3.65 |
— |
— |
|||||||
|
April – June 2026 |
Fixed Swaps |
20,000 |
$ |
3.65 |
— |
— |
|||||||
|
July – September 2026 |
Fixed Swaps |
20,000 |
$ |
3.65 |
— |
— |
|||||||
|
October – December 2026 |
Fixed Swaps |
20,000 |
$ |
3.65 |
— |
— |
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CONFERENCE CALL AND WEBCAST INFORMATION
Talos will host a conference call, which will be broadcast live over the internet, on Thursday, February 27, 2025 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/investor-relations/presentation-webcast/default.aspx#event-calendar. Alternatively, the conference call can be accessed by dialing (800) 836-8184 (North American toll-free) or (646) 357-8785 (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 March 6, 2025 and can be accessed by dialing (888) 660-6345 and using access code 46986#. For more information, please refer to the Fourth Quarter 2024 Earnings Presentation available under Presentations and Webcasts on the Investor Relations section of Talos’s website.
ABOUT TALOS ENERGY
Talos Energy (NYSE: TALO) is a technically driven, innovative, independent energy company focused on maximizing long-term value through its Upstream Exploration & Production business in the United States Gulf of America and offshore Mexico. We leverage decades of technical and offshore operational expertise to acquire, explore, and produce assets in key geological trends while maintaining a focus on safe and efficient operations, environmental responsibility, and community impact. For more information, visit www.talosenergy.com.
INVESTOR RELATIONS CONTACT
Clay Jeansonne
[email protected]
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
The information in this communication 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 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. Forward-looking statements are based on management’s 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 our current beliefs, based on currently available information, as to the outcome and timing of future events. Forward-looking statements may include statements about: business strategy; estimated ultimate recovery (EUR) and reserves; drilling prospects, inventories, projects and programs; our ability to replace the reserves that we produce through drilling and property acquisitions; financial strategy, liquidity and capital required for our development program and other capital expenditures; realized oil and natural gas prices; risks related to future mergers and acquisitions and/or to realize the expected benefits of any such transaction timing and amount of future production of oil, natural gas and NGLs; our hedging strategy and results; future drilling plans; availability of pipeline connections on economic terms; competition, government regulations, including financial assurance requirements, and legislative and political developments; our ability to obtain permits and governmental approvals, including the potential impact of the revised biological opinion by the National Marine Fisheries Service; pending legal, governmental or environmental matters; our marketing of oil, natural gas and NGLs; our integration of acquisitions and the anticipated performance of the combined company; future leasehold or business acquisitions on desired terms; costs of developing properties; general economic conditions, including the impact of sustained inflation and associated changes in monetary policy; political and economic conditions and events in foreign oil, natural gas and NGL producing countries and acts of terrorism or sabotage; credit markets; volatility in the political, legal and regulatory environments in connection with the U.S. Presidential transition and Mexican presidential transition; estimates of future income taxes; our estimates and forecasts of the timing, number, profitability and other results of wells we expect to drill and other exploration activities; our strategy with respect to our Zama asset; uncertainty regarding our future operating results and our future revenues and expenses; impact of new accounting pronouncements on earnings in future periods; recent and pending managerial changes; and plans, objectives, expectations and intentions contained in this communication that are not historical. 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; global demand for oil and natural gas; the ability or willingness of OPEC and other state-controlled oil companies to set and maintain oil production levels and the impact of any such actions; the lack of a resolution to the war in Ukraine and increasing hostilities in the Middle East, and their impact on commodity markets; the impact of any pandemic, and governmental measures related thereto; 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, winter storms and loop currents; cybersecurity threats; elevated inflation and the impact of central bank policy in response thereto; 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, including the impact of financial assurance requirements; changes in U.S. labor and trade policies, including the imposition of tariffs and the resulting consequences; 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; recent and pending management changes, including the appointment of a new Chief Executive Officer and the other risks discussed in “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2024 filed with the SEC subsequent to the issuance of this communication. 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 communication 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 communication.
PRODUCTION ESTIMATES
Estimates of 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, adverse weather conditions such as hurricanes, global political and macroeconomic events and numerous other factors. Our estimates are based on certain other assumptions, such as well performance and estimated resource potential and ultimate recovery, which may vary significantly from those assumed. Therefore, we can give no assurance that our future production volumes will be as estimated.
RESERVE INFORMATION
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. In addition, we use “estimated gross resource potential,” “gross reserves,” and “estimated ultimate recovery” (or EUR) in this release which are not measures of “reserves” prepared in accordance with SEC guidelines or permitted to be included in SEC filings. These types of resource estimates do not represent, and are not intended to represent, any category of reserves based on SEC definitions, are inherently more uncertain than estimates of proved reserves or other reserves prepared in accordance with SEC guidelines. These types of estimates are subject to a substantially greater risk of actually being realized.
USE OF NON-GAAP FINANCIAL MEASURES
This release includes the use of certain measures that have not been calculated in accordance with U.S. generally acceptable accounting principles (GAAP) such as, but not limited to, EBITDA, Adjusted EBITDA, LTM Adjusted EBITDA, Pro Forma LTM Adjusted EBITDA, Net Debt, Net Debt to LTM Adjusted EBITDA, Net Debt to Pro Forma LTM Adjusted EBITDA, Adjusted Free Cash Flow and Leverage, Adjusted EBITDA excluding hedges, Adjusted EBITDA excluding CCS, Adjusted EBITDA excluding CCS and hedges, Adjusted EBITDA Free Cash Flow excluding CCS, Adjusted Net Income (Loss) excluding CCS, Adjusted Net Income (Loss) per diluted share, General & Administrative Expenses excluding CCS, Cash Operating Expenses and Workovers, G&A and PV-10. Non-GAAP financial measures 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. Reconciliations for non-GAAP measure to GAAP measures are included at the end of this release.
|
|
||||||
|
|
||||||
|
|
|
|||||
|
|
||||||
|
Current assets: |
||||||
|
Cash and cash equivalents |
$ |
108,172 |
$ |
33,637 |
||
|
Accounts receivable: |
||||||
|
Trade, net |
236,694 |
178,977 |
||||
|
Joint interest, net |
133,562 |
79,337 |
||||
|
Other, net |
34,002 |
19,296 |
||||
|
Assets from price risk management activities |
33,486 |
36,152 |
||||
|
Prepaid assets |
77,487 |
64,387 |
||||
|
Other current assets |
35,980 |
10,389 |
||||
|
Total current assets |
659,383 |
422,175 |
||||
|
Property and equipment: |
||||||
|
Proved properties |
9,784,832 |
7,906,295 |
||||
|
Unproved properties, not subject to amortization |
587,238 |
268,315 |
||||
|
Other property and equipment |
35,069 |
34,027 |
||||
|
Total property and equipment |
10,407,139 |
8,208,637 |
||||
|
Accumulated depreciation, depletion and amortization |
(5,191,865) |
(4,168,328) |
||||
|
Total property and equipment, net |
5,215,274 |
4,040,309 |
||||
|
Other long-term assets: |
||||||
|
Restricted cash |
106,260 |
102,362 |
||||
|
Assets from price risk management activities |
253 |
17,551 |
||||
|
Equity method investments |
111,269 |
146,049 |
||||
|
Other well equipment |
58,306 |
54,277 |
||||
|
Notes receivable, net |
17,748 |
16,207 |
||||
|
Operating lease assets |
11,294 |
11,418 |
||||
|
Other assets |
12,008 |
5,961 |
||||
|
|
$ |
6,191,795 |
$ |
4,816,309 |
||
|
|
||||||
|
Current liabilities: |
||||||
|
Accounts payable |
$ |
117,055 |
$ |
84,193 |
||
|
Accrued liabilities |
326,913 |
227,690 |
||||
|
Accrued royalties |
77,672 |
55,051 |
||||
|
Current portion of long-term debt |
— |
33,060 |
||||
|
Current portion of asset retirement obligations |
97,166 |
77,581 |
||||
|
Liabilities from price risk management activities |
6,474 |
7,305 |
||||
|
Accrued interest payable |
49,084 |
42,300 |
||||
|
Current portion of operating lease liabilities |
3,837 |
2,666 |
||||
|
Other current liabilities |
44,854 |
48,769 |
||||
|
Total current liabilities |
723,055 |
578,615 |
||||
|
Long-term liabilities: |
||||||
|
Long-term debt |
1,221,399 |
992,614 |
||||
|
Asset retirement obligations |
1,052,569 |
819,645 |
||||
|
Liabilities from price risk management activities |
3,537 |
795 |
||||
|
Operating lease liabilities |
15,489 |
18,211 |
||||
|
Other long-term liabilities |
416,041 |
251,278 |
||||
|
Total liabilities |
3,432,090 |
2,661,158 |
||||
|
Commitments and contingencies |
||||||
|
Stockholdersʼ equity: |
||||||
|
Preferred stock; $0.01 par value; 30,000,000 shares authorized and zero shares issued or outstanding as of December 31, 2024 and 2023, respectively |
— |
— |
||||
|
Common stock; $0.01 par value; 270,000,000 shares authorized; 187,434,908 and 127,480,361 shares issued as of December 31, 2024 and 2023, respectively |
1,874 |
1,275 |
||||
|
Additional paid-in capital |
3,274,626 |
2,549,097 |
||||
|
Accumulated deficit |
(424,110) |
(347,717) |
||||
|
Treasury stock, at cost; 7,417,385 and 3,400,000 shares as of December 31, 2024 and 2023, respectively |
(92,685) |
(47,504) |
||||
|
Total stockholdersʼ equity |
2,759,705 |
2,155,151 |
||||
|
|
$ |
6,191,795 |
$ |
4,816,309 |
||
|
|
||||||||||||
|
|
|
|||||||||||
|
|
|
|
|
|||||||||
|
Revenues: |
||||||||||||
|
Oil |
$ |
437,914 |
$ |
362,651 |
$ |
1,806,148 |
$ |
1,357,732 |
||||
|
Natural gas |
29,840 |
14,651 |
105,528 |
68,034 |
||||||||
|
NGL |
17,431 |
7,657 |
61,892 |
32,120 |
||||||||
|
Total revenues |
485,185 |
384,959 |
1,973,568 |
1,457,886 |
||||||||
|
Operating expenses: |
||||||||||||
|
Lease operating expense |
110,206 |
103,546 |
566,041 |
389,621 |
||||||||
|
Production taxes |
133 |
638 |
1,377 |
2,451 |
||||||||
|
Depreciation, depletion and amortization |
274,554 |
183,058 |
1,023,558 |
663,534 |
||||||||
|
Accretion expense |
30,551 |
22,722 |
117,604 |
86,152 |
||||||||
|
General and administrative expense |
41,563 |
37,236 |
201,517 |
158,493 |
||||||||
|
Other operating (income) expense |
1,013 |
3,017 |
(109,454) |
(52,155) |
||||||||
|
Total operating expenses |
458,020 |
350,217 |
1,800,643 |
1,248,096 |
||||||||
|
Operating income (expense) |
27,165 |
34,742 |
172,925 |
209,790 |
||||||||
|
Interest expense |
(41,536) |
(44,295) |
(187,638) |
(173,145) |
||||||||
|
Price risk management activities income (expense) |
(42,989) |
94,596 |
(1,458) |
80,928 |
||||||||
|
Equity method investment income (expense) |
(1,235) |
(6,147) |
(10,289) |
(3,209) |
||||||||
|
Other income (expense) |
3,535 |
1,921 |
(44,930) |
12,371 |
||||||||
|
Net income (loss) before income taxes |
(55,060) |
80,817 |
(71,390) |
126,735 |
||||||||
|
Income tax benefit (expense) |
(9,448) |
5,081 |
(5,003) |
60,597 |
||||||||
|
|
$ |
(64,508) |
$ |
85,898 |
$ |
(76,393) |
$ |
187,332 |
||||
|
Net income (loss) per common share: |
||||||||||||
|
Basic |
$ |
(0.36) |
$ |
0.69 |
$ |
(0.44) |
$ |
1.58 |
||||
|
Diluted |
$ |
(0.36) |
$ |
0.69 |
$ |
(0.44) |
$ |
1.57 |
||||
|
Weighted average common shares outstanding: |
||||||||||||
|
Basic |
180,064 |
124,150 |
175,605 |
118,459 |
||||||||
|
Diluted |
180,064 |
125,173 |
175,605 |
119,262 |
||||||||
|
|
|||||||||
|
|
|||||||||
|
|
|
|
|||||||
|
Cash flows from operating activities: |
|||||||||
|
Net income (loss) |
$ |
(76,393) |
$ |
187,332 |
$ |
381,915 |
|||
|
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities |
|||||||||
|
Depreciation, depletion, amortization and accretion expense |
1,141,162 |
749,686 |
470,625 |
||||||
|
Amortization of deferred financing costs and original issue discount |
9,303 |
15,039 |
14,379 |
||||||
|
Equity-based compensation expense |
14,462 |
12,953 |
15,953 |
||||||
|
Price risk management activities (income) expense |
1,458 |
(80,928) |
272,191 |
||||||
|
Net cash received (paid) on settled derivative instruments |
4,710 |
(9,457) |
(425,559) |
||||||
|
Equity method investment (income) expense |
10,289 |
3,209 |
(14,222) |
||||||
|
Loss (gain) on extinguishment of debt |
60,256 |
— |
1,569 |
||||||
|
Settlement of asset retirement obligations |
(108,789) |
(86,615) |
(69,596) |
||||||
|
Loss (gain) on sale of assets |
38 |
(66,115) |
303 |
||||||
|
Loss (gain) on sale of business |
(100,482) |
— |
— |
||||||
|
Changes in operating assets and liabilities: |
|||||||||
|
Accounts receivable |
8,576 |
20,352 |
14,927 |
||||||
|
Other current assets |
(6,964) |
7,066 |
(36,545) |
||||||
|
Accounts payable |
(3,831) |
(60,401) |
24,258 |
||||||
|
Other current liabilities |
1,290 |
(96,960) |
73,531 |
||||||
|
Other non-current assets and liabilities, net |
7,508 |
(76,092) |
(13,990) |
||||||
|
Net cash provided by (used in) operating activities |
962,593 |
519,069 |
709,739 |
||||||
|
Cash flows from investing activities: |
|||||||||
|
Exploration, development and other capital expenditures |
(508,914) |
(561,434) |
(323,164) |
||||||
|
Cash acquired in excess of payments for acquisitions |
— |
17,617 |
— |
||||||
|
Payments for acquisitions, net of cash acquired |
(936,214) |
— |
(3,500) |
||||||
|
Proceeds from (cash paid for) sale of property and equipment, net |
1,161 |
73,004 |
1,937 |
||||||
|
Contributions to equity method investees |
(22,988) |
(29,447) |
(2,250) |
||||||
|
Investment in intangible assets |
— |
(12,366) |
— |
||||||
|
Proceeds from sales of business |
146,676 |
— |
— |
||||||
|
Proceeds from sale of equity method investment |
— |
— |
15,000 |
||||||
|
Net cash provided by (used in) investing activities |
(1,320,279) |
(512,626) |
(311,977) |
||||||
|
Cash flows from financing activities: |
|||||||||
|
Issuance of common stock |
387,717 |
— |
— |
||||||
|
Issuance of senior notes |
1,250,000 |
— |
— |
||||||
|
Redemption of senior notes |
(897,116) |
(30,000) |
(18,184) |
||||||
|
Proceeds from Bank Credit Facility |
880,000 |
825,000 |
85,000 |
||||||
|
Repayment of Bank Credit Facility |
(1,080,000) |
(625,000) |
(460,000) |
||||||
|
Deferred financing costs |
(32,872) |
(11,775) |
(189) |
||||||
|
Other deferred payments |
(2,389) |
(1,545) |
— |
||||||
|
Payments of finance lease |
(17,834) |
(16,306) |
(25,493) |
||||||
|
Purchase of treasury stock |
(45,181) |
(47,504) |
— |
||||||
|
Employee stock awards tax withholdings |
(6,206) |
(7,459) |
(4,603) |
||||||
|
Net cash provided by (used in) financing activities |
436,119 |
85,411 |
(423,469) |
||||||
|
Net increase (decrease) in cash, cash equivalents and restricted cash |
78,433 |
91,854 |
(25,707) |
||||||
|
Cash, cash equivalents and restricted cash: |
|||||||||
|
Balance, beginning of period |
135,999 |
44,145 |
69,852 |
||||||
|
Balance, end of period |
$ |
214,432 |
$ |
135,999 |
$ |
44,145 |
|||
|
Supplemental non-cash transactions: |
|||||||||
|
Capital expenditures included in accounts payable and accrued liabilities |
$ |
85,550 |
$ |
114,972 |
$ |
105,773 |
|||
|
Supplemental cash flow information: |
|||||||||
|
Interest paid, net of amounts capitalized |
$ |
130,841 |
$ |
130,313 |
$ |
91,809 |
|||
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 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. In addition, we believe that non-GAAP measures excluding CCS are a meaningful measure of financial performance that can be used by investors, analysts and management in evaluating the performance of our “go-forward” business after giving effect to our CCS divestiture during the first quarter of 2024, and will assist such readers of our financial statements in considering the results of this business in comparative periods.
Reconciliation of General and Administrative Expenses to Adjusted General and Administrative Expenses Excluding CCS
We believe the presentation of Adjusted General and Administrative Expenses excluding CCS 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. Adjusted General & Administrative Expenses excluding CCS 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:
General and Administrative Expenses. General and Administrative Expenses generally consist of costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production operations, bad debt expense, equity-based compensation expense, audit and other fees for professional services and legal compliance. A portion of these expenses are allocated based on the percentage of employees dedicated to each operating segment.
|
|
|
|
||||
|
|
||||||
|
Total General and administrative expense |
$ |
41,563 |
$ |
201,517 |
||
|
CCS Segment |
(59) |
(10,454) |
||||
|
Transaction and other expenses(1) |
(1,047) |
(45,953) |
||||
|
Non-cash equity-based compensation expense |
(5,603) |
(14,415) |
||||
|
Adjusted General & Administrative Expenses excluding CCS |
$ |
34,854 |
$ |
130,695 |
||
|
_________________________ |
|
|
(1) |
For the twelve months ended December 31, 2024, transaction expenses include $39.1 million in costs related to the QuarterNorth Acquisition, inclusive of $22.2 million in severance expense, $8.5 million in costs related to the TLCS Divestiture, inclusive of a net $3.0 million in severance expense, and $5.0 million in severance expense related to the departure of the Company’s President and Chief Executive Officer. |
Reconciliation of Net Income (Loss) to EBITDA, Adjusted EBITDA, and Adjusted EBITDA Excluding CCS
“EBITDA,” “Adjusted EBITDA” and “Adjusted EBITDA excluding CCS” 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, Adjusted EBITDA, and Adjusted EBITDA excluding CCS 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 other (income) expenses, decommissioning obligations, the net change in fair value of derivatives (mark to market effect, net of cash settlements and premiums related to these derivatives), (gain) loss on debt extinguishment, non-cash write-down of other well equipment and non-cash equity-based compensation expense.
Adjusted EBITDA excluding hedges. We have historically provided as a supplement to—rather than in lieu of—Adjusted EBITDA including hedges, provides useful information regarding our results of operations and profitability by illustrating the operating results of our oil and natural gas properties without the benefit or detriment, as applicable, of our financial oil and natural gas hedges. By excluding our oil and natural gas hedges, we are able to convey actual operating results using realized market prices during the period, thereby providing analysts and investors with additional information they can use to evaluate the impacts of our hedging strategies over time.
Adjusted EBITDA excluding CCS. Adjusted EBITDA plus equity method investment loss, general and administrative expense, other operating expenses (income), other income, and non-cash equity-based compensation expense attributable to CCS.
The following tables present a reconciliation of the GAAP financial measure of Net Income (loss) to EBITDA, Adjusted EBITDA, Adjusted EBITDA excluding hedges for each of the periods indicated (in thousands):
|
|
||||||||||||
|
|
|
|
|
|
||||||||
|
|
||||||||||||
|
Net Income (loss) |
$ |
(64,508) |
$ |
88,173 |
$ |
12,381 |
$ |
(112,439) |
||||
|
Interest expense |
41,536 |
46,275 |
48,982 |
50,845 |
||||||||
|
Income tax expense (benefit) |
9,448 |
18,111 |
(983) |
(21,573) |
||||||||
|
Depreciation, depletion and amortization |
274,554 |
274,249 |
259,091 |
215,664 |
||||||||
|
Accretion expense |
30,551 |
29,418 |
30,732 |
26,903 |
||||||||
|
EBITDA |
291,581 |
456,226 |
350,203 |
159,400 |
||||||||
|
Transaction and other (income) expenses(1) |
1,193 |
(17,687) |
6,629 |
(49,157) |
||||||||
|
Decommissioning obligations(2) |
797 |
2,725 |
4,182 |
855 |
||||||||
|
Derivative fair value (gain) loss(3) |
42,989 |
(126,291) |
(2,302) |
87,062 |
||||||||
|
Net cash received (paid) on settled derivative instruments(3) |
19,651 |
6,071 |
(17,518) |
(3,494) |
||||||||
|
Loss on extinguishment of debt |
— |
— |
— |
60,256 |
||||||||
|
Non-cash equity-based compensation expense |
5,603 |
3,315 |
2,790 |
2,754 |
||||||||
|
Adjusted EBITDA |
361,814 |
324,359 |
343,984 |
257,676 |
||||||||
|
Add: Net cash (received) paid on settled derivative instruments(3) |
(19,651) |
(6,071) |
17,518 |
3,494 |
||||||||
|
Adjusted EBITDA excluding hedges |
$ |
342,163 |
$ |
318,288 |
$ |
361,502 |
$ |
261,170 |
||||
|
_________________________ |
|
|
(1) |
For the three months ended September 30, 2024, transaction expenses includes $4.7 million in severance costs related to the departure of the Company’s former President and Chief Executive Officer on August 29, 2024; $9.3 million in costs related to the QuarterNorth Acquisition, inclusive of $8.1 million in severance expense for the three months ended June 30, 2024; $28.1 million in costs related to the QuarterNorth acquisition, inclusive of $14.2 million in severance expense and $9.8 million in costs related to the divestiture of TLCS, inclusive of $3.7 million in severance expense for the three months ended March 31, 2024. Other income (expense) includes restructuring expenses, cost saving initiatives and other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the three months ended September 30, 2024, it includes an incremental $13.5 million gain on the TLCS Divestiture due to the recognition of contingent consideration as well as a $7.0 million increase in fair value of a service credit acquired via the QuarterNorth Acquisition. For the three months ended March 31, 2024, the amount includes a gain of $86.9 million related to the divestiture of TLCS. |
|
(2) |
Estimated decommissioning obligations were 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 and are included in “Other operating (income) expense” on our consolidated statements of operations. |
|
(3) |
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. |
|
|
||||||||||||
|
|
|
|
|
|
||||||||
|
|
||||||||||||
|
Adjusted EBITDA |
$ |
361,814 |
$ |
324,359 |
$ |
343,984 |
$ |
257,676 |
||||
|
CCS Costs: |
||||||||||||
|
Equity method investment loss |
— |
— |
— |
7,970 |
||||||||
|
General and administrative expense |
59 |
(577) |
(796) |
11,768 |
||||||||
|
Other operating expense |
— |
— |
— |
(11) |
||||||||
|
Other income |
— |
— |
— |
(5) |
||||||||
|
Transaction and other (income) expenses(3) |
(59) |
577 |
796 |
(9,803) |
||||||||
|
Non-cash equity-based compensation expense |
— |
— |
— |
(47) |
||||||||
|
Adjusted EBITDA excluding CCS |
361,814 |
324,359 |
343,984 |
267,548 |
||||||||
|
Add: Net cash paid on settled derivative instruments(1) |
(19,651) |
(6,071) |
17,518 |
3,494 |
||||||||
|
Adjusted EBITDA excluding CCS and hedges |
$ |
342,163 |
$ |
318,288 |
$ |
361,502 |
$ |
271,042 |
||||
|
Production: |
||||||||||||
|
Boe(2) |
9,081 |
8,878 |
8,686 |
7,248 |
||||||||
|
Adjusted EBITDA excluding CCS margin and Adjusted EBITDA excluding CCS and hedges margin: |
||||||||||||
|
Adjusted EBITDA excluding CCS per Boe(2) |
$ |
39.84 |
$ |
36.54 |
$ |
39.60 |
$ |
36.91 |
||||
|
Adjusted EBITDA excluding CCS and hedges per Boe(1)(2) |
$ |
37.68 |
$ |
35.85 |
$ |
41.62 |
$ |
37.40 |
||||
|
_________________________ |
|
|
(1) |
The adjustments for the derivative fair value (gain) loss and net cash receipts (payments) on settled derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled. |
|
(2) |
One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities. |
|
(3) |
For the three months ended March 31, 2024, transaction expenses includes $9.8 million in costs related to the divestiture of TLCS, inclusive of $3.7 million in severance expense. |
Reconciliation of Adjusted EBITDA to Adjusted Free Cash Flow Excluding CCS and Reconciliation of Net Cash Provided by Operating Activities to Adjusted Free Cash Flow Excluding CCS
“Adjusted Free Cash Flow excluding CCS” 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. Adjusted Free Cash Flow excluding CCS 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 income taxes in the period, therefore cash income taxes have no impact to the reported Adjusted Free Cash Flow before changes in working capital number.
|
|
|
|
||||
|
|
||||||
|
Adjusted EBITDA |
$ |
361,814 |
$ |
1,287,833 |
||
|
Upstream Capital expenditures |
(129,888) |
(484,060) |
||||
|
Plugging & abandonment |
(22,715) |
(108,789) |
||||
|
Decommissioning obligations settled |
(353) |
(5,447) |
||||
|
Investment in Mexico |
(3,361) |
(5,469) |
||||
|
CCS capital expenditures |
— |
(17,519) |
||||
|
Interest expense(1) |
(41,536) |
(182,763) |
||||
|
Adjusted Free Cash Flow (before changes in working capital) |
163,961 |
483,786 |
||||
|
CCS capital expenditures |
— |
17,519 |
||||
|
CCS Costs: |
||||||
|
Equity method investment loss |
— |
7,970 |
||||
|
General and administrative expense |
59 |
10,454 |
||||
|
Other operating expense |
— |
(11) |
||||
|
Other income |
— |
(5) |
||||
|
Transaction and other (income) expenses(2) |
(59) |
(8,489) |
||||
|
Non-cash equity-based compensation expense |
— |
(47) |
||||
|
Adjusted Free Cash Flow excluding CCS (before changes in working capital) |
$ |
163,961 |
$ |
511,177 |
||
|
_________________________ |
|
|
(1) |
Interest expense excludes $4.9 million in fees associated with the unutilized bridge loan that we do not view as a meaningful indicator of our operating performance. |
|
(2) |
For the twelve months ended December 31, 2024, transaction expenses includes $8.5 million in costs related to the TLCS Divestiture, inclusive of a net $3.0 million in severance expense. |
|
|
|
|
||||
|
|
||||||
|
Net cash provided by operating activities(1) |
$ |
349,337 |
$ |
962,593 |
||
|
(Increase) decrease in operating assets and liabilities |
(49,497) |
(6,579) |
||||
|
Upstream Capital expenditures(2) |
(129,889) |
(484,060) |
||||
|
Decommissioning obligations settled |
(353) |
(5,447) |
||||
|
Investment in Mexico |
(3,361) |
(5,469) |
||||
|
CCS capital expenditures |
— |
(17,519) |
||||
|
Transaction and other (income) expenses(3) |
(11,874) |
41,460 |
||||
|
Decommissioning obligations(4) |
797 |
8,559 |
||||
|
Amortization of deferred financing costs and original issue discount |
(2,373) |
(9,303) |
||||
|
Income tax benefit |
9,448 |
5,003 |
||||
|
Other adjustments |
1,726 |
(5,452) |
||||
|
Adjusted Free Cash Flow (before changes in working capital) |
163,961 |
483,786 |
||||
|
CCS capital expenditures |
— |
17,519 |
||||
|
CCS Costs: |
||||||
|
Equity method investment loss |
— |
7,970 |
||||
|
General and administrative expense |
59 |
10,454 |
||||
|
Other operating expense |
— |
(11) |
||||
|
Other income |
— |
(5) |
||||
|
Transaction and other (income) expenses(5) |
(59) |
(8,489) |
||||
|
Non-cash equity-based compensation expense |
— |
(47) |
||||
|
Adjusted Free Cash Flow excluding CCS (before changes in working capital) |
$ |
163,961 |
$ |
511,177 |
||
|
_________________________ |
|
|
(1) |
Includes settlement of asset retirement obligations. |
|
(2) |
Includes accruals and excludes acquisitions. |
|
(3) |
For the twelve months ended December 31, 2024, transaction expenses include $39.1 million in costs related to the QuarterNorth Acquisition, inclusive of $22.2 million in severance expense, $8.5 million in costs related to the TLCS Divestiture, inclusive of a net $3.0 million in severance expense, and $5.0 million in severance expense related to the departure of the Company’s President and Chief Executive Officer. Other income (expense) includes restructuring expenses, cost saving initiatives and other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the twelve months ended December 31, 2024, the amount includes a $9.5 million gain related to an increase in fair value of a service credit acquired via the QuarterNorth Acquisition. |
|
(4) |
Estimated decommissioning obligations were 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. |
|
(5) |
For the twelve months ended December 31, 2024, transaction expenses includes $8.5 million in costs related to the TLCS Divestiture, inclusive of a net $3.0 million in severance expense. |
Reconciliation of Net Income to Adjusted Net Income (Loss) and Adjusted Earnings per Share and to Adjusted Net Income (Loss) excluding CCS and Adjusted Earnings per Share excluding CCS
“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.
|
|
|
|||||||||||||||||
|
|
|
|
|
|
||||||||||||||
|
|
||||||||||||||||||
|
Net Income (loss) |
$ |
(64,508) |
$ |
(0.36) |
$ |
(0.36) |
$ |
(76,393) |
$ |
(0.44) |
$ |
(0.44) |
||||||
|
Transaction and other (income) expenses(1) |
1,193 |
$ |
0.01 |
$ |
0.01 |
(59,022) |
$ |
(0.34) |
$ |
(0.34) |
||||||||
|
Decommissioning obligations(2) |
797 |
$ |
0.00 |
$ |
0.00 |
8,559 |
$ |
0.05 |
$ |
0.05 |
||||||||
|
Derivative fair value loss(3) |
42,989 |
$ |
0.24 |
$ |
0.24 |
1,458 |
$ |
0.01 |
$ |
0.01 |
||||||||
|
Net cash received on paid derivative instruments(3) |
19,651 |
$ |
0.11 |
$ |
0.11 |
4,710 |
$ |
0.03 |
$ |
0.03 |
||||||||
|
Unutilized bridge loan fees |
— |
$ |
— |
$ |
— |
4,875 |
$ |
0.03 |
$ |
0.03 |
||||||||
|
Non-cash income tax benefit |
9,448 |
$ |
0.05 |
$ |
0.05 |
5,003 |
$ |
0.03 |
$ |
0.03 |
||||||||
|
Loss on extinguishment of debt |
— |
$ |
— |
$ |
— |
60,256 |
$ |
0.34 |
$ |
0.34 |
||||||||
|
Non-cash equity-based compensation expense |
5,603 |
$ |
0.03 |
$ |
0.03 |
14,462 |
$ |
0.08 |
$ |
0.08 |
||||||||
|
Adjusted Net Income (Loss)(4) |
$ |
15,173 |
$ |
0.08 |
$ |
0.08 |
$ |
(36,092) |
$ |
(0.21) |
$ |
(0.21) |
||||||
|
CCS Costs: |
||||||||||||||||||
|
Equity method investment loss |
— |
$ |
— |
$ |
— |
7,970 |
$ |
0.05 |
$ |
0.05 |
||||||||
|
Depreciation, depletion and amortization |
— |
$ |
— |
$ |
— |
22 |
$ |
0.00 |
$ |
0.00 |
||||||||
|
General and administrative expense |
59 |
$ |
0.00 |
$ |
0.00 |
10,454 |
$ |
0.06 |
$ |
0.06 |
||||||||
|
Other operating expense |
— |
$ |
— |
$ |
— |
(11) |
$ |
(0.00) |
$ |
(0.00) |
||||||||
|
Other income |
— |
$ |
— |
$ |
— |
(5) |
$ |
(0.00) |
$ |
(0.00) |
||||||||
|
Transaction and other (income) expenses(5) |
(59) |
$ |
(0.00) |
$ |
(0.00) |
(8,489) |
$ |
(0.05) |
$ |
(0.05) |
||||||||
|
Non-cash equity-based compensation expense |
— |
$ |
— |
$ |
— |
(47) |
$ |
(0.00) |
$ |
(0.00) |
||||||||
|
Adjusted Net Income (Loss) excluding CCS(4) |
$ |
15,173 |
$ |
0.08 |
$ |
0.08 |
$ |
(26,198) |
$ |
(0.15) |
$ |
(0.15) |
||||||
|
Weighted average common shares outstanding at December 31, 2024: |
||||||||||||||||||
|
Basic |
180,064 |
175,605 |
||||||||||||||||
|
Diluted |
180,686 |
175,605 |
||||||||||||||||
|
_________________________ |
|
|
(1) |
For the twelve months ended December 31, 2024, transaction expenses include $39.1 million in costs related to the QuarterNorth Acquisition, inclusive of $22.2 million in severance expense, $8.5 million in costs related to the TLCS Divestiture, inclusive of a net $3.0 million in severance expense, and $5.0 million in severance expense related to the departure of the Company’s President and Chief Executive Officer. Other income (expense) includes other miscellaneous income and expenses that the Company does not view as a meaningful indicator of its operating performance. For the twelve months ended December 31, 2024, the amount includes a gain of $100.4 million related to the TLCS Divestiture and a $9.5 million gain related to an increase in fair value of a service credit acquired via the QuarterNorth Acquisition. |
|
(2) |
Estimated decommissioning obligations were 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. |
|
(3) |
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. |
|
(4) |
The per share impacts reflected in this table were calculated independently and may not sum to total adjusted basic and diluted EPS due to rounding. |
|
(5) |
For the twelve months ended December 31, 2024, transaction expenses includes $8.5 million in costs related to the TLCS Divestiture, inclusive of a net $3.0 million in severance expense. |
Reconciliation of Total Debt to Net Debt and Net Debt to LTM Adjusted EBITDA
We believe the presentation of Net Debt, LTM Adjusted EBITDA, Net Debt to LTM Adjusted EBITDA and Net Debt to Pro Forma 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 minus cash and cash equivalents.
Net Debt to LTM Adjusted EBITDA. Net Debt divided by the LTM Adjusted EBITDA.
|
|
|
||
|
|
|||
|
9.000% Second-Priority Senior Secured Notes – due February 2029 |
$ |
625,000 |
|
|
9.375% Second-Priority Senior Secured Notes – due February 2031 |
625,000 |
||
|
Bank Credit Facility – matures March 2027 |
— |
||
|
Total Debt |
1,250,000 |
||
|
Less: Cash and cash equivalents |
(108,172) |
||
|
Net Debt |
$ |
1,141,828 |
|
|
Calculation of LTM Adjusted EBITDA: |
|||
|
Adjusted EBITDA for three months period ended March 31, 2024 |
$ |
257,676 |
|
|
Adjusted EBITDA for three months period ended June 30, 2024 |
343,984 |
||
|
Adjusted EBITDA for three months period ended September 30, 2024 |
324,359 |
||
|
Adjusted EBITDA for three months period ended December 31, 2024 |
361,814 |
||
|
LTM Adjusted EBITDA |
$ |
1,287,833 |
|
|
Acquired Assets Adjusted EBITDA: |
|||
|
Adjusted EBITDA for period January 1, 2024 to March 4, 2024 |
99,490 |
||
|
LTM Adjusted EBITDA from Acquired Assets |
$ |
99,490 |
|
|
Pro Forma LTM Adjusted EBITDA |
$ |
1,387,323 |
|
|
|
|||
|
Net Debt / Pro Forma LTM Adjusted EBITDA(1) |
0.8x |
||
|
_________________________ |
|
|
(1) |
Net Debt / Pro Forma LTM Adjusted EBITDA figure excludes the Finance Lease. Had the Finance Lease been included, Net Debt / Pro Forma LTM Adjusted EBITDA would have been 0.9x. |
Reconciliation of PV-10 to Standardized Measure – Proved Reserves
Reconciliation of PV-10 to Standardized Measure PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of the Company’s properties. Talos and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies’ properties without regard to the specific tax characteristics of such entities. PV-10 may be reconciled to the Standardized Measure of discounted future net cash flows at such dates by adding the discounted future income taxes associated with such reserves to the Standardized Measure.
The table below presents the reconciliation of the standardized measure of discounted future net cash flows to PV-10 of our proved reserves:
|
|
|
||
|
Standardized measure (1)(2) |
$ |
3,564,204 |
|
|
Present value of future income taxes discounted at 10% |
636,520 |
||
|
PV-10 (Non-GAAP) |
$ |
4,200,724 |
|
|
_________________________ |
|
|
(1) |
All estimated future costs to settle asset retirement obligations associated with our proved reserves have been included in our calculation of the standardized measure for the period presented. |
|
(2) |
Standardized measure is based on management estimates and is not audited by third party reserve engineers. |
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SOURCE Talos Energy
