HOUSTON, Feb. 28, 2023 /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, 2022. The Company also announced its year-end 2022 reserves figures pro forma for the recently closed acquisition, as well as 2023 operational and financial guidance for the combined company. Finally, Talos announced its participation in a major onshore CO2 sequestration leasehold in southeast Texas, bringing gross storage capacity in the region to more than 1 billion tons of CO2 in close proximity to multiple large industrial markets.
Fourth Quarter 2022 Highlights:
- Production of 56.6 thousand barrels of oil equivalent per day (“MBoe/d”) (68% oil, 76% liquids), inclusive of impacts from loop currents, planned and unplanned maintenance, and other miscellaneous items.
- Net Income of $2.8 million, or $0.03 Net Income per diluted share, and Adjusted Net Income(1) of $16.6 million, or $0.20 Adjusted Net Income per diluted share.
- Adjusted EBITDA(1) of $185.2 million; Adjusted EBITDA excluding hedges(1) of $242.3 million.
- Capital Expenditures of $155.9 million, inclusive of plugging and abandonment and the settlement of decommissioning obligations.
- Paid off the balance of the Company’s credit facility, bringing leverage to 0.7x(1) and liquidity of $846.5 million at year-end.
- Advanced sustainability disclosure with the issuance of 3rd ESG report and inaugural TCFD report.
Full Year 2022 Highlights:
- Production of 59.5 MBoe/d (67% oil, 75% liquids).
- Net Income of $381.9 million, or $4.56 Net Income per diluted share, and Adjusted Net Income(1) of $244.1 million, or $2.92 Adjusted Net Income per diluted share(1).
- Adjusted EBITDA(1) of $841.8 million; Adjusted EBITDA excluding hedges(1) of $1,267.3 million.
- Net cash provided by operating activities of $709.7 million.
- Capital Expenditures of $455.5 million, inclusive of plugging and abandonment and the settlement of decommissioning obligations.
- Adjusted Free Cash Flow(1) (before changes in working capital) of $260.8 million.
- Repaid $392.5 million in credit facility borrowings and second lien notes in 2022.
- Announced and subsequently closed the acquisition of EnVen Energy Corporation (“EnVen”) for approximately $1.1 billion.
- Enhanced the Carbon Capture & Sequestration (“CCS”) portfolio to nearly 1 billion metrics tons of saline aquifer storage capacity and added strategic partners.
2023 Guidance and Long-Term Outlook
- Pro forma Proved reserves (1P reserves) at year-end 2022 of 190.0 MMBoe, with a standardized measure of $6.0 billion and with a PV-10(1)(4) of $7.2 billion(2) at year end based on SEC prices (price sensitivity included further below).
- Production between 72.0 and 76.0 MBoe/d, including 10.5 months of production from the recent EnVen acquisition.
- Oil and gas capital investments of $650 to $675 million focused on developing recent drilling successes.
- CCS investments between $70 and $90 million, which may grow as additional key milestones and further portfolio expansions are achieved.
- Expected production growth of approximately 20-25% between 2023 and 2026, or a compound annual growth rate (“CAGR”) of 6-8% per year over the same period.
- Projected cumulative Adjusted Free Cash Flow(5) of $1.7–$2.0 billion through 2026, assuming current strip pricing or $2.0–$2.5 billion assuming a flat $75/Bbl and $3.50/Mcf price deck, equating to approximately 75%-90% and 90%-110% of the Company’s current market capitalization, respectively.
- Capital allocation framework focused on continued debt reduction, investment in key Upstream and CCS catalysts, and providing a path towards returning capital to shareholders. Additionally, Talos would consider participating in share repurchases in the event of any potential significant monetization by private equity holders, subject to Board approvals.
Talos President and Chief Executive Officer Timothy S. Duncan commented: “2022 was full of milestones for Talos. We used our meaningful free cash flow generation to pay our revolver borrowings to zero at year-end. We also ended the year with a leverage ratio of 0.7x – well below our goal of 1.0x or below – and ended the year with record liquidity. In late 2022 we announced and closed in February 2023 a major acquisition that not only adds significant scale and asset diversity to our portfolio but is also very beneficial to Talos’s shareholders. In our CCS business, we completed a first-of-its-kind CO2 storage transaction with Chevron early in the year, welcoming their considerable experience into our Bayou Bend project in southeast Texas.”
Duncan continued: “We have a very positive outlook as we look forward to a busy 2023. Over the last four months, and pro-forma for our recent transaction, we have drilled six successful wells from our open water subsea and platform rig programs. We are prioritizing the acceleration to first oil from these discoveries in our 2023 capital program, with the most impactful production growth in 2024. We believe our remaining 2023 projects will help us achieve our target production growth rate while lowering our reinvestment rate over time, providing ample capital allocation opportunities. With Talos Low Carbon Solutions, we continue to add strategic U.S. Gulf Coast leasehold for CO2 storage to build the largest carbon sequestration portfolio in the United States, while advancing our efforts to build additional strategic partnerships and to attract captured CO2 volumes. Today we announced exactly that – an expansion of our partnership with Chevron in Southeast Texas with an additional major leasehold acquisition, bringing our total storage capacity in the region to over 1 billion tons, one of the largest CCS project sites in the United States.
“With respect to capital allocation, our priority continues to be generating free cash flow and lowering our total quantum of debt post-closing of our recent acquisition while also investing in our key catalysts. That includes the continuation of CCS growth and potential Upstream M&A opportunities. However, we are also very focused on building out a capital return model. That could include Talos participating in a share buyback program associated with private equity shareholder liquidity events that could occur over the next several years, helping to alleviate the short-term technical impact to Talos’s shareholder base. Our team is committed to building a diverse and sustainable energy company and we could not be more excited to see what the next twelve months bring.”
RECENT DEVELOPMENTS AND OPERATIONS UPDATE
EnVen Acquisition: On February 13, 2023, Talos closed the previously announced acquisition of EnVen. The strategic transaction expands Talos’s Gulf of Mexico operations with high margin, oil-weighted assets and significant operated infrastructure. In 2022, EnVen’s estimated production was between 22.7 – 23.0 MBoe/d. Talos’s full year 2023 operational and financial guidance includes 10.5 months of contributions from the acquired assets.
Southeast Texas CCS: Talos has elected to participate alongside Chevron in an onshore CO2 sequestration leasehold in southeast Texas. Combined with the offshore Bayou Bend CCS pore space, the total acreage equates to a gross storage resource of more than 1 billion tons of CO2 to serve multiple industrial markets within the region.
Coastal Bend CCS: In February 2023, Talos Low Carbon Solutions, Howard Energy Partners (“Howard”), the Port of Corpus Christi Authority (“POCCA”) and the Texas A&M University System were selected for a $9.0 million grant from the U.S. Department of Energy’s Carbon Storage Assurance Facility Enterprise (“CarbonSAFE”) program. Grant funding will directly reimburse a majority of upcoming technical and economic feasibility costs including a stratigraphic evaluation well, FEED studies and other key project workstreams. Award of the grant is subject to final negotiation with the Department of Energy. Additionally, Talos and Howard entered into a definitive lease agreement with the POCCA to lease the initial 13,000 acres for the sequestration storage location.
Drilling & Completions Updates:
Throughout the fourth quarter of 2022 and early 2023 Talos had six successful drilling projects, inclusive of the Company’s operated open water and platform rig programs, non-operated projects and projects contributed by the Company’s recent EnVen acquisition. The discoveries will significantly impact production growth over the next 18 months.
- Lime Rock and Venice: The two prospects successfully discovered commercial quantities of oil and natural gas. Talos expects combined gross production rates of approximately 15-20 MBoe/d from expected combined gross recoverable resources of 20-30 MMBoe. Both wells will be subsea tie-backs to the Talos owned and operated Ram Powell facility and are expected online by the first quarter of 2024. Talos owns a 60% working interest in both wells.
- Pompano: The Mount Hunter development well successfully discovered commercial quantities of oil and natural gas during the first quarter of 2023. Talos expects gross production rates of approximately 2-4 MBoe/d from expected gross recoverable resources of 5-6 MMBoe. First production is expected by the second quarter of 2023. Talos owns a 100% working interest.
- Lobster: In the Lobster platform, the A-26 ST well found pay in multiple field horizons and will achieve first production in the first quarter. Talos owns a 67% working interest. Lobster was part of the recently acquired EnVen portfolio.
- Gunflint: The Gunflint #1-ST well successfully discovered commercial quantities of oil and gas. The well will be completed and tied back with first oil expected by mid-year 2023. Talos holds a 9.6% working interest.
- Spruance: The Spruance West discovery well was drilled in the fourth quarter of 2022 and was part of the recently acquired EnVen portfolio. The well achieved an initial gross production rate of over 3.0 MBoe/d. Talos owns a 13.5% working interest.
- Puma West: The Puma West appraisal well (“PW #2”) was drilled to a total depth of 25,995 feet followed by a sidetrack (“PW #2ST”) which was drilled geologically down-dip to a total depth of 27,650 feet (collectively the “appraisal wells”). The appraisal wells encountered hydrocarbons in multiple sands. However, additional hydrocarbons from a subsequent well or sidetrack would likely be necessary to consider moving forward with a development. The PW #2 wellbore has been temporarily suspended with utility to allow for future potential sidetrack opportunities. The participating parties will begin incorporating the data acquired from the appraisal wells to determine the best path forward. Talos owns a 25% working interest with Chevron (25%) and bp (50% and Operator).
FOURTH QUARTER AND FULL YEAR 2022 RESULTS
Key Financial Highlights:
|
($ thousands): |
Three Months Ended |
Twelve Months Ended |
||||
|
Total revenues |
$ |
342,201 |
$ |
1,651,980 |
||
|
Net income |
$ |
2,750 |
$ |
381,915 |
||
|
Net income per diluted share |
$ |
0.03 |
$ |
4.56 |
||
|
Adjusted Net Income(1) |
$ |
16,637 |
$ |
244,082 |
||
|
Adjusted Net Income per diluted share(1) |
$ |
0.20 |
$ |
2.92 |
||
|
Adjusted EBITDA(1) |
$ |
185,224 |
$ |
841,774 |
||
|
Adjusted EBITDA excluding hedges(1) |
$ |
242,300 |
$ |
1,267,333 |
||
|
Capital Expenditures (including Plug & Abandonment and Decommissioning Obligations Settled) |
$ |
155,939 |
$ |
455,452 |
||
|
Adjusted EBITDA Margin: |
||||||
|
Adjusted EBITDA per Boe |
$ |
35.57 |
$ |
38.75 |
||
|
Adjusted EBITDA excluding hedges per Boe |
$ |
46.53 |
$ |
58.34 |
||
Capital Expenditures
Capital expenditures, including plugging and abandonment and the settlement of decommissioning obligations, totaled $155.9 million for the fourth quarter 2022 and $455.5 million for the full year ended 2022.
|
Three Months Ended |
Twelve Months Ended |
|||||
|
Capital Expenditures |
||||||
|
U.S. Drilling & Completions |
$ |
113,663 |
$ |
234,173 |
||
|
Mexico Appraisal & Exploration |
71 |
372 |
||||
|
Asset Management(6) |
21,323 |
102,027 |
||||
|
Seismic and G&G / Land / Capitalized G&A and other |
9,214 |
44,881 |
||||
|
CCS(7) |
751 |
2,778 |
||||
|
Total Capital Expenditures |
145,022 |
384,231 |
||||
|
Plugging & Abandonment |
9,292 |
69,596 |
||||
|
Decommissioning Obligations Settled(8) |
1,625 |
1,625 |
||||
|
Total |
$ |
155,939 |
$ |
455,452 |
||
Liquidity and Leverage
At year-end 2022 the Company had approximately $846.5 million of liquidity, with $806.3 million undrawn on its credit facility and approximately $44.1 million in cash, less approximately $3.9 million in outstanding letters of credit. On December 31, 2022, Talos had $638.5 million in total debt. Net Debt was $594.4 million(1). Net Debt to LTM Adjusted EBITDA was 0.7x(1). In conjunction with the closing of the EnVen acquisition on February 13, 2023, Talos drew approximately $130.0 million on its credit facility and assumed EnVen’s previously issued and outstanding 11.75% second priority senior secured notes.
|
As of December 31, 2022 |
|||
|
Reconciliation of Pro Forma Net Debt ($ thousands): |
Talos Standalone |
Pro Forma |
Maturity |
|
12.00% Second-Priority Senior Secured Notes |
$638,541 |
$638,541 |
January 2026 |
|
11.75% Second-Priority Senior Secured Notes |
– |
257,500 |
April 2026 |
|
Bank Credit Facility(3) |
– |
130,000 |
March 2027 |
|
Total Debt |
638,541 |
1,026,041 |
|
|
Less: Cash and cash equivalents |
(44,145) |
(44,145) |
|
|
Net Debt |
$594,396 |
$981,896 |
|
|
Footnotes: |
|
|
(1) |
Adjusted Net Income (Loss), Adjusted Earnings (Loss) per Share, Adjusted EBITDA, Adjusted EBITDA excluding hedges, Adjusted EBITDA margin, Adjusted EBITDA margin excluding hedges, LTM Adjusted EBITDA, Net Debt, Net Debt to LTM Adjusted EBITDA, Leverage, Adjusted Free Cash Flow and PV-10 are non-GAAP financial measures. See “Supplemental Non-GAAP Information” below for additional detail and reconciliations of GAAP to non-GAAP measures. |
|
(2) |
Reserves figures are presented inclusive of the plugging and abandonment obligations and before hedges, utilizing SEC pricing of $94.14 WTI per Bbl of oil and $6.36 HH per Mcf of natural gas. |
|
(3) |
Pro forma balance sheet includes $130.0 million drawn to close the EnVen transaction in February of 2023. |
|
(4) |
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 reconciliations of GAAP to non-GAAP measures, including a reconciliation of PV-10 of our proved reserves to the standardized measure of discounted future net cash flows at December 31, 2022. |
|
(5) |
Due to the forward-looking nature a reconciliation of this metric to the most directly comparable GAAP measure could not reconciled without unreasonable efforts. |
|
(6) |
Asset management consists of capital expenditures for development-related activities primarily associated with recompletions and improvements to our facilities and infrastructure. |
|
(7) |
Excludes $0.3 million and $2.7 million of expenditures reflected as “Other operating (income) expense” on the Consolidated Statements of Operations. |
|
(8) |
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. |
PRO FORMA YEAR-END 2022 RESERVES
SEC Reserves
As of December 31, 2022 including assets acquired from EnVen, Talos had proved reserves of 190.0 MMBoe, comprised of 70% oil and 77% liquids. The PV-10 of proved reserves was approximately $7.2 billion. Talos’s reserves are prepared by Talos management and audited by Netherland Sewell & Associates (“NSAI”), whereas EnVen’s reserves are fully engineered by NSAI. All reserves numbers and associated PV-10 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, 2022 based on SEC pricing of $94.14 per Bbl of oil and $6.36 per Mcf of natural gas.
In addition to proved reserves, audited probable reserves were 102.9 MMBoe with a PV-10 of $3.6 billion.
|
SEC Reserves as of December 31, 2022(1) |
|||||||||||||||
|
MBoe |
% of Total Proved |
% Oil |
Standardized |
PV -10 |
|||||||||||
|
Proved Developed Producing |
109,100 |
57 |
% |
76 |
% |
$ |
4,877,910 |
||||||||
|
Proved Developed Non-Producing |
47,243 |
25 |
% |
69 |
% |
1,369,709 |
|||||||||
|
Total Proved Developed |
156,344 |
82 |
% |
73 |
% |
6,247,619 |
|||||||||
|
Proved Undeveloped |
33,682 |
18 |
% |
55 |
% |
948,027 |
|||||||||
|
Total Proved |
190,026 |
100 |
% |
70 |
% |
$ |
5,994,973 |
$ |
7,195,646 |
||||||
Reserves Sensitivities
The following tables summarize the PV-10 values of Talos’s pro forma proved reserves at December 31, 2022, at various crude oil prices and a flat $3.50 per MMBtu gas price, inclusive of EnVen:
|
Year-End 2022 Pro Forma Reserves Sensitivity (PV-10) ($000)(2) |
||||||||||||||
|
$65 |
$75 |
$85 |
SEC |
$105 |
||||||||||
|
Proved Developed Producing |
$ |
2,851,176 |
$ |
3,453,394 |
$ |
4,055,762 |
$ |
4,877,910 |
$ |
5,271,620 |
||||
|
Proved Developed Non-Producing |
643,362 |
851,117 |
1,062,611 |
1,369,709 |
1,486,807 |
|||||||||
|
Total Proved Developed |
3,494,537 |
4,304,512 |
5,118,374 |
6,247,619 |
6,758,426 |
|||||||||
|
Proved Undeveloped |
385,923 |
531,771 |
674,812 |
948,027 |
960,046 |
|||||||||
|
Total Proved |
$ |
3,880,460 |
$ |
4,836,283 |
$ |
5,793,186 |
$ |
7,195,646 |
$ |
7,718,473 |
||||
|
(1) |
This table summarizes year end 2022 reserves of each of Talos and EnVen collectively. The proved undeveloped reserves of EnVen are based on EnVen’s development plans and NSAI’s reserve estimation methodologies. Because Talos will develop such proved undeveloped reserves in accordance with its own development plan and, in the future, will estimate proved undeveloped reserves in accordance with its own methodologies, the estimates presented herein may not be representative of Talos’s future reserve estimates with respect to these properties or the reserve estimates Talos would have reported if it had owned such properties of EnVen as of December 31, 2022. |
|
(2) |
Pro forma sensitivities are based on Talos and EnVen standalone SEC reserves databases as of December 31, 2022. Reserves volumes may fluctuate slightly based on economic limitations. Excludes PV-10s from EnVen production handling agreements categorized separately under EnVen methodologies. |
2023 OPERATIONAL AND FINANCIAL GUIDANCE
In developing its 2023 financial plan, Talos prioritized cash flow generation and the advancement of key longer-term projects that will drive shareholder value in the future. The Company incorporated the following considerations in developing its 2023 plan:
- Average daily production rates and total Upstream capital expenditures for 2023 have been focused on success-based capital expenditures that will add material production over the next 12 to 18 months, with a material impact expected in 2024 from our recent Lime Rock and Venice successes.
- Talos elected to remove the gas-weighted Lisbon prospect from its 2023 drilling calendar despite its near-term potential production rate of approximately 8-10 MBoe/d and will preserve the opportunity for a subsequent rig program.
- The closing date of the EnVen acquisition was February 13, 2023, therefore the transaction is contributing approximately 10.5 months of financial performance compared to an expected full year at the announcement of the acquisition in 2022.
The following table summarizes the Company’s proposed 2023 operational and financial guidance:
|
FY 2023 |
|||||||
|
($ Millions, unless highlighted): |
Low |
High |
|||||
|
Production |
Oil (MMBbl) |
19.2 |
20.3 |
||||
|
Natural Gas (Bcf) |
32.2 |
33.8 |
|||||
|
NGL (MMBbl) |
1.7 |
1.8 |
|||||
|
Total Production (MMBoe) |
26.3 |
27.7 |
|||||
|
Avg Daily Production (MBoe/d) |
72.0 |
76.0 |
|||||
|
Cash Expenses |
Cash Operating Expenses(1)(2)(4) |
$ |
410 |
$ |
430 |
||
|
G&A(2)(3) |
$ |
90 |
$ |
95 |
|||
|
Capex |
Upstream Capital Expenditures(5) |
$ |
650 |
$ |
675 |
||
|
CCS Investments |
CCS Expenses & Capex(5)(7) |
$ |
70 |
$ |
90 |
||
|
P&A Expenditures |
Plugging & Abandonment, Settlement of |
$ |
75 |
$ |
85 |
||
|
Interest |
Interest Expense(6) |
$ |
155 |
$ |
165 |
||
|
(1) |
Inclusive of all Lease Operating Expenses and Workover and Maintenance |
|
(2) |
Includes insurance costs |
|
(3) |
Excludes non-cash equity-based compensation |
|
(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 |
|
(7) |
Includes CCS-specific G&A costs |
|
Note: Due to the forward-looking nature a reconciliation of Cash Operating Expenses and G&A to the most directly comparable GAAP measure could not reconciled without unreasonable efforts. |
|
Key 2023 Projects
Bulleit Recompletion: Operations on the Bulleit DTR-10 Sand recompletion recommenced in February 2023 following a successful fracture stimulation, including the running of an additional casing liner due to loop currents experienced in late 2022. First production from the recompletion is expected in the first quarter of 2023.
Rigolets: Talos will drill the Rigolets prospect in the second quarter of 2023. If successful, Rigolets would flow via subsea tieback to the Company’s Pompano platform with production achievable in the second half of 2024. Talos expects gross production rates of approximately 8 to 12 MBoe/d from gross recoverable resources of 15-30 MMBoe. Talos holds a 60% working interest.
Sunspear: Talos expects to drill the Sunspear prospect in late 2023, which is a contribution from the EnVen portfolio. Talos expects gross production rates of approximately 8 to 10 MBoe/d from gross recoverable resources of 12-18 MMBoe. If successful, the project would flow to the recently acquired and EnVen operated Prince platform. Talos holds a 48% working interest.
Pancheron: Talos expects to participate in the potentially high impact Pancheron exploration prospect in the first half of 2023 following the completion of an eight block swap in the Green Canyon and Walker Ridge area in 2022. Talos holds a 30% working interest.
Zama Final Investment Decision (“FID”): Talos is continuing to collaborate with partners to finalize the Zama Field Development Plan (“FDP”). The partnership is targeting the submission of the FDP to the regulator by the March 23, 2023 deadline. The partners are advancing engineering design and other workstreams in anticipation of approval in the coming months, after which the parties will then be able to move toward FID. Upon FID, Talos anticipates adding a portion of the Zama contingent resources into Proved reserves.
CCS Investments: Talos expects to grow and advance its existing project portfolio with strategic business development activities, the advancement of engineering and design work and preparation for filing multiple Class VI permit applications, including drilling multiple stratigraphic evaluation wells.
Capital Allocation Framework
Talos intends to allocate its expected 2023 Adjusted Free Cash Flow as follows:
|
1) |
Further debt reduction of at least $100.0 million, primarily through RBL repayments post-closing of the EnVen acquisition. |
|
2) |
Funding of the high-growth CCS business in the event of key milestones and expansion opportunities are realized |
|
3) |
Incremental Adjusted Free Cash Flow will be allocated towards further debt reduction and return of capital to shareholders, primarily through share repurchases, subject to further Board approvals. |
In addition to this framework, subject to Board approval, Talos may initiate a stock buyback program to allow it to consider repurchasing shares of the Company’s common stock in the event of significant monetizations from private equity shareholders.
Adjusted Free Cash Flow generation is expected to materially increase beyond 2023. Starting in 2024 Talos expects to be in a position to initiate a broader, enhanced return of capital to shareholders, primarily through opportunistic share repurchases, subject to Board approvals.
HEDGES
The following table reflects contracted volumes and weighted average prices the Company will receive under the terms of its derivative contracts as of today:
|
Instrument Type |
Avg. Daily |
W.A. Swap |
W.A. Sub-Floor |
W.A. Floor |
W.A. Ceiling |
|
|
Crude – WTI |
(Bbls) |
(Per Bbl) |
(Per Bbl) |
(Per Bbl) |
(Per Bbl) |
|
|
Jan. – Mar. 2023 |
Fixed Swaps |
27,311 |
$70.00 |
— |
— |
— |
|
Collar |
3,622 |
— |
— |
$58.24 |
$78.90 |
|
|
3-Way Collar |
3,999 |
— |
$43.50 |
$56.56 |
$93.87 |
|
|
Apr. – Jun. 2023 |
Fixed Swaps |
23,000 |
$74.06 |
— |
— |
— |
|
Collar |
2,500 |
— |
— |
$65.00 |
$89.22 |
|
|
3-Way Collar |
9,200 |
— |
$51.32 |
$64.57 |
$108.63 |
|
|
Jul. – Sep. 2023 |
Fixed Swaps |
13,674 |
$73.66 |
— |
— |
— |
|
Collar |
4,500 |
— |
— |
$70.56 |
$89.99 |
|
|
3-Way Collar |
9,200 |
— |
$51.86 |
$65.11 |
$109.25 |
|
|
Oct. – Dec. 2023 |
Fixed Swaps |
12,000 |
$75.25 |
— |
— |
— |
|
Collar |
6,500 |
— |
— |
$67.31 |
$87.55 |
|
|
3-Way Collar |
9,200 |
— |
$51.86 |
$65.11 |
$109.25 |
|
|
Jan. – Mar. 2024 |
Fixed Swaps |
9,000 |
$75.46 |
— |
— |
— |
|
Collar |
3,000 |
— |
— |
$70.00 |
$83.67 |
|
|
3-Way Collar |
3,200 |
— |
$57.27 |
$70.00 |
$98.01 |
|
|
Apr. – Jun. 2024 |
Fixed Swaps |
11,000 |
$74.41 |
— |
— |
— |
|
Collar |
1,000 |
— |
$70.00 |
$75.00 |
||
|
Jul. – Sep. 2024 |
Fixed Swaps |
8,000 |
$72.53 |
— |
— |
— |
|
Collar |
1,000 |
— |
$70.00 |
$75.00 |
||
|
Oct. – Dec. 2024 |
Fixed Swaps |
5,000 |
$72.01 |
— |
— |
— |
|
Collar |
1,000 |
— |
— |
$70.00 |
$75.00 |
|
|
Gas – HH NYMEX |
(MMBtu) |
(Per MMBtu) |
(Per MMBtu) |
(Per MMBtu) |
(Per MMBtu) |
|
|
Jan. – Mar. 2023 |
Fixed Swaps |
43,722 |
$3.84 |
— |
— |
— |
|
Collar |
10,000 |
— |
— |
$5.25 |
$8.46 |
|
|
3-Way Collar |
3,444 |
— |
$2.50 |
$3.00 |
$5.00 |
|
|
Bought Call |
3,444 |
— |
— |
— |
$6.00 |
|
|
Apr. – Jun. 2023 |
Fixed Swaps |
39,000 |
$3.33 |
— |
— |
— |
|
Collar |
10,000 |
— |
— |
$5.25 |
$8.46 |
|
|
Jul. – Sep. 2023 |
Fixed Swaps |
20,000 |
$3.35 |
— |
— |
— |
|
Collar |
10,000 |
— |
— |
$5.25 |
$8.46 |
|
|
Oct. – Dec. 2023 |
Fixed Swaps |
20,000 |
$4.22 |
— |
— |
— |
|
Collar |
10,000 |
— |
— |
$5.25 |
$8.46 |
|
|
Jan. – Mar. 2024 |
Fixed Swaps |
15,000 |
$3.46 |
— |
— |
— |
|
Collar |
10,000 |
— |
— |
$4.00 |
$6.90 |
|
|
Apr. – Jun. 2024 |
Fixed Swaps |
10,000 |
$3.25 |
— |
— |
— |
|
Collar |
10,000 |
— |
— |
$4.00 |
$6.90 |
|
|
Jul. – Sep. 2024 |
Fixed Swaps |
– |
— |
— |
— |
— |
|
Collar |
10,000 |
— |
— |
$4.00 |
$6.90 |
|
|
Oct. – Dec. 2024 |
Fixed Swaps |
– |
— |
— |
— |
— |
|
Collar |
10,000 |
— |
— |
$4.00 |
$6.90 |
CONFERENCE CALL AND WEBCAST INFORMATION
Talos will host a conference call, which will be broadcast live over the internet, on Wednesday, March 1, 2023 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/events-calendar/default.aspx. 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 March 8, 2023 and can be accessed by dialing (877) 344-7529 and using access code 8054731.
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 future carbon capture and storage 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 storage initiatives along the U.S. Gulf of Mexico. For more information, visit www.talosenergy.com.
INVESTOR RELATIONS CONTACT
Sergio Maiworm
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, the anticipated future performance of the combined company, the success of our carbon capture and sequestration projects, commodity price volatility, the lack of a resolution to the war in Ukraine and its impact on certain commodity markets; the ability or willingness of the Organization of Petroleum Exporting Countries (“OPEC”) and non-OPEC countries, such as Saudi Arabia and Russia, to set and maintain oil production levels and the impact of any such actions; the impact of the ongoing sub-surface water flood project in the Phoenix Field and any updates to our estimated ultimate recovery from such project; lack of transportation and storage capacity as a result of oversupply, government regulations and actions or other factors; sustained inflation and the impact of central bank policy in response thereto; lack of availability of drilling and production equipment and services; environmental risks; drilling and other operating risks; regulatory changes; adverse weather events, including tropical storms, hurricanes and winter storms; cybersecurity threats; the continued impact of the coronavirus disease 2019 (“COVID-19”), including any new strains or variants, and governmental measures related thereto; the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital; the timing of development expenditures; the possibility that the anticipated benefits of recent acquisitions are not realized when expected or at all, including as a result of the impact of, or problems arising from, the integration of such acquisitions; changes to federal income tax laws and regulations, including the Inflation Reduction Act of 2022; 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” in our Annual Report on Form 10-K for the year ended December 31, 2022, to be 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.
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.
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 revisions upward or downward 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.
|
Talos Energy Inc. Consolidated Balance Sheets (In thousands, except per share amounts) |
||||||
|
Year Ended December 31, |
||||||
|
2022 |
2021 |
|||||
|
ASSETS |
||||||
|
Current assets: |
||||||
|
Cash and cash equivalents |
$ |
44,145 |
$ |
69,852 |
||
|
Accounts receivable: |
||||||
|
Trade, net |
150,598 |
173,241 |
||||
|
Joint interest, net |
54,697 |
28,165 |
||||
|
Other, net |
6,684 |
18,062 |
||||
|
Assets from price risk management activities |
25,029 |
967 |
||||
|
Prepaid assets |
84,759 |
48,042 |
||||
|
Other current assets |
1,917 |
1,674 |
||||
|
Total current assets |
367,829 |
340,003 |
||||
|
Property and equipment: |
||||||
|
Proved properties |
5,964,340 |
5,232,479 |
||||
|
Unproved properties, not subject to amortization |
154,783 |
219,055 |
||||
|
Other property and equipment |
30,691 |
29,091 |
||||
|
Total property and equipment |
6,149,814 |
5,480,625 |
||||
|
Accumulated depreciation, depletion and amortization |
(3,506,539) |
(3,092,043) |
||||
|
Total property and equipment, net |
2,643,275 |
2,388,582 |
||||
|
Other long-term assets: |
||||||
|
Assets from price risk management activities |
7,854 |
2,770 |
||||
|
Equity method investments |
1,745 |
— |
||||
|
Other well equipment inventory |
25,541 |
17,449 |
||||
|
Operating lease assets |
5,903 |
5,714 |
||||
|
Other assets |
6,479 |
12,297 |
||||
|
Total assets |
$ |
3,058,626 |
$ |
2,766,815 |
||
|
LIABILITIES AND STOCKHOLDERSʼ EQUITY |
||||||
|
Current liabilities: |
||||||
|
Accounts payable |
$ |
128,174 |
$ |
85,815 |
||
|
Accrued liabilities |
219,769 |
130,459 |
||||
|
Accrued royalties |
52,215 |
59,037 |
||||
|
Current portion of long-term debt |
— |
6,060 |
||||
|
Current portion of asset retirement obligations |
39,888 |
60,311 |
||||
|
Liabilities from price risk management activities |
68,370 |
186,526 |
||||
|
Accrued interest payable |
36,340 |
37,542 |
||||
|
Current portion of operating lease liabilities |
1,943 |
1,715 |
||||
|
Other current liabilities |
60,359 |
33,061 |
||||
|
Total current liabilities |
607,058 |
600,526 |
||||
|
Long-term liabilities: |
||||||
|
Long-term debt, net of discount and deferred financing costs |
585,340 |
956,667 |
||||
|
Asset retirement obligations |
501,773 |
373,695 |
||||
|
Liabilities from price risk management activities |
7,872 |
13,938 |
||||
|
Operating lease liabilities |
14,855 |
16,330 |
||||
|
Other long-term liabilities |
176,152 |
45,006 |
||||
|
Total liabilities |
1,893,050 |
2,006,162 |
||||
|
Commitments and contingencies |
||||||
|
Stockholdersʼ equity: |
||||||
|
Preferred stock, $0.01 par value; 30,000,000 shares authorized and no shares issued or outstanding as of December 31, 2022 and 2021 |
— |
— |
||||
|
Common stock $0.01 par value; 270,000,000 shares authorized; 82,570,328 and 81,881,477 shares issued and outstanding as of December 31, 2022 and 2021, respectively |
826 |
819 |
||||
|
Additional paid-in capital |
1,699,799 |
1,676,798 |
||||
|
Accumulated deficit |
(535,049) |
(916,964) |
||||
|
Total stockholdersʼ equity |
1,165,576 |
760,653 |
||||
|
Total liabilities and stockholdersʼ equity |
$ |
3,058,626 |
$ |
2,766,815 |
||
|
Talos Energy Inc. Consolidated Statements of Operations (In thousands, except per common share amounts) |
||||||||||||
|
Three Months Ended December 31, |
Twelve Months Ended December 31, |
|||||||||||
|
2022 |
2021 |
2022 |
2021 |
|||||||||
|
Revenues: |
||||||||||||
|
Oil |
$ |
286,348 |
$ |
320,402 |
$ |
1,365,148 |
$ |
1,064,161 |
||||
|
Natural gas |
45,559 |
44,528 |
227,306 |
130,616 |
||||||||
|
NGL |
10,294 |
18,025 |
59,526 |
49,763 |
||||||||
|
Total revenues |
342,201 |
382,955 |
1,651,980 |
1,244,540 |
||||||||
|
Operating expenses: |
||||||||||||
|
Lease operating expense |
78,936 |
74,926 |
308,092 |
283,601 |
||||||||
|
Production taxes |
818 |
824 |
3,488 |
3,363 |
||||||||
|
Depreciation, depletion and amortization |
119,456 |
105,900 |
414,630 |
395,994 |
||||||||
|
Write-down of oil and natural gas properties |
— |
18,123 |
— |
18,123 |
||||||||
|
Accretion expense |
13,595 |
14,019 |
55,995 |
58,129 |
||||||||
|
General and administrative expense |
29,012 |
19,684 |
99,754 |
78,677 |
||||||||
|
Other operating expense |
21,760 |
25,173 |
33,902 |
32,037 |
||||||||
|
Total operating expenses |
263,577 |
258,649 |
915,861 |
869,924 |
||||||||
|
Operating income |
78,624 |
124,306 |
736,119 |
374,616 |
||||||||
|
Interest expense |
(33,967) |
(33,102) |
(125,498) |
(133,138) |
||||||||
|
Price risk management activities expense |
(41,058) |
(13,473) |
(272,191) |
(419,077) |
||||||||
|
Equity method investment income |
(377) |
— |
14,222 |
— |
||||||||
|
Other income (expense) |
(191) |
928 |
31,800 |
(6,988) |
||||||||
|
Net income (loss) before income taxes |
3,031 |
78,659 |
384,452 |
(184,587) |
||||||||
|
Income tax benefit (expense) |
(281) |
2,353 |
(2,537) |
1,635 |
||||||||
|
Net income (loss) |
$ |
2,750 |
$ |
81,012 |
$ |
381,915 |
$ |
(182,952) |
||||
|
Net income (loss) per common share: |
||||||||||||
|
Basic |
$ |
0.03 |
$ |
0.99 |
$ |
4.63 |
$ |
(2.24) |
||||
|
Diluted |
$ |
0.03 |
$ |
0.99 |
$ |
4.56 |
$ |
(2.24) |
||||
|
Weighted average common shares outstanding: |
||||||||||||
|
Basic |
82,597 |
81,901 |
82,454 |
81,721 |
||||||||
|
Diluted |
84,417 |
81,901 |
83,683 |
81,721 |
||||||||
|
Talos Energy Inc. Consolidated Statements of Cash Flows (In thousands) |
|||||||||
|
Year Ended December 31, |
|||||||||
|
2022 |
2021 |
2020 |
|||||||
|
Cash flows from operating activities: |
|||||||||
|
Net income (loss) |
$ |
381,915 |
$ |
(182,952) |
$ |
(465,605) |
|||
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities |
|||||||||
|
Depreciation, depletion, amortization and accretion expense |
470,625 |
454,123 |
414,087 |
||||||
|
Write-down of oil and natural gas properties and other well inventory |
— |
23,729 |
268,615 |
||||||
|
Amortization of deferred financing costs and original issue discount |
14,379 |
13,382 |
6,804 |
||||||
|
Equity-based compensation expense |
15,953 |
10,992 |
8,669 |
||||||
|
Price risk management activities expense (income) |
272,191 |
419,077 |
(87,685) |
||||||
|
Net cash received (paid) on settled derivative instruments |
(425,559) |
(290,164) |
143,905 |
||||||
|
Equity method investment income |
(14,222) |
— |
— |
||||||
|
Loss (gain) on extinguishment of debt |
1,569 |
13,225 |
(1,662) |
||||||
|
Settlement of asset retirement obligations |
(69,596) |
(67,988) |
(43,933) |
||||||
|
Gain on sale of assets |
303 |
(687) |
— |
||||||
|
Changes in operating assets and liabilities: |
|||||||||
|
Accounts receivable |
14,927 |
(35,396) |
(34,645) |
||||||
|
Other current assets |
(36,545) |
(18,901) |
35,934 |
||||||
|
Accounts payable |
24,258 |
(6,261) |
27,096 |
||||||
|
Other current liabilities |
73,531 |
64,800 |
4,200 |
||||||
|
Other non-current assets and liabilities, net |
(13,990) |
14,409 |
26,143 |
||||||
|
Net cash provided by operating activities |
709,739 |
411,388 |
301,923 |
||||||
|
Cash flows from investing activities: |
|||||||||
|
Exploration, development and other capital expenditures |
(323,164) |
(293,331) |
(362,942) |
||||||
|
Cash paid for acquisitions, net of cash acquired |
(3,500) |
(5,399) |
(315,962) |
||||||
|
Proceeds from sale of property and equipment, net |
1,937 |
4,983 |
— |
||||||
|
Contributions to equity method investees |
(2,250) |
— |
— |
||||||
|
Proceeds from sale of equity method investment |
15,000 |
— |
— |
||||||
|
Net cash used in investing activities |
(311,977) |
(293,747) |
(678,904) |
||||||
|
Cash flows from financing activities: |
|||||||||
|
Proceeds from issuance of common stock |
— |
— |
71,100 |
||||||
|
Issuance of senior notes |
— |
600,500 |
— |
||||||
|
Redemption of senior notes and other long-term debt |
(18,184) |
(356,803) |
(5,364) |
||||||
|
Proceeds from Bank Credit Facility |
85,000 |
100,000 |
350,000 |
||||||
|
Repayment of Bank Credit Facility |
(460,000) |
(365,000) |
(60,000) |
||||||
|
Deferred financing costs |
(189) |
(27,833) |
(1,287) |
||||||
|
Other deferred payments |
— |
(7,921) |
(11,921) |
||||||
|
Payments of finance lease |
(25,493) |
(21,804) |
(17,509) |
||||||
|
Employee stock awards tax withholdings |
(4,603) |
(3,161) |
(827) |
||||||
|
Net cash provided by (used in) financing activities |
(423,469) |
(82,022) |
324,192 |
||||||
|
Net increase (decrease) in cash and cash equivalents |
(25,707) |
35,619 |
(52,789) |
||||||
|
Cash and cash equivalents: |
|||||||||
|
Balance, beginning of period |
69,852 |
34,233 |
87,022 |
||||||
|
Balance, end of period |
$ |
44,145 |
$ |
69,852 |
$ |
34,233 |
|||
|
Supplemental non-cash transactions: |
|||||||||
|
Capital expenditures included in accounts payable and accrued liabilities |
$ |
105,773 |
$ |
45,761 |
$ |
74,957 |
|||
|
Debt exchanged for common stock |
$ |
— |
$ |
— |
$ |
35,960 |
|||
|
Supplemental cash flow information: |
|||||||||
|
Interest paid, net of amounts capitalized |
$ |
91,809 |
$ |
68,891 |
$ |
67,443 |
|||
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,” “Adjusted Free Cash Flow,” “Net Debt,” “LTM Adjusted EBITDA,” “LTM Adjusted EBITDA,”, “Net Debt to LTM Adjusted EBITDA,” “Leverage” and “PV-10.” 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 other (income) expenses, decommissioning obligations, 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.
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.
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) |
December 31, |
September 30, |
June 30, |
March 31, |
||||||||
|
Reconciliation of net income (loss) to Adjusted EBITDA: |
||||||||||||
|
Net Income (loss) |
$ |
2,750 |
$ |
250,465 |
$ |
195,141 |
$ |
(66,441) |
||||
|
Interest expense |
33,967 |
29,265 |
30,776 |
31,490 |
||||||||
|
Income tax expense (benefit) |
281 |
121 |
2,607 |
(472) |
||||||||
|
Depreciation, depletion and amortization |
119,456 |
92,323 |
104,511 |
98,340 |
||||||||
|
Accretion expense |
13,595 |
13,179 |
14,844 |
14,377 |
||||||||
|
EBITDA |
170,049 |
385,353 |
347,879 |
77,294 |
||||||||
|
Transaction and other (income) expenses(1) |
4,343 |
3,219 |
(15,214) |
(26,861) |
||||||||
|
Decommissioning obligations(2) |
21,005 |
20 |
10,204 |
329 |
||||||||
|
Derivative fair value loss(3) |
41,058 |
(114,180) |
64,094 |
281,219 |
||||||||
|
Net cash payments on settled derivative instruments(3) |
(57,076) |
(81,162) |
(160,235) |
(127,086) |
||||||||
|
Loss on extinguishment of debt |
1,569 |
— |
— |
— |
||||||||
|
Non-cash equity-based compensation expense |
4,276 |
4,310 |
4,049 |
3,318 |
||||||||
|
Adjusted EBITDA |
185,224 |
197,560 |
250,777 |
208,213 |
||||||||
|
Add: Net cash payments on settled derivative instruments(3) |
57,076 |
81,162 |
160,235 |
127,086 |
||||||||
|
Adjusted EBITDA excluding hedges |
$ |
242,300 |
$ |
278,722 |
$ |
411,012 |
$ |
335,299 |
||||
|
Production and Revenue: |
||||||||||||
|
Boe(4) |
5,207 |
4,876 |
5,953 |
5,687 |
||||||||
|
Revenue – Operations |
342,201 |
377,128 |
519,085 |
413,566 |
||||||||
|
Adjusted EBITDA margin and Adjusted EBITDA excl hedges margin: |
||||||||||||
|
Adjusted EBITDA divided by – Total revenues incl hedges (%) |
65 |
% |
67 |
% |
70 |
% |
73 |
% |
||||
|
Adjusted EBITDA per Boe(4) |
$ |
35.57 |
$ |
40.52 |
$ |
42.13 |
$ |
36.61 |
||||
|
Adjusted EBITDA excl hedges divided by – Total revenues (%) |
71 |
% |
74 |
% |
79 |
% |
81 |
% |
||||
|
Adjusted EBITDA excl hedges per Boe(3) |
$ |
46.53 |
$ |
57.16 |
$ |
69.04 |
$ |
58.96 |
||||
|
(1) |
Other income (expenses) includes miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the three months ended September 30, 2022 and June 30, 2022, it includes a $1.4 and $13.9 million gain on partial sale of our investment in Bayou Bend, respectively. For the three months ended June 30, 2022, there was also a $2.5 million gain related to the settlement of an acquired imbalance. For the three months ended March 31, 2022, the amount includes $27.5 million gain as a result of the settlement agreement to resolve previously pending litigation that was filed in October 2017. |
|
(2) |
Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. |
|
(3) |
The adjustments for the derivative fair value (gain) loss and net cash receipts (payments) on settled derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled. |
|
(4) |
One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities. |
|
Upstream Segment EBITDA Reconciliation |
|||
|
($ thousands) |
Twelve Months Ended |
||
|
Reconciliation of Adjusted EBITDA to Upstream Segment Adjusted EBITDA |
|||
|
Adjusted EBITDA |
$ |
841,774 |
|
|
Plus: CCS Segment |
12,786 |
||
|
Plus: Unallocated Corporate General & Administrative Expenses |
5,280 |
||
|
Upstream Segment Adjusted EBITDA |
$ |
859,840 |
|
Reconciliation of Adjusted EBITDA to Adjusted Free Cash Flow and Reconciliation of Net Cash Provided by Operating Activities to Adjusted Free Cash Flow
“Adjusted 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. Adjusted 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, Plugging & Abandonment and Decommissioning Obligations Settled. Actual capital expenditures, plugging & abandonment and decommissioning obligations settled 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 Adjusted Free Cash Flow before changes in working capital number.
|
($ thousands) |
Three Months Ended |
Twelve Months Ended |
||||
|
Reconciliation of Adjusted EBITDA to Adjusted Free Cash Flow (before changes in working capital) |
||||||
|
Adjusted EBITDA |
$ |
185,224 |
$ |
841,774 |
||
|
Less: Capital expenditures and plugging & abandonment |
(154,314) |
(453,827) |
||||
|
Less: Decommissioning obligations settled |
(1,625) |
(1,625) |
||||
|
Less: Interest expense |
(33,967) |
(125,498) |
||||
|
Adjusted Free Cash Flow (before changes in working capital) |
$ |
(4,682) |
$ |
260,824 |
||
|
($ thousands) |
Three Months Ended |
Twelve Months Ended |
||||
|
Reconciliation of net cash provided by operating activities to Adjusted Free Cash Flow (before changes in working capital) |
||||||
|
Net cash provided by operating activities(1) |
$ |
170,811 |
$ |
709,739 |
||
|
(Increase) decrease in operating assets and liabilities |
(50,420) |
(62,181) |
||||
|
Investment in properties(2) |
(145,022) |
(384,231) |
||||
|
Decommissioning obligations settled |
(1,625) |
(1,625) |
||||
|
Transaction and other (income) expenses(3) |
4,343 |
(19,226) |
||||
|
Decommissioning obligations(4) |
21,005 |
31,558 |
||||
|
Amortization of deferred financing costs and original issue discount |
(3,765) |
(14,379) |
||||
|
Other adjustments |
(9) |
1,169 |
||||
|
Adjusted Free Cash Flow (before changes in working capital) |
$ |
(4,682) |
$ |
260,824 |
||
|
(1) |
Includes settlement of asset retirement obligations. |
|
(2) |
Includes accruals and excludes acquisitions. |
|
(3) |
Other income (expenses) includes miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the twelve months ended December 31, 2022, there was a $27.5 million gain as a result of the settlement agreement to resolve previously pending litigation that was filed in October 2017, $15.3 million gain on partial sale of our investment in Bayou Bend, and $2.5 million gain related to the settlement of an acquired imbalance. |
|
(4) |
Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. |
Reconciliation of Net Income to Adjusted Net Income (Loss) and Adjusted Earnings per Share
“Adjusted Net Income (Loss)” and “Adjusted Earnings per Share” are to provide management and investors with (i) important supplemental indicators of the operational performance of our business, (ii) additional criteria for evaluating our performance relative to our peers and (iii) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. Adjusted Net Income (Loss) and Adjusted Earnings per Share have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP or as an alternative to net income (loss), operating income (loss), earnings per share or any other measure of financial performance presented in accordance with GAAP.
Adjusted Net Income (Loss). Net income (loss) plus transaction related costs and other (income) expenses, decommissioning obligations, derivative fair value (gain) loss, net cash receipts (payments) on settled derivative instruments, non-cash income tax expense and non-cash equity-based compensation expense.
Adjusted Earnings per Share. Adjusted Net Income (Loss) divided by the number of common shares.
|
Three Months Ended December 31, 2022 |
Twelve Months Ended December 31, 2022 |
|||||||||||||||||
|
($ thousands, except per share amounts) |
Basic per |
Diluted per |
Basic per |
Diluted per |
||||||||||||||
|
Reconciliation of Net Income to Adjusted Net Income: |
||||||||||||||||||
|
Net Income |
$ |
2,750 |
$ |
0.03 |
$ |
0.03 |
$ |
381,915 |
$ |
4.63 |
$ |
4.56 |
||||||
|
Transaction and other (income) expenses(1) |
4,343 |
$ |
0.05 |
$ |
0.05 |
(34,513) |
$ |
(0.42) |
$ |
(0.41) |
||||||||
|
Decommissioning obligations(2) |
21,005 |
$ |
0.25 |
$ |
0.25 |
31,558 |
$ |
0.38 |
$ |
0.38 |
||||||||
|
Derivative fair value loss(3) |
41,058 |
$ |
0.50 |
$ |
0.49 |
272,191 |
$ |
3.30 |
$ |
3.25 |
||||||||
|
Net cash payments on settled derivative instruments(3) |
(57,076) |
$ |
(0.69) |
$ |
(0.68) |
(425,559) |
$ |
(5.16) |
$ |
(5.09) |
||||||||
|
Non-cash income tax expense |
281 |
$ |
0.00 |
$ |
0.00 |
2,537 |
$ |
0.03 |
$ |
0.03 |
||||||||
|
Non-cash equity-based compensation expense |
4,276 |
$ |
0.05 |
$ |
0.05 |
15,953 |
$ |
0.19 |
$ |
0.19 |
||||||||
|
Adjusted Net Income |
$ |
16,637 |
$ |
0.20 |
$ |
0.20 |
$ |
244,082 |
$ |
2.96 |
$ |
2.92 |
||||||
|
Weighted average common shares outstanding at December 31, 2022: |
||||||||||||||||||
|
Basic |
82,597 |
82,454 |
||||||||||||||||
|
Diluted |
84,417 |
83,683 |
||||||||||||||||
|
(1) |
Other income (expenses) includes miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the twelve months ended December 31, 2022, there was a $27.5 million gain as a result of the settlement agreement to resolve previously pending litigation that was filed in October 2017, $15.3 million gain on partial sale of our investment in Bayou Bend, and $2.5 million gain related to the settlement of an acquired imbalance. |
|
(2) |
Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. |
|
(3) |
The adjustments for the derivative fair value (gain) loss and net cash receipts (payments) on settled derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted Net Income (Loss) on an unrealized basis during the period the derivatives settled. |
Reconciliation of Total Debt to Net Debt and Net Debt to LTM Adjusted EBITDA
We believe the presentation of Net Debt, LTM Adjusted EBITDA and Net Debt to LTM Adjusted EBITDA is important to provide management and investors with additional important information to evaluate our business. These measures are widely used by investors and ratings agencies in the valuation, comparison, rating and investment recommendations of companies.
Net Debt. Total Debt principal of the Company minus cash and cash equivalents.
Net Debt to LTM Adjusted EBITDA. Net Debt divided by the LTM Adjusted EBITDA.
|
December 31, 2022 |
|||
|
Reconciliation of Net Debt ($ thousands): |
|||
|
12.00% Second-Priority Senior Secured Notes – due January 2026 |
$ |
638,541 |
|
|
Bank Credit Facility – matures November 2024 |
— |
||
|
Total Debt |
638,541 |
||
|
Less: Cash and cash equivalents |
(44,145) |
||
|
Net Debt |
$ |
594,396 |
|
|
Calculation of LTM EBITDA: |
|||
|
Adjusted EBITDA for three months period ended March 31, 2022 |
$ |
208,213 |
|
|
Adjusted EBITDA for three months period ended June 30, 2022 |
250,777 |
||
|
Adjusted EBITDA for three months period ended September 30, 2022 |
197,560 |
||
|
Adjusted EBITDA for three months period ended December 31, 2022 |
185,224 |
||
|
LTM Adjusted EBITDA |
$ |
841,774 |
|
|
Reconciliation of Net Debt to LTM Adjusted EBITDA: |
|||
|
Net Debt / LTM Adjusted EBITDA(1) |
0.7 |
x |
|
|
(1) |
Net Debt / LTM Adjusted EBITDA figures excludes the Finance Lease. Had the Finance Lease been included, Net Debt / LTM Adjusted EBITDA would have been 0.9x. |
Reconciliation of PV-10 to Standardized Measure (Pro Forma for EnVen)
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 PV-10 to Standardized Measure on a pro forma basis inclusive of the EnVen acquisition:
|
Year Ended |
||||
|
Standardized measure(1)(2) |
$ |
5,994,973 |
||
|
Present value of future income taxes discounted at 10% |
1,200,673 |
|||
|
PV-10 (Non-GAAP) |
$ |
7,195,646 |
||
|
(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
