HOUSTON, March 10, 2021 /PRNewswire/ -- Talos Energy Inc. ("Talos" or the "Company") (NYSE: TALO) today announced its operational and financial results for the fourth quarter and full year 2020. The Company also announced its year-end 2020 reserves figures as well as 2021 operational and financial guidance.
Key Highlights - Fourth Quarter 2020:
- Production of 59.4 thousand barrels of oil equivalent per day ("MBoe/d") net. Year-end production exit rate was over 71.0 MBoe/d net.
- Net Loss of $430.7 million inclusive of $267.9 million in commodity price-related impairments, or $5.73 loss per diluted share, and Adjusted Net Loss(1) of $31.2 million, or $0.41 adjusted loss per diluted share.
- Adjusted EBITDA(1) of $106.4 million, for an Adjusted EBITDA margin of over 60%.
- Capital expenditures, inclusive of plugging and abandonment costs, of $71.0 million. Free Cash Flow of approximately $12.2 million after interest expense.
- Liquidity of $545.9 million as of January 31, 2021.
- Year-end 2020 proved reserves of 163 MMBoe (67% oil, 78% proved developed), with a PV-10(1) of approximately $2.0 billion, based on SEC pricing of $39.54 per barrel of WTI and $1.99 per MMBtu, prior to adjustments for crude grade differentials, certain gathering, transportation, quality differentials and other costs. Proved Reserves increased by approximately 21 MMBoe from year end 2019, based on SEC commodity prices at the time of both reports. When adjusting commodity prices to $55 per barrel and $2.50 per MMBtu, commodity prices similar to the year end 2019 SEC price, the increase in reserves for year end 2020 compared to year end 2019 improves to over 43 MMboe.
(1) | Adjusted Net Loss, Adjusted Loss per Share, Adjusted EBITDA, Adjusted EBITDA margin, 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. |
President and Chief Executive Officer Timothy S. Duncan commented: "I am proud of how the Talos team responded to the challenges we all faced in 2020. With the onset of unexpected crises, our focus for the year was to further improve our cost structure and to bolster our asset value and credit profile through the capital plan, while also placing the business on solid footing to advance in 2021. After a challenging year, that is the position we are in. I'm particularly happy with our execution in the fourth quarter, with new wells coming online and continued success in our operating cost reduction efforts. That resulted in strong free cash flow generation in the quarter, as well as EBITDA margins going back over 60%, despite the hurricane downtime experienced in the quarter. By executing on different capital markets initiatives in late 2020 and early 2021, we have built a significant liquidity position and we are well-positioned moving forward. We also progressed in our emissions reduction initiatives in 2020, and we expect to report a third straight year of emissions reduction when our second annual ESG report is published by the summer of 2021."
Duncan continued: "With improving margins and a continued focus on free cash flow generation, we expect to have a lower capital investment program in 2021 compared to 2020, despite an improving commodity price environment, balanced across low-risk projects and potential high-impact catalysts. We will take our successful platform rig program from our Green Canyon 18 facility to the Pompano area in Mississippi Canyon, and we will continue to invest in our successful Tornado water flood project. The Company also expects results from numerous high-impact catalysts in the coming months. Talos is presently participating in the high-impact Puma West exploration well. We are finalizing unitization and thereafter seeking to sanction our Zama project in Mexico, for which our third-party reserve auditor recently increased their resource estimates. Lastly, we're actively working on a diverse range of business development and M&A opportunities, building on our successful track record. Each of these opportunities could be material value drivers for our shareholders throughout the year and beyond."
RECENT DEVELOPMENTS AND OPERATIONS UPDATE
Drilling and Exploration Activities - U.S. Gulf of Mexico
Tornado Water Flood: Talos initiated the first-ever deepwater intra-well water flood project in the second half of 2020 in its prolific Tornado field. The Tornado water injection well has established injection rates between 23,000 and 25,000 barrels of water per day into the producing B-6 Sand, causing notable increases in reservoir pressure and production. The Company expects the water flood project to augment the field recovery by approximately 25 - 35 MMBoe gross in combination with the planned 2021 Tornado Attic well. Talos holds a 65.0% working interest in the Tornado field and is the operator.
Kaleidoscope: Talos initiated production from the Kaleidoscope well in late December 2020 as part of the Green Canyon 18 platform rig program. The well is currently flowing at approximately 4.9 MBoe/d gross, 4.0 MBoe/d net. Talos holds a 100.0% working interest in the well and is the operator.
Tokum: Talos successfully drilled and completed the Tokum development well following the Kaleidoscope completion. The well was brought online in late February of 2021 ahead of schedule and under budget, and is currently producing approximately 2.4 MBoe/d gross, 2.0 MBoe/d net. Talos holds a 100% working interest in the well and is the operator.
Puma West: Drilling was resumed in February 2021 by the operator following a temporary pause in early 2020 ahead of the Middle and Lower Miocene subsalt objectives. bp is the operator and holds a 50.0% working interest. Talos and Chevron each hold a 25.0% working interest. On February 1, 2021, Talos and bp received final approval and were granted the adjacent Green Canyon 866 block, which the companies had jointly bid for in the November 2020 lease sale.
Drilling and Exploration Activities - Mexico
Zama Unitization: Talos, the Block 7 partners and Petróleos Mexicanos ("Pemex") received an extension from Mexico's Ministry of Energy ("SENER") through March 25, 2021 to finalize a unitization framework to be reviewed by SENER prior to a public announcement. Pending the conclusion of unitization discussions in the coming weeks, Talos would aim to reach Final Investment Decision ("FID") on the project before year-end 2021.
In parallel with the unitization discussions, Netherland, Sewell & Associates, Inc. ("NSAI") has updated its contingent resource estimates on Zama by integrating additional rock and fluid data obtained during the appraisal program and now estimates gross volumes of 735 MMBoe of 2C resources, with 60% of the resources expected to be contained within Block 7.
Corporate Activities
Capital Markets Transactions: In December 2020 and January 2021, Talos completed three capital markets offerings totaling approximately $675 million in gross proceeds, which, after fees and expenses, were utilized to retire the Company's 11.00% Second Lien Notes due April 2022, pay down a significant portion of the outstanding borrowings under its credit facility and for general corporate purposes.
Spring Borrowing Base Redetermination: Talos has initiated and is actively working on its spring borrowing base redetermination process. As part of the redetermination, Talos intends to extend the current May 2022 maturity. The Company expects to complete this process in the coming months.
ESG Activities: Talos advanced its emissions reduction goals in 2020, furthering its three-year trend of reductions in both total air emissions and greenhouse gas intensity. The Company also continued its track record of safe operations, sustaining its TRIR below the average for oil and gas companies operating in the Gulf of Mexico, and completed the year with less than three quarters of one barrel of hydrocarbons released from over 24 million gross barrels of oil equivalent operated by Talos. The company expects to produce its second annual comprehensive ESG report by the summer of 2021.
Recent Regulatory Action: On January 20, 2021 the Department of the Interior issued a Secretarial Order revising delegation authorities related to approvals for new oil and gas activities on federal lands and waters, including the federal Outer Continental Shelf, for 60 days. The order explicitly does not apply to existing operations under valid leases, and is not a moratorium or ban on leasing or permits. Talos and other industry participants have had numerous permits approved since the order was issued and Talos has not experienced any material delays or rejections from any permit applications.
Subsequently, an Executive Order was issued on January 27, 2021 temporarily suspending new leasing of federal lands and waters, including the federal Outer Continental Shelf. The order is not permanent, and explicitly does not impact existing, valid leases that are already in place. Talos currently has over 1.4 million gross acres under lease in the basin. Execution of Talos's 2021 and longer-term business plan is not dependent on new leasing and the Company does not expect a material adverse impact to its business as a result of this order.
FOURTH QUARTER 2020 RESULTS
Key Financial Highlights:
Three Months Ended | ||||
Period results ($ million, except per share and Boe amounts): | ||||
Total Revenue and Other | $ | 175.7 | ||
Net Loss | $ | (430.7) | ||
Loss per diluted share | $ | (5.73) | ||
Adjusted Net Loss(1) | $ | (31.2) | ||
Adjusted Loss per diluted share(1) | $ | (0.41) | ||
Adjusted EBITDA(1) | $ | 106.4 | ||
Capital Expenditures (including Plug & Abandonment) | $ | 71.0 | ||
Adjusted EBITDA Margin(1): | ||||
Adjusted EBITDA (% of Revenue - Operations) | 62 | % | ||
Adjusted EBITDA per Boe | $ | 19.47 | ||
Production, Realized Prices and Revenue
Production for the fourth quarter of 2020 was 5.5 MMBoe, with oil production accounting for 67% and liquids accounting for 77% of the total. Fourth quarter production was negatively impacted by hurricane and third party-downtime. Partially offsetting this downtime, production from Ram Powell was re-established in December, following several months of unplanned maintenance in the facility. Additionally, the Kaleidoscope well commenced production in the last week of December, resulting in a production exit rate of over 71.0 MBoe/d. Oil price realizations, net of certain gathering, transportation, quality differentials and other costs, were $40.63 per barrel, before hedges. Natural Gas price realizations, net of certain gathering, transportation and other costs, were $2.38 per Mcf, before hedges.
Three Months Ended | ||||
Production volumes | ||||
Oil production volume (MBbls) | 3,655 | |||
Natural Gas production volume (MMcf) | 7,691 | |||
NGL production volume (MBbls) | 531 | |||
Total production volume (MBoe) | 5,467 | |||
Average net daily production volumes | ||||
Oil (MBbl/d) | 39.7 | |||
Natural Gas (MMcf/d) | 83.6 | |||
NGL (MBbl/d) | 5.8 | |||
Total average net daily (MBoe/d) | 59.4 | |||
Average realized prices (excluding hedges)(2) | ||||
Oil ($/Bbl) | $ | 40.63 | ||
Natural Gas ($/Mcf) | 2.38 | |||
NGL ($/Bbl) | 10.86 | |||
Average realized price ($/Boe) | $ | 31.57 | ||
Average NYMEX prices | ||||
WTI ($/Bbl) | $ | 42.52 | ||
Henry Hub ($/MMBtu) | $ | 2.53 | ||
Revenues ($ million) | ||||
Oil | $ | 148.5 | ||
Natural Gas | 18.3 | |||
NGL | 5.8 | |||
Revenue - Operations | $ | 172.6 | ||
Other | 3.1 | |||
Total Revenue and Other | $ | 175.7 | ||
Three Months Ended December 31, 2020 | ||||||||||||||||
Production | % Oil | % Liquids | % Operated | |||||||||||||
Average net daily production volumes by Core Area (MBoe/d) | ||||||||||||||||
Green Canyon Area | 15.5 | 82 | % | 88 | % | 95 | % | |||||||||
Mississippi Canyon Area | 26.3 | 80 | % | 87 | % | 46 | % | |||||||||
Shelf and Gulf Coast | 17.6 | 35 | % | 50 | % | 54 | % | |||||||||
Total average net daily (MBoe/d) | 59.4 | 67 | % | 77 | % | 61 | % | |||||||||
Expenses
Total lease operating expenses ("LOE"), inclusive of workover and maintenance and insurance costs for the quarter, were $62.4 million or $11.41/Boe. General and administrative expenses ("G&A") for the quarter, excluding stock-based compensation, transaction-related expenses and other one-time time expenses, was $12.3 million, or $2.25/Boe.
($ Millions and Per Boe) | Three Months December 31, 2020 | Per Boe | ||||||
Lease Operating Expenses | $ | 62.4 | $ | 11.41 | ||||
General & Administrative Expenses (excluding non-cash and non-recurring items) | $ | 12.3 | $ | 2.25 | ||||
Other Financial Metrics
Capital Expenditures and Plugging & Abandonment Activities
Capital expenditures for the quarter include the impact of earlier-than-expected awards of leases from the November 2020 federal lease sale, as well as a scope expansion on the Company's Kaleidoscope project in December 2020.
($ Millions) | Three Months Ended | |||
Capital Expenditures | ||||
U.S. Drilling & Completions | $ | 46.1 | ||
Mexico Appraisal & Exploration | 0.3 | |||
Asset Management | 2.9 | |||
Seismic and G&G / Land / Capitalized G&A | 12.3 | |||
Total Capital Expenditures | $ | 61.6 | ||
Plugging & Abandonment | 9.4 | |||
Total Capital Expenditures and Plugging & Abandonment | $ | 71.0 | ||
Liquidity & Debt
As of January 31, 2021, inclusive of the Company's recently completed capital markets activities, Talos had $545.9 million of liquidity, including $64.5 million in cash on hand and $465.0 million drawn on the $960.0 million borrowing base under its credit facility. At year end 2020, the Company had $1,021.1 million in total debt, inclusive of $62.0 million related to the HP-I finance lease. Inclusive of pre-closing contributions from acquisitions completed throughout the year, Net Debt to Credit Facility LTM Adjusted EBITDA(1), as determined in accordance with the Company's credit agreement, was 2.2x.
YEAR-END 2020 RESERVES
SEC Reserves
As of December 31, 2020, Talos had proved reserves of 163.0 MMBoe, comprised of 67% oil, 74% liquids and 78% was proved developed. The PV-10 of proved reserves was approximately $2.0 billion. The reserves and associated PV-10 are audited by NSAI and are fully burdened by and net of all plugging & abandonment costs associated with the properties included in the reserves report. The following table summarizes Talos's proved reserves at December 31, 2020 based on SEC pricing of $39.54 per barrel and $1.99 per MMBtu:
SEC Reserves as of December 31, 2020 | ||||||||||||||||||||||
MBoe | % of Total | % Oil | Standardized Measure (in thousands) | PV -10 (in | ||||||||||||||||||
Proved Developed Producing | 89,692 | 55 | % | 72 | % | $ | 1,556,221 | |||||||||||||||
Proved Developed Non-Producing | 37,428 | 23 | % | 54 | % | 197,924 | ||||||||||||||||
Total Proved Developed | 127,120 | 78 | % | 67 | % | 1,754,145 | ||||||||||||||||
Proved Undeveloped | 35,913 | 22 | % | 68 | % | 244,340 | ||||||||||||||||
Total Proved | 163,033 | $ | 1,904,934 | $ | 1,998,485 | |||||||||||||||||
In addition to the proved reserves, Talos's audited probable reserves at December 31, 2020 were 69.2 MMBoe and had a PV-10 of $773.2 million.
Reserves Sensitivities
The following tables summarize the volumes and PV-10 values of Talos's proved reserves at December 31, 2020 at various crude oil prices:
Year End 2020 Reserves Sensitivity (MBoe) ($ / Bbl) | |||||
SEC(3) | $50 | $55 | $60 | $65 | |
Proved Developed Producing | 89,692 | 95,577 | 96,787 | 97,135 | 97,505 |
Proved Developed Non-Producing | 37,428 | 45,018 | 46,135 | 46,845 | 47,700 |
Total Proved Developed | 127,120 | 140,594 | 142,922 | 143,980 | 145,205 |
Proved Undeveloped | 35,913 | 40,910 | 41,974 | 42,380 | 42,624 |
Total Proved | 163,033 | 181,505 | 184,896 | 186,360 | 187,829 |
Year End 2020 Reserves Sensitivity (PV-10) ($ / Bbl) | |||||
SEC(3) | $50 | $55 | $60 | $65 | |
Proved Developed Producing | $1,556,221 | $2,123,616 | $2,392,900 | $2,656,139 | $2,922,119 |
Proved Developed Non-Producing | 197,924 | 356,195 | 430,091 | 504,335 | 579,145 |
Total Proved Developed | 1,754,145 | 2,479,811 | 2,822,990 | 3,160,475 | 3,501,264 |
Proved Undeveloped | 244,340 | 421,412 | 508,600 | 600,126 | 688,172 |
Total Proved | $1,998,485 | $2,901,223 | $3,331,591 | $3,760,601 | $4,189,436 |
Footnotes: | |
(1) | Adjusted Net Loss, Adjusted Loss per Share, Adjusted EBITDA, Adjusted EBITDA margin, Credit Facility LTM Adjusted EBITDA, Net Debt to Credit Facility LTM Adjusted EBITDA, 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) | Average realized prices are net of certain gathering, transportation, quality differentials and other costs. |
(3) | SEC pricing as of December 31, 2020 of $39.54 per barrel and $1.99 per MMBtu. |
2021 OPERATIONAL AND FINANCIAL GUIDANCE
Guidance Overview
Talos has announced its 2021 operational and financial guidance. Key highlights include:
- Production of 63.0 - 67.0 MBoe/d equating to ~19% growth from 2020 actuals or ~2% growth from 2020 figures adjusted for the material impacts of hurricanes and COVID-19 issues at the mid-point of the guidance range. 2021 production guidance includes the impact of shut-ins to the Pompano facility in the first and second quarters of 2021 for tie-in of the Praline project (for which Talos will collect future production handling fees) and platform rig construction ahead of an upcoming drilling campaign as well as materially increased weather-related risking for the year.
- Cash Operating and General and Administrative Expenses of $290 - $310 million and $60 - $65 million, respectively. Figures include significant incremental workover activity of approximately $15 million over 2020 levels, including a deepwater intervention workover that will positively impact production in 2021 but will be classified as expense in the Company's financials. Figures also incorporate a full year impact from three acquisitions in 2020.
- Capital Expenditures of $340 - $370 million, of which approximately 70% is drilling, completions and asset management. The 2021 program is primarily focused on lower-risk development and exploitation projects with quick turnaround to first oil along with selected exploration exposure. The guidance range represents a ~12% reduction from 2020 levels.
The following table summarizes the Company's proposed 2021 financial guidance:
FY 2021 | |||
($ Millions, unless highlighted) | Low | High | |
Production | Oil (MMBbl) | 15.7 | 16.6 |
Natural Gas (Bcf) | 34.5 | 37.0 | |
NGL (MMBbl) | 1.6 | 1.7 | |
Total (MMBoe) | 23.0 | 24.5 | |
Avg Daily Production (MBoe/d) | 63.0 | 67.0 | |
Cash Expenses | Cash Operating Expenses(1)(2) | $290 | $310 |
G&A(2)(3) | $60 | $65 | |
Capex | Capital Expenditures(4)(5) | $340 | $370 |
1) | Inclusive of all Lease Operating Expenses and Workover and Maintenance |
2) | Includes insurance costs |
3) | Excludes non-cash equity-based compensation |
4) | Includes Plugging & Abandonment |
5) | Excludes acquisitions |
2021 Capital Projects
The Company's 2021 capital expenditures program focuses primarily on asset management, development and exploitation project categories which carry lower risk than exploration with quick turnaround to first production. These 2021 projects are focused around Talos-owned and operated infrastructure and carry high working interests. Additionally, Talos is currently drilling the Puma West high-impact exploration well, and may execute an additional high-impact exploration project by year end.
GC-18 Program: Talos is executing additional asset management activities prior to completing the platform rig program in the Green Canyon 18 field. Talos successfully completed the Tokum development well in February 2021.
Pompano Program: Talos expects to execute a four-well program around its 100% owned and operated Pompano facility, including two recompletions, one workover and one development well, Salamanca. Talos expects the asset management projects completed and online by year-end 2021 and the Salamanca well online by the first quarter of 2022, with additional opportunities based on the success of the initial program. The Pompano facility will undergo planned shut-ins in the first and second quarters of 2021 for the tieback of the third-party Praline development and for the construction of the platform rig that will be utilized in the 2021 drilling program.
Tornado Attic Well: Talos expects to drill and complete a sidetrack development well to optimize the successful 2020 water flood project in the Company's operated Tornado field. Once online by the fourth quarter of 2021, the attic well is expected to initially generate 8.0 - 10.0 gross, 3.7 - 4.6 MBoe/d net from the additional recovery resulting from the water flood project.
High-Impact Exploration: Talos is currently drilling the Puma West exploration well. The Company may selectively add an additional high-impact exploration project during 2021, which is included in the 2021 guidance. Exploration wells are higher risk than other categories and carry longer lead-times to first oil, but creates significant shareholder value while providing material reserves and production rate additions when successful.
HEDGES
The following table reflects contracted volumes and weighted average prices the Company will receive under the terms of its derivative contracts as of March 10, 2021 and includes contracts entered into after December 31, 2020:
Instrument Type | Avg. Daily Volume | Weighted Avg. Swap Price | Weighted Avg. Put Price | Weighted Avg. Call Price | |||||||
Crude - WTI | (Bbls) | (Per Bbl) | (Per Bbl) | (Per Bbl) | |||||||
January - December 2021 | Swaps | 26,177 | $44.46 | --- | --- | ||||||
January - December 2021 | Collars | 1,000 | --- | $30.00 | $40.00 | ||||||
January - December 2022 | Swaps | 16,353 | $47.11 | --- | --- | ||||||
January - June 2023 | Swaps | 2,000 | $53.33 | --- | --- | ||||||
Crude - LLS | |||||||||||
January - December 2021 | Swaps | 3,000 | $38.83 | --- | --- | ||||||
Natural Gas - HH NYMEX | (MMBtu) | (per MMBtu) | (per MMBtu) | (per MMBtu) | |||||||
January - December 2021 | Collars | 59,244 | $2.57 | --- | --- | ||||||
January - December 2021 | Collars | 5,000 | --- | $2.50 | $3.10 | ||||||
January - December 2022 | Swaps | 31,381 | $2.62 | --- | --- | ||||||
January - June 2023 | Swaps | 5,000 | $2.61 | --- | --- |
CONFERENCE CALL AND WEBCAST INFORMATION
Talos will host a conference call, which will be broadcast live over the internet, on Thursday, March 11, 2021 at 10:00 AM Eastern Time (9:00 AM Central Time). Listeners can access the conference call live over the Internet through a webcast link on the Company's website at: https://www.talosenergy.com/investors. Alternatively, the conference call can be accessed by dialing (888) 348-8927 (U.S. toll-free), (855) 669-9657 (Canada toll-free) or (412) 902-4263 (international). Please dial in approximately 15 minutes before the teleconference is scheduled to begin and ask to be joined into the Talos Energy call. A replay of the call will be available one hour after the conclusion of the conference through March 18, 2021 and can be accessed by dialing (877) 344-7529 and using access code 10151824.
ABOUT TALOS ENERGY
Talos Energy (NYSE: TALO) is a technically driven independent exploration and production company focused on safely and efficiently maximizing cash flows and long-term value through its operations, currently in the United StatesGulf of Mexico and offshore Mexico. As one of the U.S. Gulf of Mexico's largest public independent producers, we leverage decades of geology, geophysics and offshore operations expertise towards the acquisition, exploration, exploitation and development of assets in key geological trends that are present in many offshore basins around the world. Our activities in offshore Mexico provide high impact exploration opportunities in an oil rich emerging basin. For more information, visit www.talosenergy.com.
INVESTOR RELATIONS CONTACT
Sergio Maiworm
+1.713.328.3008
investor@talosenergy.com
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
This communication may contain "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact included in this communication, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this communication, the words "could," "believe," "anticipate," "intend," "estimate," "expect," "project," "forecast, "may," "objective," "plan" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.
We caution you that these forward-looking statements are subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility, including the sharp decline in oil prices beginning in March 2020, the impact of the coronavirus disease 2019 ("COVID-19") and governmental measures related thereto on global demand for oil and natural gas and on the operations of our business, the ability or willingness of the Organization of Petroleum Exporting Countries ("OPEC") and non-OPEC countries, such as Saudi Arabia and Russia, to set and maintain oil production levels and the impact of any such actions, lack of transportation and storage capacity as a result of oversupply, government regulations and actions, including with respect to repairs to the Ram Powell facility, or other factors, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, 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, 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, and other factors that may affect our future results and business, generally, including those discussed under the heading "Risk Factors" in our Annual Report on Form 10-K for the year ended December 31, 2020, to be filed with the SEC subsequent to the issuance of this communication.
Should one or more of these risks occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, to reflect events or circumstances after the date of this communication.
Estimates for our future production volumes are based on assumptions of capital expenditure levels and the assumption that market demand and prices for oil and gas will continue at levels that allow for economic production of these products. The production, transportation, marketing and storage of oil and gas are subject to disruption due to transportation, processing and storage availability, mechanical failure, human error, hurricanes and numerous other factors. Our estimates are based on certain other assumptions, such as well performance, which may vary significantly from those assumed. Therefore, we can give no assurance that our future production volumes will be as estimated.
CAUTIONARY NOTE TO INVESTORS
The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC's definitions for such terms. In this communication, the Company uses certain broader terms such as "contingent resources" and "2C resources" that the SEC's guidelines strictly prohibit the Company from including in filings with the SEC. These types of estimates do not represent, and are not intended to represent, any category of reserves based on SEC definitions, are by their nature more speculative than estimates of proved, probable and possible reserves and do not constitute "reserves" within the meaning of the SEC's rules. These estimates are subject to greater uncertainties, and accordingly, are subject to a substantially greater risk of actually being realized. Investors are urged to consider closely the disclosures and risk factors in the reports the Company files with the SEC.
Talos Energy Inc. | ||||||||
Condensed Consolidated Balance Sheets | ||||||||
(In thousands, except per share amounts) | ||||||||
Year Ended December 31, | ||||||||
2020 | 2019 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 34,233 | $ | 87,022 | ||||
Accounts receivable | ||||||||
Trade, net | 106,220 | 107,842 | ||||||
Joint interest, net | 50,471 | 16,552 | ||||||
Other | 18,448 | 6,346 | ||||||
Assets from price risk management activities | 6,876 | 8,393 | ||||||
Prepaid assets | 29,285 | 65,877 | ||||||
Other current assets | 1,859 | 1,952 | ||||||
Total current assets | 247,392 | 293,984 | ||||||
Property and equipment: | ||||||||
Proved properties | 4,945,550 | 4,066,260 | ||||||
Unproved properties, not subject to amortization | 254,994 | 194,532 | ||||||
Other property and equipment | 32,853 | 29,843 | ||||||
Total property and equipment | 5,233,397 | 4,290,635 | ||||||
Accumulated depreciation, depletion and amortization | (2,697,228) | (2,065,023) | ||||||
Total property and equipment, net | 2,536,169 | 2,225,612 | ||||||
Other long-term assets: | ||||||||
Assets from price risk management activities | 945 | - | ||||||
Other well equipment inventory | 18,927 | 7,732 | ||||||
Operating lease assets | 6,855 | 7,779 | ||||||
Other assets | 24,258 | 54,375 | ||||||
Total assets | $ | 2,834,546 | $ | 2,589,482 | ||||
LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 104,864 | $ | 71,357 | ||||
Accrued liabilities | 163,379 | 154,816 | ||||||
Accrued royalties | 27,903 | 31,729 | ||||||
Current portion of asset retirement obligations | 49,921 | 61,051 | ||||||
Liabilities from price risk management activities | 66,010 | 19,476 | ||||||
Accrued interest payable | 9,509 | 10,249 | ||||||
Current portion of operating lease liabilities | 1,793 | 1,594 | ||||||
Other current liabilities | 24,155 | 20,180 | ||||||
Total current liabilities | 447,534 | 370,452 | ||||||
Long-term liabilities: | ||||||||
Long-term debt, net of discount and deferred financing costs | 985,512 | 732,981 | ||||||
Asset retirement obligations | 392,348 | 308,427 | ||||||
Liabilities from price risk management activities | 9,625 | 511 | ||||||
Operating lease liabilities | 18,554 | 17,239 | ||||||
Other long-term liabilities | 54,372 | 81,595 | ||||||
Total liabilities | 1,907,945 | 1,511,205 | ||||||
Commitments and contingencies (Note 12) | ||||||||
Stockholders' Equity: | ||||||||
Preferred stock, $0.01 par value; 30,000,000 shares authorized and no shares issued or outstanding | - | - | ||||||
Common stock $0.01 par value; 270,000,000 shares authorized; 81,279,989 and 54,197,004 shares | 813 | 542 | ||||||
Additional paid-in capital | 1,659,800 | 1,346,142 | ||||||
Accumulated deficit | (734,012) | (268,407) | ||||||
Total stockholders' equity | 926,601 | 1,078,277 | ||||||
Total liabilities and stockholders' equity | $ | 2,834,546 | $ | 2,589,482 | ||||
Talos Energy Inc. | ||||||||||||||||
Condensed Consolidated Statements of Operations | ||||||||||||||||
(In thousands, except per common share amounts) | ||||||||||||||||
Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||||||
2020 | 2019 | 2020 | 2019 | |||||||||||||
Revenues and Other: | ||||||||||||||||
Oil | $ | 148,503 | $ | 208,632 | $ | 506,788 | $ | 833,118 | ||||||||
Natural gas | 18,339 | 13,540 | 53,714 | 55,278 | ||||||||||||
NGL | 5,760 | 4,573 | 15,434 | 19,668 | ||||||||||||
Other | 3,109 | 6,495 | 11,550 | 19,556 | ||||||||||||
Total revenues and other | 175,711 | 233,240 | 587,486 | 927,620 | ||||||||||||
Operating expenses: | ||||||||||||||||
Lease operating expense | 62,377 | 59,197 | 246,564 | 243,427 | ||||||||||||
Production taxes | 414 | 282 | 1,054 | 1,349 | ||||||||||||
Depreciation, depletion and amortization | 101,813 | 97,413 | 364,346 | 345,931 | ||||||||||||
Write-down of oil and natural gas properties | 267,859 | (1,557) | 267,916 | 12,221 | ||||||||||||
Accretion expense | 11,993 | 7,521 | 49,741 | 34,389 | ||||||||||||
General and administrative expense | 16,691 | 23,414 | 79,175 | 77,209 | ||||||||||||
Total operating expenses | 461,147 | 186,270 | 1,008,796 | 714,526 | ||||||||||||
Operating income | (285,436) | 46,970 | (421,310) | 213,094 | ||||||||||||
Interest expense | (23,251) | (24,574) | (99,415) | (97,847) | ||||||||||||
Price risk management activities income (expense) | (66,968) | (59,508) | 87,685 | (95,337) | ||||||||||||
Other income (expense) | 2,879 | 847 | 3,018 | 2,678 | ||||||||||||
Net income (loss) before income taxes | (372,776) | (36,265) | (430,022) | 22,588 | ||||||||||||
Income tax benefit (expense) | (57,967) | 36,569 | (35,583) | 36,141 | ||||||||||||
Net income (loss) | $ | (430,743) | $ | 304 | $ | (465,605) | $ | 58,729 | ||||||||
Talos Energy Inc. | ||||||||||||
Condensed Consolidated Statements of Cash Flows | ||||||||||||
(In thousands) | ||||||||||||
Year Ended December 31, | ||||||||||||
2020 | 2019 | 2018 | ||||||||||
Cash flows from operating activities: | ||||||||||||
Net income (loss) | $ | (465,605) | $ | 58,729 | $ | 221,540 | ||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities | ||||||||||||
Depreciation, depletion, amortization and accretion expense | 414,087 | 380,320 | 324,063 | |||||||||
Write-down of oil and natural gas properties and other well inventory | 268,615 | 12,386 | 244 | |||||||||
Amortization of deferred financing costs and original issue discount | 6,804 | 5,207 | 4,253 | |||||||||
Equity based compensation, net of amounts capitalized | 8,669 | 6,964 | 2,893 | |||||||||
Price risk management activities expense (income) | (87,685) | 95,337 | (60,435) | |||||||||
Net cash received (paid) on settled derivative instruments | 143,905 | (8,820) | (111,147) | |||||||||
Gain on Extinguishment of debt | (1,662) | - | - | |||||||||
Settlement of asset retirement obligations | (43,933) | (75,331) | (112,946) | |||||||||
Changes in operating assets and liabilities: | ||||||||||||
Accounts receivable | (34,645) | 5,788 | (786) | |||||||||
Other current assets | 35,934 | (15,114) | (2,624) | |||||||||
Accounts payable | 27,096 | 7,523 | (48,825) | |||||||||
Other current liabilities | 4,200 | (35,459) | 32,044 | |||||||||
Other non-current assets and liabilities, net | 26,143 | (43,797) | 15,171 | |||||||||
Net cash provided by operating activities | 301,923 | 393,733 | 263,445 | |||||||||
Cash flows from investing activities: | ||||||||||||
Exploration, development and other capital expenditures | (362,942) | (463,409) | (240,914) | |||||||||
Cash (paid for) received from acquisitions, net of cash acquired | (315,962) | (37,916) | 278,409 | |||||||||
Proceeds from sale of other property and equipment | - | 5,369 | - | |||||||||
Net cash provided by (used in) investing activities | (678,904) | (495,956) | 37,495 | |||||||||
Cash flows from financing activities: | ||||||||||||
Proceeds from issuance of common stock | 71,100 | - | - | |||||||||
Redemption of Senior Notes and other long-term debt | (5,364) | (10,567) | (25,257) | |||||||||
Proceeds from Bank Credit Facility | 350,000 | 110,000 | 319,000 | |||||||||
Repayment of Bank Credit Facility | (60,000) | (25,000) | (54,000) | |||||||||
Repayment of LLC Bank Credit Facility | - | - | (403,000) | |||||||||
Deferred financing costs | (1,287) | (1,963) | (17,002) | |||||||||
Other deferred payments | (11,921) | (9,921) | - | |||||||||
Payments of finance lease | (17,509) | (14,133) | (12,952) | |||||||||
Employee stock transactions | (827) | (333) | - | |||||||||
Net cash provided by (used in) financing activities | 324,192 | 48,083 | (193,211) | |||||||||
Net increase (decrease) in cash, cash equivalents and restricted cash | (52,789) | (54,140) | 107,729 | |||||||||
Cash, cash equivalents and restricted cash: | ||||||||||||
Balance, beginning of period | 87,022 | 141,162 | 33,433 | |||||||||
Balance, end of period | $ | 34,233 | $ | 87,022 | $ | 141,162 | ||||||
Supplemental Non-Cash Transactions: | ||||||||||||
Capital expenditures included in accounts payable and accrued liabilities | $ | 74,957 | $ | 90,956 | $ | 100,664 | ||||||
Debt exchanged for common stock | $ | 35,960 | $ | - | $ | - | ||||||
Supplemental Cash Flow Information: | ||||||||||||
Interest paid, net of amounts capitalized | $ | 67,443 | $ | 62,571 | $ | 53,476 | ||||||
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," "Adjusted Earnings per Share," "EBITDA," "Adjusted EBITDA," "Adjusted EBITDA excluding hedges," "Adjusted EBITDA Margin," "Adjusted EBITDA Margin excluding hedges," "Free Cash Flow," "Net Debt," "LTM Adjusted EBITDA," "Credit Facility LTM Adjusted EBITDA" and "Net Debt to Credit Facility LTM Adjusted EBITDA." These disclosures may not be viewed as a substitute for results determined in accordance with GAAP and are not necessarily comparable to non-GAAP measures which may be reported by other companies.
Reconciliation of Net Income (Loss) to EBITDA and Adjusted EBITDA
"EBITDA" and "Adjusted EBITDA" are to provide management and investors with (i) additional information to evaluate, with certain adjustments, items required or permitted in calculating covenant compliance under our debt agreements, (ii) important supplemental indicators of the operational performance of our business, (iii) additional criteria for evaluating our performance relative to our peers and (iv) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. EBITDA and Adjusted EBITDA have limitations as analytical tools and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP or as alternatives to net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP. We define these as the following:
EBITDA. Net income (loss) plus interest expense, income tax expense (benefit), depreciation, depletion and amortization and accretion expense.
Adjusted EBITDA. EBITDA plus non-cash write-down of oil and natural gas properties, loss on debt extinguishment, transaction related costs, derivative fair value (gain) loss, net cash receipts (payments) on settled derivatives, non-cash (gain) loss on sale of assets, non-cash write-down of other well equipment inventory and non-cash equity-based compensation expense.
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, 2020 | March 31, | ||||||||||||||||||
Reconciliation of net income (loss) to Adjusted EBITDA: | ||||||||||||||||||||||
Net income (loss) | $ | (430,743) | $ | (52,000) | $ | (140,611) | $ | 157,749 | ||||||||||||||
Interest expense | 23,251 | 24,124 | 26,190 | 25,850 | ||||||||||||||||||
Income tax expense (benefit) | 57,967 | (28,252) | (49,392) | 55,260 | ||||||||||||||||||
Depreciation, depletion and amortization | 101,813 | 80,547 | 88,443 | 93,543 | ||||||||||||||||||
Accretion expense | 11,993 | 11,537 | 13,794 | 12,417 | ||||||||||||||||||
EBITDA | (235,719) | 35,956 | (61,576) | 344,819 | ||||||||||||||||||
Write-down of oil and natural gas properties | 267,859 | - | - | 57 | ||||||||||||||||||
Transaction and non-recurring expenses | 2,054 | 1,607 | 3,498 | 7,758 | ||||||||||||||||||
Derivative fair value (gain) loss(1) | 66,968 | 19,882 | 68,682 | (243,217) | ||||||||||||||||||
Net cash receipts (payments) on settled derivative instruments(1) | 2,376 | 19,030 | 86,039 | 36,460 | ||||||||||||||||||
Loss (Gain) on extinguishment of debt | (18) | (174) | (1,470) | - | ||||||||||||||||||
Non-cash write-down of other well equipment inventory | 566 | - | - | 133 | ||||||||||||||||||
Non-cash equity-based compensation expense | 2,348 | 2,347 | 2,347 | 1,627 | ||||||||||||||||||
Adjusted EBITDA | 106,434 | 78,648 | 97,520 | 147,637 | ||||||||||||||||||
Net cash receipts (payments) on settled derivative instruments(1) | (2,376) | (19,030) | (86,039) | (36,460) | ||||||||||||||||||
Adjusted EBITDA excluding hedges | 104,058 | 59,618 | 11,481 | 111,177 | ||||||||||||||||||
Production and Revenue: | ||||||||||||||||||||||
Boe(2) | 5,467 | 4,470 | 4,775 | 5,287 | ||||||||||||||||||
Revenue - Operations | 172,602 | 132,936 | 87,575 | 182,823 | ||||||||||||||||||
Adjusted EBITDA margin and Adjusted EBITDA excl hedges margin: | ||||||||||||||||||||||
Adjusted EBITDA divided by Revenue - Operations (%) | 62 | % | 59 | % | 111 | % | 81 | % | ||||||||||||||
Adjusted EBITDA per Boe(2) | $ | 19.47 | $ | 17.59 | $ | 20.42 | $ | 27.92 | ||||||||||||||
Adjusted EBITDA excl hedges divided by Revenue - Operations (%) | 60 | % | 45 | % | 13 | % | 61 | % | ||||||||||||||
Adjusted EBITDA excl hedges per Boe(2) | $ | 19.03 | $ | 13.34 | $ | 2.40 | $ | 21.03 | ||||||||||||||
(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 a cash basis during the period the derivatives settled. |
Reconciliation of Adjusted EBITDA to Free Cash Flow
"Free Cash Flow" provides management and investors with (i) important supplemental indicators of the operational performance of our business, (ii) additional criteria for evaluating our performance relative to our peers and (iii) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. Free Cash Flow has limitations as an analytical tool and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP or as alternatives to net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP. We define these as the following:
Capital Expenditures and Plugging & Abandonment. Actual capital expenditures and plugging & abandonment recognized in the quarter, inclusive of accruals.
Interest Expense. Actual interest expense per the income statement.
Talos did not pay any cash taxes in the period, therefore cash taxes have no impact to the reported Free Cash Flow number.
($ thousands, except per share amounts) | Three Months Ended | |||
Reconciliation of Adjusted EBITDA to Free Cash Flow | ||||
Adjusted EBITDA | $ | 106,434 | ||
Less: Capital Expenditures and Plugging & Abandonment | (71,021) | |||
Less: Interest Expense | (23,251) | |||
Free Cash Flow | $ | 12,162 | ||
Reconciliation of Net Income (Loss) to Adjusted Net Income and Adjusted Earnings per Share
"Adjusted Net Income" 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 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. 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 divided by the number of common shares.
($ thousands, except per share amounts) | Three Months Ended | |||
Reconciliation of Net Loss to Adjusted Net Loss: | ||||
Net Loss | $ | (430,743) | ||
Write-down of oil and natural gas properties | 267,859 | |||
Transaction related costs and non-recurring expenses | 2,054 | |||
Derivative fair value gain (loss)(1) | 66,968 | |||
Net cash receipts on settled derivative instruments(1) | 2,376 | |||
Non-cash income tax expense | 57,967 | |||
Non-cash equity-based compensation expense | 2,348 | |||
Adjusted Net Loss | $ | (31,171) | ||
Weighted average common shares outstanding at December 31, 2020: | ||||
Basic | 75,199 | |||
Diluted | 75,199 | |||
Net Loss per common share: | ||||
Basic | $ | (5.73) | ||
Diluted | $ | (5.73) | ||
Adjusted Net Loss per common share: | ||||
Basic | $ | (0.41) | ||
Diluted | $ | (0.41) | ||
(1) | The adjustments for the derivative fair value (gain) loss and net cash receipts (payments) on settled derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted Net Income on a cash basis during the period the derivatives settled. |
Reconciliation of Total Debt to Net Debt and Net Debt to LTM Adjusted EBITDA and Credit Facility LTM Adjusted EBITDA
We believe the presentation of Net Debt, LTM Adjusted EBITDA, Credit Facility LTM Adjusted EBITDA, Net Debt to LTM Adjusted EBITDA and Net Debt to Credit Facility LTM Adjusted EBITDA is important to provide management and investors with additional important information to evaluate our business. These measures are widely used by investors and ratings agencies in the valuation, comparison, rating and investment recommendations of companies
Net Debt. Total Debt principal of the Company plus the Finance Lease balance minus Cash.
Net Debt to LTM Adjusted EBITDA. Net Debt divided by the LTM Adjusted EBITDA.
Net Debt to Credit Facility LTM Adjusted EBITDA. Net Debt divided by the Credit Facility LTM Adjusted EBITDA.
Reconciliation of Net Debt ($ thousands) at December 31, 2020: | ||||
11.00% Second-Priority Senior Secured Notes - due April 2022 | $ | 347,254 | ||
7.50% Senior Notes - due May 2022 | 6,060 | |||
Bank Credit Facility - matures May 2022 | 640,000 | |||
Finance lease | 62,026 | |||
Total Debt | 1,055,340 | |||
Less: Cash and cash equivalent | (34,233) | |||
Net Debt | $ | 1,021,107 | ||
Calculation of LTM EBITDA: | ||||
Adjusted EBITDA for three months period ended March 31, 2020 | $ | 147,637 | ||
Adjusted EBITDA for three months period ended June 30, 2020 | 97,520 | |||
Adjusted EBITDA for three months period ended September 30, 2020 | 78,648 | |||
Adjusted EBITDA for three months period ended December 31, 2020 | 106,434 | |||
LTM Adjusted EBITDA | 430,239 | |||
Acquired Assets Adjusted EBITDA for pre-closing periods | 34,005 | |||
Credit Facility LTM Adjusted EBITDA | $ | 464,244 | ||
Reconciliation of Net Debt to LTM Adjusted EBITDA: | ||||
Net Debt / LTM Adjusted EBITDA | 2.4x | |||
Net Debt / Credit Facility LTM Adjusted EBITDA | 2.2x |
The Adjusted EBITDA information included in this communication provides additional relevant information to our investors and creditors. Talos needs to comply with a financial covenant included in its Bank Credit Facility that requires it to maintain a Net Debt to Credit Facility LTM Adjusted EBITDA ratio, as determined in accordance with the Company's credit agreement, equal to or lower than 3.0x. For purposes of covenant compliance, Credit Facility LTM Adjusted EBITDA, with certain adjustments, is calculated as the sum of quarterly Adjusted EBITDA for the 12-month period ended on that quarter, inclusive of revenue less direct operating expenditures of the Acquired Assets for periods prior to closing of the Transaction.
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