Talos Energy Announces Fourth Quarter and Full Year 2021 Results and Provides 2022 Guidance
Talos Energy Inc. (TALO) reported strong fourth-quarter results, achieving production of 68.7 MBoe/d and net income of $81 million, or $0.98 per diluted share. 2021 production averaged 64.4 MBoe/d, resulting in a net loss of $183 million. The company forecasts 2022 production between 60.0 - 64.0 MBoe/d and plans capital expenditures of $450 - $480 million, aiming for a leverage ratio reduction to approximately 1.0x by year-end. Talos also advanced its carbon capture initiatives, including a partnership for a major project in the Gulf Coast. Liquidity was $472.6 million at year-end.
- Fourth-quarter net income of $81 million, up from a $183 million loss for the full year.
- Production of 68.7 MBoe/d in Q4, with 69% oil and 77% liquids.
- Significant free cash flow generation of $93 million in Q4.
- 2022 guidance indicates a levered strategy aiming for a leverage ratio reduction to 1.0x by year-end.
- Full-year net loss of $183 million, translating to a loss of $2.24 per diluted share.
- Unplanned downtime of 3.5-4.0 MBoe/d due to the Eugene Island Pipeline impact.
- 2022 production expected to dip due to planned maintenance downtime.
HOUSTON, Feb. 24, 2022 /PRNewswire/ -- Talos Energy Inc. ("Talos" or the "Company") (NYSE: TALO) today announced its operational and financial results for the fourth quarter and full year 2021. The Company also announced its year-end 2021 reserves figures as well as 2022 operational and financial guidance.
Fourth Quarter 2021 Highlights:
- Production of 68.7 thousand barrels of oil equivalent per day ("MBoe/d") (
69% oil,77% liquids) - Net Income of
$81.0 million , or$0.98 Net Income per diluted share, and Adjusted Net Income(1) of$37.4 million , or$0.45 Adjusted Net Income per diluted share - Adjusted EBITDA(1) of
$190.4 million , or$30.12 Adjusted EBITDA per Boe; Adjusted EBITDA excluding hedges of$291.3 million , or$46.09 per Boe - Capital Expenditures of
$64.2 million , inclusive of plugging and abandonment - Free Cash Flow(1) (before changes in working capital) of
$93.0 million
Full Year 2021 Highlights:
- Production of 64.4 MBoe/d (
69% oil,77% liquids) - Net Loss of
$183.0 million , or$2.24 Net Loss per diluted share, and Adjusted Net Income(1) of$6.0 million , or$0.07 Adjusted Net Income per diluted share(1) - Adjusted EBITDA(1) of
$606.5 million , or$25.81 Adjusted EBITDA per Boe; Adjusted EBITDA excluding hedges of$896.6 million , or$38.15 per Boe - Capital Expenditures of
$338.8 million , inclusive of plugging and abandonment, equating to56% of Adjusted EBITDA ("Reinvestment Rate") - Free Cash Flow(1) (before changes in working capital) of
$134.5 million - Leverage ratio of 1.7x and liquidity of
$472.6 million at year-end - Year-end 2021 SEC Proved reserves of 162 million barrels of oil equivalent ("MMBoe") (
67% oil,76% liquids) with a Proved PV-10(1) of$3.9 billion (2)
2022 Guidance Highlights:
- Production of 60.0 - 64.0 MBoe/d, inclusive of 3.0 – 4.0 MBoe/d of deferred production from forecasted planned downtime for the year and unplanned third-party downtime realized during the first quarter
- Capital Expenditures of
$450 -$480 million , equating to an approximately55% upstream Reinvestment Rate at current commodity prices or approximately60% all-in including$30 million in carbon capture and sequestration ("CCS") investments - Reduce leverage to approximately 1.0x by year-end driven by strong free cash flow generation and focus on debt paydown
Talos President and Chief Executive Officer Timothy S. Duncan commented: "It was an outstanding fourth quarter with high operational uptime, record production, excellent oil-weighted margins and significant free cash flow generation, which allowed us to end the year with a meaningfully improved leverage ratio and liquidity profile. With a capital allocation focus around our owned infrastructure, we ended 2021 with our highest percentage of Proved Developed reserves since becoming publicly traded in 2018 and with a Proved PV-10 of
Duncan continued: "Our 2022 upstream capital plan will invest across a broad range of project types, including several with short-cycle times to first production through our owned infrastructure and a series of deepwater subsea drilling projects with material resource and production rate potential that can be important contributors in 2023 and beyond. We are excited to begin the appraisal of Puma West, a high-impact exploration discovery from early 2021, with a second well in the latter half of 2022 with the goal of accelerating development. In our CCS business we will make measured investments that will lay the foundation for future success, including maturing our previously announced projects as well as aggressively pursuing more opportunities along the Gulf Coast. Even with more third-party downtime impacting production this year compared to last, we still expect 2022 to be an exciting year financially and strategically. Over the coming years, we expect that the impact of a successful infrastructure-led, subsea drilling campaign on top of our strong base business will generate in excess of
RECENT DEVELOPMENTS AND OPERATIONS UPDATE
Carbon Capture: Talos rapidly advanced its CCS business in the fourth quarter with several key announcements, including the Company's strategic alliance with TechnipFMC and its agreement with Freeport LNG and Storegga to develop a Point Source CCS solution, which could become the first active carbon sequestration project on the U.S. Gulf Coast. In February 2022, Talos and its partner, Storegga, signed a memorandum of understanding with EnLink Midstream to jointly develop the River Bend CCS project, a fully-integrated CCS offering in the Baton Rouge – New Orleans industrial corridor, one of the most concentrated sources of carbon emissions in the U.S. With an anticipated storage capacity of over 500 million metric tons of CO2, it is believed to be the one of the largest CCS projects in the country.
Additionally, in December 2021 Talos announced Robin Fielder as its first Executive Vice President - Low Carbon Strategy and Chief Sustainability Officer. Ms. Fielder will serve as the lead executive for Talos's rapidly growing CCS business as well as oversee all ESG and sustainability initiatives and reporting. Ms. Fielder brings over 20 years of executive leadership and commercial and technical experience across the energy value chain at multiple publicly traded upstream and midstream companies.
Shareholder and Governance Update: In December 2021, Talos announced the resignation of the two representatives of Apollo Global Management ("Apollo") and one of the two representatives of Riverstone Holdings ("Riverstone") from the Company's Board of Directors ("Board"). The resignations were not due to any issues or concerns specific to Talos. Apollo's Board members resigned as a result of Apollo's reduced ownership after recent share sales. In January 2022, Apollo subsequently reduced its ownership stake to approximately
Eugene Island Pipeline Downtime: Talos has experienced approximately 30 days of unplanned third-party downtime to date in the first quarter of 2022 resulting from maintenance of the Eugene Island Pipeline System ("EIPS"), which carries Talos's production from the HP-1 and Green Canyon 18 facilities. The third-party pipeline shut-in has resulted in a total production impact of approximately 3.5 – 4.0 MBoe/d for the first quarter of 2022 or 0.8 – 1.0 MBoe/d for the full year 2022 as of the date of this release. This impact is incorporated into the Company's 2022 operational and financial guidance.
ESG Updates: Talos published its second annual environmental, social and governance ("ESG") report in December 2021. The Company substantially increased the volume and quality of disclosures and further clarified the mapping of its reporting to recognized industry standards in its report. In 2021, Talos established a
FOURTH QUARTER AND FULL YEAR 2021 RESULTS
Key Financial Highlights:
Three Months | Twelve Months | |||||
Period results ($ million): | ||||||
Total Revenues | $ | 382.9 | $ | 1,244.5 | ||
Net Income (Loss) | $ | 81.0 | $ | (183.0) | ||
Net Income (Loss) per diluted share | $ | 0.98 | $ | (2.24) | ||
Adjusted Net Income(1) | $ | 37.4 | $ | 6.0 | ||
Adjusted Net Income per diluted share(1) | $ | 0.45 | $ | 0.07 | ||
Adjusted EBITDA(2) | $ | 190.4 | $ | 606.5 | ||
Adjusted EBITDA excluding hedges | $ | 291.3 | $ | 896.6 | ||
Capital Expenditures (including Plug & Abandonment) | $ | 64.2 | $ | 338.8 | ||
Adjusted EBITDA Margin: | ||||||
Adjusted EBITDA per Boe | $ | 30.12 | $ | 25.81 | ||
Adjusted EBITDA excluding hedges per Boe | $ | 46.09 | $ | 38.15 | ||
Production
Production was 68.7 MBoe/d net for the quarter and was
Three Months Ended | ||||
Average net daily production volumes | ||||
Oil (MBbl/d) | 47.1 | |||
Natural Gas (MMcf/d) | 95.0 | |||
NGL (MBbl/d) | 5.8 | |||
Total average net daily (MBoe/d) | 68.7 | |||
Three Months Ended December 31, 2021 | ||||||||||||
Production | % Oil | % Liquids | % Operated | |||||||||
Average net daily production volumes by Core Area (MBoe/d) | ||||||||||||
Green Canyon Area | 25.9 | 81 | % | 88 | % | 98 | % | |||||
Mississippi Canyon Area | 27.1 | 73 | % | 83 | % | 56 | % | |||||
Shelf and Gulf Coast | 15.7 | 40 | % | 48 | % | 52 | % | |||||
Total average net daily (MBoe/d) | 68.7 | 69 | % | 77 | % | 71 | % | |||||
Capital Expenditures
Capital expenditures, including plugging and abandonment, totaled
Three Months | Twelve Months | |||||
Capital Expenditures | ||||||
U.S. Drilling & Completions | $ | 14.0 | $ | 129.4 | ||
Mexico Appraisal & Exploration | 0.1 | 0.9 | ||||
Asset Management | 28.0 | 90.0 | ||||
Seismic and G&G / Land / Capitalized G&A | 12.1 | 50.5 | ||||
Total Capital Expenditures | 54.2 | 270.8 | ||||
Plugging & Abandonment | 10.0 | 68.0 | ||||
Total Capital Expenditures and Plugging & Abandonment | $ | 64.2 | $ | 338.8 | ||
Liquidity and Leverage
At year-end the Company had approximately
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, Credit Facility LTM Adjusted EBITDA, Net Debt, 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) | Reserves figures are presented inclusive of the plugging and abandonment obligations and before hedges, utilizing SEC pricing of |
YEAR-END 2021 RESERVES
SEC Reserves
As of December 31, 2021, Talos had proved reserves of 162 MMBoe, comprised of
SEC Reserves as of December 31, 2021 | |||||||||||||||
MBoe | % of Total | % Oil | Standardized | PV -10 | |||||||||||
Proved Developed Producing | 95,649 | 59 | % | 73 | % | $ | 3,073,168 | ||||||||
Proved Developed Non-Producing | 40,637 | 25 | % | 57 | % | 599,010 | |||||||||
Total Proved Developed | 136,286 | 84 | % | 69 | % | 3,672,178 | |||||||||
Proved Undeveloped | 25,305 | 16 | % | 57 | % | 253,819 | |||||||||
Total Proved | 161,591 | $ | 3,440,611 | $ | 3,925,997 | ||||||||||
Estimated Proved Reserves | |||||||||||||||
MBoe | % Oil | % Natural | % NGLs | % Proved Developed | |||||||||||
Green Canyon | 52,777 | 79 | % | 14 | % | 7 | % | 81 | % | ||||||
Mississippi Canyon | 67,349 | 75 | % | 16 | % | 9 | % | 90 | % | ||||||
Shelf & Gulf Coast | 41,465 | 38 | % | 51 | % | 11 | % | 79 | % | ||||||
Total United States | 161,591 | 67 | % | 24 | % | 9 | % | 84 | % | ||||||
Reserves Sensitivities
The following tables summarize the PV-10 values of Talos's proved reserves at December 31, 2021 at various crude oil prices:
End 2021 Reserves Sensitivity (PV-10) ( | ||||
Proved Developed Producing | ||||
Proved Developed Non-Producing | 495,716 | 645,585 | 794,432 | 941,257 |
Total Proved Developed | 3,204,706 | 3,897,885 | 4,592,909 | 5,287,559 |
Proved Undeveloped | 194,732 | 277,820 | 355,665 | 433,613 |
Total Proved | ||||
2022 OPERATIONAL AND FINANCIAL GUIDANCE
The Company's financial framework in 2022 is intended to deliver stable production levels, strong operating margins, solid free cash flow and significant debt reduction. Talos expects to execute on these financial parameters while investing in its unique catalysts as a conventional-focused offshore leader, including high-impact deepwater exploitation and exploration wells and the Company's rapidly growing CCS business. Talos expects to deliver an attractive financial profile while advancing its differentiated opportunity set for the future.
Guidance Overview
- Production of 60.0 - 64.0 MBoe/d (
66% oil and75% liquids), which includes approximately 45 - 60 days of planned downtime for HP-1 dry-dock maintenance and approximately 30 days of unplanned downtime realized to date from the EIPS third-party pipeline outage impacting a portion of our asset base. The normalized production range for 2022 is 63.0 – 68.0 MBoe/d, prior to adjustments of 2.0 - 3.0 MBoe/d and 0.8 – 1.0 MBoe/d for the year for dry-dock and the EIPS downtime, respectively.
The HP-1 dry-dock process satisfies regulatory requirements for periodic maintenance of the Company's HP-1 floating production unit, which operates the Company's Phoenix and Tornado fields. The dry-dock process has historically enabled outstanding production uptimes and safety and environmental records at the facility. The 2022 dry-dock is expected to occur during the months of June and July.
- Cash Operating Expenses and General and Administrative Expenses of
$300 -$320 million and$68 -$73 million , respectively. Cash expenses include approximately$20 million in dry-dock maintenance expenses for the HP-1, additional cash expenses related to CCS and expected cost inflation adjustments.
- Capital Expenditures of
$450 -$480 million , inclusive of a wide spectrum of drilling and completions projects, all plugging and abandonment expenditures and approximately$30 million in CCS investments. Capital expenditures throughout the year are weighted to the third and fourth quarters. Additionally, approximately50% of the 2022 drilling and completion program are targeted to generate production beginning in 2023 and beyond.
- Interest Expense of
$115 -$125 million , inclusive of approximately$95 -$100 million of cash interest expense on debt and the HP-1 finance lease as well as approximately$20 -$25 million of non-cash expenses and surety charges.
- Leverage ratio reduction to approximately 1.0x by year-end 2022, with debt reduction resulting from significant free cash flow at current market conditions.
The following table summarizes the Company's proposed 2022 operational and financial guidance:
FY 2022 | |||
($ Millions, unless highlighted) | Low | High | |
Production | Oil (MMBbl) | 14.6 | 15.5 |
Natural Gas (Bcf) | 33.1 | 35.3 | |
NGL (MMBbl) | 1.8 | 1.9 | |
Total (MMBoe) | 21.9 | 23.4 | |
Avg Daily Production (MBoe/d) | 60.0 | 64.0 | |
Cash Expenses | Cash Operating Expenses(1)(2) | ||
G&A(2)(3) | |||
Capex | Capital Expenditures(4)(5) | ||
Interest | Interest Expense(6) | ||
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 |
6) | Includes cash interest expense on debt and finance lease, surety charges and amortization of deferred financing costs and original issue discounts |
2022 Capital Projects
The Company's 2022 capital program is focused on full-lifecycle exploration and production projects as well as evolving CCS opportunities. The Company's upstream investments will target a range of short-cycle, infrastructure-led asset management and development projects as well as numerous higher-impact exploitation and exploration targets with the potential to add material reserves and production in the future. Additionally, the Company will make targeted CCS investments. Despite approximately
2022 Planned Activity: Talos will execute one asset management and up to six drilling and completions projects utilizing both an ultra-deepwater floater rig and a platform-based rig. Subject to final business development activities and the timing of rig delivery in the second half of 2022, two to three wells drilled from the deepwater floater rig will be operated by Talos and located in the Mississippi Canyon Miocene fairway, with working interests of 40
Puma West Appraisal: Talos, along with affiliates of bp plc ("bp") and Chevron U.S.A. Inc. ("Chevron") (collectively, the "Co-Owners") expect to begin operations of the Puma West appraisal program in the second half of 2022. The successful 2021 Puma West discovery well was drilled to 23,530 feet and found high-quality pay containing rock and fluid properties consistent with other high impact discoveries in the area. The discovery well was suspended as a "keeper" for future development. The 2022 appraisal well will delineate the discovered resource while also evaluating additional prospective Miocene sands. The Co-Owners are actively working through potential subsea tie-back options to nearby host facilities in order to accelerate first production upon a successful appraisal result. bp is the operator and holds a
Carbon Capture: Talos plans to advance its previously announced Texas GLO, Freeport LNG and River Bend CCS projects with stratigraphic well tests and preliminary front-end engineering and design studies in advance of EPA Class VI permitting processes. Additionally, Talos expects additional lease acquisition costs from forthcoming potential projects as well as geological and geophysical investments. The Company anticipates that 2022 capital expenditure levels for CCS are appropriate to mature existing projects and aggressively pursue additional opportunities, advancing towards final investment decision on a project-by-project basis in the future.
HEDGES
The following table reflects contracted volumes and weighted average prices the Company will receive under the terms of its derivative contracts as of the date of this release:
Instrument Type | Avg. Daily Volume | Weighted Avg. Swap Price | ||||
Crude – WTI | (Bbls) | (Per Bbl) | ||||
January - March 2022 | Swaps | 29,600 | ||||
April - June 2022 | Swaps | 27,341 | ||||
July - September 2022 | Swaps | 18,000 | ||||
October - December 2022 | Swaps | 19,326 | ||||
January - March 2023 | Swaps | 20,000 | ||||
April - June 2023 | Swaps | 12,000 | ||||
July - September 2023 | Swaps | 7,000 | ||||
October - December 2023 | Swaps | 5,000 | ||||
January - March 2024 | Swaps | 4,000 | ||||
April - June 2024 | Swaps | 2,000 | ||||
Natural Gas – HH NYMEX | (MMBtu) | (Per MMBtu) | ||||
January - March 2022 | Swaps | 61,000 | ||||
April - June 2022 | Swaps | 56,352 | ||||
July - September 2022 | Swaps | 31,000 | ||||
October - December 2022 | Swaps | 34,000 | ||||
January - March 2023 | Swaps | 42,000 | ||||
April - June 2023 | Swaps | 29,000 | ||||
July - September 2023 | Swaps | 5,000 | ||||
October - December 2023 | Swaps | 5,000 | ||||
January - March 2024 | Swaps | 10,000 | ||||
April - June 2024 | Swaps | 10,000 |
CONFERENCE CALL AND WEBCAST INFORMATION
Talos will host a conference call, which will be broadcast live over the internet, on Friday, February 25, 2022 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 until March 4, 2022 and can be accessed by dialing (877) 344-7529 and using access code 6660290.
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 Coast and Gulf of Mexico. For more information, visit www.talosenergy.com.
INVESTOR RELATIONS CONTACT
Sergio Maiworm
+1.713.328.3008
investor@talosenergy.com
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
This communication may contain "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact included in this communication, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this communication, the words "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, our ability to realize the results contemplated by our 2022 guidance, the success of our CCS business, 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 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, 2021, 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.
Talos Energy Inc. Consolidated Balance Sheets (In thousands, except per share amounts) | ||||||
Year Ended December 31, | ||||||
2021 | 2020 | |||||
ASSETS | ||||||
Current assets: | ||||||
Cash and cash equivalents | $ | 69,852 | $ | 34,233 | ||
Accounts receivable: | ||||||
Trade, net | 173,241 | 106,220 | ||||
Joint interest, net | 28,165 | 50,471 | ||||
Other, net | 18,062 | 18,448 | ||||
Assets from price risk management activities | 967 | 6,876 | ||||
Prepaid assets | 48,042 | 29,285 | ||||
Other current assets | 1,674 | 1,859 | ||||
Total current assets | 340,003 | 247,392 | ||||
Property and equipment: | ||||||
Proved properties | 5,232,479 | 4,945,550 | ||||
Unproved properties, not subject to amortization | 219,055 | 254,994 | ||||
Other property and equipment | 29,091 | 32,853 | ||||
Total property and equipment | 5,480,625 | 5,233,397 | ||||
Accumulated depreciation, depletion and amortization | (3,092,043) | (2,697,228) | ||||
Total property and equipment, net | 2,388,582 | 2,536,169 | ||||
Other long-term assets: | ||||||
Assets from price risk management activities | 2,770 | 945 | ||||
Other well equipment inventory | 17,449 | 18,927 | ||||
Operating lease assets | 5,714 | 6,855 | ||||
Other assets | 12,297 | 24,258 | ||||
Total assets | $ | 2,766,815 | $ | 2,834,546 | ||
LIABILITIES AND STOCKHOLDERSʼ EQUITY | ||||||
Current liabilities: | ||||||
Accounts payable | $ | 85,815 | $ | 104,864 | ||
Accrued liabilities | 130,459 | 163,379 | ||||
Accrued royalties | 59,037 | 27,903 | ||||
Current portion of long-term debt | 6,060 | — | ||||
Current portion of asset retirement obligations | 60,311 | 49,921 | ||||
Liabilities from price risk management activities | 186,526 | 66,010 | ||||
Accrued interest payable | 37,542 | 9,509 | ||||
Current portion of operating lease liabilities | 1,715 | 1,793 | ||||
Other current liabilities | 33,061 | 24,155 | ||||
Total current liabilities | 600,526 | 447,534 | ||||
Long-term liabilities: | ||||||
Long-term debt, net of discount and deferred financing costs | 956,667 | 985,512 | ||||
Asset retirement obligations | 373,695 | 392,348 | ||||
Liabilities from price risk management activities | 13,938 | 9,625 | ||||
Operating lease liabilities | 16,330 | 18,554 | ||||
Other long-term liabilities | 45,006 | 54,372 | ||||
Total liabilities | 2,006,162 | 1,907,945 | ||||
Commitments and contingencies (Note 12) | ||||||
Stockholdersʼ equity: | ||||||
Preferred stock, | — | — | ||||
Common stock | 819 | 813 | ||||
Additional paid-in capital | 1,676,798 | 1,659,800 | ||||
Accumulated deficit | (916,964) | (734,012) | ||||
Total stockholdersʼ equity | 760,653 | 926,601 | ||||
Total liabilities and stockholdersʼ equity | $ | 2,766,815 | $ | 2,834,546 | ||
Talos Energy Inc. Consolidated Statements of Operations (In thousands, except per common share amounts) | ||||||||||||
Three Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||
2021 | 2020 | 2021 | 2020 | |||||||||
Revenues: | ||||||||||||
Oil | $ | 320,402 | $ | 148,503 | $ | 1,064,161 | $ | 506,788 | ||||
Natural gas | 44,528 | 18,339 | 130,616 | 53,714 | ||||||||
NGL | 18,025 | 5,760 | 49,763 | 15,434 | ||||||||
Total revenues | 382,955 | 172,602 | 1,244,540 | 575,936 | ||||||||
Operating expenses: | ||||||||||||
Lease operating expense | 74,926 | 62,377 | 283,601 | 246,564 | ||||||||
Production taxes | 824 | 414 | 3,363 | 1,054 | ||||||||
Depreciation, depletion and amortization | 105,900 | 101,813 | 395,994 | 364,346 | ||||||||
Write-down of oil and natural gas properties | 18,123 | 267,859 | 18,123 | 267,916 | ||||||||
Accretion expense | 14,019 | 11,993 | 58,129 | 49,741 | ||||||||
General and administrative expense | 19,684 | 16,691 | 78,677 | 79,175 | ||||||||
Other operating (income) expense | 25,173 | (3,109) | 32,037 | (11,550) | ||||||||
Total operating expenses | 258,649 | 458,038 | 869,924 | 997,246 | ||||||||
Operating income (expense) | 124,306 | (285,436) | 374,616 | (421,310) | ||||||||
Interest expense | (33,102) | (23,251) | (133,138) | (99,415) | ||||||||
Price risk management activities income (expense) | (13,473) | (66,968) | (419,077) | 87,685 | ||||||||
Other income (expense) | 928 | 2,879 | (6,988) | 3,018 | ||||||||
Net income (loss) before income taxes | 78,659 | (372,776) | (184,587) | (430,022) | ||||||||
Income tax benefit (expense) | 2,353 | (57,967) | 1,635 | (35,583) | ||||||||
Net income (loss) | $ | 81,012 | $ | (430,743) | $ | (182,952) | $ | (465,605) | ||||
Net income (loss) per common share: | ||||||||||||
Basic | $ | 0.99 | $ | (5.73) | $ | (2.24) | $ | (6.88) | ||||
Diluted | $ | 0.98 | $ | (5.73) | $ | (2.24) | $ | (6.88) | ||||
Weighted average common shares outstanding: | ||||||||||||
Basic | 81,909 | 75,199 | 81,769 | 67,664 | ||||||||
Diluted | 82,558 | 75,199 | 81,769 | 67,664 | ||||||||
Talos Energy Inc. Consolidated Statements of Cash Flows (In thousands) | |||||||||
Year Ended December 31, | |||||||||
2021 | 2020 | 2019 | |||||||
Cash flows from operating activities: | |||||||||
Net income (loss) | $ | (182,952) | $ | (465,605) | $ | 58,729 | |||
Adjustments to reconcile net income (loss) to net cash | |||||||||
Depreciation, depletion, amortization and accretion expense | 454,123 | 414,087 | 380,320 | ||||||
Write-down of oil and natural gas properties and other well inventory | 23,729 | 268,615 | 12,386 | ||||||
Amortization of deferred financing costs and original issue discount | 13,382 | 6,804 | 5,207 | ||||||
Equity-based compensation expense | 10,992 | 8,669 | 6,964 | ||||||
Price risk management activities expense (income) | 419,077 | (87,685) | 95,337 | ||||||
Net cash received (paid) on settled derivative instruments | (290,164) | 143,905 | (8,820) | ||||||
Loss (gain) on extinguishment of debt | 13,225 | (1,662) | — | ||||||
Settlement of asset retirement obligations | (67,988) | (43,933) | (75,331) | ||||||
Gain on sale of assets | (687) | — | — | ||||||
Changes in operating assets and liabilities: | |||||||||
Accounts receivable | (35,396) | (34,645) | 5,788 | ||||||
Other current assets | (18,901) | 35,934 | (15,114) | ||||||
Accounts payable | (6,261) | 27,096 | 7,523 | ||||||
Other current liabilities | 64,800 | 4,200 | (35,459) | ||||||
Other non-current assets and liabilities, net | 14,409 | 26,143 | (43,797) | ||||||
Net cash provided by operating activities | 411,388 | 301,923 | 393,733 | ||||||
Cash flows from investing activities: | |||||||||
Exploration, development and other capital expenditures | (293,331) | (362,942) | (463,409) | ||||||
Cash paid for acquisitions, net of cash acquired | (5,399) | (315,962) | (37,916) | ||||||
Proceeds from sale of property and equipment, net | 4,983 | — | 5,369 | ||||||
Net cash used in investing activities | (293,747) | (678,904) | (495,956) | ||||||
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 | (356,803) | (5,364) | (10,567) | ||||||
Proceeds from Bank Credit Facility | 100,000 | 350,000 | 110,000 | ||||||
Repayment of Bank Credit Facility | (365,000) | (60,000) | (25,000) | ||||||
Deferred financing costs | (27,833) | (1,287) | (1,963) | ||||||
Other deferred payments | (7,921) | (11,921) | (9,921) | ||||||
Payments of finance lease | (21,804) | (17,509) | (14,133) | ||||||
Employee stock awards tax withholdings | (3,161) | (827) | (333) | ||||||
Net cash provided by (used in) financing activities | (82,022) | 324,192 | 48,083 | ||||||
Net increase (decrease) in cash and cash equivalents | 35,619 | (52,789) | (54,140) | ||||||
Cash and cash equivalents: | |||||||||
Balance, beginning of period | 34,233 | 87,022 | 141,162 | ||||||
Balance, end of period | $ | 69,852 | $ | 34,233 | $ | 87,022 | |||
Supplemental non-cash transactions: | |||||||||
Capital expenditures included in accounts payable and accrued liabilities | $ | 45,761 | $ | 74,957 | $ | 90,956 | |||
Debt exchanged for common stock | $ | — | $ | 35,960 | $ | — | |||
Supplemental cash flow information: | |||||||||
Interest paid, net of amounts capitalized | $ | 68,891 | $ | 67,443 | $ | 62,571 | |||
SUPPLEMENTAL NON-GAAP INFORMATION
Certain financial information included in our financial results are not measures of financial performance recognized by accounting principles generally accepted in the United States, or GAAP. These non-GAAP financial measures are "Adjusted Net Income (Loss)," "Adjusted Earnings per Share," "EBITDA," "Adjusted EBITDA," "Adjusted EBITDA excluding hedges," "Adjusted EBITDA Margin," "Adjusted EBITDA Margin excluding hedges," "Free Cash Flow," "Net Debt," "LTM Adjusted EBITDA," "Credit Facility LTM Adjusted EBITDA,", "Net Debt to Credit Facility LTM Adjusted EBITDA" 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 non-recurring expenses, derivative fair value (gain) loss, net cash receipts (payments) on settled derivatives, (gain) loss on debt extinguishment, non-cash write-down of other well equipment inventory and non-cash equity-based compensation expense.
We also present Adjusted EBITDA excluding hedges and as a percentage of revenue to further analyze our business, which are outlined below:
Adjusted EBITDA Margin. EBITDA divided by Revenue, as a percentage. It is also defined as Adjusted EBITDA divided by the total production volume, expressed in Boe, in the period, and described as dollar per Boe. We believe the presentation of Adjusted EBITDA margin is important to provide management and investors with information about how much we retain in Adjusted EBITDA terms as compared to the revenue we generate and how much per barrel we generate after accounting for certain operational and corporate costs.
The following table presents a reconciliation of the GAAP financial measure of net income (loss) to EBITDA, Adjusted EBITDA, Adjusted EBITDA excluding hedges, Adjusted EBITDA Margin and Adjusted EBITDA Margin excluding hedges for each of the periods indicated (in thousands, except for Boe, $/Boe and percentage data):
Three Months Ended | ||||||||||||
($ thousands, except per Boe) | December 31, | September 30, | June 30, | March 31, | ||||||||
Reconciliation of net income (loss) to Adjusted EBITDA: | ||||||||||||
Net Income (Loss) | $ | 81,012 | $ | (16,691) | $ | (125,782) | $ | (121,491) | ||||
Interest expense | 33,102 | 32,390 | 33,570 | 34,076 | ||||||||
Income tax expense (benefit) | (2,353) | (364) | 498 | 584 | ||||||||
Depreciation, depletion and amortization | 105,900 | 88,596 | 99,841 | 101,657 | ||||||||
Accretion expense | 14,019 | 13,668 | 15,457 | 14,985 | ||||||||
EBITDA | 231,680 | 117,599 | 23,584 | 29,811 | ||||||||
Write-down of oil and natural gas properties | 18,123 | — | — | — | ||||||||
Transaction and other expenses(1) | 19,710 | 1,370 | 4,083 | 1,778 | ||||||||
Derivative fair value loss(2) | 13,473 | 81,479 | 186,617 | 137,508 | ||||||||
Net cash payments on settled derivative | (100,912) | (71,634) | (69,237) | (48,381) | ||||||||
Loss on extinguishment of debt | — | — | — | 13,225 | ||||||||
Non-cash write-down of other well equipment | 5,606 | — | — | — | ||||||||
Non-cash equity-based compensation expense | 2,698 | 2,613 | 3,017 | 2,664 | ||||||||
Adjusted EBITDA | 190,378 | 131,427 | 148,064 | 136,605 | ||||||||
Add: Net cash payments on settled derivative | 100,912 | 71,634 | 69,237 | 48,381 | ||||||||
Adjusted EBITDA excluding hedges | $ | 291,290 | $ | 203,061 | $ | 217,301 | $ | 184,986 | ||||
Production and Revenue: | ||||||||||||
Boe(2) | 6,320 | 5,200 | 6,031 | 5,949 | ||||||||
Revenue - Operations | 382,955 | 266,908 | 303,768 | 266,908 | ||||||||
Adjusted EBITDA margin and Adjusted EBITDA | ||||||||||||
Adjusted EBITDA divided by Revenue - | 50 | % | 49 | % | 49 | % | 51 | % | ||||
Adjusted EBITDA per Boe(2) | $ | 30.12 | $ | 25.27 | $ | 24.55 | $ | 22.96 | ||||
Adjusted EBITDA excl hedges divided by Revenue - | 76 | % | 76 | % | 72 | % | 69 | % | ||||
Adjusted EBITDA excl hedges per Boe(2) | $ | 46.09 | $ | 39.05 | $ | 36.03 | $ | 31.10 | ||||
(1) | Includes transaction related expenses, restructuring expenses, cost saving initiatives and other miscellaneous income and expenses. |
(2) | The adjustments for the derivative fair value (gain) loss and net cash receipts (payments) on settled derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled. |
(3) | One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities. |
Reconciliation of Adjusted EBITDA to Free Cash Flow
"Free Cash Flow" before changes in working capital provides management and investors with (i) important supplemental indicators of the operational performance of our business, (ii) additional criteria for evaluating our performance relative to our peers and (iii) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. Free Cash Flow has limitations as an analytical tool and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP or as alternatives to net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP. We define these as the following:
Capital Expenditures and Plugging & Abandonment. Actual capital expenditures and plugging & abandonment recognized in the quarter, inclusive of accruals.
Interest Expense. Actual interest expense per the income statement.
Talos did not pay any cash taxes in the period, therefore cash taxes have no impact to the reported Free Cash Flow before changes in working capital number.
($ thousands, except per share amounts) | Three Months | Twelve Months | ||||
Reconciliation of Adjusted EBITDA to Free Cash Flow (before changes in | ||||||
Adjusted EBITDA | $ | 190,378 | $ | 606,474 | ||
Less: Capital Expenditures and Plugging & Abandonment | (64,272) | (338,822) | ||||
Less: Interest Expense | (33,102) | (133,138) | ||||
Free Cash Flow (before changes in working capital) | $ | 93,004 | $ | 134,514 | ||
Reconciliation of Net Income (Loss) to Adjusted Net Income (Loss) and Adjusted Earnings per Share
"Adjusted Net Income (Loss)" and "Adjusted Earnings per Share" are to provide management and investors with (i) important supplemental indicators of the operational performance of our business, (ii) additional criteria for evaluating our performance relative to our peers and (iii) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. Adjusted Net Income (Loss) and Adjusted Earnings per Share have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP or as an alternative to net income (loss), operating income (loss), earnings per share or any other measure of financial performance presented in accordance with GAAP.
Adjusted Net Income (Loss). Net income (loss) plus accretion expense, transaction related costs, derivative fair value (gain) loss, net cash receipts (payments) on settled derivative instruments and non-cash equity-based compensation expense.
Adjusted Earnings per Share. Adjusted Net Income (Loss) divided by the number of common shares.
($ thousands, except per share amounts) | Three Months Ended December 31, 2021 | Twelve Months | ||||
Reconciliation of Net Income (Loss) to Adjusted Net Income: | ||||||
Net Income (Loss) | $ | 81,012 | $ | (182,952) | ||
Write-down of oil and natural gas properties | 18,123 | 18,123 | ||||
Transaction related costs and other expenses | 19,710 | 26,941 | ||||
Derivative fair value loss(1) | 13,473 | 419,077 | ||||
Net cash payments on settled derivative instruments(1) | (100,912) | (290,164) | ||||
Non-cash write-down of other well equipment inventory | 5,606 | 5,606 | ||||
Non-cash income tax benefit | (2,353) | (1,635) | ||||
Non-cash equity-based compensation expense | 2,698 | 10,992 | ||||
Adjusted Net Income | $ | 37,357 | $ | 5,988 | ||
Weighted average common shares outstanding: | ||||||
Basic | 81,909 | 81,769 | ||||
Diluted | 82,558 | 81,769 | ||||
Net Income (Loss) per common share: | ||||||
Basic | $ | 0.99 | $ | (2.24) | ||
Diluted | $ | 0.98 | $ | (2.24) | ||
Adjusted Net Income per common share: | ||||||
Basic | $ | 0.46 | $ | 0.07 | ||
Diluted | $ | 0.45 | $ | 0.07 | ||
(1) | The adjustments for the derivative fair value (gain) loss and net cash receipts (payments) on settled derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted Net Income (Loss) on an unrealized basis during the period the derivatives settled. |
Reconciliation of Total Debt to Net Debt and Net Debt to LTM Adjusted EBITDA and Credit Facility LTM Adjusted EBITDA
We believe the presentation of Net Debt, LTM Adjusted EBITDA, Credit Facility LTM Adjusted EBITDA, Net Debt to LTM Adjusted EBITDA and Net Debt to Credit Facility LTM Adjusted EBITDA is important to provide management and investors with additional important information to evaluate our business. These measures are widely used by investors and ratings agencies in the valuation, comparison, rating and investment recommendations of companies
Net Debt. Total Debt principal of the Company plus the finance lease balance minus cash and cash equivalents.
Net Debt to LTM Adjusted EBITDA. Net Debt divided by the LTM Adjusted EBITDA.
Net Debt to Credit Facility LTM Adjusted EBITDA. Net Debt divided by the Credit Facility LTM Adjusted EBITDA.
Reconciliation of Net Debt ($ thousands) at December 31, 2021: | ||||||
$ | 650,000 | |||||
6,060 | ||||||
Bank Credit Facility – matures November 2024 | 375,000 | |||||
Finance lease | 40,221 | |||||
Total Debt | 1,071,281 | |||||
Less: Cash and cash equivalents | (69,852) | |||||
Net Debt | $ | 1,001,429 | ||||
Calculation of LTM EBITDA: | ||||||
Adjusted EBITDA for three months period ended March 31, 2021 | $ | 136,605 | ||||
Adjusted EBITDA for three months period ended June 30, 2021 | 148,064 | |||||
Adjusted EBITDA for three months period ended September 30, 2021 | 131,427 | |||||
Adjusted EBITDA for three months period ended December 31, 2021 | 190,378 | |||||
LTM Adjusted EBITDA | $ | 606,474 | ||||
Acquired Assets Adjusted EBITDA for pre-closing periods | --- | |||||
Credit Facility LTM Adjusted EBITDA | $ | 606,474 | ||||
Reconciliation of Net Debt to LTM Adjusted EBITDA: | ||||||
Net Debt / LTM Adjusted EBITDA | 1.7x | |||||
Net Debt / Credit Facility LTM Adjusted EBITDA | 1.7x | |||||
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.
Reconciliation of PV-10 to Standardized Measure
PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of the Company's properties. Talos and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies' properties without regard to the specific tax characteristics of such entities. PV-10 may be reconciled to the Standardized Measure of discounted future net cash flows at such dates by adding the discounted future income taxes associated with such reserves to the Standardized Measure.
The table below presents the reconciliation of PV-10 to Standardized Measure:
Year Ended December 31, | ||||||
2021 | ||||||
Standardized measure | $ | 3,440,611 | ||||
Present value of future income taxes discounted at | 485,386 | |||||
PV-10 (Non-GAAP) | $ | 3,925,997 | ||||
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SOURCE Talos Energy
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