HOUSTON, Nov. 6, 2023
/PRNewswire/ -- Talos Energy Inc. ("Talos" or the "Company") (NYSE:
TALO) today announced its operational and financial results for
fiscal quarter ended September 30, 2023.
Third Quarter 2023
Highlights:
- Production of 63.7 thousand barrels of oil equivalent per day
("MBoe/d") (76% oil, 83% liquids), inclusive of 2.4 MBoe/d of
impacts from sustained loop currents requiring intermittent
shut-ins of Talos's HP-1 floating production unit and associated
infrastructure, as well as additional downtime.
- Revenue of $383.1 million, driven
by realized prices (excluding hedges) of $80.75 per barrel for oil, $17.02 per barrel for natural gas liquids
("NGLs"), and $2.81 per thousand
cubic feet ("Mcf") for natural gas.
- Net Loss of $2.1 million, or
$0.02 Net Loss per diluted share, and
Adjusted Net Income* of $18.6
million, or $0.15 Adjusted Net
Income per diluted share*.
- Adjusted EBITDA* of $248.8
million and Upstream Adjusted EBITDA* of $255.2 million.
- Capital expenditures of $194.6
million, inclusive of plugging and abandonment and Carbon
Capture & Sequestration ("CCS").
- Net cash provided by operating activities of $65.7 million.
- Adjusted Free Cash Flow* of $8.5
million, excluding the $74.85
million cash received at closing of the partial sale in
Talos Energy Mexico 7, S. de R.L. de C.V. ("Talos Mexico") to an
affiliate of Grupo Carso.
Talos President and Chief
Executive Officer Timothy S. Duncan
commented: "During the third quarter, we were pleased with the
advancements we made on several aspects of our business. Our
operations team is working hard on our Lime Rock and Venice discoveries, which are expected to come
online as scheduled in early 2024. We have recently signed an
important exploration agreement with Repsol, where we are pooling
resources with the goal of developing an inventory of impactful
wells that could be tied to existing Talos infrastructure.
Additionally, we closed the Talos Mexico transaction with
Grupo Carso and are encouraged about
growing our partnership and progressing Zama toward FID and first
oil. Our CCS portfolio continues to receive strong endorsement from
the industry, as we welcomed Equinor as a partner with a 25%
interest in Bayou Bend following its purchase from Carbonvert.
Lastly, at Harvest Bend, we have several EPA Class VI permit
applications in process."
Duncan continued: "Weather-related disruptions in the
Gulf of Mexico typically impact
our production and drilling operations during the third quarter of
the year. This quarter, we experienced production downtime related
to sustained loop currents in the Green Canyon area which impacted
the floating production unit in our Phoenix Field. However, our
oil-weighted assets continued to deliver strong realizations, with
a netback margin of close to $45 per
barrel of oil equivalent. As that production is restored and new
developments are added, we look forward to positive momentum as we
close out the year."
RECENT DEVELOPMENTS AND OPERATIONS UPDATE
Drilling Joint Venture: In November 2023, Talos and an affiliate of Repsol
entered into a 50/50 partnership to conduct a seismic reprocessing
project covering approximately 400,000 gross acres, of which 96,500
acres are under lease by Talos, in the deepwater Green Canyon and
Atwater Valley areas of the U.S.
Gulf of Mexico. The joint venture
aims to identify future subsea tie-back exploitation and
exploration prospects in the area using Talos's Neptune facility as
the host platform.
Mexico Divestiture: In September
2023, Talos announced the closing of the sale of a 49.9%
equity interest in Talos Mexico to an affiliate of Grupo Carso. Talos received $74.85 million in cash at closing, with an
additional $49.90 million due upon
first production, for an aggregate price of $124.75 million. Talos Mexico, now owned 50.1% by
Talos and 49.9% by Grupo Carso,
holds a 17.4% unitized interest in the Zama project.
Exploration and Production Updates:
Lime Rock and Venice: Completion, construction, and
subsea installation operations for Talos's Lime Rock and
Venice discoveries remain on
track. The Company anticipates first production by early 2024 from
both wells, which will be tied-backed to the Talos-owned and
operated Ram Powell facility. Talos owns a 60% working interest in
both wells.
Non-Operated Updates: Drilling of the Marmalard
well, operated by Murphy Oil Corporation, was recently completed,
finding pay sands in both field targets, and will be moving to
completion operations in an effort to achieve first production in
early 2024. Talos holds an 11.4% working interest. The Odd Job
subsea pump project, operated by Kosmos Energy, intended to sustain
long-term production from the field, continues to progress and
remains on track to be in service by mid-2024. Talos holds a 17.5%
working interest.
Downtime Updates: During the third quarter 2023,
sustained loop currents requiring intermittent shut-ins of Talos's
HP-1 floating production unit and associated infrastructure
impacted production by approximately 2.4 MBoe/d for the quarter, or
0.8 MBoe/d for the full year 2023. On Talos's operated Neptune
facility, Talos continues to work on optimization efforts,
including new chemical treatments and topside modifications,
expected to be completed in the fourth quarter 2023. The Claiborne
#1 well, operated by Beacon Offshore Energy LLC, was shut-in early
in the third quarter 2023, impacting production by approximately
1.2 MBoe/d. The operator is planning a rig intervention for the
fourth quarter 2023 to reinstate production in the first quarter of
2024. Talos holds a 25.25% working interest.
TLCS Updates:
Stratigraphic Wells: The Bayou Bend CCS partnership
expects to spud the Talos-operated offshore stratigraphic well
during the fourth quarter 2023. As previously announced, the
partnership also expects to drill a Chevron-operated onshore
stratigraphic well in the first half 2024. Talos Low Carbon
Solutions ("TLCS") also intends to drill its first stratigraphic
wells at its Harvest Bend CCS and Coastal Bend CCS projects in
2024.
Class VI Permits: TLCS's
first EPA Class VI permit application filed in August 2023 for its Harvest Bend CCS project
received administrative completeness status in October 2023. This first step of the EPA's
permitting process determines that the permit application contains
all required information. The next step is technical review. In
October 2023, TLCS filed its second
Class VI permit application for two additional wells at its Harvest
Bend CCS project. TLCS aims to file additional Class VI permit
applications in 2024 for its Bayou Bend CCS, Harvest Bend
CCS, and Coastal Bend CCS projects.
Capital Raise: Talos continues to explore a capital
raise in TLCS. The Company will provide further updates when
available.
THIRD QUARTER 2023 RESULTS
Key Financial Highlights:
($ thousands, except
per share and per BOE amounts)
|
Three Months
Ended
September 30, 2023
|
|
Total
revenues
|
$
|
383,135
|
|
Net Loss
|
$
|
(2,103)
|
|
Net Loss per diluted
share
|
$
|
(0.02)
|
|
Adjusted Net
Income*
|
$
|
18,565
|
|
Adjusted Net Income per
diluted share*
|
$
|
0.15
|
|
Adjusted
EBITDA*
|
$
|
248,817
|
|
Adjusted EBITDA
excluding hedges*
|
$
|
255,130
|
|
Upstream Adjusted
EBITDA*
|
$
|
255,228
|
|
Upstream Adjusted
EBITDA excluding hedges*
|
$
|
261,541
|
|
Capital Expenditures
(including Plug & Abandonment)
|
$
|
194,638
|
|
Upstream Adjusted
EBITDA Margin:
|
|
|
Upstream Adjusted
EBITDA per Boe*
|
$
|
43.59
|
|
Upstream Adjusted
EBITDA excluding hedges per Boe*
|
$
|
44.67
|
|
Production
Production was 63.7 MBoe/d for the third quarter 2023 and was
76% oil and 83% liquids.
|
Three Months
Ended
September 30, 2023
|
|
Average net daily
production volumes
|
|
|
Oil
(MBbl/d)
|
|
48.4
|
|
Natural Gas
(MMcf/d)
|
|
65.3
|
|
NGL
(MBbl/d)
|
|
4.4
|
|
Total average net daily
(MBoe/d)
|
|
63.7
|
|
|
Three Months Ended
September 30, 2023
|
|
|
Production
|
|
% Oil
|
|
% Liquids
|
|
% Operated
|
|
Average net daily
production volumes by Core Area (MBoe/d)
|
|
|
|
|
|
|
|
|
Green Canyon
Area
|
|
20.8
|
|
|
84
|
%
|
|
90
|
%
|
|
87
|
%
|
Mississippi Canyon
Area
|
|
31.1
|
|
|
80
|
%
|
|
87
|
%
|
|
72
|
%
|
Shelf and Gulf
Coast
|
|
11.8
|
|
|
50
|
%
|
|
60
|
%
|
|
60
|
%
|
Total average net daily
(MBoe/d)
|
|
63.7
|
|
|
76
|
%
|
|
83
|
%
|
|
75
|
%
|
Lease Operating & General and Administrative
Expenses
Total lease operating expenses, inclusive of workover and
maintenance and insurance costs for the quarter, were $103.5 million or $17.69/Boe. Upstream General and Administrative
expenses* for the quarter, excluding non-cash equity-based
compensation, was $20.7 million, or
$3.54/Boe. Upstream General and
Administrative expenses* is shown inclusive of $1.7 million in transaction-related expenses.
($ thousands, except
per BOE amounts)
|
Three Months
Ended
September 30, 2023
|
|
Per
Boe
|
|
Lease Operating
Expenses
|
$
|
103,548
|
|
$
|
17.69
|
|
Upstream General &
Administrative Expenses (excluding non-cash equity-based
compensation)*
|
$
|
20,711
|
|
$
|
3.54
|
|
Capital Expenditures
Upstream capital expenditures, including plugging and
abandonment and settled decommissioning obligations, totaled
$180.5 million for the third quarter
2023.
($
thousands)
|
Three Months
Ended
September 30, 2023
|
|
Nine Months
Ended
September 30, 2023
|
|
Upstream Capital
Expenditures
|
|
|
|
|
U.S. drilling &
completions
|
$
|
85,239
|
|
$
|
317,900
|
|
Mexico appraisal &
exploration
|
|
94
|
|
|
291
|
|
Asset
management(1)
|
|
20,949
|
|
|
81,677
|
|
Seismic and G&G,
land, capitalized G&A and other
|
|
12,448
|
|
|
48,493
|
|
Total Upstream Capital
Expenditures
|
|
118,730
|
|
|
448,361
|
|
Plugging &
Abandonment
|
|
23,414
|
|
|
71,097
|
|
Decommissioning
Obligations Settled(2)
|
|
38,368
|
|
|
40,415
|
|
Total
Upstream
|
$
|
180,512
|
|
$
|
559,873
|
|
|
|
(1)
|
Asset management
consists of capital expenditures for development-related activities
primarily associated with recompletions and improvements to our
facilities and infrastructure.
|
(2)
|
Settlement of
decommissioning obligations as a result of working interest
partners or counterparties of divestiture transactions that were
unable to perform the required abandonment obligations due to
bankruptcy or insolvency.
|
CCS expenses totaled $5.0 million
for the third quarter 2023, which is accounted for in the Company's
reported Adjusted EBITDA* figure. CCS capital expenditures totaled
$14.1 million for the third quarter
2023, which mainly includes investments in Bayou Bend and funding
for general ongoing operations.
($
thousands)
|
Three Months
Ended
September 30, 2023
|
|
Nine Months
Ended
September 30, 2023
|
|
CCS
Investments
|
|
|
|
|
CCS
Expenses
|
$
|
5,045
|
|
$
|
13,562
|
|
CCS Capital
Expenditures
|
|
14,126
|
|
|
37,183
|
|
Total CCS
Investments
|
$
|
19,171
|
|
$
|
50,745
|
|
Liquidity and Leverage
At September 30, 2023, Talos had
approximately $752.9 million of
liquidity, with $750.0 million
undrawn on its credit facility and approximately $13.6 million in cash, less approximately
$10.8 million in outstanding letters
of credit.
On September 30, 2023, Talos had $1,096.0 million in total debt. Net Debt* was
$1,082.4 million. Net Debt to Pro
Forma Last Twelve Months ("LTM") Adjusted EBITDA* was 1.1x.
Footnotes:
*See "Supplemental Non-GAAP Information" for details and
reconciliations of GAAP to non-GAAP financial measures.
OPERATIONAL & FINANCIAL GUIDANCE UPDATES
For the fourth quarter 2023, Talos expects average daily
production of 66.5 - 68.5 MBoe/d.
|
|
Fourth Quarter
2023
|
|
|
|
Low
|
|
High
|
|
Production
|
Oil (MMBbl)
|
|
4.5
|
|
|
4.6
|
|
|
Natural Gas
(Mcf)
|
|
7.2
|
|
|
7.4
|
|
|
NGL (MMBbl)
|
|
0.4
|
|
|
0.4
|
|
|
Total Production
(MMBoe)
|
|
6.1
|
|
|
6.3
|
|
|
Avg Daily Production
(MBoe/d)
|
|
66.5
|
|
|
68.5
|
|
For the full year 2023, Talos's average daily production
per day is projected toward the low end of the current guidance of
66.0 - 71.0 MBoe/d given the fourth quarter 2023 production
guidance update,
Cash operating expenses and general and administrative expenses
are expected towards the low end of the current range of
$410 - $430
million and $90 - $95 million, respectively.
Overall, capital expenditures, inclusive of plugging and
abandonment, settled decommissioning obligations, and CCS
Investments are projected to be in line with the current total
guidance range. Specifically, Upstream capital expenditures are
expected towards the low end of the current guided range of
$650 - $675
million and CCS Investments are projected at or below the
low end of the current range of $70 -
$90 million. Plugging and abandonment
and decommissioning spending for the full year 2023 is now
estimated to be $120 - $130 million.
Note: Due to the forward-looking nature a reconciliation of Cash
Operating Expenses and G&A to the most directly comparable GAAP
measure could not reconciled without unreasonable efforts.
HEDGES
The following table reflects contracted volumes and weighted
average prices the Company will receive under the terms of its
derivative contracts as of November 6,
2023:
|
Instrument
Type
|
Avg. Daily
Volume
|
|
W.A.
Swap
|
|
W.A. Sub-
Floor
|
|
W.A.
Floor
|
|
W.A.
Ceiling
|
|
Crude –
WTI
|
|
(Bbls)
|
|
(Per
Bbl)
|
|
(Per
Bbl)
|
|
(Per
Bbl)
|
|
(Per
Bbl)
|
|
October - December
2023
|
Fixed Swaps
|
|
12,000
|
|
$
|
75.25
|
|
---
|
|
---
|
|
---
|
|
October - December
2023
|
Collar
|
|
7,826
|
|
---
|
|
---
|
|
$
|
67.76
|
|
$
|
86.40
|
|
October - December
2023
|
3-Way Collar
|
|
9,200
|
|
---
|
|
$
|
51.86
|
|
$
|
65.11
|
|
$
|
109.25
|
|
January - March
2024
|
Fixed Swaps
|
|
18,000
|
|
$
|
73.98
|
|
---
|
|
---
|
|
---
|
|
January - March
2024
|
Collar
|
|
3,000
|
|
---
|
|
---
|
|
$
|
70.00
|
|
$
|
83.67
|
|
January - March
2024
|
3-Way Collar
|
|
3,200
|
|
---
|
|
$
|
57.27
|
|
$
|
70.00
|
|
$
|
98.01
|
|
April - June
2024
|
Fixed Swaps
|
|
21,500
|
|
$
|
73.86
|
|
---
|
|
---
|
|
---
|
|
April - June
2024
|
Collar
|
|
1,000
|
|
---
|
|
---
|
|
$
|
70.00
|
|
$
|
75.00
|
|
July - September
2024
|
Fixed Swaps
|
|
13,000
|
|
$
|
75.48
|
|
---
|
|
---
|
|
---
|
|
July - September
2024
|
Collar
|
|
1,000
|
|
---
|
|
---
|
|
$
|
70.00
|
|
$
|
75.00
|
|
October - December
2024
|
Fixed Swaps
|
|
12,000
|
|
$
|
74.65
|
|
---
|
|
---
|
|
---
|
|
October - December
2024
|
Collar
|
|
1,000
|
|
---
|
|
---
|
|
$
|
70.00
|
|
$
|
75.00
|
|
January - March
2025
|
Fixed Swaps
|
|
10,000
|
|
$
|
71.97
|
|
---
|
|
---
|
|
---
|
|
April - June
2025
|
Fixed Swaps
|
|
6,000
|
|
$
|
75.28
|
|
---
|
|
---
|
|
---
|
|
July - September
2025
|
Fixed Swaps
|
|
6,000
|
|
$
|
75.28
|
|
---
|
|
---
|
|
---
|
|
October - December
2025
|
Fixed Swaps
|
|
6,000
|
|
$
|
75.28
|
|
---
|
|
---
|
|
---
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas – HH
NYMEX
|
|
(MMBtu)
|
|
(Per
MMBtu)
|
|
(Per
MMBtu)
|
|
(Per
MMBtu)
|
|
(Per
MMBtu)
|
|
October - December
2023
|
Fixed Swaps
|
|
20,000
|
|
$
|
4.22
|
|
---
|
|
---
|
|
---
|
|
October - December
2023
|
Collar
|
|
10,000
|
|
---
|
|
---
|
|
$
|
5.25
|
|
$
|
8.46
|
|
January - March
2024
|
Fixed Swaps
|
|
25,000
|
|
$
|
3.48
|
|
---
|
|
---
|
|
---
|
|
January - March
2024
|
Collar
|
|
10,000
|
|
---
|
|
---
|
|
$
|
4.00
|
|
$
|
6.90
|
|
April - June
2024
|
Fixed Swaps
|
|
25,000
|
|
$
|
3.33
|
|
---
|
|
---
|
|
---
|
|
April - June
2024
|
Collar
|
|
10,000
|
|
---
|
|
---
|
|
$
|
4.00
|
|
$
|
6.90
|
|
July - September
2024
|
Fixed Swaps
|
|
10,000
|
|
$
|
3.52
|
|
---
|
|
---
|
|
---
|
|
July - September
2024
|
Collar
|
|
10,000
|
|
---
|
|
---
|
|
$
|
4.00
|
|
$
|
6.90
|
|
October - December
2024
|
Fixed Swaps
|
|
10,000
|
|
$
|
3.52
|
|
---
|
|
---
|
|
---
|
|
October - December
2024
|
Collar
|
|
10,000
|
|
---
|
|
---
|
|
$
|
4.00
|
|
$
|
6.90
|
|
January - March
2025
|
Fixed Swaps
|
|
20,000
|
|
$
|
4.14
|
|
---
|
|
---
|
|
---
|
|
April - June
2025
|
Fixed Swaps
|
|
10,000
|
|
$
|
3.91
|
|
---
|
|
---
|
|
---
|
|
July - September
2025
|
Fixed Swaps
|
|
10,000
|
|
$
|
3.91
|
|
---
|
|
---
|
|
---
|
|
October - December
2025
|
Fixed Swaps
|
|
10,000
|
|
$
|
3.91
|
|
---
|
|
---
|
|
---
|
|
CONFERENCE CALL AND WEBCAST INFORMATION
Talos will host a conference call, which will be broadcast live
over the internet, on Tuesday, November 7,
2023 at 10:00 AM Eastern Time
(9:00 AM Central Time). Listeners can
access the conference call through a webcast link on the Company's
website at:
https://www.talosenergy.com/investor-relations/events-calendar/default.aspx.
Alternatively, the conference call can be accessed by dialing (888)
348-8927 (U.S. toll-free), (855) 669-9657 (Canada toll-free) or (412) 902-4263
(international). Please dial in approximately 15 minutes before the
teleconference is scheduled to begin and ask to be joined into the
Talos Energy call. A replay of the call will be available one hour
after the conclusion of the conference until November 14, 2023 and can be accessed by dialing
(877) 344-7529 and using access code 4883529.
ABOUT TALOS ENERGY
Talos Energy (NYSE: TALO) is a technically driven,
innovative, independent energy company focused on safely and
efficiently maximizing long-term value through its Upstream
Exploration & Production and Low Carbon Solutions businesses.
We currently operate in the United
States ("U.S.") and offshore Mexico. We leverage decades of technical and
offshore operational expertise to acquire, explore, and produce
assets in key geological trends while developing opportunities to
reduce industrial emissions through carbon capture and storage
projects along the U.S. Gulf Coast. For more information, visit
www.talosenergy.com.
INVESTOR RELATIONS
CONTACT
investor@talosenergy.com
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
The information in this communication includes "forward-looking
statements" within the meaning of the Securities Act of 1933, as
amended (the "Securities Act"), and the Securities Exchange Act of
1934, as amended (the "Exchange Act"). All statements, other than
statements of historical fact included in this communication
regarding our strategy, future operations, financial position,
estimated revenues and losses, projected costs, prospects, plans
and objectives of management are forward-looking statements. When
used in this communication, the words "will," "could," "believe,"
"anticipate," "intend," "estimate," "expect," "project,"
"forecast," "may," "objective," "plan" and similar expressions are
intended to identify forward-looking statements, although not all
forward-looking statements contain such identifying words.
Forward-looking statements are based on management's current
expectations and assumptions about future events and are based on
currently available information as to the outcome and timing of
future events. Forward-looking statements may include statements
about: business strategy; reserves and prospective storage
resources; drilling prospects, inventories, projects and programs;
our ability to replace the reserves through drilling and property
acquisitions; financial strategy, liquidity and capital required
for our development program and other capital expenditures;
realized oil and natural gas prices; timing and amount of future
production of oil, natural gas and NGLs; our hedging strategy and
results; future drilling and CCS plans; availability of pipeline
connections on economic terms; competition, government regulations
and legislative and political developments; the timing of, and our
ability to obtain, permits and governmental approvals; pending
legal, governmental or environmental matters; our marketing of our
products; our integration of acquisitions, including EnVen, and
future performance of the combined company; future leasehold or
business acquisitions on desired terms; costs of developing
properties; general economic conditions, including the impact of
continued inflation and associated changes in monetary policy;
political and economic conditions and events in foreign oil,
natural gas and NGL producing countries, including embargoes,
hostilities and acts of terrorism or sabotage; credit markets;
estimates of future income taxes; our estimates and forecasts of
the timing, number, profitability and other results of wells we
expect to drill and other exploration activities; the success of
our CCS opportunities, including as a result of the associated
permitting process, our access to capital to finance such
opportunities, the timing and amount of revenues therefrom and
potential future customers; the uncertainty inherent in estimating
subsurface storage resources and utilization capacity in our CCS
projects; our ongoing strategy with respect to our Zama asset;
uncertainty regarding our future operating results and our future
revenues and expenses; impact of new accounting pronouncements on
earnings in future periods; and plans, objectives, expectations and
intentions contained in this communication that are not
historical.
These forward-looking statements are subject to numerous risks
and uncertainties, most of which are difficult to predict and many
of which are beyond our control. Examples of such risks include,
but are not limited to, commodity price volatility; global demand
for oil and natural gas; the ability or willingness of OPEC and
other state-controlled oil companies to set and maintain oil
production levels and the impact of any such actions; the lack of a
resolution to the war in Ukraine
and increasing hostilities in the Middle
East, and their impact on certain commodity markets; lack of
transportation and storage capacity as a result of oversupply,
government and regulations; lack of availability of drilling and
production equipment and services; adverse weather events,
including tropical storms, hurricanes, winter storms and loop
currents; cybersecurity threats; sustained inflation and the impact
of governmental policy in response thereto; environmental risks;
failure to find, acquire or gain access to other discoveries and
prospects or to successfully develop and produce from our current
discoveries and prospects; geologic risk; drilling and other
operating risks; well control risk; regulatory changes; the
uncertainty inherent in estimating reserves and in projecting
future rates of production; cash flow and access to capital; the
timing of development expenditures; potential adverse reactions or
competitive responses to our acquisitions and other transactions;
the possibility that the anticipated benefits of our acquisitions
are not realized when expected or at all, including as a result of
the impact of, or problems arising from, the integration of
acquired assets and operations; risks associated with permitting
for—and access to capital to finance—our CCS opportunities;
technological innovations and scientific developments; physical and
transition risks associated with climate change; increased
attention to ESG and sustainability-related matters; risks that the
Company may face regarding potentially conflicting anti-ESG
initiatives from certain U.S. state or other governments; and the
other risks discussed in Part I, Item 1A. "Risk Factors" of
Talos Energy Inc.'s Annual Report on Form 10-K for the year ended
December 31, 2022 and in Part II,
Item 1A. "Risk Factors" of Talos Energy Inc.'s Quarterly Report on
Form 10-Q for the period ended March 31,
2023 , each as filed with the SEC.
Reserve engineering is a process of estimating underground
accumulations of oil, natural gas and NGLs that cannot be measured
in an exact way. The accuracy of any reserve estimate depends on
the quality of available data, the interpretation of such data and
price and cost assumptions made by reserve engineers. In addition,
the results of drilling, testing and production activities may
justify upward or downward revisions of estimates that were made
previously. If significant, such revisions would change the
schedule of any further production and development drilling.
Accordingly, reserve estimates may differ significantly from the
quantities of oil, natural gas and NGLs that are ultimately
recovered.
Should any risks or uncertainties occur, or should underlying
assumptions prove incorrect, our actual results and plans could
differ materially from those expressed in any forward-looking
statements. All forward-looking statements, expressed or implied,
included in this communication are expressly qualified in their
entirety by this cautionary statement. This cautionary statement
should also be considered in connection with any subsequent written
or oral forward-looking statements that we or persons acting on our
behalf may issue. Except as otherwise required by applicable law,
we disclaim any duty to update any forward-looking statements, all
of which are expressly qualified by the statements in this section,
to reflect events or circumstances after the date of this
communication.
Talos Energy
Inc.
Consolidated Balance
Sheets
(In thousands,
except share amounts)
|
|
|
|
|
September 30,
2023
|
|
December 31,
2022
|
|
|
(Unaudited)
|
|
|
|
ASSETS
|
|
|
|
|
Current
assets:
|
|
|
|
|
Cash and cash
equivalents
|
$
|
13,631
|
|
$
|
44,145
|
|
Accounts
receivable:
|
|
|
|
|
Trade, net
|
|
181,384
|
|
|
150,598
|
|
Joint interest,
net
|
|
93,798
|
|
|
54,697
|
|
Other, net
|
|
10,744
|
|
|
6,684
|
|
Assets from price risk
management activities
|
|
11,497
|
|
|
25,029
|
|
Prepaid
assets
|
|
86,077
|
|
|
84,759
|
|
Other current
assets
|
|
14,457
|
|
|
1,917
|
|
Total current
assets
|
|
411,588
|
|
|
367,829
|
|
Property and
equipment:
|
|
|
|
|
Proved
properties
|
|
7,691,828
|
|
|
5,964,340
|
|
Unproved properties,
not subject to amortization
|
|
267,297
|
|
|
154,783
|
|
Other property and
equipment
|
|
33,795
|
|
|
30,691
|
|
Total property and
equipment
|
|
7,992,920
|
|
|
6,149,814
|
|
Accumulated
depreciation, depletion and amortization
|
|
(3,985,613)
|
|
|
(3,506,539)
|
|
Total property and
equipment, net
|
|
4,007,307
|
|
|
2,643,275
|
|
Other long-term
assets:
|
|
|
|
|
Restricted
cash
|
|
101,760
|
|
|
—
|
|
Assets from price risk
management activities
|
|
4,550
|
|
|
7,854
|
|
Equity method
investments
|
|
141,682
|
|
|
1,745
|
|
Other well equipment
inventory
|
|
44,643
|
|
|
25,541
|
|
Notes receivable,
net
|
|
15,805
|
|
|
—
|
|
Operating lease
assets
|
|
12,313
|
|
|
5,903
|
|
Other
assets
|
|
13,452
|
|
|
6,479
|
|
Total
assets
|
$
|
4,753,100
|
|
$
|
3,058,626
|
|
LIABILITIES AND
STOCKHOLDERSʼ EQUITY
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
Accounts
payable
|
$
|
125,557
|
|
$
|
128,174
|
|
Accrued
liabilities
|
|
205,095
|
|
|
219,769
|
|
Accrued
royalties
|
|
54,092
|
|
|
52,215
|
|
Current portion of
long-term debt
|
|
33,109
|
|
|
—
|
|
Current portion of
asset retirement obligations
|
|
69,288
|
|
|
39,888
|
|
Liabilities from price
risk management activities
|
|
55,042
|
|
|
68,370
|
|
Accrued interest
payable
|
|
30,536
|
|
|
36,340
|
|
Current portion of
operating lease liabilities
|
|
2,859
|
|
|
1,943
|
|
Other current
liabilities
|
|
54,221
|
|
|
60,359
|
|
Total current
liabilities
|
|
629,799
|
|
|
607,058
|
|
Long-term
liabilities:
|
|
|
|
|
Long-term
debt
|
|
1,018,774
|
|
|
585,340
|
|
Asset retirement
obligations
|
|
747,560
|
|
|
501,773
|
|
Liabilities from price
risk management activities
|
|
8,981
|
|
|
7,872
|
|
Operating lease
liabilities
|
|
18,888
|
|
|
14,855
|
|
Other long-term
liabilities
|
|
267,036
|
|
|
176,152
|
|
Total
liabilities
|
|
2,691,038
|
|
|
1,893,050
|
|
Commitments and
contingencies
|
|
|
|
|
Stockholdersʼ
equity:
|
|
|
|
|
Preferred stock; $0.01
par value; 30,000,000 shares authorized and zero shares issued or
outstanding
as of September 30, 2023 and December 31, 2022
|
|
—
|
|
|
—
|
|
Common stock; $0.01
par value; 270,000,000 shares authorized; 127,480,361 and
82,570,328 shares
issued as of September 30, 2023 and December 31, 2022,
respectively
|
|
1,275
|
|
|
826
|
|
Additional paid-in
capital
|
|
2,541,906
|
|
|
1,699,799
|
|
Accumulated
deficit
|
|
(433,615)
|
|
|
(535,049)
|
|
Treasury stock, at
cost; 3,400,000 and zero shares as of September 30, 2023 and
December 31,
2022, respectively
|
|
(47,504)
|
|
|
—
|
|
Total stockholdersʼ
equity
|
|
2,062,062
|
|
|
1,165,576
|
|
Total liabilities
and stockholdersʼ equity
|
$
|
4,753,100
|
|
$
|
3,058,626
|
|
Talos Energy
Inc.
Consolidated
Statements of Operations
(In thousands,
except per share amounts)
(Unaudited)
|
|
|
|
|
Three Months Ended
September 30,
|
|
Nine Months Ended
September 30,
|
|
|
2023
|
|
2022
|
|
2023
|
|
2022
|
|
Revenues:
|
|
|
|
|
|
|
|
|
Oil
|
$
|
359,404
|
|
$
|
295,585
|
|
$
|
995,081
|
|
$
|
1,078,800
|
|
Natural gas
|
|
16,871
|
|
|
68,360
|
|
|
53,383
|
|
|
181,747
|
|
NGL
|
|
6,860
|
|
|
13,183
|
|
|
24,463
|
|
|
49,232
|
|
Total
revenues
|
|
383,135
|
|
|
377,128
|
|
|
1,072,927
|
|
|
1,309,779
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
Lease operating
expense
|
|
103,548
|
|
|
81,760
|
|
|
286,075
|
|
|
229,156
|
|
Production
taxes
|
|
600
|
|
|
955
|
|
|
1,813
|
|
|
2,670
|
|
Depreciation,
depletion and amortization
|
|
163,359
|
|
|
92,323
|
|
|
480,476
|
|
|
295,174
|
|
Accretion
expense
|
|
21,256
|
|
|
13,179
|
|
|
63,430
|
|
|
42,400
|
|
General and
administrative expense
|
|
24,888
|
|
|
25,289
|
|
|
121,257
|
|
|
70,742
|
|
Other operating
(income) expense
|
|
(57,287)
|
|
|
(366)
|
|
|
(55,172)
|
|
|
12,142
|
|
Total operating
expenses
|
|
256,364
|
|
|
213,140
|
|
|
897,879
|
|
|
652,284
|
|
Operating income
(expense)
|
|
126,771
|
|
|
163,988
|
|
|
175,048
|
|
|
657,495
|
|
Interest
expense
|
|
(45,637)
|
|
|
(29,265)
|
|
|
(128,850)
|
|
|
(91,531)
|
|
Price risk management
activities income (expense)
|
|
(98,802)
|
|
|
114,180
|
|
|
(13,668)
|
|
|
(231,133)
|
|
Equity method
investment income (expense)
|
|
(2,493)
|
|
|
991
|
|
|
2,938
|
|
|
14,599
|
|
Other income
(expense)
|
|
2,193
|
|
|
692
|
|
|
10,450
|
|
|
31,991
|
|
Net income (loss)
before income taxes
|
|
(17,968)
|
|
|
250,586
|
|
|
45,918
|
|
|
381,421
|
|
Income tax benefit
(expense)
|
|
15,865
|
|
|
(121)
|
|
|
55,516
|
|
|
(2,256)
|
|
Net income
(loss)
|
$
|
(2,103)
|
|
$
|
250,465
|
|
$
|
101,434
|
|
$
|
379,165
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per
common share:
|
|
|
|
|
|
|
|
|
Basic
|
$
|
(0.02)
|
|
$
|
3.03
|
|
$
|
0.86
|
|
$
|
4.60
|
|
Diluted
|
$
|
(0.02)
|
|
$
|
2.99
|
|
$
|
0.85
|
|
$
|
4.54
|
|
Weighted average common
shares outstanding:
|
|
|
|
|
|
|
|
|
Basic
|
|
124,103
|
|
|
82,576
|
|
|
118,459
|
|
|
82,406
|
|
Diluted
|
|
124,103
|
|
|
83,818
|
|
|
119,262
|
|
|
83,438
|
|
Talos Energy
Inc.
Consolidated
Statements of Cash Flows
(In
thousands)
(Unaudited)
|
|
|
Nine Months Ended
September 30,
|
|
|
2023
|
|
2022
|
|
Cash flows from
operating activities:
|
|
|
|
|
Net income
(loss)
|
$
|
101,434
|
|
$
|
379,165
|
|
Adjustments to
reconcile net income to net cash provided by operating
activities:
|
|
|
|
|
Depreciation,
depletion, amortization and accretion expense
|
|
543,906
|
|
|
337,574
|
|
Amortization of
deferred financing costs and original issue discount
|
|
11,247
|
|
|
10,614
|
|
Equity-based
compensation expense
|
|
9,080
|
|
|
11,677
|
|
Price risk management
activities (income) expense
|
|
13,668
|
|
|
231,133
|
|
Net cash received
(paid) on settled derivative instruments
|
|
(10,474)
|
|
|
(368,483)
|
|
Equity method
investment (income) expense
|
|
(2,938)
|
|
|
(14,599)
|
|
Settlement of asset
retirement obligations
|
|
(71,097)
|
|
|
(60,304)
|
|
(Gain) loss on sale of
assets
|
|
(66,115)
|
|
|
390
|
|
Changes in operating
assets and liabilities:
|
|
|
|
|
Accounts
receivable
|
|
3,821
|
|
|
23,783
|
|
Other current
assets
|
|
(12,992)
|
|
|
(28,576)
|
|
Accounts
payable
|
|
(30,063)
|
|
|
16,677
|
|
Other current
liabilities
|
|
(89,511)
|
|
|
(6,682)
|
|
Other non-current
assets and liabilities, net
|
|
(57,155)
|
|
|
6,559
|
|
Net cash provided by
(used in) operating activities
|
|
342,811
|
|
|
538,928
|
|
Cash flows from
investing activities:
|
|
|
|
|
Exploration,
development and other capital expenditures
|
|
(438,506)
|
|
|
(209,592)
|
|
Proceeds from (cash
paid for) acquisitions, net of cash acquired
|
|
17,617
|
|
|
(3,500)
|
|
Proceeds from (cash
paid for) sale of property and equipment, net
|
|
66,183
|
|
|
1,690
|
|
Contributions to
equity method investees
|
|
(29,372)
|
|
|
(2,250)
|
|
Proceeds from sale of
equity method investments
|
|
—
|
|
|
15,000
|
|
Investment in
intangible assets
|
|
(7,796)
|
|
|
—
|
|
Net cash provided by
(used in) investing activities
|
|
(391,874)
|
|
|
(198,652)
|
|
Cash flows from
financing activities:
|
|
|
|
|
Redemption of senior
notes
|
|
(15,000)
|
|
|
(6,060)
|
|
Proceeds from Bank
Credit Facility
|
|
675,000
|
|
|
35,000
|
|
Repayment of Bank
Credit Facility
|
|
(460,000)
|
|
|
(350,000)
|
|
Deferred financing
costs
|
|
(11,775)
|
|
|
(211)
|
|
Other deferred
payments
|
|
(841)
|
|
|
—
|
|
Payments of finance
lease
|
|
(12,117)
|
|
|
(19,764)
|
|
Purchase of treasury
stock
|
|
(47,504)
|
|
|
—
|
|
Employee stock awards
tax withholdings
|
|
(7,454)
|
|
|
(4,603)
|
|
Net cash provided by
(used in) financing activities
|
|
120,309
|
|
|
(345,638)
|
|
|
|
|
|
|
Net increase (decrease)
in cash, cash equivalents and restricted cash
|
|
71,246
|
|
|
(5,362)
|
|
Cash, cash equivalents
and restricted cash:
|
|
|
|
|
Balance, beginning of
period
|
|
44,145
|
|
|
69,852
|
|
Balance, end of
period
|
$
|
115,391
|
|
$
|
64,490
|
|
|
|
|
|
|
Supplemental non-cash
transactions:
|
|
|
|
|
Capital expenditures
included in accounts payable and accrued liabilities
|
$
|
90,688
|
|
$
|
78,191
|
|
Supplemental cash flow
information:
|
|
|
|
|
Interest paid, net of
amounts capitalized
|
$
|
108,931
|
|
$
|
89,187
|
|
SUPPLEMENTAL NON-GAAP INFORMATION
Certain financial information included in our financial results
are not measures of financial performance recognized by accounting
principles generally accepted in the
United States, or GAAP. These non-GAAP financial measures
may not be viewed as a substitute for results determined in
accordance with GAAP and are not necessarily comparable to non-GAAP
measures which may be reported by other companies.
Reconciliation of General and Administrative Expenses to
Upstream General and Administrative Expenses
We believe the presentation of Upstream General and
Administrative Expenses excluding non-cash equity-based
compensation provides management and investors with (i) important
supplemental indicators of the operational performance of our core
upstream 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.
Upstream General & Administrative Expenses 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 general and administrative expenses, net income
(loss), operating income (loss) or any other measure of financial
performance presented in accordance with GAAP. We define these as
the following:
General and Administrative Expenses. General and
administrative expenses consists of costs incurred for overhead,
including payroll and benefits for our corporate staff, costs of
maintaining our headquarters, costs of managing our production
operations, bad debt expense, equity-based compensation expense,
audit and other fees for professional services and legal
compliance. A portion of these expenses are allocated based on the
percentage of employees dedicated to each operating segment.
Upstream General and Administrative Expenses. Upstream
general and administrative expenses consist of general and
administrative expenses for the Upstream Segment.
($
thousands)
|
Three Months
Ended
September 30, 2023
|
|
Reconciliation of
General & Administrative Expenses to Upstream General &
Administrative Expenses
(excluding non-cash equity-based compensation):
|
|
|
Total General and
administrative expense
|
$
|
24,888
|
|
CCS Segment
|
|
(2,472)
|
|
Unallocated
corporate
|
|
(1,362)
|
|
Non-cash equity-based
compensation expense
|
|
(343)
|
|
Upstream General &
Administrative Expenses (excluding non-cash equity-based
compensation)
|
$
|
20,711
|
|
Reconciliation of Net Income (Loss) to EBITDA, Adjusted
EBITDA and Upstream Adjusted EBITDA
"EBITDA," "Adjusted EBITDA" and "Upstream Adjusted EBITDA"
provide management and investors with (i) additional information to
evaluate, with certain adjustments, items required or permitted in
calculating covenant compliance under our debt agreements, (ii)
important supplemental indicators of the operational performance of
our business, (iii) additional criteria for evaluating our
performance relative to our peers and (iv) supplemental information
to investors about certain material non-cash and/or other items
that may not continue at the same level in the future. EBITDA,
Adjusted EBITDA, and Upstream Adjusted EBITDA have limitations as
analytical tools and should not be considered in isolation or as
substitutes for analysis of our results as reported under GAAP or
as alternatives to net income (loss), operating income (loss) or
any other measure of financial performance presented in accordance
with GAAP. We define these as the following:
EBITDA. Net income (loss) plus interest expense; income
tax expense (benefit); depreciation, depletion and amortization;
and accretion expense.
Adjusted EBITDA. EBITDA plus non-cash write-down of oil
and natural gas properties, transaction and other (income)
expenses, decommissioning obligations, derivative fair value (gain)
loss, net cash receipts (payments) on settled derivatives, (gain)
loss on debt extinguishment, non-cash write-down of other well
equipment inventory and non-cash equity-based compensation
expense.
Adjusted EBITDA excluding hedges. We have historically
provided as a supplement to—rather than in lieu of—Adjusted EBITDA
including hedges, provides useful information regarding our results
of operations and profitability by illustrating the operating
results of our oil and natural gas properties without the benefit
or detriment, as applicable, of our financial oil and natural gas
hedges. By excluding our oil and natural gas hedges, we are able to
convey actual operating results using realized market prices during
the period, thereby providing analysts and investors with
additional information they can use to evaluate the impacts of our
hedging strategies over time.
Upstream Adjusted EBITDA. Adjusted EBITDA plus equity
method investment loss, general and administrative expense, other
operating expenses (income), other income, and non-cash
equity-based compensation expense attributable to CCS and
unallocated corporate costs.
We also present Adjusted EBITDA excluding hedges and Upstream
Adjusted EBITDA excluding hedges as a percentage of revenue and on
a per barrel of oil equivalent basis, respectively, to further
analyze our business, which are outlined below:
Adjusted EBITDA Margin and Upstream Adjusted EBITDA
Margin. Adjusted EBITDA divided by Revenue, as a
percentage. It is also defined as Upstream 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 of Upstream Adjusted EBITDA we generate after accounting
for certain operational and corporate costs.
The following tables present 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, and Upstream Adjusted
EBITDA, Upstream Adjusted EBITDA excluding hedges, Upstream
Adjusted EBITDA Margin, and Upstream Adjusted EBITDA Margin
excluding hedges for each of the periods indicated (in thousands,
except for Boe, $/Boe and percentage data):
|
Three Months
Ended
|
|
($
thousands)
|
September 30,
2023
|
|
June 30,
2023
|
|
March 31,
2023
|
|
December 31,
2022
|
|
Reconciliation of
Net Income (Loss) to Adjusted EBITDA:
|
|
|
|
|
|
|
|
|
Net Income
(loss)
|
$
|
(2,103)
|
|
$
|
13,677
|
|
$
|
89,860
|
|
$
|
2,750
|
|
Interest
expense
|
|
45,637
|
|
|
45,632
|
|
|
37,581
|
|
|
33,967
|
|
Income tax expense
(benefit)
|
|
(15,865)
|
|
|
6,892
|
|
|
(46,543)
|
|
|
281
|
|
Depreciation,
depletion and amortization
|
|
163,359
|
|
|
169,794
|
|
|
147,323
|
|
|
119,456
|
|
Accretion
expense
|
|
21,256
|
|
|
22,760
|
|
|
19,414
|
|
|
13,595
|
|
EBITDA
|
|
212,284
|
|
|
258,755
|
|
|
247,635
|
|
|
170,049
|
|
Transaction and other
(income) expenses(1)
|
|
(64,321)
|
|
|
3,513
|
|
|
22,009
|
|
|
4,343
|
|
Decommissioning
obligations(2)
|
|
7,972
|
|
|
741
|
|
|
741
|
|
|
21,005
|
|
Derivative fair value
(gain) loss(3)
|
|
98,802
|
|
|
(26,197)
|
|
|
(58,937)
|
|
|
41,058
|
|
Net cash received
(paid) on settled derivative instruments(3)
|
|
(6,313)
|
|
|
8,162
|
|
|
(12,323)
|
|
|
(57,076)
|
|
Loss on extinguishment
of debt
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,569
|
|
Non-cash equity-based
compensation expense
|
|
393
|
|
|
4,749
|
|
|
3,938
|
|
|
4,276
|
|
Adjusted
EBITDA
|
|
248,817
|
|
|
249,723
|
|
|
203,063
|
|
|
185,224
|
|
Add: Net cash
(received) paid on settled derivative
instruments(3)
|
|
6,313
|
|
|
(8,162)
|
|
|
12,323
|
|
|
57,076
|
|
Adjusted EBITDA
excluding hedges
|
$
|
255,130
|
|
$
|
241,561
|
|
$
|
215,386
|
|
$
|
242,300
|
|
Revenue:
|
|
|
|
|
|
|
|
|
Revenue -
Operations
|
|
383,135
|
|
|
367,210
|
|
|
322,582
|
|
|
342,201
|
|
Adjusted EBITDA margin
and Adjusted EBITDA excl hedges margin:
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
divided by - Total revenue incl hedges (%)
|
|
66
|
%
|
|
67
|
%
|
|
65
|
%
|
|
65
|
%
|
Adjusted EBITDA
divided by - Total revenue (%)
|
|
67
|
%
|
|
66
|
%
|
|
67
|
%
|
|
71
|
%
|
|
|
(1)
|
For the three months
ended September 30, 2023, transaction expenses include $1.5 million
in costs related to the EnVen Acquisition, inclusive of $0.9
million in severance expense. For the three months ended June 30,
2023, transaction expenses include $2.7 million in costs
related to the EnVen Acquisition, inclusive of $1.4 million in
severance expense. For the three months ended March 31,
2023, transaction expenses include $35.2 million in costs
related to the EnVen Acquisition, inclusive of $22.6 million in
severance expense. Transaction expenses are included in "General
and administrative expense" on our consolidated statements of
operations. Other income (expense) includes other miscellaneous
income and expenses that we do not view as a meaningful indicator
of our operating performance. For the three months ended September
30, 2023, it includes a $66.2 million gain on the Mexico
divestiture. For the three months ended March 31, 2023, it includes
a $8.6 million gain on the funding of the capital carry of its
investment in Bayou Bend by Chevron that is included in "Equity
method investment income (expense)" on our consolidated statements
of operations.
|
(2)
|
Estimated
decommissioning obligations were a result of working interest
partners or counterparties of divestiture transactions that were
unable to perform the required abandonment obligations due to
bankruptcy or insolvency and are included in "Other operating
(income) expense" on our consolidated statements of
operations.
|
(3)
|
The adjustments for the
derivative fair value (gain) loss and net cash receipts (payments)
on settled derivative instruments have the effect of adjusting net
income (loss) for changes in the fair value of derivative
instruments, which are recognized at the end of each accounting
period because we do not designate commodity derivative instruments
as accounting hedges. This results in reflecting commodity
derivative gains and losses within Adjusted EBITDA on an unrealized
basis during the period the derivatives settled.
|
($ thousands, except
per BOE amounts)
|
Three Months
Ended
September 30, 2023
|
|
Reconciliation of
Adjusted EBITDA to Upstream Adjusted EBITDA:
|
|
|
Adjusted
EBITDA
|
$
|
248,817
|
|
CCS and Corporate
Unallocated Costs:
|
|
|
Equity method
investment loss
|
|
2,611
|
|
General and
administrative expense
|
|
3,835
|
|
Other operating
expense
|
|
127
|
|
Other
income
|
|
(5)
|
|
Transaction and other
income (expenses)(1)
|
|
(106)
|
|
Non-cash equity-based
compensation expense
|
|
(51)
|
|
Upstream Adjusted
EBITDA
|
|
255,228
|
|
Add: Net cash paid on
settled derivative instruments(2)
|
|
6,313
|
|
Upstream Adjusted
EBITDA excluding hedges
|
$
|
261,541
|
|
Production:
|
|
|
Boe(3)
|
|
5,855
|
|
Upstream Adjusted
EBITDA margin and Upstream Adjusted EBITDA excl hedges
margin:
|
|
|
Upstream Adjusted
EBITDA per Boe(3)
|
$
|
43.59
|
|
Upstream Adjusted
EBITDA excl hedges per Boe(2)(3)
|
$
|
44.67
|
|
|
|
(1)
|
Transaction and other
income (expense) includes other miscellaneous income and expenses
that we do not view as a meaningful indicator of our operating
performance.
|
(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 Adjusted Free Cash Flow
and Reconciliation of Net Cash Provided by Operating Activities to
Adjusted Free Cash Flow
"Adjusted Free Cash Flow" before changes in working capital
provides management and investors with (i) important supplemental
indicators of the operational performance of our business, (ii)
additional criteria for evaluating our performance relative to our
peers and (iii) supplemental information to investors about certain
material non-cash and/or other items that may not continue at the
same level in the future. Adjusted Free Cash Flow has limitations
as an analytical tool and should not be considered in isolation or
as substitutes for analysis of our results as reported under GAAP
or as alternatives to net income (loss), operating income (loss) or
any other measure of financial performance presented in accordance
with GAAP. We define these as the following:
Capital Expenditures and Plugging & Abandonment.
Actual capital expenditures and plugging & abandonment
recognized in the quarter, inclusive of accruals.
Interest Expense. Actual interest expense per the income
statement.
Talos did not pay any cash income taxes in the period, therefore
cash income taxes have no impact to the reported Adjusted Free Cash
Flow before changes in working capital number.
($
thousands)
|
Three Months
Ended
September 30, 2023
|
|
Reconciliation of
Adjusted EBITDA to Adjusted Free Cash Flow (before changes in
working capital):
|
|
|
Adjusted
EBITDA
|
$
|
248,817
|
|
Upstream capital
expenditures
|
|
(118,730)
|
|
Plugging &
abandonment
|
|
(23,414)
|
|
Decommissioning
obligations settled
|
|
(38,368)
|
|
CCS capital
expenditures
|
|
(14,126)
|
|
Interest
expense
|
|
(45,637)
|
|
Adjusted Free Cash Flow
(before changes in working capital)
|
$
|
8,542
|
|
|
($
thousands)
|
Three Months
Ended
September 30, 2023
|
|
Reconciliation of
Net Cash Provided by Operating Activities to Adjusted Free Cash
Flow (before
changes in working capital):
|
|
|
Net cash provided by
operating activities(1)
|
$
|
65,728
|
|
(Increase) decrease in
operating assets and liabilities
|
|
126,248
|
|
Upstream capital
expenditures(2)
|
|
(118,730)
|
|
Decommissioning
obligations settled
|
|
(38,368)
|
|
CCS capital
expenditures
|
|
(14,126)
|
|
Transaction and other
(income) expenses(3)
|
|
1,859
|
|
Decommissioning
obligations(4)
|
|
7,972
|
|
Amortization of
deferred financing costs and original issue discount
|
|
(3,618)
|
|
Income tax
benefit
|
|
(15,865)
|
|
Other
adjustments
|
|
(2,558)
|
|
Adjusted Free Cash Flow
(before changes in working capital)
|
$
|
8,542
|
|
|
|
(1)
|
Includes settlement of
asset retirement obligations.
|
(2)
|
Includes accruals and
excludes acquisitions.
|
(3)
|
The transaction
expenses include $1.5 million in costs related to the EnVen
Acquisition, inclusive of $0.9 million in severance expense. Other
income (expenses) includes miscellaneous income and expenses that
we do not view as a meaningful indicator of our operating
performance.
|
(4)
|
Estimated
decommissioning obligations were a result of working interest
partners or counterparties of divestiture transactions that were
unable to perform the required abandonment obligations due to
bankruptcy or insolvency.
|
Reconciliation of Net Income to Adjusted Net Income (Loss)
and Adjusted Earnings per Share
"Adjusted Net Income (Loss)" and "Adjusted Earnings per Share"
are to provide management and investors with (i) important
supplemental indicators of the operational performance of our
business, (ii) additional criteria for evaluating our performance
relative to our peers and (iii) supplemental information to
investors about certain material non-cash and/or other items that
may not continue at the same level in the future. Adjusted Net
Income (Loss) and Adjusted Earnings per Share have limitations as
analytical tools and should not be considered in isolation or as a
substitute for analysis of our results as reported under GAAP or as
an alternative to net income (loss), operating income (loss),
earnings per share or any other measure of financial performance
presented in accordance with GAAP.
Adjusted Net Income (Loss). Net income (loss) plus
accretion expense, transaction related costs, derivative fair value
(gain) loss, net cash receipts (payments) on settled derivative
instruments and non-cash equity-based compensation expense.
Adjusted Earnings per Share. Adjusted Net Income (Loss)
divided by the number of common shares.
|
Three Months
Ended
September 30, 2023
|
|
($ thousands, except
per share amounts)
|
|
|
Basic per
Share
|
|
Diluted per
Share
|
|
Reconciliation of
Net Loss to Adjusted Net Income:
|
|
|
|
|
|
|
Net Loss
|
$
|
(2,103)
|
|
$
|
(0.02)
|
|
$
|
(0.02)
|
|
Transaction and other
(income) expenses(1)
|
|
(64,321)
|
|
$
|
(0.52)
|
|
$
|
(0.51)
|
|
Decommissioning
obligations(2)
|
|
7,972
|
|
$
|
0.06
|
|
$
|
0.06
|
|
Derivative fair value
loss(3)
|
|
98,802
|
|
$
|
0.80
|
|
$
|
0.79
|
|
Net cash received on
paid derivative instruments(3)
|
|
(6,313)
|
|
$
|
(0.05)
|
|
$
|
(0.05)
|
|
Non-cash income tax
benefit
|
|
(15,865)
|
|
$
|
(0.13)
|
|
$
|
(0.13)
|
|
Non-cash equity-based
compensation expense
|
|
393
|
|
$
|
0.00
|
|
$
|
0.00
|
|
Adjusted Net
Income(4)
|
$
|
18,565
|
|
$
|
0.15
|
|
$
|
0.15
|
|
|
|
|
|
|
|
|
Weighted average common
shares outstanding at September 30, 2023:
|
|
|
|
|
|
|
Basic
|
|
124,103
|
|
|
|
|
|
Diluted
|
|
124,964
|
|
|
|
|
|
|
|
(1)
|
The transaction
expenses include $1.5 million in costs related to the EnVen
Acquisition, inclusive of $0.9 million in severance expense. Other
income (expenses) includes miscellaneous income and expenses that
we do not view as a meaningful indicator of our operating
performance. It includes a $66.2 million gain on the Mexico
divestiture.
|
(2)
|
Estimated
decommissioning obligations were a result of working interest
partners or counterparties of divestiture transactions that were
unable to perform the required abandonment obligations due to
bankruptcy or insolvency.
|
(3)
|
The adjustments for the
derivative fair value (gain) loss and net cash receipts (payments)
on settled derivative instruments have the effect of adjusting net
income (loss) for changes in the fair value of derivative
instruments, which are recognized at the end of each accounting
period because we do not designate commodity derivative instruments
as accounting hedges. This results in reflecting commodity
derivative gains and losses within Adjusted Net Income (Loss) on an
unrealized basis during the period the derivatives
settled.
|
(4)
|
The per share impacts
reflected in this table were calculated independently and may not
sum to total adjusted basic and diluted EPS due to
rounding.
|
Reconciliation of Total Debt to Net Debt and Net Debt
to LTM Adjusted EBITDA
We believe the presentation of Net Debt, LTM Adjusted EBITDA,
and Net Debt to LTM Adjusted EBITDA is important to provide
management and investors with additional important information to
evaluate our business. These measures are widely used by investors
and ratings agencies in the valuation, comparison, rating and
investment recommendations of companies.
Net Debt. Total Debt principal minus cash and cash
equivalents.
Net Debt to LTM Adjusted EBITDA. Net Debt divided by
the LTM Adjusted EBITDA.
($
thousands)
|
September 30,
2023
|
|
Reconciliation of
Net Debt:
|
|
|
12.00% Second-Priority
Senior Secured Notes – due January 2026
|
$
|
638,541
|
|
11.75% Senior Secured
Second Lien Notes – due April 2026
|
|
242,500
|
|
Bank Credit Facility –
matures March 2027
|
|
215,000
|
|
Total Debt
|
|
1,096,041
|
|
Less: Cash and cash
equivalents
|
|
(13,631)
|
|
Net Debt
|
$
|
1,082,410
|
|
|
|
|
Calculation of LTM
Adjusted EBITDA:
|
|
|
Adjusted EBITDA for
three months period ended December 30, 2022
|
$
|
185,224
|
|
Adjusted EBITDA for
three months period ended March 31, 2022
|
|
203,063
|
|
Adjusted EBITDA for
three months period ended June 30, 2023
|
|
249,723
|
|
Adjusted EBITDA for
three months period ended September 30, 2023
|
|
248,817
|
|
LTM Adjusted
EBITDA
|
$
|
886,827
|
|
|
|
|
Acquired Assets
Adjusted EBITDA:
|
|
|
Adjusted EBITDA for
three months period ended December 31, 2022
|
|
73,891
|
|
Adjusted EBITDA for the
period January 1, 2023 to February 13, 2023
|
|
33,120
|
|
LTM Adjusted EBITDA
from Acquired Assets
|
$
|
107,011
|
|
|
|
|
Pro Forma LTM Adjusted
EBITDA
|
$
|
993,838
|
|
|
|
|
Reconciliation of
Net Debt to Pro Forma LTM Adjusted EBITDA:
|
|
|
Net Debt / Pro Forma
LTM Adjusted EBITDA(1)
|
1.1x
|
|
|
|
(1)
|
Net Debt / Pro Forma
LTM Adjusted EBITDA figure excludes the Finance Lease. Had the
Finance Lease been included, Net Debt / Pro Forma LTM Adjusted
EBITDA would have been 1.2x.
|
View original
content:https://www.prnewswire.com/news-releases/talos-energy-announces-third-quarter-2023-operational-and-financial-results-301979206.html
SOURCE Talos Energy