HOUSTON, Aug. 8, 2023
/PRNewswire/ -- Talos Energy Inc. ("Talos" or the "Company") (NYSE:
TALO) today announced its operational and financial results for
fiscal quarter ended June 30,
2023.
Key Highlights:
- Drilled a successful commercial discovery at the Talos-operated
Sunspear prospect.
- Announced a transaction with Grupo
Carso, selling a 49.9% interest in Talos Energy Mexico 7, S.
de R.L. de C.V. ("Talos Mexico"), a wholly-owned subsidiary of the
Company, which holds a working interest in the Zama project, for
approximately $125 million.
- Filed first EPA Class VI permit for carbon sequestration, with
at least one additional permit expected to be filed by
year-end.
- Continue to explore a capital raise for the Company's Talos Low
Carbon Solutions ("TLCS") platform.
- Repurchased 1.5 million shares of common stock for $20.9 million at an average price of $13.89 per share.
Second Quarter Summary:
- Production of 70.3 thousand barrels of oil equivalent per day
("MBoe/d") (75% oil, 83% liquids).
- Revenue of $367.2 million, driven
by realized prices (excluding hedges) of $71.44 per barrel for oil, $16.25 per barrel for natural gas liquids
("NGLs"), and $2.46 per thousand
cubic feet ("Mcf") for natural gas.
- Net Income of $13.7 million, or
$0.11 Net Income per diluted share,
and Adjusted Net Income(1) of $11.5 million, or $0.09 Adjusted Net Income per diluted share.
- Upstream Adjusted EBITDA(1) of $253.6 million.
- Capital expenditures of $191.2
million, inclusive of plugging and abandonment and Carbon
Capture & Sequestration ("CCS").
- Net cash provided by operating activities of $214.2 million.
- Adjusted Free Cash Flow(1) of $12.9 million.
Talos President and Chief
Executive Officer Timothy S. Duncan
commented: "We made great progress advancing key catalysts and had
solid execution across our business in the second quarter. The
ongoing integration of the EnVen transaction and our increased oil
and liquids exposure underpinned another quarter with strong
margins. We are excited about our discovery at Sunspear, a prospect
and host facility acquired in the EnVen transaction. This success
further demonstrates our belief that owning critical assets in the
Gulf of Mexico can significantly
enhance subsea drilling economics. We announced a transaction for
our Talos Mexico subsidiary, welcoming Grupo Carso as a co-owner in a structure that
establishes a baseline valuation for Zama but retains significant
upside as we work to maximize the value of that asset. Finally, we
are pleased to see the progress in our CCS business. We recently
filed a Class VI permit application, which is an important
milestone. We also continue to explore a capital raise for our
Talos Low Carbon Solution platform and we'll provide an update when
appropriate."
RECENT DEVELOPMENTS AND OPERATIONS UPDATE
Shareholder Return Program: During the second quarter 2023,
Talos opportunistically repurchased 1.5 million shares of common
stock for $20.9 million, representing
an average price of $13.89 per share.
As of June 30, 2023, the Company has
purchased 3.4 million shares or 3% of total outstanding shares with
remaining authorization to repurchase up to approximately
$52.5 million of additional common
stock under its $100 million
program.
Mexico Divestiture: In May
2023, Talos announced a transaction with Grupo Carso to sell a 49.9% interest in Talos
Mexico, which holds a 17.4% stake in Zama. The transaction valued
the Talos Mexico entity at a $250
million valuation. Talos expects to receive approximately
$125 million for the 49.9% stake,
including approximately $75 million
paid at closing and approximately $50
million due upon first production. The transaction is
expected to close during the third quarter 2023, subject to
regulatory approval.
In June 2023, Mexico's Comisión Nacional de Hidrocarburos
approved the Zama Unit Development Plan previously submitted in
March 2023. Talos is actively working
with the Zama Unit's Integrated Project Team to progress the
front-end engineering and design ("FEED") and other workstreams
required to reach a Final Investment Decision ("FID").
Drilling and Completion 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 the first
quarter 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.
Sunspear: The Sunspear exploitation well successfully
discovered commercial quantities of oil and natural gas in
July 2023. Talos's preliminary
post-drill analysis indicates approximately 260 feet of gross true
vertical thickness of oil pay (177 feet net across two targets),
including 149 feet of net oil pay in the main target in line with
pre-drill expectations. The project will flow to the recently
acquired Prince platform with first oil expected in the next 18 to
24 months. Working interest partners are Talos 48.0%, an entity
managed by Ridgewood Energy Corporation 47.5%, and Houston Energy
4.5%.
Longhorn: The Longhorn prospect, designed to test deep
objectives underneath the Lobster field, found non-commercial
levels of hydrocarbons in the deep zone, though the well
encountered over 50 feet of pay across two legacy field pays. The
well has been suspended and will be analyzed for completion
alongside the next Lobster field development well, which is
expected to spud in the third quarter 2023.
Pancheron: Drilling of the Pancheron exploration
prospect in the second quarter 2023 encountered non-commercial
quantities of hydrocarbons, and plugging and abandonment operations
have been completed. Talos held a 30% working interest, bp held a
33% working interest, and Oxy held a 37% working interest and was
the operator. Pre-drill probability of success was estimated at
approximately 30%.
Other Operated Production and Downtime
Updates: During the second quarter 2023, Talos completed
the planned well interventions on its operated Bulleit DTR-10 Sand
recompletion and Mount Hunter development well. The interventions
successfully improved overall reservoir productivity. Additionally,
on Talos's operated Neptune facility, the Company continues to work
on optimization efforts, including new chemical treatments and
topside modifications, expected to be completed in the fourth
quarter 2023.
Non-Operated Project Updates: The Odd Job subsea pump
project, operated by Kosmos Energy, which is intended to sustain
long-term production from the field, continues to progress and
remains on track to be in service by mid-2024. Talos has a 17.5%
working interest. Drilling on the Marmalard well, operated by
Murphy Oil, is expected to commence in the third quarter 2023.
Talos holds a 11.4% working interest.
TLCS Updates:
Exploring Capital Raise: Talos continues to explore a
capital raise to scale up the development of its existing TLCS
portfolio and accelerate its growth. The Company will provide
further updates when available.
Stratigraphic Wells and Class VI
Permits: As previously announced, the Bayou Bend
partnership has contracted a rig and expects to drill a
Talos-operated offshore stratigraphic well during the second half
2023. Additionally, the partnership expects to drill a
Chevron-operated onshore stratigraphic well in the first half 2024.
Separately, in early August 2023,
TLCS filed its first EPA Class VI permit for its Harvest Bend CCS
project (formerly known as River Bend CCS), in which TLCS holds a
60% interest. TLCS also intends to file at least one additional EPA
Class VI permit application across its portfolio by year-end.
SECOND QUARTER 2023 RESULTS
Key Financial Highlights:
($ thousands, except
per share and per BOE amounts)
|
Three Months
Ended
June 30,
2023
|
|
Total
revenues
|
$
|
367,210
|
|
Net income
|
$
|
13,677
|
|
Net income per diluted
share
|
$
|
0.11
|
|
Adjusted Net
Income(1)
|
$
|
11,537
|
|
Adjusted Net Income per
diluted share(1)
|
$
|
0.09
|
|
Adjusted
EBITDA(1)
|
$
|
249,723
|
|
Adjusted EBITDA
excluding hedges(1)
|
$
|
241,561
|
|
Upstream Adjusted
EBITDA(1)
|
$
|
253,615
|
|
Upstream Adjusted
EBITDA excluding hedges(1)
|
$
|
245,453
|
|
Capital Expenditures
(including Plug & Abandonment, Decommissioning
Obligations Settled and CCS)
|
$
|
191,205
|
|
Upstream Adjusted
EBITDA Margin:
|
|
|
Upstream Adjusted
EBITDA per Boe(1)
|
$
|
39.67
|
|
Upstream Adjusted
EBITDA excluding hedges per Boe(1)
|
$
|
38.39
|
|
Production
Production was 70.3 MBoe/d for the second quarter 2023 and was
75% oil and 83% liquids.
|
Three Months
Ended
June 30,
2023
|
|
Average daily
production volumes
|
|
|
Oil
(MBbl/d)
|
|
52.8
|
|
Natural Gas
(MMcf/d)
|
|
72.9
|
|
NGL
(MBbl/d)
|
|
5.3
|
|
Total average daily
(MBoe/d)
|
|
70.3
|
|
|
Three Months Ended
June 30, 2023
|
|
|
Production
|
|
% Oil
|
|
% Liquids
|
|
% Operated
|
|
Average daily
production volumes by Core Area (MBoe/d)
|
|
|
|
|
|
|
|
|
Green Canyon
Area
|
|
22.7
|
|
|
84
|
%
|
|
91
|
%
|
|
88
|
%
|
Mississippi Canyon
Area
|
|
34.6
|
|
|
79
|
%
|
|
87
|
%
|
|
70
|
%
|
Shelf and Gulf
Coast
|
|
13.0
|
|
|
50
|
%
|
|
58
|
%
|
|
61
|
%
|
Total average daily
(MBoe/d)
|
|
70.3
|
|
|
75
|
%
|
|
83
|
%
|
|
74
|
%
|
Lease Operating & General and Administrative
Expenses
Total lease operating expenses, inclusive of workover and
maintenance and insurance costs for the quarter, were $101.2 million or $15.82/Boe. Upstream General and Administrative
expenses for the quarter, excluding non-cash equity-based
compensation, was $25.0 million, or
$3.91/Boe. Upstream General and
Administrative expenses is shown inclusive of $3.5 million in transaction-related expenses.
($ thousands, except
per BOE amounts)
|
Three Months
Ended
June 30,
2023
|
|
Per
Boe
|
|
Lease Operating
Expenses
|
$
|
101,165
|
|
$
|
15.82
|
|
Upstream General &
Administrative Expenses (excluding non-cash equity-based
compensation)(1)
|
$
|
24,994
|
|
$
|
3.91
|
|
Capital Expenditures
Upstream capital expenditures, including plugging and
abandonment, totaled $189.3 million
for the second quarter 2023.
($
thousands)
|
Three Months
Ended
June 30,
2023
|
|
Six Months
Ended
June 30,
2023
|
|
Upstream Capital
Expenditures
|
|
|
|
|
U.S. drilling &
completions
|
$
|
120,331
|
|
$
|
232,661
|
|
Mexico appraisal &
exploration
|
|
101
|
|
|
197
|
|
Asset
management(1)
|
|
15,784
|
|
|
60,728
|
|
Seismic and G&G,
land, capitalized G&A and other
|
|
14,212
|
|
|
36,045
|
|
Total Upstream Capital
Expenditures
|
|
150,428
|
|
|
329,631
|
|
Plugging &
Abandonment
|
|
37,570
|
|
|
47,683
|
|
Decommissioning
Obligations Settled(2)
|
|
1,339
|
|
|
2,047
|
|
Total
Upstream
|
$
|
189,337
|
|
$
|
379,361
|
|
|
|
(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 $2.4 million
for the second quarter 2023, which is accounted for in the
Company's reported Adjusted EBITDA figure. CCS capital expenditures
totaled $1.9 million for the second
quarter 2023, which mainly includes investments in Bayou Bend and
funding for general ongoing operations.
($
thousands)
|
Three Months
Ended
June 30,
2023
|
|
Six Months
Ended
June 30,
2023
|
|
CCS
Investments
|
|
|
|
|
CCS
Expenses
|
$
|
2,360
|
|
$
|
8,517
|
|
CCS Capital
Expenditures
|
|
1,868
|
|
|
23,057
|
|
Total CCS
Investments
|
$
|
4,228
|
|
$
|
31,574
|
|
Liquidity and Leverage
At June 30, 2023, Talos had
approximately $771.8 million of
liquidity, with $765.0 million
undrawn on its credit facility and approximately $17.5 million in cash, less approximately
$10.8 million in outstanding letters
of credit.
On June 30, 2023, Talos had $1,081.0
million in total debt. Net Debt was $1,063.5 million(1). Net Debt to Pro
Forma LTM Adjusted EBITDA was 1.0x(1).
Footnotes:
|
(1)
|
Adjusted Net Income
(Loss), Adjusted Income (Loss) per Share, Adjusted EBITDA, Adjusted
EBITDA excluding hedges, Upstream Adjusted EBITDA, Upstream
Adjusted EBITDA excluding hedges, Adjusted EBITDA margin, Adjusted
EBITDA margin excluding hedges, Upstream Adjusted EBITDA margin or
per Boe, Upstream Adjusted EBITDA margin excluding hedges or per
Boe, Upstream General and Administrative Expenses, Credit Facility
LTM Adjusted EBITDA, Net Debt, Net Debt to Pro Forma LTM Adjusted
EBITDA, Adjusted Free Cash Flow and PV-10 are non-GAAP financial
measures. See "Supplemental Non-GAAP Information" below for
additional detail and reconciliations of GAAP to non-GAAP
measures.
|
HEDGES
The following table reflects contracted volumes and weighted
average prices the Company will receive under the terms of its
derivative contracts as of August 8,
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)
|
|
July - September
2023
|
Fixed Swaps
|
|
14,348
|
|
$
|
73.92
|
|
---
|
|
---
|
|
---
|
|
July - September
2023
|
Collar
|
|
4,500
|
|
---
|
|
---
|
|
$
|
70.56
|
|
$
|
89.99
|
|
July - September
2023
|
3-Way Collar
|
|
9,200
|
|
---
|
|
$
|
51.86
|
|
$
|
65.11
|
|
$
|
109.25
|
|
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
|
|
15,000
|
|
$
|
72.55
|
|
---
|
|
---
|
|
---
|
|
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
|
|
18,500
|
|
$
|
72.68
|
|
---
|
|
---
|
|
---
|
|
April - June
2024
|
Collar
|
|
1,000
|
|
---
|
|
---
|
|
$
|
70.00
|
|
$
|
75.00
|
|
July - September
2024
|
Fixed Swaps
|
|
8,000
|
|
$
|
72.53
|
|
---
|
|
---
|
|
---
|
|
July - September
2024
|
Collar
|
|
1,000
|
|
---
|
|
---
|
|
$
|
70.00
|
|
$
|
75.00
|
|
October - December
2024
|
Fixed Swaps
|
|
7,000
|
|
$
|
70.68
|
|
---
|
|
---
|
|
---
|
|
October - December
2024
|
Collar
|
|
1,000
|
|
---
|
|
---
|
|
$
|
70.00
|
|
$
|
75.00
|
|
January - March
2025
|
Fixed Swaps
|
|
4,000
|
|
$
|
67.00
|
|
---
|
|
---
|
|
---
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas – HH
NYMEX
|
|
(MMBtu)
|
|
(Per
MMBtu)
|
|
(Per
MMBtu)
|
|
(Per
MMBtu)
|
|
(Per
MMBtu)
|
|
July - September
2023
|
Fixed Swaps
|
|
20,000
|
|
$
|
3.35
|
|
---
|
|
---
|
|
---
|
|
July - September
2023
|
Collar
|
|
10,000
|
|
---
|
|
---
|
|
$
|
5.25
|
|
$
|
8.46
|
|
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
|
|
10,000
|
|
$
|
4.37
|
|
---
|
|
---
|
|
---
|
|
CONFERENCE CALL AND WEBCAST INFORMATION
Talos will host a conference call, which will be broadcast live
over the internet, on Wednesday, August 9,
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 August 16, 2023 and can be accessed by dialing
(877) 344-7529 and using access code 7754475.
ABOUT TALOS ENERGY
Talos Energy (NYSE: TALO) is a technically driven independent
exploration and production company focused on safely and
efficiently maximizing long-term value through its operations,
currently in the United States and
offshore Mexico, both upstream
through oil and gas exploration and production and downstream
through the development of future carbon capture and storage
opportunities. As one of the Gulf of
Mexico's largest public independent producers, we leverage
decades of technical and offshore operational expertise towards the
acquisition, exploration and development of assets in key
geological trends that are present in many offshore basins around
the world. With a focus on environmental stewardship, we are also
utilizing our expertise to explore opportunities to reduce
industrial emissions through our carbon capture and storage
initiatives along the U.S. Gulf of
Mexico. For more information, visit
www.talosenergy.com.
INVESTOR RELATIONS CONTACT
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 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; 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; 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 ("OPEC Plus") to set and
maintain oil production levels; the impact of any such actions; the
lack of a resolution to the war in Ukraine and its 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 and winter storms;
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; 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 (the "2022 Annual
Report") and Part II, Item IA. "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. In addition, we use the terms "gross true vertical
thickness," "TVT" and "oil pay" in this communication, which are
not measures of "reserves" prepared in accordance with SEC
guidelines or permitted to be included in SEC filings. These
resource estimates are inherently more uncertain than estimates of
reserves prepared in accordance with SEC guidelines.
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 per share amounts)
|
|
|
|
|
June 30,
2023
|
|
December 31,
2022
|
|
|
(Unaudited)
|
|
|
|
ASSETS
|
|
|
|
|
Current
assets:
|
|
|
|
|
Cash and cash
equivalents
|
$
|
17,525
|
|
$
|
44,145
|
|
Accounts
receivable:
|
|
|
|
|
Trade, net
|
|
157,329
|
|
|
150,598
|
|
Joint interest,
net
|
|
86,615
|
|
|
54,697
|
|
Other, net
|
|
30,233
|
|
|
6,684
|
|
Assets from price risk
management activities
|
|
45,522
|
|
|
25,029
|
|
Prepaid
assets
|
|
85,697
|
|
|
84,759
|
|
Other current
assets
|
|
17,251
|
|
|
1,917
|
|
Total current
assets
|
|
440,172
|
|
|
367,829
|
|
Property and
equipment:
|
|
|
|
|
Proved
properties
|
|
7,526,625
|
|
|
5,964,340
|
|
Unproved properties,
not subject to amortization
|
|
401,710
|
|
|
154,783
|
|
Other property and
equipment
|
|
32,088
|
|
|
30,691
|
|
Total property and
equipment
|
|
7,960,423
|
|
|
6,149,814
|
|
Accumulated
depreciation, depletion and amortization
|
|
(3,822,916)
|
|
|
(3,506,539)
|
|
Total property and
equipment, net
|
|
4,137,507
|
|
|
2,643,275
|
|
Other long-term
assets:
|
|
|
|
|
Restricted
cash
|
|
100,973
|
|
|
—
|
|
Assets from price risk
management activities
|
|
8,655
|
|
|
7,854
|
|
Equity method
investments
|
|
22,436
|
|
|
1,745
|
|
Other well equipment
inventory
|
|
44,645
|
|
|
25,541
|
|
Notes receivable,
net
|
|
15,413
|
|
|
—
|
|
Operating lease
assets
|
|
18,104
|
|
|
5,903
|
|
Other
assets
|
|
17,508
|
|
|
6,479
|
|
Total
assets
|
$
|
4,805,413
|
|
$
|
3,058,626
|
|
LIABILITIES AND
STOCKHOLDERSʼ EQUITY
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
Accounts
payable
|
$
|
184,177
|
|
$
|
128,174
|
|
Accrued
liabilities
|
|
220,417
|
|
|
219,769
|
|
Accrued
royalties
|
|
51,248
|
|
|
52,215
|
|
Current portion of
long-term debt
|
|
33,156
|
|
|
—
|
|
Current portion of
asset retirement obligations
|
|
57,551
|
|
|
39,888
|
|
Liabilities from price
risk management activities
|
|
8,247
|
|
|
68,370
|
|
Accrued interest
payable
|
|
42,351
|
|
|
36,340
|
|
Current portion of
operating lease liabilities
|
|
3,136
|
|
|
1,943
|
|
Other current
liabilities
|
|
91,599
|
|
|
60,359
|
|
Total current
liabilities
|
|
691,882
|
|
|
607,058
|
|
Long-term
liabilities:
|
|
|
|
|
Long-term
debt
|
|
1,000,109
|
|
|
585,340
|
|
Asset retirement
obligations
|
|
741,501
|
|
|
501,773
|
|
Liabilities from price
risk management activities
|
|
1,417
|
|
|
7,872
|
|
Operating lease
liabilities
|
|
25,173
|
|
|
14,855
|
|
Other long-term
liabilities
|
|
283,443
|
|
|
176,152
|
|
Total
liabilities
|
|
2,743,525
|
|
|
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 June 30, 2023
and December 31, 2022
|
|
—
|
|
|
—
|
|
Common stock; $0.01
par value; 270,000,000 shares authorized; 127,455,965 and
82,570,328 shares
issued as of June 30,
2023 and December 31, 2022, respectively
|
|
1,275
|
|
|
826
|
|
Additional paid-in
capital
|
|
2,539,629
|
|
|
1,699,799
|
|
Accumulated
deficit
|
|
(431,512)
|
|
|
(535,049)
|
|
Treasury stock, at
cost; 3,400,000 and zero shares as of June 30, 2023 and December
31, 2022, respectively
|
|
(47,504)
|
|
|
—
|
|
Total stockholdersʼ
equity
|
|
2,061,888
|
|
|
1,165,576
|
|
Total liabilities
and stockholdersʼ equity
|
$
|
4,805,413
|
|
$
|
3,058,626
|
|
Talos Energy
Inc.
Consolidated
Statements of Operations
(In thousands,
except per common share amounts)
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
|
2023
|
|
2022
|
|
2023
|
|
2022
|
|
Revenues:
|
|
|
|
|
|
|
|
|
Oil
|
$
|
342,983
|
|
$
|
429,329
|
|
$
|
635,677
|
|
$
|
783,215
|
|
Natural gas
|
|
16,329
|
|
|
70,406
|
|
|
36,512
|
|
|
113,387
|
|
NGL
|
|
7,898
|
|
|
19,350
|
|
|
17,603
|
|
|
36,049
|
|
Total
revenues
|
|
367,210
|
|
|
519,085
|
|
|
689,792
|
|
|
932,651
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
Lease operating
expense
|
|
101,165
|
|
|
87,582
|
|
|
182,527
|
|
|
147,396
|
|
Production
taxes
|
|
607
|
|
|
864
|
|
|
1,213
|
|
|
1,715
|
|
Depreciation,
depletion and amortization
|
|
169,794
|
|
|
104,511
|
|
|
317,117
|
|
|
202,851
|
|
Accretion
expense
|
|
22,760
|
|
|
14,844
|
|
|
42,174
|
|
|
29,221
|
|
General and
administrative expense
|
|
33,182
|
|
|
22,925
|
|
|
96,369
|
|
|
45,453
|
|
Other operating
(income) expense
|
|
(723)
|
|
|
12,372
|
|
|
2,115
|
|
|
12,508
|
|
Total operating
expenses
|
|
326,785
|
|
|
243,098
|
|
|
641,515
|
|
|
439,144
|
|
Operating
income
|
|
40,425
|
|
|
275,987
|
|
|
48,277
|
|
|
493,507
|
|
Interest
expense
|
|
(45,632)
|
|
|
(30,776)
|
|
|
(83,213)
|
|
|
(62,266)
|
|
Price risk management
activities income (expense)
|
|
26,197
|
|
|
(64,094)
|
|
|
85,134
|
|
|
(345,313)
|
|
Equity method
investment income (expense)
|
|
(2,012)
|
|
|
13,466
|
|
|
5,431
|
|
|
13,608
|
|
Other
income
|
|
1,591
|
|
|
3,165
|
|
|
8,257
|
|
|
31,299
|
|
Net income before
income taxes
|
|
20,569
|
|
|
197,748
|
|
|
63,886
|
|
|
130,835
|
|
Income tax benefit
(expense)
|
|
(6,892)
|
|
|
(2,607)
|
|
|
39,651
|
|
|
(2,135)
|
|
Net
income
|
$
|
13,677
|
|
$
|
195,141
|
|
$
|
103,537
|
|
$
|
128,700
|
|
|
|
|
|
|
|
|
|
|
Net income per common
share:
|
|
|
|
|
|
|
|
|
Basic
|
$
|
0.11
|
|
$
|
2.36
|
|
$
|
0.90
|
|
$
|
1.56
|
|
Diluted
|
$
|
0.11
|
|
$
|
2.33
|
|
$
|
0.89
|
|
$
|
1.55
|
|
Weighted average common
shares outstanding:
|
|
|
|
|
|
|
|
|
Basic
|
|
125,436
|
|
|
82,566
|
|
|
115,590
|
|
|
82,320
|
|
Diluted
|
|
125,667
|
|
|
83,665
|
|
|
116,363
|
|
|
83,247
|
|
Talos Energy
Inc.
Consolidated
Statements of Cash Flows
(In
thousands)
|
|
|
|
|
Six Months Ended
June 30,
|
|
|
2023
|
|
2022
|
|
Cash flows from
operating activities:
|
|
|
|
|
Net income
|
$
|
103,537
|
|
$
|
128,700
|
|
Adjustments to
reconcile net income to net cash provided by operating
activities:
|
|
|
|
|
Depreciation,
depletion, amortization and accretion expense
|
|
359,291
|
|
|
232,072
|
|
Amortization of
deferred financing costs and original issue discount
|
|
7,629
|
|
|
6,952
|
|
Equity-based
compensation expense
|
|
8,687
|
|
|
7,367
|
|
Price risk management
activities expense (income)
|
|
(85,134)
|
|
|
345,313
|
|
Net cash paid on
settled derivative instruments
|
|
(4,161)
|
|
|
(287,321)
|
|
Equity method
investment income
|
|
(5,431)
|
|
|
(13,608)
|
|
Settlement of asset
retirement obligations
|
|
(47,683)
|
|
|
(39,768)
|
|
Loss on sale of
assets
|
|
—
|
|
|
390
|
|
Changes in operating
assets and liabilities:
|
|
|
|
|
Accounts
receivable
|
|
35,127
|
|
|
(57,394)
|
|
Other current
assets
|
|
(23,790)
|
|
|
(31,435)
|
|
Accounts
payable
|
|
(3,890)
|
|
|
23,360
|
|
Other current
liabilities
|
|
(22,975)
|
|
|
33,284
|
|
Other non-current
assets and liabilities, net
|
|
(44,124)
|
|
|
6,453
|
|
Net cash provided by
operating activities
|
|
277,083
|
|
|
354,365
|
|
Cash flows from
investing activities:
|
|
|
|
|
Exploration,
development and other capital expenditures
|
|
(298,658)
|
|
|
(128,082)
|
|
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
|
|
(8,488)
|
|
|
1,597
|
|
Contributions to
equity method investees
|
|
(15,260)
|
|
|
(2,250)
|
|
Proceeds from sale of
equity method investments
|
|
—
|
|
|
15,000
|
|
Investment in
intangible assets
|
|
(7,796)
|
|
|
—
|
|
Net cash used in
investing activities
|
|
(312,585)
|
|
|
(117,235)
|
|
Cash flows from
financing activities:
|
|
|
|
|
Redemption of senior
notes
|
|
(15,000)
|
|
|
(6,060)
|
|
Proceeds from Bank
Credit Facility
|
|
505,000
|
|
|
35,000
|
|
Repayment of Bank
Credit Facility
|
|
(305,000)
|
|
|
(210,000)
|
|
Deferred financing
costs
|
|
(11,775)
|
|
|
(129)
|
|
Other deferred
payments
|
|
(462)
|
|
|
—
|
|
Payments of finance
lease
|
|
(8,026)
|
|
|
(12,836)
|
|
Purchase of treasury
stock
|
|
(47,504)
|
|
|
—
|
|
Employee stock awards
tax withholdings
|
|
(7,378)
|
|
|
(4,476)
|
|
Net cash provided by
(used in) financing activities
|
|
109,855
|
|
|
(198,501)
|
|
|
|
|
|
|
Net increase in cash,
cash equivalents and restricted cash
|
|
74,353
|
|
|
38,629
|
|
Cash, cash equivalents
and restricted cash:
|
|
|
|
|
Balance, beginning of
period
|
|
44,145
|
|
|
69,852
|
|
Balance, end of
period
|
$
|
118,498
|
|
$
|
108,481
|
|
|
|
|
|
|
Supplemental non-cash
transactions:
|
|
|
|
|
Capital expenditures
included in accounts payable and accrued liabilities
|
$
|
113,319
|
|
$
|
47,354
|
|
Supplemental cash flow
information:
|
|
|
|
|
Interest paid, net of
amounts capitalized
|
$
|
63,492
|
|
$
|
47,570
|
|
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 "Upstream General and Administrative Expenses," "Adjusted Net
Income (Loss)," "Adjusted Earnings per Share," "EBITDA," "Adjusted
EBITDA," "Upstream Adjusted EBITDA," "Adjusted EBITDA excluding
hedges," "Upstream Adjusted EBITDA excluding hedges," "Adjusted
EBITDA Margin," "Upstream Adjusted EBITDA Margin," "Adjusted
EBITDA Margin excluding hedges," "Upstream Adjusted EBITDA Margin
excluding hedges," "Adjusted Free Cash Flow," "Net Debt," "LTM
Adjusted EBITDA," "Credit Facility LTM Adjusted EBITDA,", "Net Debt
to Pro Forma 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 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
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 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. Generally 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.
($
thousands)
|
Three Months
Ended
June 30,
2023
|
|
Reconciliation of
General & Administrative Expenses to Upstream General &
Administrative Expenses
(excluding non-cash
equity-based compensation):
|
|
|
Total General and
Administrative Expenses
|
$
|
33,182
|
|
CCS Segment
|
|
(2,445)
|
|
Unallocated
corporate
|
|
(1,836)
|
|
Non-cash equity-based
compensation expense
|
|
(3,907)
|
|
Upstream General &
Administrative Expenses (excluding non-cash equity-based
compensation)
|
$
|
24,994
|
|
Reconciliation of Net Income (Loss) to EBITDA, Adjusted
EBITDA and Upstream Adjusted EBITDA
"EBITDA," "Adjusted EBITDA" and "Upstream Adjusted EBITDA" are
to provide management and investors with (i) additional information
to evaluate, with certain adjustments, items required or permitted
in calculating covenant compliance under our debt agreements, (ii)
important supplemental indicators of the operational performance of
our business, (iii) additional criteria for evaluating our
performance relative to our peers and (iv) supplemental information
to investors about certain material non-cash and/or other items
that may not continue at the same level in the future. EBITDA and
Adjusted EBITDA have limitations as analytical tools and should not
be considered in isolation or as substitutes for analysis of our
results as reported under GAAP or as alternatives to net income
(loss), operating income (loss) or any other measure of financial
performance presented in accordance with GAAP. We define these as
the following:
EBITDA. Net income (loss) plus interest expense, income
tax expense (benefit), depreciation, depletion and amortization and
accretion expense.
Adjusted EBITDA. EBITDA plus non-cash write-down of oil
and natural gas properties, transaction and other (income)
expenses, decommissioning obligations, derivative fair value (gain)
loss, net cash receipts (payments) on settled derivatives, (gain)
loss on debt extinguishment, non-cash write-down of other well
equipment inventory and non-cash equity-based compensation
expense.
Adjusted EBITDA excluding hedges. We have historically
provided as a supplement to—rather than in lieu of—Adjusted EBITDA
including hedges, provides useful information regarding our results
of operations and profitability by illustrating the operating
results of our oil and natural gas properties without the benefit
or detriment, as applicable, of our financial oil and natural gas
hedges. By excluding our oil and natural gas hedges, we are able to
convey actual operating results using realized market prices during
the period, thereby providing analysts and investors with
additional information they can use to evaluate the impacts of our
hedging strategies over time.
Upstream Adjusted EBITDA. Adjusted EBITDA plus certain
CCS and corporate unallocated costs of equity method investment
loss, general and administrative expense, other operating income,
other income, and non-cash equity-based compensation expense.
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, Upstream Adjusted EBITDA, Adjusted EBITDA excluding
hedges, 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)
|
June 30,
2023
|
|
March 31,
2023
|
|
December 31,
2022
|
|
September 30,
2022
|
|
Reconciliation of Net
Income (Loss) to Adjusted EBITDA:
|
|
|
|
|
|
|
|
|
Net Income
|
$
|
13,677
|
|
$
|
89,860
|
|
$
|
2,750
|
|
$
|
250,465
|
|
Interest
expense
|
|
45,632
|
|
|
37,581
|
|
|
33,967
|
|
|
29,265
|
|
Income tax expense
(benefit)
|
|
6,892
|
|
|
(46,543)
|
|
|
281
|
|
|
121
|
|
Depreciation,
depletion and amortization
|
|
169,794
|
|
|
147,323
|
|
|
119,456
|
|
|
92,323
|
|
Accretion
expense
|
|
22,760
|
|
|
19,414
|
|
|
13,595
|
|
|
13,179
|
|
EBITDA
|
|
258,755
|
|
|
247,635
|
|
|
170,049
|
|
|
385,353
|
|
Transaction and other
(income) expenses(1)
|
|
3,513
|
|
|
22,009
|
|
|
4,343
|
|
|
3,219
|
|
Decommissioning
obligations(2)
|
|
741
|
|
|
741
|
|
|
21,005
|
|
|
20
|
|
Derivative fair value
(gain) loss(3)
|
|
(26,197)
|
|
|
(58,937)
|
|
|
41,058
|
|
|
(114,180)
|
|
Net cash received
(paid) on settled derivative instruments(3)
|
|
8,162
|
|
|
(12,323)
|
|
|
(57,076)
|
|
|
(81,162)
|
|
Loss on extinguishment
of debt
|
|
—
|
|
|
—
|
|
|
1,569
|
|
|
—
|
|
Non-cash equity-based
compensation expense
|
|
4,749
|
|
|
3,938
|
|
|
4,276
|
|
|
4,310
|
|
Adjusted
EBITDA
|
|
249,723
|
|
|
203,063
|
|
|
185,224
|
|
|
197,560
|
|
Add: Net cash
(received) paid on settled derivative
instruments(3)
|
|
(8,162)
|
|
|
12,323
|
|
|
57,076
|
|
|
81,162
|
|
Adjusted EBITDA
excluding hedges
|
$
|
241,561
|
|
$
|
215,386
|
|
$
|
242,300
|
|
$
|
278,722
|
|
Revenue:
|
|
|
|
|
|
|
|
|
Revenue -
Operations
|
|
367,210
|
|
|
322,582
|
|
|
342,201
|
|
|
377,128
|
|
Adjusted EBITDA margin
and Adjusted EBITDA excl hedges margin:
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
divided by - Total revenue incl hedges (%)
|
|
67
|
%
|
|
65
|
%
|
|
65
|
%
|
|
67
|
%
|
Adjusted EBITDA
divided by - Total revenue (%)
|
|
66
|
%
|
|
67
|
%
|
|
71
|
%
|
|
74
|
%
|
|
|
(1)
|
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 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
June 30,
2023
|
|
Reconciliation of
Adjusted EBITDA to Upstream Adjusted EBITDA:
|
|
|
Adjusted
EBITDA
|
$
|
249,723
|
|
CCS and Corporate
Unallocated Costs:
|
|
|
Equity method
investment loss
|
|
2,135
|
|
General and
administrative expense
|
|
4,279
|
|
Other operating
income
|
|
(1,654)
|
|
Other
income
|
|
(26)
|
|
Non-cash equity-based
compensation expense
|
|
(842)
|
|
Upstream Adjusted
EBITDA
|
|
253,615
|
|
Add: Net cash received
on settled derivative instruments(1)
|
|
(8,162)
|
|
Upstream Adjusted
EBITDA excluding hedges
|
$
|
245,453
|
|
Production:
|
|
|
Boe(2)
|
|
6,393
|
|
Upstream Adjusted
EBITDA margin and Upstream Adjusted EBITDA excl hedges
margin:
|
|
|
Upstream Adjusted
EBITDA per Boe(2)
|
$
|
39.67
|
|
Upstream Adjusted
EBITDA excl hedges per Boe(1)(2)
|
$
|
38.39
|
|
(1)
|
The adjustments for the
derivative fair value (gain) loss and net cash receipts (payments)
on settled derivative instruments have the effect of adjusting net
income (loss) for changes in the fair value of derivative
instruments, which are recognized at the end of each accounting
period because we do not designate commodity derivative instruments
as accounting hedges. This results in reflecting commodity
derivative gains and losses within Adjusted EBITDA on an unrealized
basis during the period the derivatives settled.
|
(2)
|
One Boe is equal to six
Mcf of natural gas or one Bbl of oil or NGLs based on an
approximate energy equivalency. This is an energy content
correlation and does not reflect a value or price relationship
between the commodities.
|
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 taxes in the period, therefore cash
taxes have no impact to the reported Adjusted Free Cash Flow before
changes in working capital number.
($
thousands)
|
Three Months
Ended
June 30,
2023
|
|
Reconciliation of
Adjusted EBITDA to Adjusted Free Cash Flow (before changes in
working capital)
|
|
|
Adjusted
EBITDA
|
$
|
249,723
|
|
Upstream capital
expenditures
|
|
(150,428)
|
|
Plugging &
abandonment
|
|
(37,570)
|
|
Decommissioning
obligations settled
|
|
(1,339)
|
|
CCS capital
expenditures
|
|
(1,868)
|
|
Interest
expense
|
|
(45,632)
|
|
Adjusted Free Cash Flow
(before changes in working capital)
|
$
|
12,886
|
|
($
thousands)
|
Three Months
Ended
June 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)
|
$
|
214,226
|
|
(Increase) decrease in
operating assets and liabilities
|
|
(53,358)
|
|
Upstream capital
expenditures(2)
|
|
(150,428)
|
|
Decommissioning
obligations settled
|
|
(1,339)
|
|
CCS capital
expenditures
|
|
(1,868)
|
|
Transaction and other
(income) expenses(3)
|
|
3,513
|
|
Decommissioning
obligations(4)
|
|
741
|
|
Amortization of
deferred financing costs and original issue discount
|
|
(3,481)
|
|
Income tax
benefit
|
|
6,892
|
|
Other
adjustments
|
|
(2,012)
|
|
Adjusted Free Cash Flow
(before changes in working capital)
|
$
|
12,886
|
|
|
|
(1)
|
Includes settlement of
asset retirement obligations.
|
(2)
|
Includes accruals and
excludes acquisitions.
|
(3)
|
For the three months
ended June 30, 2023, transaction expenses include $2.7 million in
costs related to the EnVen Acquisition, inclusive of $1.4 million
in severance expense. Other income (expenses) includes
miscellaneous income and expenses that we do not view as a
meaningful indicator of our operating performance.
|
(4)
|
Estimated
decommissioning obligations were a result of working interest
partners or counterparties of divestiture transactions that were
unable to perform the required abandonment obligations due to
bankruptcy or insolvency.
|
Reconciliation of Net Income to Adjusted Net Income (Loss)
and Adjusted Earnings per Share
"Adjusted Net Income (Loss)" and "Adjusted Earnings per Share"
are to provide management and investors with (i) important
supplemental indicators of the operational performance of our
business, (ii) additional criteria for evaluating our performance
relative to our peers and (iii) supplemental information to
investors about certain material non-cash and/or other items that
may not continue at the same level in the future. Adjusted Net
Income (Loss) and Adjusted Earnings per Share have limitations as
analytical tools and should not be considered in isolation or as a
substitute for analysis of our results as reported under GAAP or as
an alternative to net income (loss), operating income (loss),
earnings per share or any other measure of financial performance
presented in accordance with GAAP.
Adjusted Net Income (Loss). Net income (loss) plus
accretion expense, transaction related costs, derivative fair value
(gain) loss, net cash receipts (payments) on settled derivative
instruments and non-cash equity-based compensation expense.
Adjusted Earnings per Share. Adjusted Net Income (Loss)
divided by the number of common shares.
|
Three Months Ended
June 30, 2023
|
|
($ thousands, except
per share amounts)
|
|
|
Basic per
Share
|
|
Diluted per
Share
|
|
Reconciliation of Net
Income to Adjusted Net Loss:
|
|
|
|
|
|
|
Net Income
|
$
|
13,677
|
|
$
|
0.11
|
|
$
|
0.11
|
|
Transaction and other
(income) expenses(1)
|
|
3,513
|
|
$
|
0.03
|
|
$
|
0.03
|
|
Decommissioning
obligations(2)
|
|
741
|
|
$
|
0.01
|
|
$
|
0.01
|
|
Derivative fair value
gain(3)
|
|
(26,197)
|
|
$
|
(0.21)
|
|
$
|
(0.21)
|
|
Net cash received on
settled derivative instruments(3)
|
|
8,162
|
|
$
|
0.07
|
|
$
|
0.06
|
|
Non-cash income tax
expense
|
|
6,892
|
|
$
|
0.05
|
|
$
|
0.05
|
|
Non-cash equity-based
compensation expense
|
|
4,749
|
|
$
|
0.04
|
|
$
|
0.04
|
|
Adjusted Net
Income
|
$
|
11,537
|
|
$
|
0.09
|
|
$
|
0.09
|
|
|
|
|
|
|
|
|
Weighted average common
shares outstanding at June 30, 2023:
|
|
|
|
|
|
|
Basic
|
|
125,436
|
|
|
|
|
|
Diluted
|
|
125,667
|
|
|
|
|
|
|
|
(1)
|
For the three months
ended June 30, 2023, transaction expenses include $2.7 million in
costs related to the EnVen Acquisition, inclusive of $1.4 million
in severance expense. Other income (expense) includes other
miscellaneous income and expenses that we do not view as a
meaningful indicator of our operating performance.
|
(2)
|
Estimated
decommissioning obligations were a result of working interest
partners or counterparties of divestiture transactions that were
unable to perform the required abandonment obligations due to
bankruptcy or insolvency.
|
(3)
|
The adjustments for the
derivative fair value (gain) loss and net cash receipts (payments)
on settled derivative instruments have the effect of adjusting net
income (loss) for changes in the fair value of derivative
instruments, which are recognized at the end of each accounting
period because we do not designate commodity derivative instruments
as accounting hedges. This results in reflecting commodity
derivative gains and losses within Adjusted Net Income (Loss) on an
unrealized basis during the period the derivatives
settled.
|
Reconciliation of Total Debt to Net Debt and Net Debt to LTM
Adjusted EBITDA
We believe the presentation of Net Debt, LTM Adjusted EBITDA,
and Net Debt to LTM Adjusted EBITDA is important to provide
management and investors with additional important information to
evaluate our business. These measures are widely used by investors
and ratings agencies in the valuation, comparison, rating and
investment recommendations of companies.
Net Debt. Total Debt principal minus cash and cash
equivalents.
Net Debt to LTM Adjusted EBITDA. Net Debt divided by
the LTM Adjusted EBITDA.
($
thousands)
|
June 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
|
|
200,000
|
|
Total Debt
|
|
1,081,041
|
|
Less: Cash and cash
equivalents
|
|
(17,525)
|
|
Net Debt
|
$
|
1,063,516
|
|
|
|
|
Calculation of LTM
Adjusted EBITDA:
|
|
|
Adjusted EBITDA for
three months period ended September 30, 2022
|
$
|
197,560
|
|
Adjusted EBITDA for
three months period ended December 31, 2022
|
|
185,224
|
|
Adjusted EBITDA for
three months period ended March 31, 2023
|
|
203,063
|
|
Adjusted EBITDA for
three months period ended June 30, 2023
|
|
249,723
|
|
LTM Adjusted
EBITDA
|
$
|
835,570
|
|
|
|
|
Acquired Assets
Adjusted EBITDA:
|
|
|
Adjusted EBITDA for
three months period ended September 30, 2022
|
$
|
102,867
|
|
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
|
$
|
209,878
|
|
|
|
|
Pro Forma LTM Adjusted
EBITDA
|
$
|
1,045,448
|
|
|
|
|
Reconciliation of Net
Debt to Pro Forma LTM Adjusted EBITDA:
|
|
|
Net Debt / Pro Forma
LTM Adjusted EBITDA(1)
|
1.0x
|
|
|
|
(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
|
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SOURCE Talos Energy