HOUSTON, Feb. 28,
2024 /PRNewswire/ -- Talos Energy Inc. ("Talos" or
the "Company") (NYSE: TALO) today announced its operational and
financial results for fiscal quarter and full year ended
December 31, 2023. Talos also announced its year-end 2023
reserves estimates and the Company's 2024 operational and financial
guidance pro forma for the pending QuarterNorth acquisition.
Recent Highlights
- Fourth quarter 2023 production and full year 2023 production,
operating expenses, general and administrative expenses, and
capital expenditures all in-line or better than guidance.
- First production from Lime Rock and Venice projects was achieved ahead of schedule
at rates near the high end of expectations.
- Announced the $1.29 billion
acquisition of QuarterNorth Energy Inc. ("QuarterNorth"), which is
expected to close in March 2024.
- Refinanced approximately $865
million in 2026 notes, extending maturities to 2029 and 2031
and reducing interest costs on Talos's bonds by 275-300 basis
points.
2024 Guidance
- Production between 87.0 and 93.0 thousand barrels of oil
equivalent per day ("MBoe/d") (over 70% oil), assuming only nine
months of contributions from QuarterNorth. As a reference, actual
production from the combined asset base was approximately 99 MBoe/d
in the fourth quarter of 2023 and 106 MBoe/d in January 2024.
- Upstream capital expenditures, inclusive of QuarterNorth, of
$565 to $595
million, a reduction from Talos standalone 2023 levels.
- Evaluating a full range of strategic alternatives for the Talos
Low Carbon Solutions ("TLCS") subsidiary.
- Capital allocation framework focused on material debt reduction
and investment in key Upstream projects.
- Based on recent strip pricing, Talos is targeting year-end 2024
leverage of 1.0x or less, including acquisition debt incurred
offset by targeted debt paydown of approximately $400 million throughout the year from cash flow
generation, excluding any potential proceeds from TLCS.
Talos President and Chief
Executive Officer Timothy S. Duncan,
stated, "The fourth quarter and early 2024 provided several
examples of progress toward our goal of becoming a large-scale
offshore exploration and production company. We had a solid
operational fourth quarter, delivering 67.7 Mboe/d of oil-weighted
production, generating Upstream margins of approximately
$42 per barrel of oil equivalent. We
brought our Venice and Lime Rock
discoveries online ahead of schedule and near the high end of our
rate guidance, allowing us to enter 2024 with a strong production
rate. Through multiple tactical transactions, we laid the
groundwork for inventory expansion, consolidating leases and adding
acreage and prospects with high-quality partners. Finally, in
January we announced the QuarterNorth acquisition, which should
significantly grow our 2024 production, lower our corporate decline
rate, expand our inventory, and improve our margins."
Duncan continued, "Following the announcement of the
QuarterNorth transaction, we launched several capital markets
offerings, which reduced our financing rates and deferred bond
maturities to the end of the decade. In 2024, we expect
year-over-year production growth of approximately 35%-40%, while
capital expenditures are expected to be less than standalone 2023
levels, resulting in material expected free cash flow generation. I
am pleased about the trajectory of our business and look forward to
an exciting year."
RECENT DEVELOPMENTS AND OPERATIONS UPDATE
Exploration and Production Updates:
QuarterNorth Acquisition: In January 2024, Talos announced the acquisition of
QuarterNorth, a privately-held U.S. Gulf
of Mexico exploration and production company. The
transaction advances Talos's portfolio with valuable operated
infrastructure and oil-weighted deepwater assets that will grow our
production and provide attractive future development opportunities.
We expect the transaction to enhance Talos's financial performance
on key metrics, accelerate deleveraging and improve credit
strength. The transaction is currently expected to close in
March 2024.
Lime Rock and Venice: Talos successfully started
production from the Lime Rock and Venice discoveries in late 2023 ahead of
schedule and with early production rates near the high end of
expected ranges. Talos expects combined gross recoverable resources
of 20-30 MMBoe and owns a 60% working interest in both wells.
Exploration Updates: In December
2023, Talos executed agreements to consolidate acreage
across 15 deepwater blocks in the Green Canyon area. The
consolidation provides the ability to execute prospective drilling
opportunities more efficiently and includes several identified
prospects. Talos's participation is expected to be between 15% and
20%. Also in December 2023, Talos was
selected as a high bidder on 13 deepwater blocks in the latest
federal offshore lease sale. In November
2023, Talos and Repsol S.A. entered into a drilling joint
venture covering approximately 400,000 prospective gross acres. The
joint venture aims to identify future subsea tie-back prospects in
the area using Talos's Neptune facility as the host platform.
Joint Decommissioning Agreement: In February 2024, Talos and Helix Energy Solutions
Group, Inc. ("Helix") executed a five-year agreement in which Helix
will provide decommissioning services for offshore wells and
infrastructure, primarily on the U.S. Gulf of Mexico Shelf.
Decommissioning work under the agreement is expected to start in
the second quarter 2024.
TLCS Updates:
Seeking Strategic Alternatives: Talos is expanding its
capital raise process to include a full range of strategic
alternatives for its TLCS subsidiary, and will provide additional
updates as available. Talos intends to focus its capital allocation
in 2024 on maximizing free cash flow generation net of planned
Upstream investments and is primarily focused on debt reduction in
the near term.
Other CCS Updates: Bayou Bend CCS LLC commenced drilling
an offshore and an onshore stratigraphic well for carbon
sequestration in the first quarter 2024. Harvest Bend CCS LLC filed
and received administrative completeness status from the EPA for
two Class VI permit applications in late 2023.
FOURTH QUARTER AND FULL YEAR 2023 RESULTS
Key Financial Highlights:
($ thousands, except
per share amounts)
|
Three Months Ended
December 31, 2023
|
|
Twelve Months Ended
December 31, 2023
|
|
Total
revenues
|
$
|
384,959
|
|
$
|
1,457,886
|
|
Net Income
(Loss)
|
$
|
85,898
|
|
$
|
187,332
|
|
Net Income (Loss) per
diluted share
|
$
|
0.68
|
|
$
|
1.55
|
|
Adjusted Net Income
(Loss)*
|
$
|
(960)
|
|
$
|
27,887
|
|
Adjusted Net Income
(Loss) per diluted share*
|
$
|
(0.01)
|
|
$
|
0.23
|
|
Adjusted
EBITDA*
|
$
|
249,115
|
|
$
|
950,718
|
|
Adjusted EBITDA
excluding hedges*
|
$
|
248,098
|
|
$
|
960,175
|
|
Upstream Capital
Expenditures
|
$
|
148,109
|
|
$
|
596,470
|
|
Production
Production for the fourth quarter and full year 2023 was 67.7
MBoe/d (76% oil, 83% liquids), and 66.3 MBoe/d (75% oil, 82%
liquids), respectively.
|
Three Months
Ended
December 31, 2023
|
|
Twelve Months
Ended
December 31, 2023
|
|
Oil
(MBbl/d)
|
|
51.1
|
|
|
49.5
|
|
Natural Gas
(MMcf/d)
|
|
69.8
|
|
|
71.8
|
|
NGL
(MBbl/d)
|
|
4.9
|
|
|
4.8
|
|
Total average net daily
(MBoe/d)
|
|
67.7
|
|
|
66.3
|
|
|
Three Months Ended
December 31, 2023
|
|
|
Production
|
|
% Oil
|
|
% Liquids
|
|
% Operated
|
|
Green Canyon
Area
|
|
22.3
|
|
|
83
|
%
|
|
89
|
%
|
|
88
|
%
|
Mississippi Canyon
Area
|
|
32.3
|
|
|
79
|
%
|
|
87
|
%
|
|
75
|
%
|
Shelf and Gulf
Coast
|
|
13.1
|
|
|
55
|
%
|
|
63
|
%
|
|
60
|
%
|
Total average net daily
(MBoe/d)
|
|
67.7
|
|
|
76
|
%
|
|
83
|
%
|
|
76
|
%
|
|
Twelve Months Ended
December 31, 2023
|
|
|
Production
|
|
% Oil
|
|
% Liquids
|
|
% Operated
|
|
Green Canyon
Area
|
|
21.4
|
|
|
84
|
%
|
|
89
|
%
|
|
88
|
%
|
Mississippi Canyon
Area
|
|
31.8
|
|
|
79
|
%
|
|
87
|
%
|
|
71
|
%
|
Shelf and Gulf
Coast
|
|
13.1
|
|
|
50
|
%
|
|
58
|
%
|
|
60
|
%
|
Total average net daily
(MBoe/d)
|
|
66.3
|
|
|
75
|
%
|
|
82
|
%
|
|
74
|
%
|
Capital Expenditures
Upstream capital expenditures for the fourth quarter and full
year 2023, including plugging and abandonment and settled
decommissioning obligations, totaled $173.8
million, and $733.7 million
respectively.
($
thousands)
|
Three Months Ended
December 31, 2023
|
|
Twelve Months Ended
December 31, 2023
|
|
U.S. drilling &
completions
|
$
|
129,354
|
|
$
|
447,254
|
|
Mexico appraisal &
exploration
|
|
—
|
|
|
291
|
|
Asset
management(1)
|
|
2,293
|
|
|
83,970
|
|
Seismic and G&G,
land, capitalized G&A and other
|
|
16,462
|
|
|
64,955
|
|
Total Upstream Capital
Expenditures
|
|
148,109
|
|
|
596,470
|
|
Plugging &
Abandonment and Decommissioning Obligations
Settled(2)
|
|
25,687
|
|
|
137,199
|
|
Total
Upstream
|
$
|
173,796
|
|
$
|
733,669
|
|
__________________________________
|
(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 for the fourth quarter and full year 2023 totaled
$9.3 million, and $22.9 million, respectively, which is included in
Talos's reported Adjusted EBITDA* figure. CCS capital
expenditures for the fourth quarter and full year 2023 totaled
$3.8 million, and $41.0 million, respectively, which mainly
includes investments in Bayou Bend and funding for general ongoing
operations.
($
thousands)
|
Three Months
Ended
December 31, 2023
|
|
Twelve Months
Ended
December 31, 2023
|
|
CCS
Expenses
|
$
|
9,321
|
|
$
|
22,883
|
|
CCS Capital
Expenditures
|
|
3,778
|
|
|
40,961
|
|
Total CCS Costs
Incurred
|
$
|
13,099
|
|
$
|
63,844
|
|
Liquidity and Leverage
At December 31, 2023, Talos had
approximately $787.9 million of
liquidity, with $765.0 million
undrawn on its credit facility and approximately $33.6 million in cash, less approximately
$10.8 million in outstanding letters
of credit. On December 31, 2023, Talos had $1,066.0 million in total debt. Net
Debt* was $1,032.4
million. Net Debt to Pro Forma Last Twelve Months ("LTM")
Adjusted EBITDA* was 1.0x, inclusive of EnVen
pre-closing contributions to Adjusted EBITDA in early 2023, as
permitted by the terms of our Bank Credit Facility.
($
thousands)
|
|
December 31,
2023
|
|
Bank Credit
Facility-matures March 2027
|
$
|
200,000
|
|
12.00% Second-Priority
Senior Secured Notes -- due January 2026
|
|
638,541
|
|
11.75% Senior Secured
Second Lien Notes -- due April 2026
|
|
227,500
|
|
Total Debt
|
|
1,066,041
|
|
Less: Cash and cash
equivalents
|
|
(33,637)
|
|
Net Debt
|
$
|
1,032,404
|
|
On February 7, 2024, Talos
completed an upsized debt offering of $1,250.0 million in aggregate principal amount of
Second-Priority Senior Secured Notes, consisting of $625.0 million of 9.000% Second-Priority Senior
Secured Notes due 2029 and $625.0
million of 9.375% Second-Priority Senior Secured Notes due
2031. Talos used the net proceeds from the debt offering to fund
the redemption of all of the outstanding 12.00% Second-Priority
Senior Secured Notes due January 2026
and the 11.75% Senior Secured Second Lien Notes due April 2026.
The following table summarizes Talos's bonds outstanding as of
December 31, 2023 and pro forma for
the refinancing subsequent to year-end 2023.
($
thousands)
|
|
December 31,
2023
|
|
Pro Forma for
Refinancing
|
|
12.00% Second-Priority
Senior Secured Notes -- due January 2026
|
$
|
638,541
|
|
$
|
-
|
|
11.75% Senior Secured
Second Lien Notes -- due April 2026
|
|
227,500
|
|
|
-
|
|
New 9.000%
Second-Priority Senior Secured Notes -- due February
2029
|
|
-
|
|
|
625,000
|
|
New 9.375%
Second-Priority Senior Secured Notes -- due February
2031
|
|
-
|
|
|
625,000
|
|
Total Second Lien
Notes
|
$
|
866,041
|
|
$
|
1,250,000
|
|
Footnotes:
*See "Supplemental Non-GAAP Information" for details and
reconciliations of GAAP to non-GAAP financial measures.
HISTORICAL AND PRO FORMA YEAR-END 2023 RESERVES
SEC Reserves
As of December 31, 2023, Talos had
proved reserves of 152.8 MMBoe and, on a pro forma basis, including
assets expected to be acquired from QuarterNorth, would have had
proved reserves of 215.8 MMBoe. The Standardized Measure of Talos's
standalone reserves was approximately $3.0
billion and the PV-10 of Talos proved reserves was
approximately $3.5 billion. The PV-10
of pro forma proved reserves was approximately $5.1 billion. Talos's reserves and Talos's
QuarterNorth figures are prepared by Talos management and audited
by Netherland Sewell &
Associates ("NSAI"). All figures are fully burdened by and net of
all plugging and abandonment costs associated with the properties
included in the reserves report. The following tables summarize
proved reserves at December 31, 2023
based on SEC pricing of $78.21 per
barrel of oil and $2.64 per MMBtu of
natural gas. The acquisition of QuarterNorth is currently expected
to close in March 2024.
In addition to proved reserves, Talos's audited probable
reserves were 87.4 MMBoe and pro forma audited probable reserves
were 148.4 MMBoe with a corresponding PV-10 of approximately
$2.5 billion and $3.9 billion, respectively.
|
Pro Forma SEC
Reserves as of December 31, 2023(1)(2)(3)
|
|
|
MBoe
|
|
% of Total
Proved
|
|
% Oil
|
|
PV -10
(in thousands)
|
|
Proved Developed
Producing
|
|
128,674
|
|
|
60
|
%
|
|
76
|
%
|
$
|
4,214,100
|
|
Proved Developed
Non-Producing
|
|
42,661
|
|
|
20
|
%
|
|
65
|
%
|
|
438,256
|
|
Total Proved
Developed
|
|
171,335
|
|
|
79
|
%
|
|
73
|
%
|
|
4,652,356
|
|
Proved
Undeveloped
|
|
44,442
|
|
|
21
|
%
|
|
62
|
%
|
|
441,992
|
|
Total
Proved
|
|
215,778
|
|
|
100
|
%
|
|
71
|
%
|
$
|
5,094,348
|
|
Reserves Sensitivities
The following tables summarize the PV-10 values of Talos's
proved reserves at December 31, 2023, at various crude oil
prices and a flat $3.50 per MMBtu gas
price, except as noted below, inclusive of QuarterNorth.
|
Pro Forma Year-End
2023 Reserves Sensitivity (PV-10)
($000)(4)
|
|
|
$65
|
|
$75
|
|
SEC(2)
|
|
$85
|
|
$95
|
|
Proved Developed
Producing
|
$
|
3,300,092
|
|
$
|
4,078,540
|
|
$
|
4,214,100
|
|
$
|
4,866,048
|
|
$
|
5,653,819
|
|
Proved Developed
Non-Producing
|
|
193,174
|
|
|
401,457
|
|
|
438,256
|
|
|
608,591
|
|
|
804,670
|
|
Total Proved
Developed
|
|
3,493,266
|
|
|
4,479,997
|
|
|
4,652,356
|
|
|
5,474,640
|
|
|
6,458,489
|
|
Proved
Undeveloped
|
|
261,985
|
|
|
429,085
|
|
|
441,992
|
|
|
601,967
|
|
|
777,635
|
|
Total
Proved
|
$
|
3,755,252
|
|
$
|
4,909,082
|
|
$
|
5,094,348
|
|
$
|
6,076,607
|
|
$
|
7,236,124
|
|
(1)
|
This table summarizes
year end 2023 reserves of Talos and QuarterNorth collectively.
The acquisition of QuarterNorth cannot be guaranteed. In the event
the QuarterNorth acquisition is not completed, the reserve volumes
and associated figures presented above would be materially
reduced.
|
(2)
|
Reserves figures are
presented inclusive of the plugging and abandonment obligations and
before hedges, utilizing SEC pricing of $78.21 per barrel of oil
and $2.64 per MMBtu of natural gas.
|
(3)
|
PV-10 is a non-GAAP
financial measure and differs from the standardized measure of
discounted future net cash flows, which is the most directly
comparable GAAP financial measure. See "Supplemental Non-GAAP
Information" below for additional detail and reconciliations of
GAAP to non-GAAP measures, including a reconciliation of PV-10 of
our stand-alone proved reserves to the corresponding standardized
measure of discounted future net cash flows at December 31, 2023.
With respect to the pro forma PV-10 giving effect to our pending
acquisition, we are unable to reconcile to Standardized Measure
without unreasonable efforts. Similarly, PV-10 cannot be reconciled
to Standardized Measure for prices other than SEC pricing, because
GAAP does not prescribe any corresponding measure based on other
pricing, and accordingly it is not practicable to prepare any such
reconciliation.
|
(4)
|
Pro forma sensitivities
are based on Talos and QuarterNorth SEC reserves databases as of
December 31, 2023. Reserves volumes may fluctuate slightly based on
economic limitations.
|
2024 OPERATIONAL & FINANCIAL GUIDANCE
Talos intends to prioritize significant free cash flow
generation and the advancement of key Upstream projects expected to
drive future shareholder value creation in its 2024 operational and
financial plan, in addition to the integration of QuarterNorth.
Talos expects its level of capital investments in 2024, inclusive
of QuarterNorth, to be less than Talos standalone 2023 levels. This
is expected to result in an attractive reinvestment rate of 45%-50%
(excluding plugging and abandonment) and material cash flow
generation. Talos is targeting total debt reduction of
approximately $400 million and to end
2024 with a leverage ratio of 1.0x or less, inclusive of
acquisition debt incurred offset by debt paydown.
Talos's 2024 production guidance includes known and expected
deductions from baseline production of the assets, including 1)
only nine assumed months of QuarterNorth contributions (versus
twelve months pro forma), 2) expected planned downtime for facility
and downstream maintenance, including the Helix Producer I ("HP-I")
drydock and Katmai shut-in, among others, and 3) expected but
unplanned downtime for risking and weather-related events.
For the first quarter 2024, Talos expects average daily
production of 70.0 - 72.0 MBoe/d, which includes the impact of the
planned HP-1 dry-dock shut-in in March
2024 and does not include any contributions from
QuarterNorth. Talos's actual January
2024 standalone production was approximately 73.5 MBoe/d,
and preliminary standalone February
2024 production was approximately 75.0 MBoe/d.
The following summarizes key elements of Talos's 2024 production
guidance.
|
|
FY
2024
|
|
|
|
Low
|
|
High
|
|
Pro Forma Estimate
Before Known & Estimated Unplanned Reductions
|
|
105.0
|
|
|
110.0
|
|
Less: QuarterNorth
Partial Year Contribution
|
|
(8.3)
|
|
|
(8.0)
|
|
Less: Planned Downtime
Impacts
|
|
(5.8)
|
|
|
(5.5)
|
|
Less: Weather and
Unplanned Downtime Risking
|
|
(4.0)
|
|
|
(3.5)
|
|
Net Risked
Production Estimate (MBoe/d)
|
|
87.0
|
|
|
93.0
|
|
|
Note: Figures may not
sum due to rounding.
|
Cash operating expenses include a full twelve month impact of
EnVen, as compared to approximately ten and a half months in 2023,
and nine assumed months of QuarterNorth as well as approximately
$15 million related to the HP-1
drydock and other associated maintenance. This guidance also
includes the execution of multiple deepwater workover projects that
will increase and/or reinstate production. The following
summarizes Talos's full year 2024 operational and financial
guidance.
For more information, please refer to the Fourth Quarter 2023
Earnings Presentation available under Presentations and Filings on
the Investor Relations section of Talos's website.
|
|
FY
2024
|
|
($ Millions, unless
highlighted):
|
|
Low
|
|
High
|
|
Production
|
Oil (MMBbl)
|
|
23.0
|
|
|
24.0
|
|
|
Natural Gas
(Mcf)
|
|
38.0
|
|
|
44.0
|
|
|
NGL (MMBbl)
|
|
2.5
|
|
|
2.7
|
|
|
Total Production
(MMBoe)
|
|
31.8
|
|
|
34.0
|
|
|
Avg Daily Production
(MBoe/d)
|
|
87.0
|
|
|
93.0
|
|
Cash
Expenses
|
Cash Operating
Expenses(1)(2)(4)*
|
$
|
505
|
|
$
|
525
|
|
|
Workovers
|
$
|
45
|
|
$
|
55
|
|
|
G&A(2)(3)*
|
$
|
100
|
|
$
|
110
|
|
Capex
|
Upstream Capital
Expenditures(5)
|
$
|
565
|
|
$
|
595
|
|
P&A
Expenditures
|
P&A,
Decommissioning
|
$
|
90
|
|
$
|
100
|
|
Interest
|
Interest
Expense(6)
|
$
|
175
|
|
$
|
185
|
|
(1)
|
Includes Lease
Operating Expenses and Maintenance.
|
(2)
|
Includes insurance
costs.
|
(3)
|
Excludes non-cash
equity-based compensation.
|
(4)
|
Includes reimbursements
under production handling agreements.
|
(5)
|
Excludes
acquisitions.
|
(6)
|
Includes cash interest
expense on debt and finance lease, surety charges and amortization
of deferred financing costs and original issue
discounts.
|
|
*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 February 28,
2024. The table includes Talos volumes only and does not
include any associated derivative instruments assumed as part of
the QuarterNorth acquisition:
|
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)
|
|
January - March
2024
|
Fixed Swaps
|
|
19,363
|
|
$
|
74.06
|
|
---
|
|
---
|
|
---
|
|
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
|
|
25,500
|
|
$
|
74.06
|
|
---
|
|
---
|
|
---
|
|
April - June
2024
|
Collar
|
|
1,000
|
|
---
|
|
---
|
|
$
|
70.00
|
|
$
|
75.00
|
|
July - September
2024
|
Fixed Swaps
|
|
17,000
|
|
$
|
75.40
|
|
---
|
|
---
|
|
---
|
|
July - September
2024
|
Collar
|
|
1,000
|
|
---
|
|
---
|
|
$
|
70.00
|
|
$
|
75.00
|
|
October - December
2024
|
Fixed Swaps
|
|
19,000
|
|
$
|
74.46
|
|
---
|
|
---
|
|
---
|
|
October - December
2024
|
Collar
|
|
1,000
|
|
---
|
|
---
|
|
$
|
70.00
|
|
$
|
75.00
|
|
January - March
2025
|
Fixed Swaps
|
|
10,000
|
|
$
|
71.97
|
|
---
|
|
---
|
|
---
|
|
April - June
2025
|
Fixed Swaps
|
|
9,000
|
|
$
|
73.81
|
|
---
|
|
---
|
|
---
|
|
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)
|
|
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
|
|
15,000
|
|
$
|
3.35
|
|
---
|
|
---
|
|
---
|
|
October - December
2024
|
Collar
|
|
10,000
|
|
---
|
|
---
|
|
$
|
4.00
|
|
$
|
6.90
|
|
January - March
2025
|
Fixed Swaps
|
|
20,000
|
|
$
|
4.14
|
|
---
|
|
---
|
|
---
|
|
April - June
2025
|
Fixed Swaps
|
|
15,000
|
|
$
|
3.63
|
|
---
|
|
---
|
|
---
|
|
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 Thursday, February 29,
2024 at 10:00 AM Eastern Time
(9:00 AM Central Time). Listeners can
access the conference call through a webcast link on the Company's
website at:
https://www.talosenergy.com/investor-relations/events-calendar/default.aspx.
Alternatively, the conference call can be accessed by dialing (888)
348-8927 (U.S. toll-free), (855) 669-9657 (Canada toll-free) or (412) 902-4263
(international). Please dial in approximately 15 minutes before the
teleconference is scheduled to begin and ask to be joined into the
Talos Energy call. A replay of the call will be available one hour
after the conclusion of the conference until March 7, 2024 and can be accessed by dialing
(877) 344-7529 and using access code 2924676. For more information,
please refer to the Fourth Quarter 2023 Earnings Presentation
available under Presentations and Filings on the Investor Relations
section of Talos's website.
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 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 STATEMENT
The information in this communication includes "forward-looking
statements" within the meaning of Section 27A of the Securities Act
of 1933, as amended (the "Securities Act"), and Section 21E of the
Securities Exchange Act of 1934, as amended (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. These forward-looking
statements are based on our current believe, based on currently
available information, as to the outcome and timing of future
events. Forward-looking statements may include statements about:
risks related to the pending and future mergers and acquisitions,
such as the acquisition of QuarterNorth Energy Inc.
("QuarterNorth," and such transaction, the "QuarterNorth
Acquisition"), including the risk that we may fail to complete such
transaction on the terms contemplated or at all, and/or to realize
the expected benefits of any such transaction; business strategy;
recoverable resources, reserves and prospective storage resources;
drilling prospects, inventories, projects and programs; our ability
to replace the reserves that we produce 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 low carbon
solutions plans, including potential strategic alternatives;
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 oil, natural gas and NGLS; our integration of
acquisitions, including the QuarterNorth Acquisition, 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 and acts of terrorism or sabotage; credit
markets; volatility in the political, legal and regulatory
environments ahead of the upcoming domestic and foreign
presidential elections; 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 low carbon solutions business,
including as a result of any development opportunities, permitting,
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 in
our low carbon solutions 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. These 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 Israel and the Middle East, and their impact on commodity
markets; the impact of any pandemic and governmental measures
related thereto; lack of transportation and storage capacity as a
result of oversupply, government and regulations; the effect of a
possible U.S. government shutdown and resulting impact on economic
conditions and delays in regulatory and permitting approvals; 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 central bank 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 "Risk Factors" of our Annual Report on Form 10-K for
the year ended December 31, 2023
filed with the SEC. 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.
PRODUCTION ESTIMATES
Estimates for our future production volumes are based on
assumptions of capital expenditure levels and the assumption that
market demand and prices for oil and gas will continue at levels
that allow for economic production of these products. The
production, transportation, marketing and storage of oil and gas
are subject to disruption due to transportation, processing and
storage availability, mechanical failure, human error, adverse
weather conditions such as hurricanes, global political and
macroeconomic events and numerous other factors. Our estimates are
based on certain other assumptions, such as well performance, which
may vary significantly from those assumed. Therefore, we can give
no assurance that our future production volumes will be as
estimated.
RESERVE INFORMATION
Reserve engineering is a process of estimating underground
accumulations of oil, natural gas and NGLs that cannot be measured
in an exact way. The accuracy of any reserve estimate depends on
the quality of available data, the interpretation of such data and
price and cost assumptions made by reserve engineers. In addition,
the results of drilling, testing and production activities may
justify 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. Certain reserve estimates herein were prepared based on
specified management price parameters as indicated herein. These
specified prices reflect what we believe to be reasonable
assumptions as to average future commodity prices over the
productive lives of our properties and those to be acquired from
QuarterNorth. However, we caution you that the pricing used is not
a projection of future oil and natural gas prices, and should be
carefully considered in addition to, and not as a substitute for,
SEC prices, when considering our oil, natural gas and NGL
reserves.
USE OF NON-GAAP FINANCIAL MEASURES
This release includes the use of certain measures that have not
been calculated in accordance with U.S. generally acceptable
accounting principles (GAAP) such as, but not limited to, EBITDA,
Adjusted EBITDA, PV-10, LTM Adjusted EBITDA, Pro Forma LTM Adjusted
EBITDA, Net Debt, Net Debt/LTM Adjusted EBITDA, Net Debt/Pro Forma
LTM Adjusted EBITDA, Adjusted Free Cash Flow and Leverage. Non-GAAP
financial measures 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. Reconciliations for non-GAAP
measure to GAAP measures are included at the end of this
release.
Talos Energy
Inc.
Consolidated Balance
Sheets
(In thousands,
except share amounts)
|
|
|
Year Ended
December 31,
|
|
|
2023
|
|
2022
|
|
ASSETS
|
|
|
|
|
Current
assets:
|
|
|
|
|
Cash and cash
equivalents
|
$
|
33,637
|
|
$
|
44,145
|
|
Accounts
receivable:
|
|
|
|
|
Trade, net
|
|
178,977
|
|
|
150,598
|
|
Joint interest,
net
|
|
79,337
|
|
|
54,697
|
|
Other, net
|
|
19,296
|
|
|
6,684
|
|
Assets from price risk
management activities
|
|
36,152
|
|
|
25,029
|
|
Prepaid
assets
|
|
64,387
|
|
|
84,759
|
|
Other current
assets
|
|
10,389
|
|
|
1,917
|
|
Total current
assets
|
|
422,175
|
|
|
367,829
|
|
Property and
equipment:
|
|
|
|
|
Proved
properties
|
|
7,906,295
|
|
|
5,964,340
|
|
Unproved properties,
not subject to amortization
|
|
268,315
|
|
|
154,783
|
|
Other property and
equipment
|
|
34,027
|
|
|
30,691
|
|
Total property and
equipment
|
|
8,208,637
|
|
|
6,149,814
|
|
Accumulated
depreciation, depletion and amortization
|
|
(4,168,328)
|
|
|
(3,506,539)
|
|
Total property and
equipment, net
|
|
4,040,309
|
|
|
2,643,275
|
|
Other long-term
assets:
|
|
|
|
|
Restricted
cash
|
|
102,362
|
|
|
—
|
|
Assets from price risk
management activities
|
|
17,551
|
|
|
7,854
|
|
Equity method
investments
|
|
146,049
|
|
|
1,745
|
|
Other well
equipment
|
|
54,277
|
|
|
25,541
|
|
Notes receivable,
net
|
|
16,207
|
|
|
—
|
|
Operating lease
assets
|
|
11,418
|
|
|
5,903
|
|
Other
assets
|
|
5,961
|
|
|
6,479
|
|
Total
assets
|
$
|
4,816,309
|
|
$
|
3,058,626
|
|
LIABILITIES AND
STOCKHOLDERSʼ EQUITY
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
Accounts
payable
|
$
|
84,193
|
|
$
|
128,174
|
|
Accrued
liabilities
|
|
227,690
|
|
|
219,769
|
|
Accrued
royalties
|
|
55,051
|
|
|
52,215
|
|
Current portion of
long-term debt
|
|
33,060
|
|
|
—
|
|
Current portion of
asset retirement obligations
|
|
77,581
|
|
|
39,888
|
|
Liabilities from price
risk management activities
|
|
7,305
|
|
|
68,370
|
|
Accrued interest
payable
|
|
42,300
|
|
|
36,340
|
|
Current portion of
operating lease liabilities
|
|
2,666
|
|
|
1,943
|
|
Other current
liabilities
|
|
48,769
|
|
|
60,359
|
|
Total current
liabilities
|
|
578,615
|
|
|
607,058
|
|
Long-term
liabilities:
|
|
|
|
|
Long-term
debt
|
|
992,614
|
|
|
585,340
|
|
Asset retirement
obligations
|
|
819,645
|
|
|
501,773
|
|
Liabilities from price
risk management activities
|
|
795
|
|
|
7,872
|
|
Operating lease
liabilities
|
|
18,211
|
|
|
14,855
|
|
Other long-term
liabilities
|
|
251,278
|
|
|
176,152
|
|
Total
liabilities
|
|
2,661,158
|
|
|
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 December 31, 2023 and 2022,
respectively
|
|
—
|
|
|
—
|
|
Common stock; $0.01
par value; 270,000,000 shares authorized; 127,480,361 and
82,570,328 shares issued as of December 31, 2023 and 2022,
respectively
|
|
1,275
|
|
|
826
|
|
Additional paid-in
capital
|
|
2,549,097
|
|
|
1,699,799
|
|
Accumulated
deficit
|
|
(347,717)
|
|
|
(535,049)
|
|
Treasury stock, at
cost; 3,400,000 and zero shares as of December 31, 2023 and 2022,
respectively
|
|
(47,504)
|
|
|
—
|
|
Total stockholdersʼ
equity
|
|
2,155,151
|
|
|
1,165,576
|
|
Total liabilities
and stockholdersʼ equity
|
$
|
4,816,309
|
|
$
|
3,058,626
|
|
Talos Energy
Inc.
Consolidated
Statements of Operations
(In thousands,
except per share amounts)
|
|
|
Three Months Ended
December 31,
|
|
Twelve Months Ended
December 31,
|
|
|
2023
|
|
2022
|
|
2023
|
|
2022
|
|
Revenues:
|
|
|
|
|
|
|
|
|
Oil
|
$
|
362,651
|
|
$
|
286,348
|
|
$
|
1,357,732
|
|
$
|
1,365,148
|
|
Natural gas
|
|
14,651
|
|
|
45,559
|
|
|
68,034
|
|
|
227,306
|
|
NGL
|
|
7,657
|
|
|
10,294
|
|
|
32,120
|
|
|
59,526
|
|
Total
revenues
|
|
384,959
|
|
|
342,201
|
|
|
1,457,886
|
|
|
1,651,980
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
Lease operating
expense
|
|
103,546
|
|
|
78,936
|
|
|
389,621
|
|
|
308,092
|
|
Production
taxes
|
|
638
|
|
|
818
|
|
|
2,451
|
|
|
3,488
|
|
Depreciation,
depletion and amortization
|
|
183,058
|
|
|
119,456
|
|
|
663,534
|
|
|
414,630
|
|
Accretion
expense
|
|
22,722
|
|
|
13,595
|
|
|
86,152
|
|
|
55,995
|
|
General and
administrative expense
|
|
37,236
|
|
|
29,012
|
|
|
158,493
|
|
|
99,754
|
|
Other operating
(income) expense
|
|
3,017
|
|
|
21,760
|
|
|
(52,155)
|
|
|
33,902
|
|
Total operating
expenses
|
|
350,217
|
|
|
263,577
|
|
|
1,248,096
|
|
|
915,861
|
|
Operating income
(expense)
|
|
34,742
|
|
|
78,624
|
|
|
209,790
|
|
|
736,119
|
|
Interest
expense
|
|
(44,295)
|
|
|
(33,967)
|
|
|
(173,145)
|
|
|
(125,498)
|
|
Price risk management
activities income (expense)
|
|
94,596
|
|
|
(41,058)
|
|
|
80,928
|
|
|
(272,191)
|
|
Equity method
investment income (expense)
|
|
(6,147)
|
|
|
(377)
|
|
|
(3,209)
|
|
|
14,222
|
|
Other income
(expense)
|
|
1,921
|
|
|
(191)
|
|
|
12,371
|
|
|
31,800
|
|
Net income (loss)
before income taxes
|
|
80,817
|
|
|
3,031
|
|
|
126,735
|
|
|
384,452
|
|
Income tax benefit
(expense)
|
|
5,081
|
|
|
(281)
|
|
|
60,597
|
|
|
(2,537)
|
|
Net income
(loss)
|
$
|
85,898
|
|
$
|
2,750
|
|
$
|
187,332
|
|
$
|
381,915
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per
common share:
|
|
|
|
|
|
|
|
|
Basic
|
$
|
0.69
|
|
$
|
0.03
|
|
$
|
1.56
|
|
$
|
4.63
|
|
Diluted
|
$
|
0.69
|
|
$
|
0.03
|
|
$
|
1.55
|
|
$
|
4.56
|
|
Weighted average common
shares outstanding:
|
|
|
|
|
|
|
|
|
Basic
|
|
124,150
|
|
|
82,597
|
|
|
119,894
|
|
|
82,454
|
|
Diluted
|
|
125,173
|
|
|
84,418
|
|
|
120,752
|
|
|
83,683
|
|
Talos Energy
Inc.
Consolidated
Statements of Cash Flows
(In
thousands)
|
|
|
Year Ended
December 31,
|
|
|
2023
|
|
2022
|
|
2021
|
|
Cash flows from
operating activities:
|
|
|
|
|
|
|
Net income
(loss)
|
$
|
187,332
|
|
$
|
381,915
|
|
$
|
(182,952)
|
|
Adjustments to
reconcile net income (loss) to net cash provided by (used in)
operating activities
|
|
|
|
|
|
|
Depreciation,
depletion, amortization and accretion expense
|
|
749,686
|
|
|
470,625
|
|
|
454,123
|
|
Write-down of oil and
natural gas properties and other well equipment
|
|
—
|
|
|
—
|
|
|
23,729
|
|
Amortization of
discount, premium and deferred financing costs
|
|
15,039
|
|
|
14,379
|
|
|
13,382
|
|
Equity-based
compensation expense
|
|
12,953
|
|
|
15,953
|
|
|
10,992
|
|
Price risk management
activities (income) expense
|
|
(80,928)
|
|
|
272,191
|
|
|
419,077
|
|
Net cash received
(paid) on settled derivative instruments
|
|
(9,457)
|
|
|
(425,559)
|
|
|
(290,164)
|
|
Equity method
investment (income) expense
|
|
3,209
|
|
|
(14,222)
|
|
|
—
|
|
Loss (gain) on
extinguishment of debt
|
|
—
|
|
|
1,569
|
|
|
13,225
|
|
Settlement of asset
retirement obligations
|
|
(86,615)
|
|
|
(69,596)
|
|
|
(67,988)
|
|
Gain (loss) on sale of
assets
|
|
(66,115)
|
|
|
303
|
|
|
(687)
|
|
Changes in operating
assets and liabilities:
|
|
|
|
|
|
|
Accounts
receivable
|
|
20,352
|
|
|
14,927
|
|
|
(35,396)
|
|
Other current
assets
|
|
7,066
|
|
|
(36,545)
|
|
|
(18,901)
|
|
Accounts
payable
|
|
(60,401)
|
|
|
24,258
|
|
|
(6,261)
|
|
Other current
liabilities
|
|
(96,960)
|
|
|
73,531
|
|
|
64,800
|
|
Other non-current
assets and liabilities, net
|
|
(76,092)
|
|
|
(13,990)
|
|
|
14,409
|
|
Net cash provided by
(used in) operating activities
|
|
519,069
|
|
|
709,739
|
|
|
411,388
|
|
Cash flows from
investing activities:
|
|
|
|
|
|
|
Exploration,
development and other capital expenditures
|
|
(561,434)
|
|
|
(323,164)
|
|
|
(293,331)
|
|
Proceeds from (cash
paid for) acquisitions, net of cash acquired
|
|
17,617
|
|
|
(3,500)
|
|
|
(5,399)
|
|
Proceeds from (cash
paid for) sale of property and equipment, net
|
|
73,004
|
|
|
1,937
|
|
|
4,983
|
|
Contributions to
equity method investees
|
|
(29,447)
|
|
|
(2,250)
|
|
|
—
|
|
Investment in
intangible assets
|
|
(12,366)
|
|
|
—
|
|
|
—
|
|
Proceeds from sale of
equity method investment
|
|
—
|
|
|
15,000
|
|
|
—
|
|
Net cash provided by
(used in) investing activities
|
|
(512,626)
|
|
|
(311,977)
|
|
|
(293,747)
|
|
Cash flows from
financing activities:
|
|
|
|
|
|
|
Issuance of senior
notes
|
|
—
|
|
|
—
|
|
|
600,500
|
|
Redemption of senior
notes
|
|
(30,000)
|
|
|
(18,184)
|
|
|
(356,803)
|
|
Proceeds from Bank
Credit Facility
|
|
825,000
|
|
|
85,000
|
|
|
100,000
|
|
Repayment of Bank
Credit Facility
|
|
(625,000)
|
|
|
(460,000)
|
|
|
(365,000)
|
|
Deferred financing
costs
|
|
(11,775)
|
|
|
(189)
|
|
|
(27,833)
|
|
Other deferred
payments
|
|
(1,545)
|
|
|
—
|
|
|
(7,921)
|
|
Payments of finance
lease
|
|
(16,306)
|
|
|
(25,493)
|
|
|
(21,804)
|
|
Purchase of treasury
stock
|
|
(47,504)
|
|
|
—
|
|
|
—
|
|
Employee stock awards
tax withholdings
|
|
(7,459)
|
|
|
(4,603)
|
|
|
(3,161)
|
|
Net cash provided by
(used in) financing activities
|
|
85,411
|
|
|
(423,469)
|
|
|
(82,022)
|
|
|
|
|
|
|
|
|
Net increase (decrease)
in cash, cash equivalents and restricted cash
|
|
91,854
|
|
|
(25,707)
|
|
|
35,619
|
|
Cash, cash equivalents
and restricted cash:
|
|
|
|
|
|
|
Balance, beginning of
period
|
|
44,145
|
|
|
69,852
|
|
|
34,233
|
|
Balance, end of
period
|
$
|
135,999
|
|
$
|
44,145
|
|
$
|
69,852
|
|
|
|
|
|
|
|
|
Supplemental non-cash
transactions:
|
|
|
|
|
|
|
Capital expenditures
included in accounts payable and accrued liabilities
|
$
|
114,972
|
|
$
|
105,773
|
|
$
|
45,761
|
|
Supplemental cash flow
information:
|
|
|
|
|
|
|
Interest paid, net of
amounts capitalized
|
$
|
130,313
|
|
$
|
91,809
|
|
$
|
68,891
|
|
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 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, $/Boe and percentage data):
($
thousands)
|
Three Months
Ended
December 31, 2023
|
|
Twelve Months
Ended
December 31, 2023
|
|
Reconciliation of
Net Income (Loss) to Adjusted EBITDA:
|
|
|
|
|
Net Income
(loss)
|
$
|
85,898
|
|
$
|
187,332
|
|
Interest
expense
|
|
44,295
|
|
|
173,145
|
|
Income tax expense
(benefit)
|
|
(5,081)
|
|
|
(60,597)
|
|
Depreciation,
depletion and amortization
|
|
183,058
|
|
|
663,534
|
|
Accretion
expense
|
|
22,722
|
|
|
86,152
|
|
EBITDA
|
|
330,892
|
|
|
1,049,566
|
|
Transaction and other
(income) expenses(1)
|
|
5,504
|
|
|
(33,295)
|
|
Decommissioning
obligations(2)
|
|
2,425
|
|
|
11,879
|
|
Derivative fair value
(gain) loss(3)
|
|
(94,596)
|
|
|
(80,928)
|
|
Net cash received
(paid) on settled derivative instruments(3)
|
|
1,017
|
|
|
(9,457)
|
|
Non-cash equity-based
compensation expense
|
|
3,873
|
|
|
12,953
|
|
Adjusted
EBITDA
|
|
249,115
|
|
|
950,718
|
|
Add: Net cash
(received) paid on settled derivative
instruments(3)
|
|
(1,017)
|
|
|
9,457
|
|
Adjusted EBITDA
excluding hedges
|
$
|
248,098
|
|
$
|
960,175
|
|
_________________________________
|
(1)
|
Transaction expenses
includes $40.4 million in costs related to the EnVen
Acquisition, inclusive of $25.3 million and nil in severance
expenses for the twelve months ended December 31, 2023,
respectively. Other income (expense) includes restructuring
expenses, cost saving initiatives and other miscellaneous income
and expenses that we do not view as a meaningful indicator of our
operating performance. For the twelve months ended December 31,
2023, the amount includes a $66.2 million gain on the Mexico
Divestiture. The amount includes a gain on the funding of the
capital carry of our investment in Bayou Bend by Chevron of $8.6
million for the twelve months ended December 31, 2023.
|
(2)
|
Estimated
decommissioning obligations were a result of working interest
partners or counterparties of divestiture transactions that were
unable to perform the required abandonment obligations due to
bankruptcy or insolvency and are included in "Other operating
(income) expense" on our consolidated statements of
operations.
|
(3)
|
The adjustments for the
derivative fair value (gain) loss and net cash receipts (payments)
on settled derivative instruments have the effect of adjusting net
income (loss) for changes in the fair value of derivative
instruments, which are recognized at the end of each accounting
period because we do not designate commodity derivative instruments
as accounting hedges. This results in reflecting commodity
derivative gains and losses within Adjusted EBITDA on an unrealized
basis during the period the derivatives settled.
|
($ thousands, except
per BOE amounts)
|
Three Months
Ended
December 31, 2023
|
|
Twelve Months
Ended
December 31, 2023
|
|
Reconciliation of
Adjusted EBITDA to Upstream Adjusted EBITDA:
|
|
|
|
|
Adjusted
EBITDA
|
$
|
249,115
|
|
$
|
950,718
|
|
CCS and Corporate
Unallocated Costs:
|
|
|
|
|
Equity method
investment loss
|
|
5,894
|
|
|
3,329
|
|
General and
administrative expense
|
|
6,519
|
|
|
19,466
|
|
Other operating
expense
|
|
(93)
|
|
|
300
|
|
Other
income
|
|
(6)
|
|
|
(5,069)
|
|
Transaction and other
income (expenses)(1)
|
|
(336)
|
|
|
13,142
|
|
Non-cash equity-based
compensation expense
|
|
(690)
|
|
|
(2,157)
|
|
Upstream Adjusted
EBITDA
|
|
260,403
|
|
|
979,729
|
|
Add: Net cash paid on
settled derivative instruments(2)
|
|
(1,017)
|
|
|
9,457
|
|
Upstream Adjusted
EBITDA excluding hedges
|
$
|
259,386
|
|
$
|
989,186
|
|
Production:
|
|
|
|
|
Boe(3)
|
|
6,224
|
|
|
24,195
|
|
Upstream Adjusted
EBITDA margin and Upstream Adjusted EBITDA excl hedges
margin:
|
|
|
|
|
Upstream Adjusted
EBITDA per Boe(3)
|
$
|
41.84
|
|
$
|
40.49
|
|
Upstream Adjusted
EBITDA excl hedges per Boe(2)(3)
|
$
|
41.68
|
|
$
|
40.88
|
|
______________________________________
|
(1)
|
Other income (expense)
includes restructuring expenses, cost saving initiatives and other
miscellaneous income and expenses that we do not view as a
meaningful indicator of our operating performance. The amount
includes a gain on the funding of the capital carry of our
investment in Bayou Bend by Chevron of $8.6 million for the twelve
months ended December 31, 2023.
|
(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
December 31, 2023
|
|
Twelve Months
Ended
December 31, 2023
|
|
Reconciliation of
Adjusted EBITDA to Adjusted Free Cash Flow (before changes in
working capital):
|
|
|
|
|
Adjusted
EBITDA
|
$
|
249,115
|
|
$
|
950,718
|
|
Upstream capital
expenditures
|
|
(148,109)
|
|
|
(596,470)
|
|
Plugging &
abandonment
|
|
(15,518)
|
|
|
(86,615)
|
|
Decommissioning
obligations settled
|
|
(10,169)
|
|
|
(50,584)
|
|
CCS capital
expenditures
|
|
(3,778)
|
|
|
(40,961)
|
|
Interest
expense
|
|
(44,295)
|
|
|
(173,145)
|
|
Adjusted Free Cash Flow
(before changes in working capital)
|
$
|
27,246
|
|
$
|
2,943
|
|
|
($
thousands)
|
Three Months Ended
December 31, 2023
|
|
Twelve Months Ended
December 31, 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)
|
$
|
176,258
|
|
$
|
519,069
|
|
(Increase) decrease in
operating assets and liabilities
|
|
20,135
|
|
|
206,035
|
|
Upstream capital
expenditures(2)
|
|
(148,109)
|
|
|
(596,470)
|
|
Decommissioning
obligations settled
|
|
(10,169)
|
|
|
(50,584)
|
|
CCS capital
expenditures
|
|
(3,778)
|
|
|
(40,961)
|
|
Transaction and other
(income) expenses(3)
|
|
5,817
|
|
|
41,786
|
|
Decommissioning
obligations(4)
|
|
2,425
|
|
|
11,879
|
|
Amortization of
deferred financing costs and original issue discount
|
|
(3,792)
|
|
|
(15,039)
|
|
Income tax
benefit
|
|
(5,081)
|
|
|
(60,597)
|
|
Other
adjustments
|
|
(6,460)
|
|
|
(12,175)
|
|
Adjusted Free Cash Flow
(before changes in working capital)
|
$
|
27,246
|
|
$
|
2,943
|
|
______________________________
|
(1)
|
Includes settlement of
asset retirement obligations.
|
(2)
|
Includes accruals and
excludes acquisitions.
|
(3)
|
Transaction expenses
includes $40.4 million in costs related to the EnVen Acquisition,
inclusive of $25.3 million and nil in severance expenses for the
twelve months ended December 31, 2023, respectively. Other income
(expense) includes restructuring expenses, cost saving initiatives
and other miscellaneous income and expenses that we do not view as
a meaningful indicator of our operating performance. For the twelve
months ended December 31, 2023, the amount includes a $66.2 million
gain on the Mexico Divestiture. The amount includes a gain on the
funding of the capital carry of our investment in Bayou Bend by
Chevron of $8.6 million for the twelve months ended December 31,
2023.
|
(4)
|
Estimated
decommissioning obligations were a result of working interest
partners or counterparties of divestiture transactions that were
unable to perform the required abandonment obligations due to
bankruptcy or insolvency.
|
Reconciliation of Net Income to Adjusted Net Income (Loss)
and Adjusted Earnings per Share
"Adjusted Net Income (Loss)" and "Adjusted Earnings per Share"
are to provide management and investors with (i) important
supplemental indicators of the operational performance of our
business, (ii) additional criteria for evaluating our performance
relative to our peers and (iii) supplemental information to
investors about certain material non-cash and/or other items that
may not continue at the same level in the future. Adjusted Net
Income (Loss) and Adjusted Earnings per Share have limitations as
analytical tools and should not be considered in isolation or as a
substitute for analysis of our results as reported under GAAP or as
an alternative to net income (loss), operating income (loss),
earnings per share or any other measure of financial performance
presented in accordance with GAAP.
Adjusted Net Income (Loss). Net income (loss) plus
accretion expense, transaction related costs, derivative fair value
(gain) loss, net cash receipts (payments) on settled derivative
instruments and non-cash equity-based compensation expense.
Adjusted Earnings per Share. Adjusted Net Income (Loss)
divided by the number of common shares.
|
Three Months Ended
December 31, 2023
|
|
Twelve Months Ended
December 31, 2023
|
|
($ thousands, except
per share amounts)
|
|
|
Basic per
Share
|
|
Diluted per
Share
|
|
|
|
Basic per
Share
|
|
Diluted per
Share
|
|
Reconciliation of
Net Income (Loss) to Adjusted Net Income (Loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
(loss)
|
$
|
85,898
|
|
$
|
0.69
|
|
$
|
0.68
|
|
$
|
187,332
|
|
$
|
1.56
|
|
$
|
1.55
|
|
Transaction and other
(income) expenses(1)
|
|
5,504
|
|
$
|
0.04
|
|
$
|
0.04
|
|
|
(33,295)
|
|
$
|
(0.28)
|
|
$
|
(0.28)
|
|
Decommissioning
obligations(2)
|
|
2,425
|
|
$
|
0.02
|
|
$
|
0.02
|
|
|
11,879
|
|
$
|
0.10
|
|
$
|
0.10
|
|
Derivative fair value
loss(3)
|
|
(94,596)
|
|
$
|
(0.76)
|
|
$
|
(0.75)
|
|
|
(80,928)
|
|
$
|
(0.67)
|
|
$
|
(0.67)
|
|
Net cash received on
paid derivative instruments(3)
|
|
1,017
|
|
$
|
0.01
|
|
$
|
0.01
|
|
|
(9,457)
|
|
$
|
(0.08)
|
|
$
|
(0.08)
|
|
Non-cash income tax
benefit
|
|
(5,081)
|
|
$
|
(0.04)
|
|
$
|
(0.04)
|
|
|
(60,597)
|
|
$
|
(0.51)
|
|
$
|
(0.50)
|
|
Non-cash equity-based
compensation expense
|
|
3,873
|
|
$
|
0.03
|
|
$
|
0.03
|
|
|
12,953
|
|
$
|
0.11
|
|
$
|
0.11
|
|
Adjusted Net Income
(Loss)(4)
|
$
|
(960)
|
|
$
|
(0.01)
|
|
$
|
(0.01)
|
|
$
|
27,887
|
|
$
|
0.23
|
|
$
|
0.23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common
shares outstanding at December 31, 2023:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
124,150
|
|
|
|
|
|
|
119,894
|
|
|
|
|
|
Diluted
|
|
126,196
|
|
|
|
|
|
|
120,752
|
|
|
|
|
|
___________________________________
|
(1)
|
Transaction expenses
includes $40.4 million in costs related to the EnVen Acquisition,
inclusive of $25.3 million and nil in severance expenses for the
twelve months ended December 31, 2023, respectively. Other income
(expense) includes restructuring expenses, cost saving initiatives
and other miscellaneous income and expenses that we do not view as
a meaningful indicator of our operating performance. For the twelve
months ended December 31, 2023, the amount includes a $66.2 million
gain on the Mexico Divestiture. The amount includes a gain on the
funding of the capital carry of our investment in Bayou Bend by
Chevron of $8.6 million for the twelve months ended December 31,
2023.
|
(2)
|
Estimated
decommissioning obligations were a result of working interest
partners or counterparties of divestiture transactions that were
unable to perform the required abandonment obligations due to
bankruptcy or insolvency.
|
(3)
|
The adjustments for the
derivative fair value (gain) loss and net cash receipts (payments)
on settled derivative instruments have the effect of adjusting net
income (loss) for changes in the fair value of derivative
instruments, which are recognized at the end of each accounting
period because we do not designate commodity derivative instruments
as accounting hedges. This results in reflecting commodity
derivative gains and losses within Adjusted Net Income (Loss) on an
unrealized basis during the period the derivatives
settled.
|
(4)
|
The per share impacts
reflected in this table were calculated independently and may not
sum to total adjusted basic and diluted EPS due to
rounding.
|
Reconciliation of Total Debt to Net Debt and Net Debt to LTM
Adjusted EBITDA
We believe the presentation of Net Debt, LTM Adjusted EBITDA,
and Net Debt to LTM Adjusted EBITDA is important to provide
management and investors with additional important information to
evaluate our business. These measures are widely used by investors
and ratings agencies in the valuation, comparison, rating and
investment recommendations of companies.
Net Debt. Total Debt principal minus cash and cash
equivalents.
Net Debt to LTM Adjusted EBITDA. Net Debt divided by
the LTM Adjusted EBITDA.
($
thousands)
|
December 31,
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
|
|
227,500
|
|
Bank Credit Facility –
matures March 2027
|
|
200,000
|
|
Total Debt
|
|
1,066,041
|
|
Less: Cash and cash
equivalents
|
|
(33,637)
|
|
Net Debt
|
$
|
1,032,404
|
|
|
|
|
LTM Adjusted
EBITDA
|
$
|
950,718
|
|
LTM Adjusted EBITDA
from Acquired Assets (from January 1, 2023 to February 13,
2023)
|
|
33,120
|
|
Pro Forma LTM Adjusted
EBITDA
|
$
|
983,838
|
|
|
|
|
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.
|
Reconciliation of PV-10 to Standardized Measure
Reconciliation of PV-10 to Standardized Measure PV-10 is a
non-GAAP financial measure and generally differs from Standardized
Measure, the most directly comparable GAAP financial measure,
because it does not include the effects of income taxes on future
net revenues. PV-10 is not an estimate of the fair market value of
the Company's properties. Talos and others in the industry use
PV-10 as a measure to compare the relative size and value of proved
reserves held by companies and of the potential return on
investment related to the companies' properties without regard to
the specific tax characteristics of such entities. PV-10 may be
reconciled to the Standardized Measure of discounted future net
cash flows at such dates by adding the discounted future income
taxes associated with such reserves to the Standardized
Measure.
The table below presents the reconciliation of the standardized
measure of discounted future net cash flows to PV-10 of our proved
reserves:
($
thousands)
|
Year Ended
December 31, 2023
|
|
Standardized measure
(1)(2)
|
$
|
3,043,488
|
|
Present value of future
income taxes discounted at 10%
|
|
455,330
|
|
PV-10
(Non-GAAP)
|
$
|
3,498,818
|
|
________________________________
|
(1)
|
All estimated future
costs to settle asset retirement obligations associated with our
proved reserves have been included in our calculation of the
standardized measure for the period presented.
|
(2)
|
Standardized measure is
based on management estimates and is not audited by third party
reserve engineers.
|
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SOURCE Talos Energy