HOUSTON, March 13, 2019 /PRNewswire/ -- Talos Energy
Inc. ("Talos" or the "Company") (NYSE: TALO) today announced its
financial and operational results for the fourth quarter and full
year 2018.
Key Highlights of the Fourth Quarter 2018:
- Year-end 2018 proved reserves of 151.7 million barrels of oil
equivalent ("MMBoe"), of which 76% is proved developed
- Standardized measure of discounted future net cash flows of
$3.3 billion and PV-10(1)
of proved reserves of $3.9 billion,
with proved developed producing ("PDP") reserves accounting for
$2.5 billion
- Production of 53.4 thousands of barrels of oil equivalent per
day ("MBoe/d"), or 4.9 MMBoe in the fourth quarter
- Net Income of $306.3 million and
Earnings Per Share of $5.66 in the
fourth quarter
- Adjusted Net Income(2) of $49.3 million and Adjusted Earnings Per
Share(2) of $0.91 in the
fourth quarter
- Adjusted EBITDA(2) of $158.8
million in the fourth quarter. Excluding hedges, Adjusted
EBITDA(2) was $175.1
million
- Adjusted EBITDA Margin(2) of 61% or $32.33 per barrel of oil equivalent ("Boe") in
the fourth quarter. Excluding hedges, the Adjusted EBITDA
Margin(2) was 68% or $35.66 per Boe.
- As of December 31, 2018,
liquidity position of $460.3 million,
including $320.4 million available
under the $600.0 million Bank Credit
Facility and approximately $139.9
million of cash. In the fourth quarter of 2018 the Company's
Borrowing Base was increased by approximately 42% to $850 million; however, Talos elected to maintain
the commitments at $600 million
- As of December 31, 2018 the
Company's total debt principal balance was $766.2 million, inclusive of $93.7 million capital lease. Net Debt to
Annualized Adjusted EBITDA(2) was 1.0x
- Capital expenditures, inclusive of Plugging and Abandonment
costs, was $142.4 million in the
fourth quarter
(1)
|
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 proved reserves to the standardized measure of discounted
future net cash flows at December 31, 2018.
|
|
|
(2)
|
Adjusted Net Income,
Adjusted Earnings per share, Adjusted EBITDA, Adjusted EBITDA
excluding hedges, Adjusted EBITDA Margin, Adjusted EBITDA Margin
excluding hedges, Net Debt, Annualized Adjusted EBITDA, and Net
Debt to Annualized Adjusted EBITDA are non-GAAP financial measures.
See "Supplemental Non-GAAP Information" below for additional detail
and reconciliations of GAAP to non-GAAP measures.
|
Combination with Stone Energy Corporation
On May 10, 2018, Talos Energy LLC and Stone Energy
Corporation ("Stone") completed a strategic transaction pursuant to
which both became wholly-owned subsidiaries of the Company ("Stone
Combination"). Talos Energy LLC was considered the accounting
acquirer in the Stone Combination under accounting principles
generally accepted in the United States
of America ("GAAP"). Accordingly, the Company's historical
financial and operating data, which cover periods prior to
May 10, 2018, reflect only the assets, liabilities and
operations of Talos Energy LLC (as the Company's predecessor prior
to May 10, 2018), and do not reflect the assets, liabilities
and operations of Stone prior to May 10, 2018.
The pro forma financial information set forth in this press
release gives pro forma effect to the Stone Combination as if it
occurred on January 1, 2018. Stone's acquisition of the Ram
Powell deepwater assets on May 1, 2018 and Ram Powell's
respective financial results are included in the Company's pro
forma results from May 1, 2018 onwards. Unless expressly
stated as pro forma, the financial and operating data in this press
release is presented in a historical basis.
Additional Highlights
|
Three months
ended
December 31, 2018
|
|
Year ended
December 31, 2018
|
|
As
Reported
|
|
As
Reported
|
|
Pro
Forma
|
Total production
volumes (MBoe)
|
4,910
|
|
16,742
|
|
19,143
|
Oil (MBbl/d) - Avg
daily production
|
38.9
|
|
32.2
|
|
36.8
|
NGLs (MBbl/d) - Avg
daily production
|
3.2
|
|
3.2
|
|
3.7
|
Natural Gas (MMcfe/d)
- Avg daily production
|
67.6
|
|
62.4
|
|
71.7
|
Total average
daily (MBoe/d)
|
53.4
|
|
45.9
|
|
52.4
|
|
|
|
|
|
|
Period results ($
million):
|
|
|
|
|
|
Revenues
|
$258.7
|
|
$891.3
|
|
$1,013.2
|
Net Income
|
$306.3
|
|
$221.5
|
|
$274.6
|
Earnings per
share
|
$5.66
|
|
$4.81
|
|
$5.96
|
Adjusted Net
Income(1)
|
$49.3
|
|
$122.4
|
|
$173.8
|
Adjusted Earnings per
share(1)
|
$0.91
|
|
$2.66
|
|
$3.77
|
Adjusted
EBITDA(1)
|
$158.8
|
|
$502.7
|
|
$585.0
|
Adjusted EBITDA excl.
hedges(1)
|
$175.1
|
|
$613.9
|
|
$701.7
|
Capital Expenditures
(including Plug & Abandonment)
|
$142.4
|
|
$397.8
|
|
$452.4
|
Adjusted EBITDA
margin(1):
|
|
|
|
|
|
Adjusted EBITDA (% of
revenue)
|
61%
|
|
56%
|
|
58%
|
Adjusted EBITDA per
Boe
|
$32.33
|
|
$30.03
|
|
$30.56
|
Adjusted EBITDA excl
hedges (% of revenue)
|
68%
|
|
69%
|
|
69%
|
Adjusted EBITDA excl
hedges per Boe
|
$35.66
|
|
$36.67
|
|
$36.66
|
|
|
(1)
|
Adjusted Net Income,
Adjusted Earnings per share, Adjusted EBITDA, Adjusted EBITDA
excluding hedges, Adjusted EBITDA Margin, Adjusted EBITDA Margin
excluding hedges, Net Debt and Net Debt to Annualized Adjusted
EBITDA are non-GAAP financial measures. See "Supplemental Non-GAAP
Information" below for additional detail and reconciliations of
GAAP to non-GAAP measures.
|
President and Chief Executive Officer Timothy S. Duncan commented: "2018 was a
transformative year for the company, as we combined the best
aspects of two companies, following our merger with Stone Energy.
The benefits of the combination have shown results
immediately, as we are a stronger, free cash flow positive company
with ample liquidity and a significant inventory of drilling
locations in both the US Gulf of Mexico and offshore Mexico. Our strategy of executing asset
management and drilling projects around existing infrastructure in
the US Gulf of Mexico complements our high impact exploration and
development projects in offshore Mexico."
"In the last twelve months we have seen our proved developed
reserves increase 20%, as compared to the pro forma reserves at
December 31, 2017. We have also added
three small bolt-on transactions at a low entry cost, including the
Gunflint acquisition in January of 2019. We have increased our
liquidity position and continued to improve our already robust
leverage metrics. We have also re-affirmed the potential of our
globally recognized Zama discovery through our ongoing appraisal
program."
"Our average daily production in 2018 on a pro forma basis was
52.4 MBoe/d, which was on the high end of our pro forma guidance
range of 49.0 – 53.0 MBoe/d, allowing us to generate $585 million of pro forma Adjusted EBITDA for the
full year 2018, inclusive of hedges, and a pro forma capital
program of $452 million, inclusive of
plugging and abandoning activities ("P&A"). Although the
merger with Stone required us to spend more capital in 2018 on
P&A and non-recurring repairs and maintenance than we normally
would have, in 2019 those costs are expected to go down
materially."
"In the US Gulf of Mexico, we executed a series of deepwater
subsea tie-back projects in 2018 and early 2019, namely the Mt.
Providence well, which was
connected to our Pompano facility, and the Tornado 3 and Boris 3
wells, that will flow back to the Helix Producer 1 ("HP-1") in our
operated Phoenix complex once the
wells are completed. The HP-1 dry-dock project in the first quarter
of 2019 was flawlessly executed by the Talos team and our partner
Helix Energy Solutions, and we expect the production in the
Phoenix complex to be restarted in
the coming days. Soon thereafter we expect to bring the impactful
Tornado 3 and Boris 3 wells online, which will put Talos in a
position to grow production year over year while continuing to
generate free cash flow in the current price environment for
2019. In shallow water, our asset management and drilling
activities have allowed assets such as Ewing Bank 305/306 to achieve production levels
not seen in the last 15 years."
"We also continue to be active and to execute on our business
development and commercial activities. In addition to the
aforementioned bolt-on acquisitions, we have acquired the Antrim
stranded discovery from ExxonMobil and have entered into
partnerships to drill two deepwater projects in 2019, the Bulleit
and Orlov prospects."
"In Mexico on the Zama project, our operations execution has
been outstanding. As part of the ongoing appraisal program we
confirmed the oil-water contact per our geological model and have
encountered more sand than expected in the first down-dip location.
We are excited about the impact this discovery will have in the
Mexican economy and to Talos shareholders. Also in offshore
Mexico, we will start to execute
on the inventory we acquired as part of the cross-assignment of
interest between Block 2 and Block 31, which includes the low-risk
but high impact Olmeca project on Block 31."
"In conclusion, we are very happy with our 2018 results, but we
are already looking forward to 2019 and beyond. We will continue to
relentlessly execute on our operations and strategy of responsibly
growing production at an appropriate pace that allows for the
continued generation of positive free cash flow while diligently
pursuing additional business development opportunities that fit our
asset footprint and core competencies. We believe this is only the
beginning of the Talos journey."
RECENT DEVELOPMENTS AND OPERATIONS UPDATE
Drilling and Exploration Activities
Deepwater
- Helix Producer 1 dry-dock: the HP-1 departed the shipyard on
March 7, 2019. After a period of sea
trials, Talos expects production from the Phoenix complex to re-start on or about
March 20, 2019, resulting in a total
shut-in period of 56 days. The production impact of the shut-in in
the Phoenix complex in the first
quarter of 2019 is estimated to be between 9.0 – 13.0 MBoe/d,
whereas the annualized impact for full year 2019 production is
estimated to be between 2.0 – 3.0 MBoe/d. This impact is already
accounted for in our annual guidance, as the shut-in in the
Phoenix complex was a known,
expected event.
- The Tornado 3 well was drilled in December, 2018 and is
scheduled to begin completions operations in late March, with an
expected duration of 21 days. The well is anticipated to commence
production by early second quarter 2019, with an expected gross
production rate between 10.0 MBoe/d – 15.0 MBoe/d, or 5.0 MBoe/d –
7.5 MBoe/d net to Talos after royalties. Talos is the operator and
owns a 65% working interest, with Kosmos Energy owning the
remaining 35% working interest.
- The Boris 3 well was spud in January
2019 and was drilled to a total depth of approximately
15,000 feet and logged approximately 75 feet gross and 56 feet net
of true vertical pay, 360 feet up-dip of 27 MMBoe of historical
production in the B-4 Sand. Boris 3 is scheduled to begin
completion operations in mid-April with an expected duration of 21
days and is expected to initiate production in the second quarter
of 2019. Talos expects Boris 3 to have initial production between
3.0 – 5.0 MBoe/d gross, or 2.8 – 4.6 MBoe/d net to Talos after
royalties. Talos is the operator and owns 100% working interest in
all Boris wells.
- Bulleit prospect: Talos has signed a participation agreement
with a subsidiary of EnVen Corporation to drill the Green Canyon 21
Bulleit prospect. Talos will be the operator and has an initial
working interest of 66.7% in the lease. Bulleit is an
amplitude-supported Pliocene prospect with similar seismic
attributes to the analogous sand section in Talos's Green Canyon 18
field, which has produced approximately 39 MMBoe to date. Talos
expects to spud the well in the second quarter of 2019. If
successful, the well would be completed and tied back to the Talos
owned and operated Green Canyon 18 ("GC 18") facility approximately
10 miles away. Talos anticipates first production within 12-18
months from spud date and estimates that Bulleit has the potential
to deliver initial production between 8.0 MBoe/d – 15.0 MBoe/d
gross on an unrisked basis.
- Orlov prospect: Talos has signed a participation agreement to
engage in the drilling of the Green Canyon 200 Orlov prospect.
Fieldwood Energy will be the operator and Talos has a working
interest of 30% in the prospect. Orlov is an amplitude-supported
Miocene prospect with similar geophysical and structural attributes
to the Talos operated Boris field, which has produced approximately
27 MMBoe to date. Talos expects the well to spud near the end of
the first quarter of 2019. If successful, the well would be
completed and tied-back to the Fieldwood operated Green Canyon 158
Bullwinkle facility. Talos anticipates first production within
12-18 months from spud date and estimates that Orlov has the
potential to deliver between 8.0 MBoe/d – 15.0 MBoe/d gross on an
unrisked basis
Mexico
Block 7 – Zama appraisal program
As previously announced, the Zama-2 appraisal penetration was
successfully and safely completed approximately 28 days ahead of
schedule and 25% below projected costs. The well confirmed a
contiguous Zama Upper Miocene sandstone interval thicker than the
Zama-1 discovery well and slightly thicker than the pre-drill
estimates for the Zama-2 well, with high quality rock properties
analogous to Upper Miocene sands in the US Gulf of Mexico.
The Zama-2 penetration also reached the oil-water contact
slightly deeper than the anticipated depth and consistent with our
geophysical models. Preliminary pressure data indicates that the
reservoir area around the Zama-2 appraisal well is connected to the
Zama-1 discovery well and Talos expects the Zama-2 vertical
sidetrack and the Zama-3 wells will provide additional information
about the reservoir connectivity and consistency.
The next step of the appraisal program is currently underway
with an up-dip vertical penetration in the Zama reservoir from the
main bore hole of the Zama-2 well, called the Zama 2-ST, which has
been cored and a drill stem test will be performed in the coming
weeks. The second appraisal well, Zama-3, will be drilled to the
south of the original discovery well and will help delineate the
reservoir continuity and quality in the southern part of the field
and will be cored to better understand the reservoir geology.
Block 2 and Block 31 Exploration program
Talos and its partners expect to drill two exploration wells in
Block 2 and two delineation wells in Block 31 in 2019.
- In Block 2, the well to test the Acan prospect is expected to
spud in the second quarter of 2019.
- In Block 31, the Olmeca-1 well is expected to be drilled in the
second half of 2019. The Olmeca complex has been significantly
de-risked by the Xaxamani-1 well drilled by Pemex in 2003. The 2019
drilling campaign will be to appraise the same geological structure
initially tested by Pemex and, if successful, a final investment
decision to develop these assets could be reached in 2020.
Business Development Activities
Acquisition of the Antrim Discovery from ExxonMobil
On January 23, 2019, Talos and
ExxonMobil ("Exxon") executed an Acquisition Agreement through
which Talos acquired 100% interest in the Antrim Project in Green
Canyon Block 364 ("GC 364").
Exxon drilled an exploratory well in GC 364 in November 2017 that encountered hydrocarbons in a
sub-salt Miocene reservoir and subsequently divested of the
discovery well and the GC 364 lease to Talos for further appraisal
and a possible development.
Talos plans to drill an additional well to further appraise the
discovered resource. The Company is still developing a detailed
timeline for the appraisal and development plan over the next few
years with significant time ahead of the June 2025 lease expiration. If the appraisal is
successful, Talos is currently considering a tie-back to the Talos
owned and operated GC 18 facility acquired from Whistler in
2018.
In addition to a nominal upfront cash consideration payment by
Talos, Exxon will receive an overriding royalty interest in the
lease as well as a future cash payment upon the earlier of 30
days following the completion of drilling operations on the first
well or by the end of the third quarter of 2020.
Gunflint Acquisition
On January 11, 2019, Talos
acquired an approximate 9.6% non-operated working interest in the
Gunflint producing asset for $29.6
million from Samson Offshore Mapleleaf, LLC. Gunflint is
located in the Company's Mississippi Canyon core area. The asset's
average production for October and November of 2018 was
approximately 1.5 - 1.8 MBoe/d and as of November 30, 2018, had proved reserves of 2.2
MMBoe (approximately 80% proved developed) - both production and
reserves are net to the Company's acquired interest, which are not
included in our year-end reserves.
PROVED RESERVES – AS OF DECEMBER 31,
2018
As of December 31, 2018, Talos had
proved reserves of 151.7 MMBoe, with 81% comprised of liquids (74%
crude oil and 7% NGLs). As compared to the pro forma year-end 2017
reserves, the Company achieved 100% reserve replacement rate. Talos
accomplished this replacement rate in a year that the drilling
program was mainly designed to convert proved undeveloped reserves
into proved developed reserves while integrating the Stone merger.
As such, proved developed reserves increased approximately 20% year
over year, and is not inclusive of the recently successful Boris 3
well in the Phoenix complex, which
is still classified as proved undeveloped in the year-end reserves.
The recently announced Gunflint transaction is also not included in
the year end reserves.
The discovered resources associated with the Company's offshore
Mexico assets are not yet
qualified as proved reserves per Securities and Exchange Commission
(the "SEC") rules and, therefore, are not included in any of the
information provided in this press release.
The standardized measure of proved reserves and the present
value of the Company's proved reserves, discounted at 10%
("PV-10")(1), at year-end 2018 were $3.3 billion and $3.9
billion, respectively. Standardized measure and PV-10
include the present value of all asset retirement obligations
associated with the relevant assets and properties.
The following table summarizes our proved reserves at
December 31, 2018:
|
Summary of Proved
Reserves(2)
|
|
MBoe
|
|
Percent of Total
Proved
|
|
Percent
Oil
|
|
Standardized
Measure
(in thousands)
|
|
PV-10(1) (in
thousands)
|
Proved Developed
Producing
|
|
78,072
|
|
|
51%
|
|
|
80%
|
|
|
|
|
$
|
2,510,213
|
Proved Developed
Non-Producing
|
|
37,456
|
|
|
25%
|
|
|
62%
|
|
|
|
|
|
680,942
|
Total Proved
Developed
|
|
115,528
|
|
|
76%
|
|
|
74%
|
|
|
|
|
|
3,191,155
|
Proved
Undeveloped
|
|
36,211
|
|
|
24%
|
|
|
75%
|
|
|
|
|
|
734,108
|
Total
Proved
|
|
151,739
|
|
|
|
|
|
|
|
$
|
3,340,246
|
|
$
|
3,925,263
|
|
|
(1)
|
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 proved reserves to the standardized measure of discounted
future net cash flows at December 31, 2018.
|
|
|
(2)
|
Proved oil, natural
gas and NGL reserves attributable to our net interests in oil and
natural gas properties were estimated and compiled for reporting
purposes by our reservoir engineers and audited by Netherland,
Sewell & Associates, Inc.
|
The following table summarizes our proved reserves by asset at
December 31, 2018:
|
|
Proved
Reserves
|
|
Operating
Area
|
|
MBoe
|
|
|
% Oil
|
|
|
% Natural
Gas
|
|
|
% NGLs
|
|
|
% Proved
Developed
|
|
United States Core
Properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Phoenix
Complex
|
|
|
63,931
|
|
|
|
78
|
%
|
|
|
14
|
%
|
|
|
8
|
%
|
|
|
55
|
%
|
Pompano
|
|
|
28,206
|
|
|
|
81
|
%
|
|
|
14
|
%
|
|
|
5
|
%
|
|
|
100
|
%
|
Ram Powell
|
|
|
18,094
|
|
|
|
59
|
%
|
|
|
28
|
%
|
|
|
13
|
%
|
|
|
100
|
%
|
Amberjack
|
|
|
8,148
|
|
|
|
88
|
%
|
|
|
10
|
%
|
|
|
2
|
%
|
|
|
100
|
%
|
United States Core
Properties Subtotal
|
|
|
118,379
|
|
|
|
77
|
%
|
|
|
16
|
%
|
|
|
7
|
%
|
|
|
76
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other United States
Properties(1)
|
|
|
33,360
|
|
|
|
65
|
%
|
|
|
30
|
%
|
|
|
5
|
%
|
|
|
78
|
%
|
Total United
States
|
|
|
151,739
|
|
|
|
74
|
%
|
|
|
19
|
%
|
|
|
7
|
%
|
|
|
76
|
%
|
|
|
(1)
|
Other United States
Properties includes Gulf of Mexico shelf and deepwater.
|
In accordance with guidelines established by the SEC, the
Company's estimated proved reserves as of December 31, 2018 were determined to be
economically producible under existing economic conditions, which
requires the use of the 12-month average price for each commodity,
calculated as the unweighted arithmetic average of the price on the
first day of each month for the year end December 31, 2018. The West Texas
Intermediate spot price and the Henry Hub spot price were utilized
as the referenced price and appropriately adjusted for quality,
transportation, fees, energy content and basis differentials.
Therefore, the standardized measure and PV-10 of Talos's proved
reserves at December 31, 2018, are
based on an average crude oil price of $65.56 per barrel and an average natural gas
price of $3.10 per MMBtu, prior to
being adjusted for quality, transportation, fees, energy content
and basis differentials. The average adjusted product prices used
in determining standardized measure and PV-10 are $69.42 per barrel of oil, $29.50 per barrel of NGL, and $3.08 per Mcf of gas.
FOURTH QUARTER 2018 RESULTS
Production, Realized Prices and Revenue
Production: Production for the fourth quarter of
2018 was 4.9 million Boe and was comprised of 3.6 million
barrels of oil, 0.3 million barrels of NGLs and
6.2 billion cubic feet ("Bcf") of natural gas. Oil and NGLs
production accounted for 79% of the total production for the fourth
quarter of 2018.
During the quarter, Talos evacuated non-essential personnel and
shut-in production on certain Gulf of
Mexico assets as a result of Hurricane Michael, which
negatively impacted production. Talos suffered no damage to its
assets. In addition to Hurricane Michael, production was negatively
affected by several minor third-party downtime events.
Although a certain level of third party downtime is expected and
planned for, these interruptions in production were limited to the
fourth quarter and are not expected to have a material impact going
forward.
The table below provides additional detail of the Company's oil,
natural gas and NGLs production volumes and sales prices per unit
for the three months and year ended December
31, 2018:
|
Three months
ended
December 31, 2018
|
|
Year ended
December 31, 2018
|
|
As
Reported
|
|
As
Reported
|
|
Pro
Forma
|
Production
volumes
|
|
|
|
|
|
Oil production volume
(MBbl)
|
3,583
|
|
11,771
|
|
13,445
|
NGL production volume
(MBbl)
|
290
|
|
1,176
|
|
1,336
|
Natural Gas
production volume (MMcf)
|
6,223
|
|
22,771
|
|
26,174
|
Total production
volume (MBoe)
|
4,910
|
|
16,742
|
|
19,143
|
|
|
|
|
|
|
Average net daily
production volumes
|
|
|
|
|
|
Oil
(MBbl/d)
|
38.9
|
|
32.2
|
|
36.8
|
NGL
(MBbl/d)
|
3.2
|
|
3.2
|
|
3.7
|
Natural Gas
(MMcf/d)
|
67.6
|
|
62.4
|
|
71.7
|
Total average net
daily (MBoe/d)
|
53.4
|
|
45.9
|
|
52.4
|
|
|
|
|
|
|
Average realized
prices (excluding hedges)(1)
|
|
|
|
|
|
Oil
($/Bbl)
|
63.04
|
|
66.42
|
|
66.35
|
NGL
($/Bbl)
|
29.47
|
|
30.50
|
|
30.20
|
Natural Gas
($/Mcf)
|
3.90
|
|
3.23
|
|
3.09
|
Barrel of oil
equivalent ($/Boe)
|
52.68
|
|
53.24
|
|
52.93
|
|
|
(1)
|
Average realized
prices are net of certain gathering, transportation and other
costs
|
The table below provides additional detail of the Company's
production by major assets for the three months ended December 31, 2018:
|
Three months
ended
December 31, 2018
|
|
Production
(MBoe/d)
|
|
Oil
(%)
|
|
Liquids
(%)
|
|
|
|
|
|
|
Average net daily
production volumes by asset
|
|
|
|
|
|
Green
Canyon
|
|
|
|
|
|
Phoenix
Complex
|
16.8
|
|
80%
|
|
87%
|
Green Canyon
18
|
1.1
|
|
90%
|
|
93%
|
Mississippi
Canyon
|
|
|
|
|
|
Amberjack
|
2.2
|
|
90%
|
|
92%
|
Pompano
|
10.3
|
|
87%
|
|
88%
|
Ram Powell
|
6.8
|
|
60%
|
|
73%
|
Shelf and
Other
|
|
|
|
|
|
Shelf /
Other
|
16.1
|
|
59%
|
|
65%
|
Total average net
daily (MBoe/d)
|
53.4
|
|
73%
|
|
79%
|
Revenue: Total revenue for the three months ended
December 31, 2018 was $258.7 million underpinned by a good
production profile in the quarter, especially oil production, and a
supportive commodity price environment in the first few weeks of
the period.
The table below summarizes the revenue by commodity for the
three months and year ended December 31,
2018 and provides additional relevant information:
|
Three months
ended
December 31, 2018
|
|
Year ended
December 31, 2018
|
|
As
Reported
|
|
As
Reported
|
|
Pro
Forma
|
Revenues ($
million)
|
|
|
|
|
|
Oil
|
225.9
|
|
781.8
|
|
892.0
|
NGL
|
8.6
|
|
35.9
|
|
40.4
|
Natural
Gas
|
24.2
|
|
73.6
|
|
80.8
|
Total
Revenue
|
258.7
|
|
891.3
|
|
1,013.2
|
|
|
|
|
|
|
Average realized
prices (excluding hedges)(1)
|
|
|
|
|
|
Oil
($/Bbl)
|
$ 63.04
|
|
66.42
|
|
66.35
|
NGL
($/Bbl)
|
$ 29.47
|
|
30.50
|
|
30.20
|
Natural Gas
($/Mcf)
|
$ 3.90
|
|
3.23
|
|
3.09
|
Barrel of oil
equivalent ($/Boe)
|
$
52.68
|
|
53.24
|
|
52.93
|
|
|
|
|
|
|
Average NYMEX
prices
|
|
|
|
|
|
WTI
($/Bbl)
|
$ 58.81
|
|
64.77
|
|
64.77
|
Henry Hub
($/MMBtu)
|
$ 3.64
|
|
3.09
|
|
3.09
|
|
|
(1)
|
Average realized
prices are net of certain gathering, transportation and other
costs
|
Expenses
Lease operating expense ("LOE"): Total lease operating
expense for the three months ended December
31, 2018 was $49.7 million, inclusive of insurance
costs.
LOE for the full year 2018 was $163.3million and, on a pro forma basis, was
$177.9 million, also inclusive of
insurance costs.
Workover and maintenance expense: For the three
months ended December 31, 2018 was
$15.3 million. These costs include
approximately $7.4 million
non-recurring expenses primarily related to structural maintenance,
including the HP-1 dry-dock.
Workover and maintenance expense for the full year 2018 on a pro
forma basis was $71.5 million.
General and administrative expense ("G&A"): General
and administrative expense for the three months ended December 31, 2018 was $24.7 million, which included $0.8 million of non-cash equity based
compensation and $4.6 million in
transaction and integration costs mainly related to the Stone
Combination and the Whistler acquisition.
General and administrative expense for the full year was
$85.8 million, which included
$32.5 million in transaction related
costs.
G&A for the full year 2018 on a pro forma basis, was
$70.6 million, which excluded
transaction costs related to the Stone Combination; however, it is
inclusive of $3.3 million of
transaction costs mainly related to the acquisition of Whistler. It
is also inclusive of $3.1 million of
non-cash equity based compensation. Normalizing these one-time and
non-cash items, our pro forma full year G&A was $64.1 million.
Price risk management activities: Price risk
management activities for the three months ended December 31, 2018 resulted in a $16.3 million expense related to cash
settlement on our derivative contracts.
Other Financial Metrics
Net Income and Adjusted EBITDA: Net income was
$306.3 million or $5.66 per share in the fourth quarter of 2018 and
net income of $221.5 million or
$4.81 per share for the full year
2018. On a pro forma basis, for the full year, net income was
$274.6 million or $5.96 per share.
Adjusted EBITDA for the three months ended on December 31, 2018 was $158.8 million and Adjusted EBITDA margin
was 61%, or $32.33 per Boe. For the
full year, Adjusted EBITDA was $502.7 million, with a margin of 56% or
$30.03 per Boe. Excluding the effect
of hedges, the margins would have been 68% or $35.66 per Boe for the fourth quarter and 69% or
$36.67 per Boe for the full year.
Pro forma Adjusted EBITDA for the full year 2018 was
$585.0 million, with a margin of
58% or $30.56 per Boe. Excluding the
effect of hedges, the pro forma margins would have been 69% or
$36.66 per Boe for the full year.
Capital Expenditures: Capital expenditures in the
fourth quarter of 2018 were $142.4
million, inclusive of Plugging & Abandonment costs. For
the full year of 2018, capital expenditures were $397.8 million, also inclusive Plugging &
Abandonment costs.
The pro forma capital expenditures for 2018 were $452.4 million, inclusive of Plugging &
Abandonment costs. Pro forma capital expenditures for the year
excludes $29.8 million of accrued,
but unpaid change of control costs for the seismic data acquired in
connection with the Stone Combination. As part of the negotiation
between the parties, these costs will be paid in 2019, 2020 and
2021 in equal installments. It also excludes non-cash equity based
compensation and $9.0 million of
corporate office renovation costs, which were reimbursed by the
property manager, thus resulting in a zero cash impact to
Talos.
The table below provides additional detail of the Company's
capital expenditures:
|
Three months
ended
December 31, 2018
|
|
Year ended
December 31, 2018
|
($
million)
|
As
Reported
|
|
As
Reported
|
|
Pro
Forma
|
U.S. Drilling &
Completions
|
81.2
|
|
163.1
|
|
181.2
|
Mexico Appraisal &
Exploration
|
12.8
|
|
14.5
|
|
14.5
|
Asset
Management
|
15.7
|
|
52.5
|
|
54.2
|
Seismic and G&G /
Land / Capitalized G&A
|
5.4
|
|
47.6
|
|
60.5
|
Total Capital
Expenditures
|
115.1
|
|
277.7
|
|
310.4
|
Plug &
Abandonment
|
27.3
|
|
112.9
|
|
142.0
|
Total Capital
Expenditures & Plug & Abandonment
|
142.4
|
|
390.6
|
|
452.4
|
Financial position: As of December 31, 2018, the Company had approximately
$672.5 million in long-term
debt, excluding deferred financing costs and original issue
discount. The balance includes $396.9 million of second lien notes,
$265.0 million of borrowings
under the bank credit facility and a $10.6 million building loan. In addition to
the Company's long-term debt, as of December
31, 2018, Talos had a capital lease obligation with a
balance of approximately $93.7 million.
Liquidity position: As of December 31, 2018, the Company had a liquidity
position of approximately $460.3 million, which included $320.3 million available under the $600.0 million bank credit facility and
approximately $139.9 million of
cash. In the fourth quarter of 2018, the Company's borrowing base
was increased by approximately 42% to $850
million; however, Talos elected to maintain the commitments
at $600 million.
Leverage and credit metrics: Annualized Adjusted
EBITDA for the six month period ended December 31, 2018 was $631.6 million. As of December 31, 2018, the Company's total debt was
$766.2 million and net debt was
$626.2 million, both including
capital lease. Therefore, the Net Debt to Annualized Adjusted
EBITDA ratio of Talos was 1.0x.
DERIVATIVE POSITION
The tables below provide additional detail on the Company's
hedge position for the full year 2019, which is inclusive of hedge
transactions entered into by March 13,
2019.
Oil Hedges
|
|
|
|
|
Weighted Average
Price
|
|
Swaps
|
Collars
|
Puts
|
Total
|
Swaps
|
Put
Strike
|
Call
Strike
|
Blend
Avg.
|
Period
|
(MBbls)
|
(MBbls)
|
(MBbls)
|
(Bbls/d)
|
($/Bbl)
|
($/Bbl)
|
($/Bbl)
|
($/Bbl)
|
01/19-12/19
|
10,094
|
-
|
-
|
27,654
|
$
55.54
|
-
|
-
|
$
55.54
|
01/20-12/20
|
1,367
|
1,095
|
-
|
6,746
|
$
57.07
|
$
55.00
|
$
60.64
|
$
56.15
|
Gas Hedges
|
|
|
|
|
Weighted Average
Price
|
|
Swaps
|
Collars
|
Puts
|
Total
|
Swaps
|
Put
Strike
|
Call
Strike
|
Blend
Avg.
|
Period
|
(MMBtu)
|
(MMBtu)
|
(MMBtu)
|
(MMBtu/d)
|
($/MMBtu)
|
($/MMBtu)
|
($/MMBtu)
|
($/MMBtu)
|
01/19-12/19
|
13,324
|
3,150
|
-
|
45,133
|
$
2.90
|
$
3.00
|
$
3.96
|
$
2.92
|
CONFERENCE CALL AND WEBCAST INFORMATION
Talos will host a conference call, which will also be broadcast
live over the internet, on Thursday, March
14, 2019 at 10:00 am Eastern
Time (9:00 am Central
Time).
Listeners can access the conference call live over the internet
through a webcast link on the Company's website at:
https://www.talosenergy.com/investors. Alternatively, the
conference call can be accessed by dialing 1-877-870-4263 (U.S.
toll-free), 1-855-669-9657 (Canada
toll-free) or 1-412-317-0790 (international). Please dial in
approximately 10 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 call through Thursday, March 21, 2019 and can be accessed by
dialing 1-877-344-7529 and using access code 10128499.
ABOUT TALOS ENERGY
Talos is a technically driven independent exploration and
production company with operations in the
United States Gulf of
Mexico and in the shallow waters off the coast of
Mexico. Our focus in the United States Gulf of Mexico is the exploration,
acquisition, exploitation and development of shallow and deepwater
assets near existing infrastructure. The shallow waters off the
coast of Mexico provide us high
impact exploration opportunities in an emerging basin. The
Company's website is located at www.talosenergy.com.
INVESTOR RELATIONS CONTACT
Sergio Maiworm
+1.713.328.3008
investor@talosenergy.com
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
This communication may contain "forward-looking statements"
within the meaning of Section 27A of the Securities Act of
1933, as amended (the "Securities Act"), and Section 21E of
the Securities Exchange Act of 1934, as amended. All statements,
other than statements of historical fact included in this
communication, regarding our strategy, future operations, financial
position, estimated revenues and losses, projected costs,
prospects, plans and objectives of management are forward-looking
statements. When used in this communication, the words "could,"
"believe," "anticipate," "intend," "estimate," "expect," "project"
and similar expressions are intended to identify forward-looking
statements, although not all forward-looking statements contain
such identifying words. These forward-looking statements are based
on our current expectations and assumptions about future events and
are based on currently available information as to the outcome and
timing of future events.
We caution you that these forward-looking statements are subject
to numerous risks and uncertainties, most of which are difficult to
predict and many of which are beyond our control. These risks
include, but are not limited to, commodity price volatility,
inflation, lack of availability of drilling and production
equipment and services, environmental risks, drilling and other
operating risks, regulatory changes, the uncertainty inherent in
estimating reserves and in projecting future rates of production,
cash flow and access to capital, the timing of development
expenditures, potential adverse reactions or changes to competitive
responses to the business combination between Talos Energy LLC and
Stone Energy Corporation, the possibility that the anticipated
benefits of such business combination are not realized when
expected or at all, including as a result of the impact of, or
problems arising from, the integration of the two companies, and
other factors that may affect our future results and business,
generally, including those discussed under the heading "Risk
Factors" in our Quarterly Report on Form 10-Q for the quarter ended
September 30, 2018, filed with the
SEC on November 5, 2018, and in our
Annual Report on Form 10-K for the year ended December 31, 2018, to be filed with the SEC
subsequent to the issuance of this communication.
Should one or more of these risks occur, or should underlying
assumptions prove incorrect, our actual results and plans could
differ materially from those expressed in any forward-looking
statements. All forward-looking statements, expressed or implied,
are expressly qualified in their entirety by this cautionary
statement. This cautionary statement should also be considered in
connection with any subsequent written or oral forward-looking
statements that we or persons acting on our behalf may issue.
Except as otherwise required by applicable law, we disclaim any
duty to update any forward-looking statements, to reflect events or
circumstances after the date of this communication.
Estimates for our future production volumes are based on
assumptions of capital expenditure levels and the assumption that
market demand and prices for oil and gas will continue at levels
that allow for economic production of these products. The
production, transportation and marketing of oil and gas are subject
to disruption due to transportation and processing availability,
mechanical failure, human error, hurricanes and numerous other
factors. Our estimates are based on certain other assumptions, such
as well performance, which may vary significantly from those
assumed. Therefore, we can give no assurance that our future
production volumes will be as estimated.
Proved reserves attributable to the Gunflint assets as of
November 30, 2018 were estimated by
Talos Energy Inc.'s internal reserve engineer based upon
information furnished by Samson Offshore Mapleleaf, LLC, as seller,
but have not been audited or prepared by any third-party
independent petroleum engineer.
TALOS ENERGY
INC.
|
CONSOLIDATED
BALANCE SHEETS
|
(In thousands,
except share amounts)
|
|
|
Year Ended
December 31,
|
|
2018
|
|
2017
|
ASSETS
|
|
|
|
|
|
Current
assets:
|
|
|
|
|
|
Cash and cash
equivalents
|
$
|
139,914
|
|
$
|
32,191
|
Restricted
cash
|
|
1,248
|
|
|
1,242
|
Accounts
receivable
|
|
|
|
|
|
Trade, net
|
|
103,025
|
|
|
62,871
|
Joint interest,
net
|
|
20,244
|
|
|
13,613
|
Other
|
|
19,686
|
|
|
12,486
|
Assets from price risk
management activities
|
|
75,473
|
|
|
1,563
|
Prepaid
assets
|
|
38,911
|
|
|
17,931
|
Inventory
|
|
—
|
|
|
840
|
Income tax
receivable
|
|
10,701
|
|
|
—
|
Other current
assets
|
|
7,644
|
|
|
2,148
|
Total current
assets
|
|
416,846
|
|
|
144,885
|
Property and
equipment:
|
|
|
|
|
|
Proved
properties
|
|
3,629,430
|
|
|
2,440,811
|
Unproved properties,
not subject to amortization
|
|
108,209
|
|
|
72,002
|
Other property and
equipment
|
|
33,191
|
|
|
8,857
|
Total property and
equipment
|
|
3,770,830
|
|
|
2,521,670
|
Accumulated
depreciation, depletion and amortization
|
|
(1,719,609)
|
|
|
(1,430,890)
|
Total property and
equipment, net
|
|
2,051,221
|
|
|
1,090,780
|
Other long-term
assets:
|
|
|
|
|
|
Assets from price risk
management activities
|
|
—
|
|
|
345
|
Other well
equipment
|
|
9,224
|
|
|
2,577
|
Other
assets
|
|
2,695
|
|
|
706
|
Total
assets
|
$
|
2,479,986
|
|
$
|
1,239,293
|
LIABILITIES AND
STOCKHOLDERS' EQUITY (DEFICIT)
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
Accounts
payable
|
$
|
51,019
|
|
$
|
72,681
|
Accrued
liabilities
|
|
188,650
|
|
|
87,973
|
Accrued
royalties
|
|
38,520
|
|
|
24,208
|
Current portion of
long-term debt
|
|
443
|
|
|
24,977
|
Current portion of
asset retirement obligations
|
|
68,965
|
|
|
39,741
|
Liabilities from price
risk management activities
|
|
550
|
|
|
49,957
|
Accrued interest
payable
|
|
10,200
|
|
|
8,742
|
Other current
liabilities
|
|
22,071
|
|
|
15,188
|
Total current
liabilities
|
|
380,418
|
|
|
323,467
|
Long-term debt, net
of discount and deferred financing costs
|
|
654,861
|
|
|
672,581
|
Asset retirement
obligations
|
|
313,852
|
|
|
174,992
|
Liabilities from
price risk management activities
|
|
—
|
|
|
18,781
|
Other long-term
liabilities
|
|
123,359
|
|
|
103,559
|
Total
liabilities
|
|
1,472,490
|
|
|
1,293,380
|
Commitments and
contingencies (Note 11)
|
|
|
|
|
|
Stockholders'
Equity:
|
|
|
|
|
|
Preferred stock, $0.01
par value; 30,000,000 shares authorized and no shares issued or
outstanding as of December 31, 2018 and December 31,
2017
|
|
—
|
|
|
—
|
Common stock $0.01 par
value; 270,000,000 shares authorized; 54,155,768 and 31,244,085
shares issued and outstanding as of December 31, 2018 and December
31, 2017, respectively
|
|
542
|
|
|
312
|
Additional paid-in
capital
|
|
1,334,090
|
|
|
489,870
|
Accumulated
deficit
|
|
(327,136)
|
|
|
(544,269)
|
Total stockholders'
equity (deficit)
|
|
1,007,496
|
|
|
(54,087)
|
Total liabilities and
stockholders' equity
|
$
|
2,479,986
|
|
$
|
1,239,293
|
TALOS ENERGY
INC.
|
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
(In thousands,
except per common share amounts)
|
|
|
Three Months
Ended
December 31,
2018
|
|
Year Ended
December 31,
2018
|
|
Year Ended
December 31,
2017
|
Revenues:
|
|
|
|
|
|
|
|
|
Oil revenue
|
$
|
225,861
|
|
$
|
781,815
|
|
$
|
344,781
|
Natural gas
revenue
|
|
24,246
|
|
|
73,610
|
|
|
48,886
|
NGL revenue
|
|
8,557
|
|
|
35,863
|
|
|
16,658
|
Other
|
|
—
|
|
|
—
|
|
|
2,503
|
Total
revenue
|
|
258,664
|
|
|
891,288
|
|
|
412,828
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
Direct lease operating
expense
|
|
44,923
|
|
|
145,988
|
|
|
109,180
|
Insurance
|
|
4,283
|
|
|
15,342
|
|
|
10,743
|
Production
taxes
|
|
456
|
|
|
1,989
|
|
|
1,460
|
Total lease operating
expense
|
|
49,662
|
|
|
163,319
|
|
|
121,383
|
Workover and
maintenance expense
|
|
15,258
|
|
|
64,961
|
|
|
32,825
|
Depreciation,
depletion and amortization
|
|
84,145
|
|
|
288,719
|
|
|
157,352
|
Accretion
expense
|
|
10,930
|
|
|
35,344
|
|
|
19,295
|
General and
administrative expense
|
|
24,696
|
|
|
85,816
|
|
|
36,673
|
Total operating
expenses
|
|
184,691
|
|
|
638,159
|
|
|
367,528
|
Operating income
(loss)
|
|
73,973
|
|
|
253,129
|
|
|
45,300
|
Interest
expense
|
|
(23,857)
|
|
|
(90,114)
|
|
|
(80,934)
|
Price risk management
activities income (expense)
|
|
256,917
|
|
|
60,435
|
|
|
(27,563)
|
Other
income
|
|
2,175
|
|
|
1,012
|
|
|
329
|
Net income (loss)
before income taxes
|
|
309,208
|
|
|
224,462
|
|
|
(62,868)
|
Income tax
expense
|
|
(2,922)
|
|
|
(2,922)
|
|
|
—
|
Net income
(loss)
|
$
|
306,286
|
|
$
|
221,540
|
|
$
|
(62,868)
|
|
|
|
|
|
|
|
|
|
Net income (loss) per
common share:
|
|
|
|
|
|
|
|
|
Basic
|
$
|
5.66
|
|
$
|
4.81
|
|
$
|
(2.01)
|
Diluted
|
$
|
5.66
|
|
$
|
4.81
|
|
$
|
(2.01)
|
Weighted average
common shares outstanding:
|
|
|
|
|
|
|
|
|
Basic
|
|
54,156
|
|
|
46,058
|
|
|
31,244
|
Diluted
|
|
54,159
|
|
|
46,061
|
|
|
31,244
|
TALOS ENERGY
INC.
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
(In
thousands)
|
|
|
Three Months
Ended
December 31,
2018
|
|
Year Ended
December 31,
2018
|
|
Year Ended
December 31,
2017
|
Cash flows from
operating activities:
|
|
|
|
|
|
|
|
|
Net income
(loss)
|
$
|
306,286
|
|
$
|
221,540
|
|
$
|
(62,868)
|
Adjustments to
reconcile net income (loss) to net cash provided by operating
activities
|
|
|
|
|
|
|
|
|
Depreciation,
depletion, amortization and accretion expense
|
|
95,075
|
|
|
324,063
|
|
|
176,647
|
Impairment
|
|
244
|
|
|
244
|
|
|
260
|
Amortization of
deferred financing costs and original issue discount
|
|
664
|
|
|
4,253
|
|
|
2,383
|
Equity based
compensation, net of amounts capitalized
|
|
764
|
|
|
2,893
|
|
|
875
|
Price risk management
activities (income) expense
|
|
(256,917)
|
|
|
(60,435)
|
|
|
27,563
|
Net cash received
(paid) on settled derivative instruments
|
|
(16,345)
|
|
|
(111,147)
|
|
|
23,834
|
Settlement of asset
retirement obligations
|
|
(27,272)
|
|
|
(112,946)
|
|
|
(32,573)
|
Changes in operating
assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
3,674
|
|
|
(786)
|
|
|
(9,132)
|
Other current
assets
|
|
11,900
|
|
|
(2,624)
|
|
|
(4,441)
|
Accounts
payable
|
|
5,204
|
|
|
(48,825)
|
|
|
2,409
|
Other current
liabilities
|
|
(8,366)
|
|
|
32,044
|
|
|
46,364
|
Other non-current
assets and liabilities, net
|
|
4,847
|
|
|
15,171
|
|
|
4,732
|
Net cash provided by
operating activities
|
|
119,758
|
|
|
263,445
|
|
|
176,053
|
Cash flows from
investing activities:
|
|
|
|
|
|
|
|
|
Exploration,
development and other capital expenditures
|
|
(66,565)
|
|
|
(240,914)
|
|
|
(155,177)
|
Cash (paid) received
for acquisitions, net of cash acquired
|
|
—
|
|
|
278,409
|
|
|
(2,464)
|
Net cash provided by
(used in) investing activities
|
|
(66,565)
|
|
|
37,495
|
|
|
(157,641)
|
Cash flows from
financing activities:
|
|
|
|
|
|
|
|
|
Redemption of Senior
Notes and other long-term debt
|
|
(106)
|
|
|
(25,257)
|
|
|
(1,000)
|
Proceeds from Bank
Credit Facility
|
|
—
|
|
|
319,000
|
|
|
10,000
|
Repayment of Bank
Credit Facility
|
|
—
|
|
|
(54,000)
|
|
|
—
|
Repayment of LLC Bank
Credit Facility
|
|
—
|
|
|
(403,000)
|
|
|
(15,000)
|
Deferred financing
costs
|
|
(12)
|
|
|
(17,002)
|
|
|
—
|
Payments of capital
lease
|
|
(3,078)
|
|
|
(12,952)
|
|
|
(12,412)
|
Contributions from
Sponsors
|
|
—
|
|
|
—
|
|
|
—
|
Distributions to
Sponsors
|
|
—
|
|
|
—
|
|
|
—
|
Net cash provided by
(used in) financing activities
|
|
(3,196)
|
|
|
(193,211)
|
|
|
(18,412)
|
|
|
|
|
|
|
|
|
|
Net increase
(decrease) in cash, cash equivalents and restricted cash
|
|
49,997
|
|
|
107,729
|
|
|
—
|
Cash, cash
equivalents and restricted cash:
|
|
|
|
|
|
|
|
|
Balance, beginning of
period
|
|
91,165
|
|
|
33,433
|
|
|
33,433
|
Balance, end of
period
|
$
|
141,162
|
|
$
|
141,162
|
|
$
|
33,433
|
|
|
|
|
|
|
|
|
|
Supplemental Non-Cash
Transactions:
|
|
|
|
|
|
|
|
|
Capital expenditures
included in accounts payable and accrued liabilities
|
|
|
|
$
|
100,664
|
|
$
|
40,626
|
Supplemental Cash Flow
Information:
|
|
|
|
|
|
|
|
|
Interest paid, net of
amounts capitalized
|
|
|
|
$
|
53,476
|
|
$
|
47,994
|
SUPPLEMENTAL NON-GAAP INFORMATION
Certain financial information included in our financial results
are not measures of financial performance recognized by accounting
principles generally accepted in the
United States, or GAAP. These non-GAAP financial measures
are "Adjusted Net Income, Adjusted Earnings Per Share, Adjusted
EBITDA", "Adjusted EBITDA excluding hedges", "Adjusted EBITDA
Margin", "Adjusted EBITDA Margin Excluding Hedges", "Net Debt",
"Annualized Adjusted EBITDA", "Net Debt to Annualized Adjusted
EBITDA" and "PV-10." These disclosures may not be viewed as a
substitute for results determined in accordance with GAAP and are
not necessarily comparable to non-GAAP measures which may be
reported by other companies.
Reconciliation of Net Income (Loss) to Adjusted EBITDA;
reconciliation of Adjusted EBITDA margin
"Adjusted EBITDA" is not a measure of net income (loss) as
determined by GAAP. We use this measure as a supplemental measure
because we believe it provides meaningful information to our
investors. We define Adjusted EBITDA as net income (loss) plus
interest expense, income tax expense, depreciation, depletion and
amortization, accretion expense, loss on debt extinguishment,
transaction related costs, the net change in the fair value of
derivatives (mark to market effect, net of cash settlements and
premiums related to these derivatives), non-cash (gain) loss on
sale of assets, non-cash write-down of oil and natural gas
properties, non-cash write-down of other well equipment inventory
and non-cash equity based compensation expense. We believe the
presentation of Adjusted EBITDA is important 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. Adjusted EBITDA has limitations as an
analytical tool 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) or any
other measure of financial performance presented in accordance with
GAAP.
"Adjusted EBITDA excluding hedges" is defined as Adjusted EBITDA
plus net cash receipts (payments) on settled derivative
instruments. We believe the presentation of Adjusted EBITDA
excluding hedges is important to provide management and investors
with information about the impact of actual commodity price changes
on our business.
"Adjusted EBITDA Margin" is defined as Adjusted EBITDA divided
by Revenue, as a percentage. It is also defined as Adjusted EBITDA
divided by the total production volume, expressed in Boe, in the
period, and described as dollar per Boe. We believe the
presentation of Adjusted EBITDA Margin is important to provide
management and investors with information about how much we retain
in Adjusted EBITDA terms as compared to the revenue we generate and
how much per barrel we generate after accounting for certain
operational and corporate costs.
"Adjusted EBITDA margin excluding hedges" bears the same
definition and our intended utility of Adjusted EBITDA margin, but
using Adjusted EBITDA excluding hedges instead of Adjusted
EBITDA.
The following table presents a reconciliation of the GAAP
financial measure of net income (loss) to Adjusted EBITDA, from
Adjusted EBITDA to Adjusted EBITDA excluding hedges, Adjusted
EBITDA margins and Adjusted EBITDA margins excluding hedges for
each of the periods indicated (in thousands, except for Boe, $/Boe
and percentage data):
|
Three Months
Ended
September 30, 2018
|
|
Three Months
Ended
December 31, 2018
|
|
Year Ended
December 31, 2018
|
($
thousands)
|
As
Reported
|
|
As
Reported
|
|
As
Reported
|
|
Pro
Forma
|
Reconciliation of
net income (loss) to Adjusted EBITDA:
|
|
|
|
|
|
|
|
Net income
(loss)
|
$
13,109
|
|
$
306,286
|
|
$
221,540
|
|
$
274,577
|
Interest
expense
|
24,837
|
|
23,857
|
|
90,114
|
|
87,274
|
Income Tax
Expense
|
-
|
|
2,922
|
|
2,922
|
|
5,577
|
Depreciation,
depletion and amortization
|
87,808
|
|
84,145
|
|
288,719
|
|
319,762
|
Accretion
expense
|
10,162
|
|
10,930
|
|
35,344
|
|
45,278
|
Loss on debt
extinguishment
|
356
|
|
-
|
|
1,764
|
|
356
|
Transaction related
costs
|
7,595
|
|
4,579
|
|
32,484
|
|
3,323
|
Derivative fair value
(gain) loss(1)
|
53,330
|
|
(256,917)
|
|
(60,435)
|
|
(36,222)
|
Net cash receipts
(payments) on settled derivative
instruments(1)
|
(40,746)
|
|
(16,345)
|
|
(111,147)
|
|
(116,705)
|
Non-cash (gain) loss
on sale of assets
|
-
|
|
(1,710)
|
|
(1,710)
|
|
(1,710)
|
Non-cash write-down of
other well equipment inventory
|
-
|
|
244
|
|
244
|
|
244
|
Non-cash equity-based
compensation expense
|
570
|
|
764
|
|
2,893
|
|
3,241
|
Adjusted
EBITDA
|
$
157,021
|
|
$
158,755
|
|
$
502,732
|
|
$
584,995
|
Net cash receipts
(payments) on settled derivative
instruments(1)
|
40,746
|
|
16,345
|
|
111,147
|
|
116,705
|
Adjusted EBITDA
excluding hedges
|
197,767
|
|
175,100
|
|
613,879
|
|
701,700
|
Production and
Revenue:
|
|
|
|
|
|
|
|
Boe(2)
|
5,052
|
|
4,910
|
|
16,742
|
|
19,143
|
Revenue
|
282,868
|
|
258,664
|
|
891,288
|
|
1,013,184
|
Adjusted EBITDA
margin and Adjusted EBITDA excl hedges margin:
|
|
|
|
|
|
|
|
Adjusted EBITDA
divided by Revenue (%)
|
56%
|
|
61%
|
|
56%
|
|
58%
|
Adjusted EBITDA per
Boe(2)
|
$
31.08
|
|
$
32.33
|
|
$
30.03
|
|
$
30.56
|
Adjusted EBITDA excl
hedges divided by Revenue (%)
|
70%
|
|
68%
|
|
69%
|
|
69%
|
Adjusted EBITDA excl
hedges per Boe(2)
|
$
39.15
|
|
$
35.66
|
|
$
36.67
|
|
$
36.66
|
|
|
(1)
|
The adjustments for
the derivative fair value (gain) loss and net cash receipts
(payments) on settled derivative instruments have the effect of
adjusting net income (loss) for changes in the fair value of
derivative instruments, which are recognized at the end of each
accounting period because we do not designate commodity derivative
instruments as accounting hedges. This results in reflecting
commodity derivative gains and losses within Adjusted EBITDA on a
cash basis during the period the derivatives settled.
|
(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 Net Income and Adjusted Earnings
per Share
"Adjusted Net Income" is not a measure of net income (loss) as
determined by GAAP. We use this measure as a supplemental measure
because we believe it provides meaningful information to our
investors. We define Adjusted Net Income as net income (loss) plus
accretion expense, loss on debt extinguishment, transaction related
costs, the net change in the fair value of derivatives (mark to
market effect, net of cash settlements and premiums related to
these derivatives) and non-cash equity based compensation expense.
We believe the presentation of Adjusted Net Income is important 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 has limitations as an analytical tool 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) or any other measure
of financial performance presented in accordance with GAAP.
"Adjusted Earnings per Share" is defined as Adjusted Net Income
divided by the number of common shares.
|
Three Months
Ended
December 31, 2018
|
|
Year Ended
December 31, 2018
|
($
thousands)
|
As
Reported
|
|
As
Reported
|
|
Pro
Forma
|
Reconciliation of
Net Income to Adjusted Net Income:
|
|
|
|
|
|
|
|
|
Net income
|
$
|
306,286
|
|
$
|
221,540
|
|
$
|
274,577
|
Accretion
expense
|
|
10,930
|
|
|
35,344
|
|
|
45,278
|
Loss on debt
extinguishment
|
|
-
|
|
|
1,764
|
|
|
356
|
Transaction related
costs
|
|
4,579
|
|
|
32,484
|
|
|
3,323
|
Derivative fair value
(gain) loss(1)
|
|
(256,917)
|
|
|
(60,435)
|
|
|
(36,222)
|
Net cash receipts
(payments) on settled derivative
instruments(1)
|
|
(16,345)
|
|
|
(111,147)
|
|
|
(116,705)
|
Non-cash equity-based
compensation expense
|
|
764
|
|
|
2,893
|
|
|
3,241
|
Adjusted Net
Income
|
$
|
49,297
|
|
$
|
122,443
|
|
$
|
173,848
|
|
|
|
|
|
|
|
|
|
Weighted average
common shares outstanding:
|
|
|
|
|
|
|
|
|
Basic
|
|
54,156
|
|
|
46,058
|
|
|
46,058
|
Diluted
|
|
54,159
|
|
|
46,061
|
|
|
46,061
|
|
|
|
|
|
|
|
|
|
Net Income per
common share
|
|
|
|
|
|
|
|
|
Basic
|
$
|
5.66
|
|
|
4.81
|
|
|
5.96
|
Diluted
|
|
5.66
|
|
|
4.81
|
|
|
5.96
|
|
|
|
|
|
|
|
|
|
Adjusted Earnings
per share
|
|
|
|
|
|
|
|
|
Basic
|
$
|
0.91
|
|
|
2.66
|
|
|
3.77
|
Diluted
|
|
0.91
|
|
|
2.66
|
|
|
3.77
|
|
|
(1)
|
The adjustments for
the derivative fair value (gain) loss and net cash receipts
(payments) on settled derivative instruments have the effect of
adjusting net income (loss) for changes in the fair value of
derivative instruments, which are recognized at the end of each
accounting period because we do not designate commodity derivative
instruments as accounting hedges. This results in reflecting
commodity derivative gains and losses within Adjusted EBITDA on a
cash basis during the period the derivatives settled.
|
Reconciliation of Net Debt and Net Debt to Annualized
Adjusted EBITDA
"Net Debt" is not a measure of Debt as determined by GAAP. We
define Net Debt as the total Debt principal of the Company plus the
Capital Lease balance minus Cash.
"Net Debt to Annualized Adjusted EBITDA" is defined as Net Debt
divided by the Annualized Adjusted EBITDA.
We believe the presentation of Net Debt, Annualized Adjusted
EBITDA and Net Debt to Annualized 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.
|
December 31,
2018
|
Reconciliation of
Net Debt ($ thousand):
|
|
|
Debt
principal
|
$
|
672,495
|
Capital
Lease
|
|
93,668
|
Gross Debt
|
|
766,163
|
Cash
|
|
(139,914)
|
Net
Debt
|
$
|
626,249
|
|
|
|
Reconciliation of
Annualized Adjusted EBITDA:
|
|
|
Adjusted EBITDA for
the three month period ended September 30, 2018
|
|
157,021
|
Adjusted EBITDA for
the three month period ended December 31, 2018
|
|
158,755
|
Adjusted EBITDA for
the six month period ended December 31, 2018
|
|
315,776
|
|
|
×2
|
Annualized Adjusted
EBITDA
|
|
631,552
|
|
|
|
Reconciliation of
Net Debt to Adjusted EBITDA
|
|
|
Net Debt / Annualized
Adjusted EBITDA
|
|
1.0x
|
The Annualized Adjusted EBITDA information included in this
communication provides additional relevant information to our
investors and creditors. Talos needs to comply with a financial
covenant included in its Bank Credit Facility that requires it to
maintain a Net Debt to Annualized Adjusted EBITDA ratio equal to or
lower than 3.0x. For purposes of covenant compliance, Annualized
Adjusted EBITDA, with certain adjustments, is calculated the
following way:
- On December 31, 2018: two times
the Adjusted EBITDA for the six month period ended on December 31, 2018
- On March 31, 2019: Adjusted
EBITDA for the nine month period ended on March 31 divided by nine and multiplied by
12
- On June 30, 2019: Adjusted EBITDA
for the 12 month period ended on June 30,
2019
- For every subsequent quarter: trailing 12 month Adjusted
EBITDA
Reconciliation of PV-10 to Standardized Measure
"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. PV-10 is a computation of the standardized
measure of discounted future net cash flows on a pre-tax basis.
PV-10 is equal to the standardized measure of discounted future net
cash flows at the applicable date, before deducting future income
taxes, discounted at 10 percent. We believe that the presentation
of PV-10 is relevant and useful to investors because it presents
the discounted future net cash flows attributable to our estimated
net proved reserves prior to taking into account future corporate
income taxes, and it is a useful measure for evaluating the
relative monetary significance of our oil and natural gas
properties. Further, investors may utilize the measure as a basis
for comparison of the relative size and value of our reserves to
other companies without regard to the specific tax characteristics
of such entities. We use this measure when assessing the potential
return on investment related to our oil and natural gas properties.
PV-10, however, is not a substitute for the standardized measure of
discounted future net cash flows. Our PV-10 measure and the
standardized measure of discounted future net cash flows do not
purport to represent the fair value of our oil and natural gas
reserves.
The following table provides a reconciliation of PV-10 of our
proved reserves to the standardized measure of discounted future
net cash flows at December 31,
2018:
|
December 31,
2018
|
Standardized
measure
|
$
|
3,340,246
|
Plus: present value
of future income taxes discounted at 10%
|
|
585,017
|
PV-10
|
|
3,925,263
|
Logo -
https://mma.prnewswire.com/media/687245/Talos_Energy_Logo.jpg