Strong
Sustainable
Growth
2 0 1 8 A N N U A L R E P O R T
66696.indd 1
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Talos Energy is an independent oil
and gas company led by a management
team with decades of experience in
offshore exploration and production.
We are experts at acquiring operated
shelf and developed deepwater assets
in the Gulf of Mexico, then exploring,
exploiting and optimizing those assets
using innovative techniques and
cutting-edge seismic technologies.
N Y S E : T A L O
66696.indd 2
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L E T T E R T O S H A R E H O L D E R S
2018 was a historic year for Talos Energy
as we completed and fully integrated our
transformative merger with Stone Energy.
The merger signifi cantly expanded the scale
and operational breadth of Talos, and its
benefi ts were immediately noticeable.
Addi(cid:415) onally, the merger set the stage for us to more broadly share
our story and values as a publicly-traded company focused on posi(cid:415) ve
free cash fl ow, moderate, sustainable growth and balance sheet discipline.
In 2018, Talos delivered solid fi nancial performance and successfully
executed on a number of complex projects and we expect more of the
same in 2019 and beyond.
We also believe in our diff eren(cid:415) ated strategy, which we have refi ned
and validated over nearly two decades. We leverage our deep
understanding of the basins in which we operate, the US Gulf of Mexico
(“GOM”) and off shore Mexico, to iden(cid:415) fy and execute on highly economic
drilling projects. In the US GOM, we are able to capitalize on the ample
infrastructure and premium commodity pricing closely (cid:415) ed to Brent,
and the current market environment further allows us to engage in low
cost acquisi(cid:415) ons and infrastructure-led explora(cid:415) on and exploita(cid:415) on
with conven(cid:415) onal off shore wells. These conven(cid:415) onal wells boast lower
ini(cid:415) al declines as compared to onshore shale projects. Complimen(cid:415) ng
these more mature assets, off shore Mexico provides Talos early access
to an emerging basin with a signifi cant resource base in shallow water
depths that allows for low oil price break-evens and facilitates shorter
development cycles. I believe our por(cid:414) olio of assets will allow Talos to
con(cid:415) nue to grow at a measured pace in the US GOM while con(cid:415) nuing
to generate posi(cid:415) ve free cash fl ow, with the ini(cid:415) a(cid:415) on of produc(cid:415) on
from our off shore Mexico assets driving a step-change in Talos’s
produc(cid:415) on and cash fl ows in the future.
As we conduct our opera(cid:415) ons, we con(cid:415) nue to live by the highest
standards of health, safety and environmental focus and stewardship.
We believe in and support the communi(cid:415) es along the coasts of both
countries in which we operate, and we appreciate and deeply value
the symbio(cid:415) c rela(cid:415) onship that we have with these communi(cid:415) es.
Quality Asset Base
Talos has a solid asset base from which to grow our company. We are
currently execu(cid:415) ng on projects that will further stabilize our produc(cid:415) on
base and add signifi cant new volumes in 2019. In addi(cid:415) on, I’m very
excited about numerous drilling prospects that we have iden(cid:415) fi ed
and are currently evalua(cid:415) ng. Some of these prospects are on previously
held Talos leases while others have been added through our targeted
business development eff orts.
Upon closing of the merger with Stone, we focused on lower-risk
but high impact projects that could grow produc(cid:415) on in 2018 while
also posi(cid:415) oning the company for sustainable growth and maintaining
our ability to generate posi(cid:415) ve free cash fl ow for years to come. And
our team has delivered on these goals to date. Our 2018 produc(cid:415) on was
approximately 5% higher than pro forma 2017 Talos and Stone produc(cid:415) on
and we increased Proved Developed reserves by 20%, as compared to
our pro forma reserves as of December 31, 2017.
In November 2018, we ini(cid:415) ated the appraisal of the Zama discovery in
off shore Mexico. I am extremely proud of our team for the opera(cid:415) onal
excellence they have achieved in Mexico as we con(cid:415) nue to safely execute
the project ahead of schedule and under budget.
Our Proved Reserves as of December 31, 2018 were 151.7 MMBoe, and the
present value of these reserves discounted at 10% was $3.9 billion on a
pre-tax basis. Approximately 80% of these reserves reside in our US GOM
deepwater assets. Importantly, the Zama discovery in off shore Mexico
is not yet included in our proved reserves, per SEC guidelines, un(cid:415) l we
reach a Final Investment Decision (“FID”).
Low Entry Cost M&A and Best Prac(cid:415) ces Seismic Reprocessing
Leads to Be(cid:425) er Drilling Economics
A key aspect of our strategy is the variety of low cost business development
opportuni(cid:415) es that are available to us. Talos is well-posi(cid:415) oned as a credible
consolida(cid:415) on candidate in the US GOM and is ready to capitalize on the
lower valua(cid:415) on market dynamics driven by the over-alloca(cid:415) on of capital
in various onshore shale plays and the resul(cid:415) ng underinvestment in off shore
projects. We were able to exploit some consolida(cid:415) on opportuni(cid:415) es in
2018 A N N UA L REP O R T
66696.indd 3
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We continue
to live by the highest
standards of health,
safety and environmental
focus and stewardship.
— Timothy S. Duncan
2018 by closing three small bolt-on transac(cid:415) ons, including the Ram Powell
and Gunfl int assets in our Mississippi Canyon core area and the Green
Canyon 18 asset in our Green Canyon core area. These assets were acquired
at compelling valua(cid:415) on metrics and add to our scalable infrastructure
base upon which we will drive further growth.
In 2018, we commenced our appraisal program on the Zama discovery,
which includes three reservoir penetra(cid:415) ons that we expect will advance
our progress toward FID in 2020. Our fi rst penetra(cid:415) on was successful
and in line with our expecta(cid:415) ons, thus valida(cid:415) ng our geophysical models.
The appraisal program is expected to conclude by mid-year 2019.
Through these acquisi(cid:415) ons we have access to underu(cid:415) lized produc(cid:415) on
facili(cid:415) es. The combina(cid:415) on of infrastructure with throughput capacity in
an area where we have a deep geological exper(cid:415) se and our reprocessed
seismic allows Talos to develop drilling opportuni(cid:415) es with enhanced
economics. For example, since the announcement of our Green Canyon 18
acquisi(cid:415) on, we were able to acquire nearby leases with subsea prospects
through the semi-annual federal lease sale, we farmed into a lease as
the operator with a drill-ready prospect, and we purchased a stranded
discovery from Exxon, all of which will (cid:415) e into the Green Canyon 18 facility
if they are successful. These business development ac(cid:415) vi(cid:415) es around
acquired infrastructure exemplify our strategy of execu(cid:415) ng low-entry
cost acquisi(cid:415) ons in order to facilitate a(cid:425) rac(cid:415) ve economic explora(cid:415) on,
exploita(cid:415) on and development ac(cid:415) vi(cid:415) es.
Globally Recognized Zama Discovery
We opportunis(cid:415) cally entered off shore Mexico in the fi rst private sector
lease auc(cid:415) on in July 2015 and competed against a number of globally
recognized companies. We narrowly outbid the compe(cid:415) tors and were
awarded two Produc(cid:415) on Sharing Contracts covering a total of over
160,000 acres in Block 7 and Block 2, both in the Sureste Basin.
Our focus was on the explora(cid:415) on of the same geological trends that
we focus on in the US GOM, which are the Lower Pliocene through the
Miocene sec(cid:415) on. These geological trends have been under-explored in an
otherwise prolifi c basin off shore Mexico. A(cid:332) er proprietarily reprocessing
the available seismic data, in 2017 we drilled the fi rst off shore explora(cid:415) on
well by the private sector in the history of Mexico resul(cid:415) ng in the Zama
discovery, which was awarded the worldwide Discovery of the Year by
Wood Mackenzie. This is an extremely pres(cid:415) gious honor for Talos and
validates our ability to execute once-in-a-genera(cid:415) on projects. Projects
like Zama serve to propel Talos forward as a compe(cid:415) (cid:415) ve force and an
industry leader.
Building for the Future
I believe Talos maintains all of the cri(cid:415) cal elements necessary to con(cid:415) nue
to drive material, long-term value crea(cid:415) on for our shareholders. The
company’s strategy has been validated through mul(cid:415) ple commodity
cycles by focusing on an environment we know best, being both pa(cid:415) ent
and opportunis(cid:415) c, and conserva(cid:415) vely managing cash fl ow and leverage
to protect our balance sheet and capital program. Today, I am very
proud that Talos has been able to generate posi(cid:415) ve free cash fl ow while
so many companies in our industry have not been able to do so. We
have also accumulated a deep inventory of highly economic projects
and a globally recognized discovery in Zama, maintained a conserva(cid:415) ve
balance sheet and established ourselves as a trusted counterparty to
transact with. We believe that we have established a great founda(cid:415) on
to build on.
In 2018, we asked a lot of our team. We successfully integrated a
signifi cant merger while simultaneously taking our fi rst steps as a
publicly-traded company. We balanced a series of challenging projects
and acquisi(cid:415) ons that helped expand the scale of our business. And we
advanced our world-class Zama discovery towards future FID on schedule.
Throughout all of these ac(cid:415) vi(cid:415) es, we proved we can reliably generate
posi(cid:415) ve free cash fl ow, maintain appropriate debt and liquidity metrics and
deliver opera(cid:415) onally. I am pleased with all that Talos has accomplished
in 2018, but we’re already looking ahead. I am truly excited about what
the future holds.
Sincerely Yours,
Timothy S. Duncan
President and Chief Execu(cid:415) ve Offi cer
2
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TA LO S EN ERG Y
3/28/19 7:07 AM
O U R C U L T U R E
Talos is a growing company
that fosters an entrepreneurial
culture of development.
We pair the profi ciency of our geological and engineering staff with cu(cid:427) ng-edge science
and technology. By combining the infl uence of refi ned data and the transfer of knowledge
and best prac(cid:415) ces, we enrich our ability to access hydrocarbon reservoirs more safely,
resourcefully and in a manner that protects both the public and the environment.
The safety, health and welfare of employees, contractors, visitors and the public is our
number one priority and foremost core value. Talos off ers compe(cid:415) (cid:415) ve benefi ts, fl exible work
schedules to promote work/life balance, opportuni(cid:415) es for advancement and much more.
Every year since our incep(cid:415) on, Talos has been ranked a Top Workplace on the Houston Chronicle
Top Workplaces list. We strive to make a posi(cid:415) ve impact on our local community through
our Community Commi(cid:425) ee. Our community ma(cid:425) ers greatly to us, and has given our employees
so much that we feel it’s our responsibility to give back. We off er a $500 annual allowance
for each employee that can be used towards a not-for-profi t organiza(cid:415) on of their choice.
Whether it be a community fundraiser, a child’s athle(cid:415) c team, or a cause-worthy dona(cid:415) on,
our employees know Talos stands behind them.
In addi(cid:415) on, we also hold quarterly events with na(cid:415) onal and local organiza(cid:415) ons such as
Houston Children’s Charity, Houston Food Bank and Oilfi eld Helping Hands in order to
provide direct opportuni(cid:415) es for our employees to make a diff erence.
HSE AT TALOS ENERGY:
KEY 2018 TALOS HSE ACCOMPLISHMENTS INCLUDE:
2018 was an exci(cid:415) ng year for Talos. We acquired
new key assets, added talent and solidifi ed our
posi(cid:415) on as one of the premier operators in the Gulf
of Mexico. As a premier operator, it is our duty to
provide a safe environment for all employees and
contractors who work for us. We defi ne safety as
freedom from unacceptable risk of harm. We are
also obligated to be stewards of the environment
and take consistent sustainable measures to avoid
any adverse environmental impacts.
HSE will always be the top priority at Talos; while
compliance, produc(cid:415) on and cost are part of our
core business priori(cid:415) es, we cannot compromise
HSE for any reason.
» Successful integra(cid:415) on of mul(cid:415) ple HSE Management Systems (i.e. Stone,
Whistler) into one consolidated SEMS and Talos Safe Opera(cid:415) ng Prac(cid:415) ces
(TSOP) program
» Best in class INC and component ra(cid:415) o include a 22% drop in the rolling
average during the course of the year
» Delivery and comple(cid:415) on of Talos-specifi c eLearning to all off shore
employees and contractors with a permanently assigned rota(cid:415) on
» HSE expecta(cid:415) ons and deliverables, integrated into the front-end of
projects through HAZID/HAZOPS, DWOPS and project-specifi c HSE plans
» Processes developed to verify correc(cid:415) ve or preven(cid:415) ve ac(cid:415) ons from
Lessons Learned have been applied in the fi eld
» Mexico Risk Management Plan approved by ASEA for the Zama
appraisal program
» Ini(cid:415) ated formalized HSE reviews with high-risk and key contractors –
predominantly crane and ARO companies
2018 A N N UA L REP O R T
66696.indd 5
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U S O P E R A T I O N S
Phoenix Complex
The Phoenix Complex, located in our Green Canyon core area, is the biggest
producing asset in our por(cid:414) olio. The complex includes the Tornado fi eld, which
Talos discovered in 2016. Following the discovery, Talos drilled a second well in
the fi eld and began produc(cid:415) on from it in December 2017. In December of 2018,
Talos successfully drilled the third well in the Tornado fi eld and expects to
commence produc(cid:415) on during the second quarter of 2019.
Produc(cid:415) on from the Phoenix Complex fl ows to the Helix Producer-1 ship,
which successfully completed its regulatory dry-dock in the fi rst quarter of 2019.
In addi(cid:415) on to Tornado 3, we also drilled the Boris 3 well in January of 2019, which
we also expect to commence produc(cid:415) on during the second quarter of 2019.
Average produc(cid:415) on from the Phoenix Complex in 2018 was approximately
17,900 Boe per day and as of December 31, 2018, the proved reserves were
63.9 MMBoe, of which 78% was oil and 86% was liquids.
Pompano and Amberjack
Pompano and Amberjack were acquired as part of the merger with Stone Energy, and they provide
a solid founda(cid:415) on for growth in the area. In July of 2018, Talos commenced produc(cid:415) on from the
Mt. Providence well, which was a subsea (cid:415) eback to the Pompano produc(cid:415) on facility.
From the closing of the Stone Energy merger to December 31, 2018, average produc(cid:415) on from the
Mississippi Canyon core area was approximately 12,555 Boe per day, and as of December 31, 2018,
the proved reserves were 36.4 MMBoe, of which 83% was oil and 87% was liquids.
Ram Powell
Ram Powell was acquired from subsidiaries of Royal Dutch Shell, ExxonMobil
Corpora(cid:415) on and Anadarko Petroleum Corpora(cid:415) on in May of 2018, immediately
prior to the closing of the merger with Stone Energy. The asset is located in a
strategic area of the US Gulf of Mexico where oil discoveries have been made
in recent years. Talos expects to commence an explora(cid:415) on and exploita(cid:415) on
drilling campaign around Ram Powell in the coming years.
Average produc(cid:415) on from Ram Powell in 2018, from the closing of the Stone
Energy merger to December 31, 2018, was approximately 7,856 Boe per day.
As of December 31, 2018, proved reserves were 18.1 MMBoe, of which 59%
was oil and 72% was liquids.
4
66696.indd 6
TA LO S EN ERG Y
3/28/19 7:07 AM
M E X I C O O P E R A T I O N S
Block 7 – Zama Discovery
Block 7 was awarded to Talos in 2015 as part of the fi rst Mexican auc(cid:415) on
to the private sector in 80 years. In 2017, Talos drilled and discovered the
Zama fi eld, which was elected the “Discovery of the Year” by two diff erent
organiza(cid:415) ons, including Wood Mackenzie. In 2018, Talos commenced the
appraisal of the Zama Discovery, which confi rmed our geological,
geophysical and reservoir modeling es(cid:415) ma(cid:415) ons.
Pok-A-Tok
Chactun
Balamku West
Balamku East
Kaan
BLOCK 7
Zama
(Discovery)
Talos es(cid:415) mates that the Zama fi eld will contain 400-800 MMBoe of
Xlapak
recoverable resources.
Prospects
Discovery
Drilled
Future Drilling
Mexico
Inset Area
Prospects
Discovery
OUR TIMELINE
2 01 5
2 017
2 01 8
2 01 9
2 0 2 0
2 0 2 2
» Awarded
Block 7 PSC
» Zama Discovery
» Zama Appraisal
» Pre-Uni(cid:415) za(cid:415) on
Agreement with
Pemex
» Finalize Zama
» Final Investment
» First Oil
Appraisal
Decision
» Conclude Uni(cid:415) za(cid:415) on
Agreement with Pemex
Block 2/31
Talos was awarded the Block 2 Produc(cid:415) on Sharing Contract in 2015. In 2018, Talos
signed a cross-assignment of interest with a subsidiary of Pan American Energy to
acquire 25% in Block 31, in exchange for 25% in Block 2 to Pan American, subject
to government approvals.
In 2018, Talos concluded its technical study of Blocks 2 and 31. In 2019, we expect
to drill four wells in the area. Of those, the Olmeca project has been de-risked by
a Pemex well drilled in 2003. The 2019 drilling campaign will appraise the same
geological structure ini(cid:415) ally tested by Pemex.
Prospects
Drilled
Future Drilling
2018 A N N UA L REP O R T
66696.indd 7
Yaluk
BLOCK 2
Acan
Itzamna
BLOCK 31
Yula
Acan
West
Zapoteca
Olmeca
West
Mexico
Inset Area
Tolteca
Xaxamani 1
Olmeca
East
Olmeca
Shore
Drilled
Future Drilling
Prospects
5
3/28/19 7:07 AM
Texas
Talos
Seismic
Louisiana
Mississippi
Alabama
Florida
Pompano
Ram Powell
Viosca Knoll
Mississippi
Canyon
Phoenix Complex
Garden
Banks
Green
Canyon
Atwater
Valley
F I N A N C I A L H I G H L I G H T S 1
YEAR ENDED (cid:904)IN THOUSANDS(cid:905)
2018 PRO FORMA2
Revenues
Net Income (Loss)
Capital Expenditures
Total Long-term Debt3
RESERVES (cid:904)MMBOE(cid:905)
Proved Developed Producing (PDP)
Proved Developed Non-Producing (PDNP)
Proved Developed
Proved Undeveloped (PUD)
Total Proved
PRODUCTION
Sales volume (MMBoe)
Average daily produc(cid:415) on (MBoe/d)
$ 1,013.2
$
274.6
452.4
766.2
78.1
37.5
115.5
36.2
151.7
19.1
52.4
2018
891.3
221.5
390.6
766.2
78.1
37.5
115.5
36.2
151.7
16.7
45.9
1 For fi nancial repor(cid:415) ng treatment of business combina(cid:415) on, please refer to pages 63, 66 and F-9 of the 10-K document
contained in this annual report.
2 Refers to the combined performance of Talos and Stone from January 1, 2018, with the addi(cid:415) on of Ram Powell from closing
of that acquisi(cid:415) on on May 1, 2018.
3 Inclusive of Capital Lease.
Note: Reconcilia(cid:415) on of Standardized Measure of oil and gas to PV-10 refer to page 15 of the 10-K contained in this annual report.
2017
$
412.8
$
(62.9)
227.2
697.6
31.8
21.9
53.7
46.9
100.6
10.5
28.7
2016
258.8
(208.1)
145.8
701.2
39.7
26.1
65.8
37.9
103.7
8.9
24.4
Talos
Seismic
Veracruz
Block 2
Block 7
Puebla
Veracruz
Oaxaca
6
Tabasco
Block 31
Chiapas
Yucatan
Campeche
Campeche
Talos Energy Blocks
GUATEMALA
TA LO S EN ERG Y
66696.indd 8
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
⌧ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018
OR
(cid:4)
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR
THE TRANSITION PERIOD FROM TO
Commission File Number 01-38497
Talos Energy Inc.
(Exact name of Registrant as specified in its Charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
333 Clay Street, Suite 3300
Houston, TX
(Address of principal executive offices)
82-3532642
(I.R.S. Employer
Identification No.)
77002
(Zip Code)
Registrant’s telephone number, including area code: (713) 328-3000
Securities registered pursuant to Section 12(b) of the Act: Common Stock, Par Value $0.01 Per Share; Common stock traded on the NYSE stock market
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES (cid:4) NO ⌧
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. YES (cid:4) NO ⌧
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past
90 days. YES ⌧ NO (cid:4)
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-
T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). YES ⌧ NO (cid:4)
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be
contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. ⌧
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging
growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of
the Exchange Act.
Large accelerated filer
Non-accelerated filer
(cid:4)
(cid:4)
Emerging growth company
(cid:4)
Accelerated filer
Smaller reporting company
⌧
(cid:4)
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised
financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. (cid:4)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES (cid:4) NO ⌧
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, based on the closing price of the shares of common
stock on The NYSE Stock Market on June 30, 2018, was $281,311,750.
The number of shares of registrant’s Common Stock outstanding as of March 6, 2019 was 54,155,805.
Portions of the registrant’s definitive proxy statement relating to the Annual Meeting of Shareholders are incorporated by reference into Part III of this report.
6696_10K.pdf
TABLE OF CONTENTS
GLOSSARY ......................................................................................................................................................
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS ......................
PART I
Items 1
Item 1A
Item 1B
Item 2
Item 3
Item 4
Item 5
Item 6
Item 7
Business .....................................................................................................................................
Risk Factors ................................................................................................................................
Unresolved Staff Comments.......................................................................................................
Properties ....................................................................................................................................
Legal Proceedings.......................................................................................................................
Mine Safety Disclosures .............................................................................................................
PART II
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases
Of Equity Securities....................................................................................................................
Selected Financial Data ..............................................................................................................
Management’s Discussion and Analysis of Financial Condition and Results of Operations ..........
Item 7A
Quantitative and Qualitative Disclosures About Market Risk ...................................................
Item 8
Item 9
Item 9A
Item 9B
Item 10
Item 11
Item 12
Item 13
Item 14
Item 15
Item 16
Financial Statements and Supplementary Data ..........................................................................
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ..........
Controls and Procedures .............................................................................................................
Other Information .......................................................................................................................
PART III
Directors, Executive Officers and Corporate Governance .........................................................
Executive Compensation ............................................................................................................
Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters....................................................................................................................
Certain Relationships and Related Transactions, and Director Independence ...........................
Principal Accounting Fees and Services.....................................................................................
Exhibits, Financial Statement Schedules....................................................................................
Form 10-K Summary..................................................................................................................
PART IV
Page
3
5
7
31
55
55
56
57
58
59
60
79
80
80
80
81
82
82
82
82
82
83
87
2
6696_10K.pdf
GLOSSARY
The following are abbreviations and definitions of certain terms used in this document, which are commonly used
in the oil and natural gas industry:
Barrel or Bbl. One stock tank barrel, or 42 United States gallons liquid volume.
Boe. One barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one barrel of crude oil or
condensate.
Boepd. Barrels of oil equivalent per day.
Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water one
degree Fahrenheit.
Completion. The installation of permanent equipment for the production of oil or natural gas.
Deepwater. Water depths of more than 600 feet.
Developed acres. The number of acres that are allocated or assignable to producing wells or wells capable of
production.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same
individual geological structural feature or stratigraphic condition.
Gross acres or gross wells. The total acres or wells in which the Company owns a working interest.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
MBblpd. One thousand barrels of crude oil or other liquid hydrocarbons per day.
MBoe. One thousand barrels of oil equivalent.
MBoepd. One thousand barrels of oil equivalent per day.
Mcf. One thousand cubic feet of natural gas.
Mcfpd. One thousand cubic feet of natural gas per day.
MMBoe. One million barrels of oil equivalent.
MMBtu. One million British thermal units (“Btus”).
MMcf. One million cubic feet of natural gas.
MMcfpd. One million cubic feet of natural gas per day.
Net acres or net wells. The sum of the fractional working interests the Company owns in gross acres or gross wells.
NGL. Natural gas liquid. Hydrocarbons which can be extracted from wet natural gas and become liquid under
various combinations of increasing pressure and lower temperature. NGLs consist primarily of ethane, propane,
butane and natural gasoline.
NYMEX. The New York Mercantile Exchange.
NYMEX Henry Hub. Henry Hub is the major exchange for pricing natural gas futures on the New York Mercantile
Exchange. It is frequently referred to as the Henry Hub Index.
Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that
proceeds from the sale of such production exceed production expenses and taxes.
Proved developed reserves. In general, proved reserves that can be expected to be recovered from existing wells
with existing equipment and operating methods. The Securities and Exchange Commission provides a complete
definition of developed oil and gas reserves in Rule 4-10(a)(6) of Regulation S-X.
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Proved reserves. Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and
engineering data, can be estimated with reasonable certainty to be economically producible – from a given date
forward, from known reservoirs and under existing economic conditions, operating methods and government
regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates
that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the
estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably
certain that it will commence the project within a reasonable time.
Proved undeveloped reserves. In general, proved reserves that are expected to be recovered from new wells on
undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. The
Securities and Exchange Commission provides a complete definition of undeveloped oil and gas reserves in
Rule 4-10(a)(31) of Regulation S-X.
PV-10. The present value of estimated future revenues, discounted at 10% annually, to be generated from the
production of proved reserves determined in accordance with Securities and Exchange Commission guidelines, net
of estimated production and future development costs, using prices and costs as of the date of estimation without
future escalation, without giving effect to (i) non-property related expenses such as general and administrative
expenses, derivatives, debt service and future income tax expense or (ii) depreciation depletion and amortization
expense.
SEC. The Securities and Exchange Commission.
SEC pricing. The unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the
period beginning January 1, 2018 and ending December 1, 2018, adjusted by lease for market differentials (quality,
transportation, fees, energy content, and regional price differentials). The Securities and Exchange Commission
provides a complete definition of prices in “Modernization of Oil and Gas Reporting” (Final Rule, Release Nos.
33-8995; 34-59192).
Shelf. Water depths up to 600 feet.
Standardized Measure: The present value of estimated future net revenue to be generated from the production of
proved reserves, determined in accordance with the rules, regulations or standards established by the SEC and the
Financial Accounting Standards Board (“FASB”) (using prices and costs in effect as of the date of estimation), less
future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of
future net revenue. For the year ending December 31, 2018, we were subject to U.S. federal and state income taxes
at the entity level. For the tax years ending December 31, 2017 and 2016, we were not subject to U.S. federal or
state income taxes (in most states) at the entity level and thus made no provision for U.S. federal or state income
taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative
transactions.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would
permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved
reserves.
Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating
activities on the property and a share of production.
WTI or West Texas Intermediate. A light crude oil produced in the United States with an API gravity of
approximately 38-40 and the sulfur content is approximately 0.3%.
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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
The information in this report 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
report, 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 report, the words
“could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “forecast,” “may,” “objective, “plan,”
and similar expressions are intended to identify forward-looking statements, although not all forward-looking
statements contain such identifying words. These forward-looking statements are based on our current expectations
and assumptions about future events and are based on currently available information as to the outcome and timing
of future events. These forward-looking statements are based on management’s current belief, based on currently
available information, as to the outcome and timing of future events. Forward-looking statements may include
statements about:
• business strategy;
•
reserves;
• exploration and development 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 plans;
• availability of pipeline connections on economic terms;
• competition, government regulations 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;
•
leasehold or business acquisitions on desired terms;
• costs of developing properties;
• general economic conditions;
• credit markets;
•
impact of new accounting pronouncements on earnings in future periods;
• 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;
• uncertainty regarding our future operating results and our future revenues and expenses; and
• plans, objectives, expectations and intentions contained in this report that are not historical.
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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, 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 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 the other
risks discussed in Part I, Item 1A, “Risk Factors” which are included herein.
Reserve engineering is a process of estimating underground accumulations of oil, natural gas and NGLs that
cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data,
the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of
drilling, testing and production activities may justify upward or downward revisions of estimates that were made
previously. If significant, such revisions would change the schedule of any further production and development
drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs
that are ultimately recovered.
Should one or more of the risks or uncertainties described herein 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 report 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 report.
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Items 1. Business
Overview
PART 1
We are a technically driven independent exploration and production company with operations in the United
States Gulf of Mexico and offshore Mexico. Our focus in the United States Gulf of Mexico is the acquisition of
deep water assets with existing infrastructure and the exploration, exploitation and development of such assets in
key geological trends. Offshore Mexico provides us high impact exploration opportunities in an oil rich emerging
basin. We use our access to an extensive seismic database and our deep technical expertise to identify, acquire and
exploit attractive assets with robust economic profiles. As of December 31, 2018, deepwater assets represent 83%
of our proved reserves.
We have historically focused our operations in the Gulf of Mexico because we believe this area provides us
with favorable geologic and economic conditions, including multiple reservoir formations, comprehensive geologic
databases, extensive infrastructure and an attractive acquisition market and because we have significant experience
and technical expertise in the basin. Additionally, we have access to state-of-the-art three-dimensional seismic data,
some of which is aided by new and enhanced reprocessing techniques that have not been previously applied to our
current acreage position. We use our broad regional seismic database and our reprocessing efforts to generate a
large and expanding inventory of high-quality prospects, which we believe greatly improves our development and
exploration success. The application of our extensive seismic database, coupled with our ability to effectively
reprocess this seismic data, allows us to both optimize our organic drilling program and better evaluate acquisition
and joint venture opportunities.
In order to determine the most attractive returns for our drilling program, we employ a disciplined portfolio
management approach to stochastically evaluate all of our drilling prospects, whether they are generated
organically from our existing acreage or are acquisition or joint venture opportunities. We add to and reevaluate
our inventory in order to deploy capital as efficiently as possible.
Talos Energy Inc. was incorporated on November 14, 2017 under the laws of the state of Delaware for the
purpose of effecting the previously disclosed business combination between Talos Energy LLC (“Talos Energy”)
and Stone Energy Corporation (“Stone”), pursuant to which each of Talos Energy and Stone became our wholly-
owned subsidiary. We refer to this business combination as the “Stone Combination,” and its date of
consummation, May 10, 2018, as the “Closing Date.” In addition, as used in this report and unless otherwise
indicated or the context otherwise requires, references to “we,” “us,” “our,” “Talos Energy Inc.,” “Talos” and the
“Company” refer to, from and after the Closing Date, Talos Energy Inc. and its consolidated subsidiaries and prior
to the Closing Date, Talos Energy and its consolidated subsidiaries.
Prior to the Stone Combination, Talos Energy Inc. had not conducted any material activities other than those
incident to its incorporation and certain matters contemplated by that certain Transaction Agreement (the
“Transaction Agreement”), dated as of November 21, 2017, among Stone, Talos Energy, us and Sailfish Merger
Sub Corporation (“Merger Sub”). The transactions contemplated by the Transaction Agreement were accounted for
as a business combination in accordance with accounting principles generally accepted in the United States of
America (“GAAP”), with Talos Energy treated as the “acquirer” and Stone treated as the “acquired” company for
financial reporting purposes. Accordingly, the reported financial condition and results of operations of Talos
Energy Inc. reflect the assets, liabilities and results of operations of Talos Energy (as our predecessor) prior to the
Closing Date, and do not reflect the assets, liabilities and results of operations of Stone prior to such date. The
assets, liabilities and results of operations of Talos Energy Inc. have not been, and will not be, restated
retrospectively to reflect the historical financial position or results of operations of Stone.
For more information on Talos Energy, our predecessor for financial reporting purposes, please read “—
Talos Energy LLC.” For more information on the Stone Combination, please read “— Stone Combination.”
Talos Energy LLC
Talos Energy was formed in 2011 under the laws of the state of Delaware and commenced commercial
operations on February 6, 2013. Prior to February 6, 2013, Talos Energy had incurred only certain general and
administrative expenses associated with the start-up of its operations.
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On February 3, 2012, Talos Energy completed a transaction with funds and other alternative investment
vehicles managed by Apollo Management VII, L.P. and Apollo Commodities Management, L.P., with respect to
Series I (“Apollo Funds”), and entities controlled by or affiliated with Riverstone Energy Partners V, L.P.
(“Riverstone Funds”, and together with the Apollo Funds, the “Sponsors”) and members of management pursuant
to which Talos Energy received a private equity capital commitment.
On February 6, 2013, Talos Energy acquired all of the equity of Energy Resource Technology GOM, LLC
(“ERT”) and its subsidiary from Helix Energy Solutions Group, Inc. (“Helix”) for approximately $625.2 million
(inclusive of purchase price and working capital adjustments of approximately $15.2 million), and payments for
ongoing guarantees from Helix to third-parties. Additionally, Talos Energy agreed to assign Helix an overriding
royalty interest in certain properties acquired in the transaction at closing. We refer to this purchase as the “ERT
Acquisition.” The ERT Acquisition was effective December 1, 2012 and closed on February 6, 2013. Prior to the
closing of the ERT Acquisition, the Sponsors and members of management had invested an aggregate of
approximately $325 million in Talos Energy to fund a portion of the ERT Acquisition as well as to fund other asset
purchases.
In September 2015, Talos Energy, together with consortium partners Sierra Oil and Gas S. de R.L de C.V.
(“Sierra”) and Premier Oil Plc (“Premier”, and together with Talos Energy and Sierra, the “Consortium”) executed
two Production Sharing Contracts (“PSCs”) with the National Hydrocarbons Commission (“CNH”), Mexico’s oil
and gas regulator, for Blocks 2 and 7 of Round 1. The PSCs were awarded to the Consortium during the first tender
of Mexico’s oil and natural gas fields in over 80 years. Blocks 2 and 7 are located in the Sureste Basin, a prolific
proven hydrocarbon province, in the shallow waters off the coast of Mexico’s Veracruz and Tabasco states,
respectively. Blocks 2 and 7 contain approximately 162,904 gross acres with numerous high impact prospects in
well-established and emerging plays. In 2017, the Consortium drilled Zama-1, the initial exploration well in Block
7, resulting in the discovery of the Zama Field. As of December 31, 2018, we were in the process of appraising the
discovery.
Stone Combination
On the Closing Date, we consummated the transactions contemplated by the Transaction Agreement and
Talos Energy and Stone became our wholly-owned subsidiaries. Pursuant to the Transaction Agreement, the
following transactions, among others, occurred: (i) Stone underwent a reorganization pursuant to which Merger
Sub merged with and into Stone, with Stone continuing as the surviving corporation and our direct wholly-owned
subsidiary (the “Merger”), and each share of Stone’s common stock outstanding immediately prior to the Merger
(other than treasury shares held by Stone, which were cancelled for no consideration) was converted into the right
to receive one share of our common stock, par value $0.01 (the “Common Stock”) and (ii) the Sponsors contributed
all of the equity interests in Talos Production LLC (“Talos Production”) (which at that time owned 100% of the
equity interests in Talos Energy) to us in exchange for an aggregate of 31,244,085 shares of Common Stock (the
“Sponsor Equity Exchange”).
Concurrently with the consummation of the Transaction Agreement, we consummated the transactions
contemplated by that certain Exchange Agreement, dated as of November 21, 2017 (the “Exchange Agreement”),
among us, Stone, the Talos Issuers (defined below), the various lenders and noteholders of the Talos Issuers listed
therein, certain funds controlled by Franklin Advisers, Inc. (“Franklin”) (such controlled noteholders, the “Franklin
Noteholders”), and certain clients of MacKay Shields LLC (“MacKay Shields”) (such noteholders, the “MacKay
Noteholders”), pursuant to which (i) the Apollo Funds and Riverstone Funds contributed $102.0 million in
aggregate principal amount of 9.75% senior notes due 2022 (“9.75% Senior Notes”) issued by Talos Production
and Talos Production Finance, Inc. (together, the “Talos Issuers”) to us in exchange for an aggregate of 2,874,049
shares of Common Stock (the “Sponsor Debt Exchange”); (ii) the holders of second lien bridge loans (“11.00%
Bridge Loans”) issued by the Talos Issuers exchanged such 11.00% Bridge Loans for $172.0 million aggregate
principal amount of 11.00% Second-Priority Senior Secured Notes due 2022 of the Talos Issuers (“11.00% Senior
Secured Notes”) and (iii) Franklin Noteholders and MacKay Noteholders exchanged their 7.50% Senior Secured
Notes due 2022 issued by Stone (“7.50% Stone Senior Notes”) for $137.4 million aggregate principal amount of
11.00% Senior Secured Notes.
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Substantially concurrent therewith, we consummated an exchange offer and consent solicitation, pursuant to
which the holders of the 7.50% Stone Senior Notes, excluding the 7.50% Stone Senior Notes held by the Franklin
Noteholders and the MacKay Noteholders, exchanged their 7.50% Stone Senior Notes for 11.00% Senior Secured
Notes and a cash payment, and a solicitation of consents to proposed amendments to the 7.50% Stone Senior Notes.
Approximately $81.5 million in aggregate principal amount of the 7.50% Stone Senior Notes were validly
tendered, and approximately $6.1 million in aggregate principal amount of 7.50% Stone Senior Notes remained
outstanding as of the Closing Date.
As a result of the closing of the transactions contemplated by the Transaction Agreement and the Exchange
Agreement (the “Transactions”) the former stakeholders of Talos Energy held approximately 63% of the
Company’s outstanding Common Stock and the former stockholders of Stone held approximately 37% of the
Company’s outstanding Common Stock as of the Closing Date.
Business Strategy
We intend to increase stockholder value through the following strategies:
Grow Production, Reserves and Cash Flow by Developing Our Attractive Asset Base in a Capital Efficient
Manner.
Our team is focused on continuously improving capital efficiency, and we believe the combination of our
experience and the existing infrastructure in the U.S. Gulf of Mexico will allow us to continue to benefit from
attractive finding and development costs. We also benefit from our proven ability to increase production from
legacy fields and identified projects. Furthermore, we intend to use our technical expertise and seismic database to
find additional drilling projects in proximity to our existing assets.
Expand Our Reserves and Production Through Lease Acquisitions and Diversified Business Development.
We intend to deploy our expertise and seismic resources to identify and acquire attractive leasehold acreage
in federal lease sales for the U.S. Gulf of Mexico. In many cases, acreage available in the federal lease sales has not
been evaluated with the latest reprocessed seismic data, resulting in an opportunity for us to identify previously
unknown drilling prospects. In the latest federal lease of the August 2018 sale, we were the fifth most active bidder
in the U.S. Gulf of Mexico, and we were the high bidder on 14 lease blocks. During that sale, we focused on blocks
that adjoin our existing properties, and we have identified specific prospects through reprocessed seismic data. In
addition, our proven track record through the drillbit and our strong financial position frequently attracts potential
drilling partners. Our deep industry relationships, technical expertise and extensive regional seismic database allow
us to effectively identify and evaluate these third-party proposed drilling projects. We intend to continue to
strategically pursue these types of drilling projects with other operators on a selected basis.
Evaluate and Pursue Accretive Acquisitions.
We intend to continue to opportunistically expand our asset base by evaluating the supply of acquisition
opportunities in the U.S. Gulf of Mexico and offshore Mexico. Our acquisition strategy is focused on operated
deepwater assets with a geological setting that can benefit from our ability to use our seismic database and our
reprocessing expertise to re-evaluate the acquired assets. By applying our disciplined valuation methodology, we
seek to reduce the risk of underperformance of the acquired properties while maintaining upside potential. In
addition, we may consider acquisition opportunities in other offshore basins with analogous geologies that are
suitable for our operational and technical expertise to the extent we believe they will create additional value for
stockholders.
Maintain High Operatorship to Leverage Our Technical Expertise.
We operate properties that generate approximately 94% of our production, and we strive to maintain a
majority of operational control over our producing properties. We believe that maintaining control of our
production enables us to apply leading practices to every aspect of our operations. In addition, maintaining high
operatorship allows us to leverage our technical team’s deep regional experience and modern seismic expertise in
order to generate attractive investment opportunities on our properties while concurrently controlling execution.
Lastly, maintaining operational control allows us to sustain our focus on maximizing our returns through reduced
development cycle times and efficient capital utilization.
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Properties
United States Gulf of Mexico Properties
Our area of focus in the United States is the Gulf of Mexico deepwater, which is generally considered to
comprise water depths over 600 feet. Our strategy is focused in areas characterized by clearly defined
infrastructure, well known production history and geological well control, which reduces operational and
investment risk. We believe the potential for large discoveries and increasing success rates in the sub-salt and mini-
basin lower Pliocene and Miocene plays have resulted in increased industry focus on this area over the last decade.
We believe our deepwater operations in the U.S. Gulf of Mexico provide significant potential growth
opportunities through our planned drilling program. Through our technical approach of starting with known
hydrocarbon systems and applying modern seismic reprocessing techniques, we have generated a substantial
inventory of deepwater prospects that we believe are capable of delivering predictable production growth. We
focus our exploitation and exploration efforts around our existing infrastructure. This subsea tie-back strategy
allows for better project economics and shorter periods between a discovery and production.
In the United States, at December 31, 2018, we had an interest in 271.0 gross producing wells (228.9
net producing wells) on 885,888 gross (624,891 net) total acres, of which 477,190 gross (342,604 net) are
developed acres. We operate properties that contain 98% of our proved reserves at December 31, 2018.
At December 31, 2018, our core properties in the United States, which represent approximately 68% of our
2018 production and 78% of our December 31, 2018 proved reserves are illustrated below:
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The following table sets forth certain information regarding our core properties in the United States:
Operating Area
United States Core Properties
Mboe
Estimated Proved Reserves
% Natural
Gas
% NGLs
% Oil
Full Year
2018 Net
Production
(MBoe)(4)
% Proved
Developed
Phoenix(1)
Pompano(2)
Ram Powell
Amberjack
63,931
28,206
18,094
8,148
United States Core Properties Subtotal 118,379
Other United States Properties(3)
Total United States
33,360
151,739
78%
81%
59%
88%
77%
65%
74%
14%
14%
28%
10%
16%
30%
19%
8%
5%
13%
2%
7%
5%
7%
55%
6,536
100%
2,486
100%
1,854
477
100%
76% 11,353
78%
5,389
76% 16,742
(1)
(2)
(3)
(4)
Production volumes and estimated proved reserves include the Tornado, Boris and Typhoon areas of the Phoenix Field, all of which tie
back to the HP-I.
Production volumes and estimated proved reserves include the Pompano and Cardona Fields, both of which tie back to the Pompano
Platform.
Other United States Properties includes Gulf of Mexico shelf and deepwater.
Production for the Pompano, Ram Powell and Amberjack Core Properties are presented from the Closing Date of the Stone Combination
through December 31, 2018.
Phoenix Field—The Phoenix Field is comprised of six operated blocks, which include Green Canyon Blocks
236, 237, 238, 280, 281, and 282, located in the deepwaters offshore Louisiana.
There are no conventional fixed or moored production platforms in the field-instead the subsea wells are tied
back to a dynamically positioned floating production unit, the Helix Producer I (“HP-I”). The HP-I interconnects
with the Phoenix Field through a production buoy that can be disconnected if the HP-I cannot maintain its position
on station, such as the approach of a hurricane or in the event of a mechanical problem with the dynamic
positioning system. There are eight active wells in the Phoenix Field and the average net daily production for the
year ended December 31, 2018 was 17,907 Boepd.
Pompano Field— The Pompano Field is comprised of seven operated blocks which include Viosca Knoll
Blocks 989 and 990, and Mississippi Canyon Blocks 26, 27, 28, 29 and 72 located in the deepwaters offshore
Louisiana. The Pompano Field’s three current subsea systems are tied back to a fixed leg platform with a total of 23
active wells. The field’s average net daily production since the Closing Date of the Stone Combination was 10,534
Boepd.
Ram Powell Field— The Ram Powell Field is comprised of six operated blocks which include Viosca Knoll
Blocks 911, 912, 913, 955, 956 and 957 located in the deepwaters offshore Louisiana. The Ram Powell Field has
eight active dry tree wells that are located on a tension leg platform in Viosca Knoll Block 956. The field’s average
net daily production since the Closing Date of the Stone Combination was 7,856 Boepd.
Amberjack Field—The Amberjack Field is comprised of three operated blocks which include Mississippi
Canyon Block 108, 109 and 110. The Amberjack Field has 29 active conventional dry tree wells located on a fixed
structure platform in Mississippi Canyon Block 109. The field’s average net daily production since the Closing
Date of the Stone Combination was 2,021 Boepd.
Mexico Properties
In September 2015, we, together with the Consortium, executed a PSC with the CNH for each of Blocks 2
and 7 of Round 1. The PSCs were awarded to the Consortium during the first tender of Mexico’s oil and natural
gas fields in over 80 years. Blocks 2 and 7 are located in the Sureste Basin, a prolific proven hydrocarbon province,
in the shallow waters off the coast of Mexico’s Veracruz and Tabasco states, respectively. Blocks 2 and 7 contain
approximately 162,904 gross acres with numerous high impact prospects in well-established and emerging plays.
Our participation interest (“PI”) in Block 2 is currently 20% and our PI in Block 7 is 35%. We are the operator of
Block 7.
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The PSCs include a cost recovery feature pursuant to which eligible costs in relation to the minimum work
program activities are recoverable in-kind at a rate of 125% of costs from future production volumes. Production
volumes are allocated in-kind between the Consortium and the United Mexican States on a monthly basis based on
the contractual value of the hydrocarbons as defined in the PSCs. Up to 60% of the monthly contractual value of
the hydrocarbons will be allocated to the Consortium to recover eligible costs incurred in petroleum activities.
Eligible costs exceeding 60% of the current month contractual value of the hydrocarbons will be recoverable in
future periods. Between 7.5% and 14% of the contractual value of the oil will be allocated to the United Mexican
States in the form of a royalty, depending upon the price of a barrel of oil, with a collar between $48.00 and
$100.00 per Bbl. The allocation for the royalty on natural gas is 0% when the price per MMBtu is below $5.00 and,
if the natural gas price exceeds $5.00 per MMBtu, the royalty allocation percentage is calculated as the price per
MMBtu divided by 100. The remaining value of the hydrocarbons after the allocation for cost recovery and
royalties is considered operating profit under the PSCs. The allocation of operating profit to the Consortium after
the allocation for cost recovery and royalties on Blocks 2 and 7 is 44% and 31%, respectively. Additionally, in the
event that the cumulative project internal rate of return in any one month exceeds 25%, the barrels of oil allocated
to the Consortium after cost recovery (“Profit Oil”) is reduced on a sliding scale. The reduction in Profit Oil varies
linearly between 0% and 75% of the entitled amount. The maximum 75% reduction occurs once the cumulative
project internal rate of return meets or exceeds 40%.
At December 31, 2018, our core properties in Mexico are presented in the following acreage map:
• Block 7— In July 2017, we completed drilling operations on the offshore Mexico Zama-1 exploration well
in Block 7, reaching a total depth of 13,480 feet. The Zama-1 well is the first offshore exploration well to
be drilled in Mexico by the private sector. Well results confirmed the base of the reservoir section, with no
penetration of an oil-water contact. The gross oil bearing interval is over 1,100 feet with petrophysical
data indicating excellent rock properties and an oil sample with 30 degree American Petroleum Institute
(“API”) gravity oil. The well has been suspended as a future producer. We are now analyzing all the data
gathered from the Zama-1 well and evaluating the optimal methods for appraisal and development of the
discovery. These contingent resources are not included in proved reserves.
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In the fourth quarter of 2018, we spud the Zama-2 well, the first appraisal well to be drilled in the field.
The Zama-2 well confirmed the results of the original Zama-1 exploration well. The Zama appraisal
campaign is expected to be completed by mid-year 2019. If the appraisal of the Zama Field confirms our
initial estimates, we expect to announce a Final Investment Decision in 2020, following Mexican
government approval of the development plan. In addition to Zama, other prospects within Block 7 are
being analyzed and matured to potentially be drilled over the next several years, assuming an extension of
the Exploration Period is approved by the CHH. See Part II, Item 8. Financial Statements and
Supplementary Data — Note 4 — Property, Plant & Equipment for further detail on Mexico properties.
Pre-Unitization Agreement with Pemex. In September 2018, we and our consortium partners in Block 7
signed a Pre-Unitization Agreement (“PUA”) with Pemex Exploration y Produccion (“Pemex”) related to
certain tracts within the Amoca-Yaxche-03 allocation and the contiguous Block 7 PSC. Both areas are
situated in the offshore portion of the Sureste Basin. The two year PUA enables information sharing
related to the Zama discovery and potential extension into Pemex’s neighboring block. The PUA has been
approved by the Mexican Secretariat of Energy (“SENER”).
• Block 2—In September 2018, we entered into a transaction (the “Hokchi Cross Assignment”) with Hokchi
Energy, S.A. de C.V. (“Hokchi”), a subsidiary of Pan American Energy LLC (“PAE”), to cross assign
25% PIs in Block 2 and Block 31. Our assignment of a 25% PI in Block 2 to Hokchi closed on December
21, 2018, and Hokchi has assumed operator responsibilities with respect to Block 2. Hokchi’s assignment
of an interest in Block 31 to us will be completed upon final approval by the CNH. In addition, Premier
exercised its option to reduce its PI in Block 2 to zero and assign a 5% PI to each of Sierra and us. Such
assignment is also subject to CNH’s approval. Upon completion of the Hokchi Cross Assignment and
Premier’s option exercise, we will own a 25% PI in each of Block 2 and Block 31, and Hokchi will be the
operator of both blocks.
In February 2019, the CHN granted approval for drilling in the Acan-1 exploration well in Block 2.
Operations are expected to begin in March 2019 and extend into the second quarter. Soon thereafter, we
plan to participate in two prospects in Block 31. Beyond the Acan prospects, we believe that Blocks 2 and
31 contain a significant portfolio of compelling prospects with strong technical ties to offsetting
discoveries.
Recent Developments
Gunflint Acquisition
On January 11, 2019, pursuant to a Purchase Sale Agreement with Samson Offshore Mapleleaf, LLC we
acquired an approximate 9.6% non-operated working interest in the Gunflint Field located in the Mississippi
Canyon area for $29.6 million.
HP-I Dry-Dock Downtime
During the first quarter of 2019, the HP-I entered into its regulatory required dry-dock period. Regulators
require the ship to go to dry-dock twice every five years. On May 7, 2019, the HP-I completed its dry-dock
requirement and departed the shipyard. After a period of sea trials, we expect production from the Phoenix Field to
commence in late March 2019. The annualized production impact of the shut-in in the Phoenix Field is estimated to
be between 2.0 MBoepd and 3.0 MBoepd.
Drilling and Exploration Activities
The Tornado 3 well’s drilling operations completed in December 2018 and completed in January 2019. We
expect production to commence by early second quarter, 2019, with an expected net production rate between 10.0
MBoepd and 15.0 MBoepd. We are the operator and own a 65% working interest.
The Boris 3 wells started drilling operations in January 2019 and completed in February 2019. We expect
production to commence in the second quarter of 2019, with a net production between or 2.8 Mboepd and 4.6
MBoepd. We are the operator and own a 100% working interest.
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Summary of Reserves
Our estimated proved reserves totaled 151.7 MMBoe at December 31, 2018. The following table summarizes
our estimated proved reserves as of December 31, 2018, 2017 and 2016 which are all located in the United States.
December 31, 2018
Proved Developed Producing
Proved Developed Non-Producing
Total Proved Developed
Proved Undeveloped
Total Proved
December 31, 2017(1)
Proved Developed Producing
Proved Developed Non-Producing
Total Proved Developed
Proved Undeveloped
Total Proved
December 31, 2016(1)
Proved Developed Producing
Proved Developed Non-Producing
Total Proved Developed
Proved Undeveloped
Total Proved
Summary of Proved Reserves
Oil
(MBbls)
Natural Gas
(MMcf)
NGL
(MBbls) Mboe
Percent of
Total
Proved
Standardized
Measure
(in thousands)
PV-10
(in
thousands)
62,162
23,368
85,530
27,009
112,539
69,409 4,342 78,072
61,955 3,762 37,456
131,364 8,104 115,528
39,660 2,592 36,211
171,024 10,696 151,739
$2,510,213
680,942
3,191,155
734,108
$ 3,340,246 $3,925,263
76%
24%
23,656
13,804
37,460
35,344
72,804
37,161 1,930 31,780
40,416 1,385 21,924
77,577 3,315 53,704
50,079 3,232 46,921
127,656 6,547 100,625
$ 776,786
270,363
1,047,149
760,520
$ 1,807,669 $1,807,669
53%
47%
28,757
16,996
45,753
26,613
72,366
52,062 2,277 39,711
44,060 1,754 26,094
96,122 4,031 65,805
54,482 2,205 37,897
150,604 6,236 103,702
$ 707,315
242,877
950,192
385,843
$ 1,336,035 $1,336,035
63%
37%
(1)
Does not include reserves acquired in the Stone Combination, which closed in May 10, 2018.
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 the standardized measure of discounted future net cash flows
to PV-10 of our proved reserves at December 31, 2018, 2017, and 2016.
December 31,
December 31,
December 31,
Standardized measure
Present value of future income taxes discounted at 10%
PV-10
2018
2017(1)
$ 3,340,246 $ 1,807,669 $ 1,336,035
—
$ 3,925,263 $ 1,807,669 $ 1,336,035
585,017
—
2016(1)
(1)
For the tax years ended December 31, 2017 and 2016, we were not a taxpaying entity for federal income tax purposes, we were not subject
to federal or state income taxes and thus made no provision for federal or state income taxes in the calculation of our standardized
measure.
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Changes in Proved Developed Reserves
Our proved developed reserves as of December 31, 2018 increased by 61.8 MMBoe to 115.5 MMBoe from
53.7 MMBoe at December 31, 2017, a 115% increase. This increase was due to:
• acquisitions of 58.0 MMBoe from the Stone Combination and 3.5 MMBoe from the Whistler Acquisition,
for more information, see Part II, Item 8. Financial Statements and Supplementary Data — Note 3 —
Acquisitions;
• Positive revisions of 4.5 MMboe;
• Proved undeveloped reserves (“PUD”) conversions of 10.0 MMBoe
• extensions and discoveries of 2.5 MMBoe primarily attributable to wells drilled in Ewing Bank Block 305
(1.3 MMBoe) and Ship Shoal Block 224 (0.5 MMBoe); and offset by
• production of 16.7 MMBoe
Development of Proved Undeveloped Reserves
The following table discloses our estimated PUD reserve activities during the year ended December 31,
2018:
Proved undeveloped reserves at December 31, 2017
Changes during the year:
Extensions and discoveries
Revisions of previous estimates
Acquired
Conversion to Proved Developed Producing reserves
Total proved undeveloped reserves changes
Proved undeveloped reserves at December 31, 2018
Oil, Natural Gas
and NGLs
(MBoe)
Future
Development
Costs
(in thousands)
46,921 $
447,721
3,108
(4,515)
654
(9,957)
(10,710)
36,211 $
27,000
(3,996)
8,367
(82,426)
(51,055)
396,666
Our PUD reserves at December 31, 2018 decreased by 10.7 MMBoe, or 23% primarily due to:
Extensions and Discoveries. We added 3.1 MMBoe of PUD reserves through an evaluation of Green Canyon
Block 18 which was initially acquired in the Whistler Acquisition. See Part II, Item 8. Financial Statements and
Supplementary Data — Note 3 — Acquisitions, for more information.
Revisions of Previous Estimates. Downward reserves revisions of 4.5 MMBoe primarily due to timing of
development of certain PUD locations to move beyond 5 years of 3.3 MMBoe and downward revisions of 1.2
MMBoe. The revisions were caused by a new geological data and changes in overall project economics, and
expiration of a block. Future development costs related to the PUD revisions decreased by $4.0 million primarily
due to a review of completion strategy and optimization of capital expenditures in the Phoenix Field.
Acquired. We added a 0.7 MMBoe PUD reserves in Bayou Hebert Field through the Stone Combination.
Conversion to Proved Developed Producing. 2017 PUD to proved developed conversions of 10.0 MMBoe
are primarily attributable to the Phoenix Field, Tornado #3ST and two wells in Main Pass Block 74, A8ST and
A11ST.
We annually review all PUD reserves to ensure an appropriate plan for development exists. Our PUD
reserves are required to be converted to proved developed reserves within five years of the date they are first
booked as PUD reserves. Future development costs associated with our PUD reserves at December 31, 2018
totaled approximately $396.7 million, primarily attributable the Phoenix Field’s $317.3 million future development
costs. When considering capital expenditures associated with other exploration projects and abandonment
obligations, we expect to fund the development of PUD reserves using cash flows from operations and, if needed,
availability under the Bank Credit Facility, in each future annual period prior to the five year expiration. Our 2019
drilling program includes development of PUD reserves, and the conversion rate may not be uniform due to
obligatory wells, newly acquired PUD reserves and production performance targets.
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Internal Controls over Reserve Estimates and Reserve Estimation Procedures
At December 31, 2018, 2017 and 2016, 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. (“NSAI”), independent petroleum engineers and
geologists, as described in further detail below.
Our policies regarding internal controls over the determination of reserves estimates require reserves reserve
quantities, reserves categorization, future producing rates, future net revenue and the present value of such future
net revenue to prepared using the definitions set forth in Regulation S-X, Rule 4-10(a) and subsequent SEC staff
interpretations and guidance. These internal controls, which are intended to ensure reliability of our reserves
estimations, include, but are not limited to, the following:
• Reserve information, as well as models used to estimate such reserves, is stored on secure database
applications to which only authorized personnel are given access rights consistent with their assigned job
function.
• A comparison of historical expenses is made to the lease operating costs in the reserve database.
•
Internal reserves estimates are reviewed by well and by area by our reservoir engineers. A variance
analysis by well to the previous year-end reserve report is performed.
• Reserve estimates are reviewed and approved by certain members of senior management, including our
President and Chief Executive Officer.
• We engaged NSAI to perform an independent audit of our processes and the reasonableness of our
estimates of proved reserves at December 31, 2018, 2017 and 2016. Our management requires that the
independent petroleum engineers and geologist’s and our reserve quantities and calculation of the net
present value of the reserves, collectively, vary by no more than 10% in the aggregate, in accordance with
SPEE auditing standards.
• Data is transferred to NSAI through a secure file transfer protocol site.
• Material reserve variances are discussed among NSAI, as applicable, our internal reservoir engineers and
our Director of Reserves to ensure the best estimate of remaining reserves.
Because these estimates depend on many assumptions, any or all of which may differ substantially from
actual results, reserve estimates may be different from the quantities of oil, natural gas and NGLs that are
ultimately recovered.
During the reserves audit, NSAI did not independently verify the accuracy and completeness of information
and data furnished by us with respect to ownership interests, oil, natural gas and NGL production, well test data,
historical costs of operation and development, product prices or any agreements relating to current and future
operations of the fields and sales of production. However, if in the course of the examination something came to
the attention of NSAI that brought into question the validity or sufficiency of any such information or data, NSAI
did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had
independently verified such information or data. When compared on a well by well basis, some of our estimates are
greater and some are less than the estimates of NSAI. Given the inherent uncertainties and judgments that go into
estimating proved reserves, differences between internal and external estimates are to be expected. NSAI
determined that its estimates of reserves have been prepared in accordance with the definitions and regulations of
the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of
reserves in future years, under existing economic and operating conditions, consistent with the definition in Rule 4-
10(a)(24) of Regulation S-X. NSAI issued unqualified audit opinions on our reserves as of December 31, 2018,
2017 and 2016 based upon its evaluations. NSAI concluded that our estimates of reserves were, in the aggregate,
reasonable and have been prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil
and Gas Reserves Information promulgated by the SPEE. The NSAI reports are filed as exhibits this report.
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Technologies Used in Reserve Estimation
The SEC’s reserves rules allow the use of techniques that have been proved effective by actual production
from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that
establishes reasonable certainty. The term “reasonable certainty” implies a high degree of confidence that the
quantities of oil, natural gas and/or NGLs actually recovered will equal or exceed the estimate. To achieve
reasonable certainty, our internal reservoir engineers employed technologies that have been demonstrated to yield
results with consistency and repeatability. The technologies and economic data used in the estimation of our proved
reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data,
historical price and cost information and property ownership interests. The accuracy of the estimates of our
reserves is a function of:
•
the quality and quantity of available data and the engineering and geological interpretation of that data;
• estimates regarding the amount and timing of future operating costs, development costs and workovers, all
of which may vary considerably from actual results;
•
•
future prices of oil, natural gas and NGLs, which may vary considerably from those mandated by the SEC;
and
the judgment of the persons preparing the estimates.
Qualifications of Primary Internal Engineer
Floyd Bone, our Director of Reserves, is the technical person primarily responsible for overseeing the
preparation of our internal reserve estimates and for coordinating reserve audits conducted by NSAI. Mr. Bone has
over 44 years of industry experience with positions of increasing responsibility, including 36 years as a reserves
evaluator or manager. Mr. Bone’s further professional qualifications include a State of Texas Professional
Engineering License, extensive internal and external reserve training and asset evaluation. In addition, Mr. Bone is
an active participant in industry reserve seminars and professional industry groups, and has been a member of the
SPEE for over 44 years. Mr. Bone reports directly to our Vice President of Corporate Development.
Drilling Activity
The following table sets forth our drilling activity:
Exploratory and Appraisal Wells(1)
Development Wells(1)
Total
Productive(2)
Productive(2)
Gross Net Gross Net Gross Net Gross Net Gross Net Gross Net Gross Net
Dry(3)
Dry(3)
Total
Total
December 31, 2018
United States
Mexico
Total
December 31, 2017
United States
Mexico
Total
December 31, 2016
United States
Mexico
Total
— — 1.0 0.1 1.0 0.1 5.0 5.0 — — 5.0 5.0 6.0 5.1
— — — — — — — — — — — — — —
— — 1.0 0.1 1.0 0.1 5.0 5.0 — — 5.0 5.0 6.0 5.1
4.0 3.7 — — 4.0 3.7 — — — — — — 4.0 3.7
— — — — — — — — — — — — — —
4.0 3.7 — — 4.0 3.7 — — — — — — 4.0 3.7
1.0 0.7 — — 1.0 0.7 — — — — — — 1.0 0.7
— — — — — — — — — — — — — —
1.0 0.7 — — 1.0 0.7 — — — — — — 1.0 0.7
(1)
(2)
(3)
As of December 31, 2018, two exploratory and appraisal wells have been excluded from the table until a determination is made if the wells
have found proved reserves. Also excluded from the table are two development wells awaiting completion. These wells are shown as
“Wells Suspended or Waiting on Completion” in the table below.
A productive well is an exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities
to justify completion as an oil or natural gas producing well. Productive wells are included in the table in the year they were determined to
be productive, as opposed to the year the well was drilled.
A dry well is an exploratory or development well that is not a productive well. Dry wells are included in the table in the year they were
determined not to be productive well, as opposed to the year the well was drilled.
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As of December 31, 2018, we had wells actively drilling or completing and wells suspended or awaiting
completion, as follows:
Actively Drilling or Completing
Wells Suspended or Waiting on
Completion
United States
Mexico
Total
Productive Wells
Exploratory
Gross Net
— —
Development
Gross Net
2.0
0.4 — —
1.7
2.0
0.4
Gross
1.7 —
1.0
1.0
Exploratory
Net
Development
Gross Net
— — —
0.4 — —
0.4 — —
1.0
1.0
The number of our productive wells is as follows:
Crude oil
Natural gas
Total (1)
(1)
3 gross wells have dual completions.
Acreage
December 31, 2018
Gross
Net
201.0
70.0
271.0
178.3
50.6
228.9
Gross and net developed and undeveloped acreage is as follows:
Developed Acres
Net
Gross
Undeveloped Acres
Gross
Net
Total Acres
Gross
Net
December 31, 2018
United States
Deepwater
Shelf
Total United States
Mexico
Total
168,714 131,360 252,895 161,895 421,609 293,255
308,476 211,244 155,803 120,392 464,279 331,636
477,190 342,604 408,698 282,287 885,888 624,891
49,809
477,190 342,604 571,602 332,096 1,048,792 674,700
— 162,904 49,809 162,904
—
Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of
whether or not such acreage contains proved reserves. Included within undeveloped acreage are those leased acres
(held by production under the terms of a lease) that are not within the spacing unit containing, or acreage assigned
to, the productive well holding such lease. The terms of our leases on undeveloped acreage as of December 31,
2018 are scheduled to expire as shown in the table below (the terms of which may be extended by drilling and
production operations):
2019(1)
2020
2021
2022
2023 and beyond
Total
Undeveloped Acreage
Gross
Net
234,199
33,280
24,200
50,439
229,484
571,602
98,424
25,556
14,984
34,008
159,124
332,096
(1)
The 2019 undeveloped acreage includes 162,904 gross and 49,809 net acres of Block 2 and 7 from Mexico’s PSCs for Round 1. The PSCs
allows us to file for a 2 year extension.
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Crude Oil, Natural Gas and NGL Production, Prices and Production Costs
Our production volumes, average sales prices and average production costs are as follows:
Production Volumes:
Crude oil (MBbls)
Natural gas (MMcf)
NGLs (MBbls)
Total (MBoe)
Percent of Boe from crude oil
Average Sales Price (including commodity derivatives):
Crude oil (MBbls)
Natural gas (MMcf)
NGLs (MBbls)
Average (MBoe)
Average Sales Price (excluding commodity derivatives):
Crude oil (MBbls)
Natural gas (MMcf)
NGLs (MBbls)
Average (MBoe)
Average Direct LOE and Workover per Boe (1)
Year Ended December 31,
2017
2018
2016
11,771
22,771
1,176
16,742
7,048
16,308
706
10,472
5,126
19,001
603
8,896
70%
67%
58%
$
$
$
$
$
$
$
$
$
57.12
3.16
30.50
46.60
66.42
3.23
30.50
53.24
12.60
$
$
$
$
$
$
$
$
$
52.46
2.93
23.59
41.46
48.92
3.00
23.59
39.18
13.56
$
$
$
$
$
$
$
$
$
68.46
3.24
15.81
47.44
38.55
2.25
15.81
28.08
16.77
(1)
Includes oil and natural gas operating costs and major maintenance expense and excludes production taxes.
Crude Oil, Natural Gas and NGL Production, Prices and Production Costs—Significant Fields
Phoenix Field
The following table sets forth certain information regarding our production volumes, average sales prices and
average production costs for the Phoenix Field, which consisted of 15% or more of our total estimated proved
reserves at December 31, 2018, 2017 and 2016:
Production Volumes:
Crude oil (MBbls)
Natural gas (MMcf)
NGLs (MBbls)
Average (MBoe)
Percent of Boe from crude oil
Year Ended December 31,
2017
2018
2016
5,160
5,311
491
6,536
4,657
5,203
520
6,044
2,600
3,235
312
3,451
79%
77%
75%
Average Sales Price (excluding commodity derivatives):
Crude oil (MBbls)
Natural gas (MMcf)
NGLs (MBbls)
Average (MBoe)
Average Direct LOE and Workover per Boe (1)(2)
$
$
$
$
$
65.11
3.57
29.04
56.48
4.17
$
$
$
$
$
48.75
3.48
24.49
42.66
4.27
$
$
$
$
$
37.88
2.84
18.97
32.92
12.30
(1)
In response to the Tornado II’s production commencement during the fourth quarter of 2016, we entered into a new production handling
agreement (“PHA”) with certain working interest partners. The fees from this PHA were recorded as a reduction to lease operating
expense beginning in 2017.
(2)
Includes oil and natural gas operating costs and major maintenance expense and excludes production taxes.
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Pompano Field
The following table sets forth certain information regarding our production volumes, average sales prices and
average production costs for the Pompano Field, which consisted of 15% or more of our total estimated proved
reserves at December 31, 2018. The information below includes the period form the Closing Date of the Stone
Combination, May 10, 2018, through December 31, 2018.
Production Volumes:
Crude oil (MBbls)
Natural gas (MMcf)
NGLs (MBbls)
Total (MBoe)
Percent of Boe from crude oil
Average Sales Price (excluding commodity derivatives):
Crude oil (MBbls)
Natural gas (MMcf)
NGLs (MBbls)
Average (MBoe)
Average Direct LOE and Workover per Boe (1)(2)
Year Ended
December 31,
2018
2,042
1,758
151
2,486
82%
69.06
3.50
30.95
61.08
1.60
$
$
$
$
$
(1)
(2)
The Pompano Field has PHAs with certain working interest partners. The PHAs are recorded as a reduction to lease operating expense.
Includes oil and natural gas operating costs and major maintenance expense and excludes production taxes.
Expenditures and Costs Incurred
For information on property development, exploration and acquisition costs, see Part II, Item 8. Financial
Statements and Supplementary Data — Note 14 — Supplemental Oil and Gas Disclosures.
Title to Properties
We believe that we have satisfactory title to our oil and natural gas properties in accordance with generally
accepted industry standards. Individual properties may be subject to burdens such as royalty, overriding royalty,
and carried, net profits, working and other outstanding interests customary in the industry. In addition, interests
may be subject to obligations or duties under applicable laws or burdens such as production payments, ordinary
course liens incidental to operating agreements and for current taxes and development obligations under oil and
natural gas leases. As is customary in the industry in the case of undeveloped properties, often limited investigation
of record title is made at the time of acquisition. Title search investigations are made prior to the consummation of
an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.
To the extent title opinions or other investigations reflect defects affecting such undeveloped properties, we are
typically responsible for curing any such title defects at our expense.
Commodity Price Risks and Price Risk Management Activities
Production from our properties is marketed using methods that are consistent with industry practices. Sales
prices for oil and natural gas production are negotiated based on factors normally considered in the industry, such
as an index or spot price, price regulations, distance from the well to the pipeline, commodity quality and
prevailing supply and demand conditions. We enter into derivative contracts on our oil and natural gas production
primarily to stabilize cash flows and reduce the risk and financial impact of downward commodity price
movements on commodity sales. For additional information regarding our commodity price risk and commodity
derivative instruments, see Part II, Item 7A — Quantitative and Qualitative Disclosures About Market Risk.
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Significant Customers
Oil and natural gas companies spend capital on exploration, drilling and production operations expenditures,
the amount of which is generally dependent on the prevailing view of future oil and natural gas prices which are
subject to many external factors which may contribute to significant volatility in future prices. We market
substantially all of our oil, natural gas and NGL production from the properties we operate and those we do not
operate. Our customers consist primarily of major oil and gas companies, well-established oil and pipeline
companies and independent oil and natural gas producers and suppliers. We perform ongoing credit evaluations of
our customers and provide allowances for probable credit losses when necessary. For the year ended December 31,
2018, 65% and 18% of our oil, natural gas and NGL revenues were attributable to Shell Trading (US) Company
and Phillips 66, respectively, which are the customers that individually represented 10% or more of our oil, natural
gas and NGL revenues.
Competitive Conditions
The oil and natural gas business is highly competitive in the exploration for and acquisition of reserves, the
acquisition of oil and natural gas leases, equipment and personnel required to find and produce reserves and in the
gathering and marketing of oil, natural gas and NGLs. We compete with large integrated oil and natural gas
companies as well as independent exploration and production companies. Certain of our competitors may have
significantly more financial or other resources available to them. In addition, certain of the larger integrated
companies may be better able to respond to industry changes, including price fluctuation, oil and natural gas
demand and governmental regulations.
However, we believe our high quality oil-weighted production base, proven expertise in utilizing seismic
technology to identify, evaluate and develop exploitation and exploration opportunities, balanced mix of assets in
the Gulf of Mexico deep and shallow waters and significant operating control give us a strong competitive position
relative to many of our competitors.
Seasonality of Business
Weather conditions affect the demand for, and prices of, oil and natural gas. Due to these seasonal
fluctuations, our results of operations for individual quarterly periods may not be indicative of the results that may
be realized on an annual basis. Generally, but not always, the demand for gas decreases during the summer months
and increases during the winter months. Seasonal anomalies such as mild winters or hot summers may impact
general seasonal changes in demand.
Insurance Matters
Our oil and natural gas operations are subject to risks incident to the operation of oil and gas wells, including
but not limited to uncontrolled flows of oil, gas, brine or well fluids into the environment, blowouts, cratering,
mechanical difficulties, fires, explosions or other physical damage, pollution or other risks, any of which could
result in substantial losses to us. In addition, our oil and natural gas properties are located in the Gulf of Mexico,
which makes us more vulnerable to tropical storms and hurricanes. These hazards can cause personal injury or loss
of life, severe damage to and destruction of property and equipment, pollution or environmental damage and the
suspension of operations. Damages arising from such occurrences may result in lawsuits asserting large claims.
Insurance may not be sufficient or effective under all circumstances or against all hazards to which we may be
subject. A successful claim for which we are not fully insured could have a material adverse effect on our financial
condition, results of operations and cash flow. Although we obtain insurance against some of these risks, we cannot
insure against all possible losses. As a result, any damage or loss not covered by insurance could have a material
adverse effect on our financial condition, results of operations and cash flow.
We have insurance policies to cover some of our risk of loss associated with our operations, and we maintain
the amount of insurance we believe is prudent. However, not all of our business activities can be insured at the
levels we desire because of either limited market availability or unfavorable economics (limited coverage for the
underlying cost).
Our general property damage insurance provides varying ranges of coverage based upon several factors,
including well counts and the cost of replacement facilities. Our general liability insurance program provides a
limit of $500 million for each occurrence and in the aggregate, and includes varying deductibles. Our Offshore
Pollution Act insurance is subject to a maximum of up to $150 million for each occurrence and in the aggregate,
including a $100,000 retention. Coverage is provided for damage to our assets resulting from a named Gulf of
Mexico windstorm; however, such coverage is subject to a maximum of $155 million per named windstorm and in
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the aggregate, and is also subject to a maximum of $25 million per occurrence retention. We separately maintain an
operators extra expense policy with additional coverage for an amount up to $500 million for Gulf of Mexico
deepwater drilling wells, $150 million for Gulf of Mexico shelf drilling wells, $75 million for Gulf of Mexico
producing and shut-in wells, $50 million for drilling and workover in inland waters and $25 million for drilling and
workover in onshore fields that would cover costs involved in making a well safe after a blow-out or getting the
well under control; re-drilling a well to the depth reached prior to the well being out of control or blown out; costs
for plugging and abandoning the well; and costs for clean-up and containment and for damages caused by
contamination and pollution. For our Mexico insurance policies, we maintain $250 million in operators extra
expense coverage for operations and $500 million per occurrence and aggregate limit for general liability.
We may increase or decrease insurance coverage around our key strategic assets, including potentially
purchasing catastrophic bond instruments. Our highest value assets, which are located in the Phoenix Field,
produce through the HP-I floating production system, which has the capability to disconnect and move away in the
event of a storm, mitigating the risk of property damage.
We customarily have reciprocal agreements with our customers and vendors in which each contracting party
is responsible for its respective personnel for liability related to work performed for us. Under these agreements, we
generally are indemnified against third party claims related to the injury or death of our customers’ or vendors’
personnel, subject to the application of various states’ laws.
Government Regulation
Exploration and development and the production and sale of oil, natural gas and NGLs are subject to
extensive federal, state, local and foreign regulations. An overview of these regulations is set forth below. We do
not believe that compliance with existing requirements will have a material adverse effect on our financial position,
results of operations or cash flows. However, current regulatory requirements may change, currently unforeseen
environmental incidents may occur or past non-compliance with environmental laws or regulations may be
discovered. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict
the future cost or impact of complying with such laws. Although the regulatory burden on the oil and natural gas
industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do
not affect us any differently or to any greater or lesser extent than they affect others in our industry with similar
types, quantities and locations of production.
General Overview
Our oil and natural gas operations are subject to various federal, state, local and foreign laws and regulations.
Generally speaking, these regulations relate to matters that include, but are not limited to:
•
location of wells;
• size of drilling and spacing units or proration units;
• number of wells that may be drilled in a unit;
• unitization or pooling of oil and natural gas properties;
• drilling and casing of wells;
•
issuance of permits in connection with exploration, drilling and production;
• well production;
• spill prevention plans;
• protection of private and public surface and ground water supplies;
• emissions permitting or limitations;
• protection of endangered species;
• use, transportation, storage and disposal of fluids and materials incidental to oil and natural gas operations;
• surface usage and the restoration of properties upon which wells have been drilled;
• calculation and disbursement of royalty payments and production taxes;
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•
requirements for the posting of supplemental bonds or providing other forms of financial assurance for
P&A obligations;
• plugging and abandoning of wells; and
•
transportation of production.
Outer Continental Shelf (“OCS”) Regulation. Our operations on federal oil and natural gas leases in the Gulf
of Mexico are subject to regulation by the Bureau of Safety and Environmental Enforcement (“BSEE”) and the
Bureau of Ocean Energy Management (“BOEM”), both agencies of the U.S. Department of the Interior (“DOI).
These leases contain relatively standardized terms and require compliance with detailed BSEE and BOEM
regulations and orders issued pursuant to various federal laws, including the federal Outer Continental Shelf Lands
Acts (“OCSLA”). These laws and regulations are subject to change, and many new requirements, including those
related to safety, permitting and performance, were imposed by BSEE and BOEM subsequent to the 2010
Deepwater Horizon incident. For offshore operations, lessees must obtain BOEM approval for exploration,
development and production plans prior to the commencement of such operations. In addition to permits required
from other agencies such as the U.S Environmental Protection Agency (the “EPA”), lessees must obtain a permit
from BSEE prior to the commencement of drilling and comply with regulations governing, among other things,
engineering and construction specifications for production facilities, safety procedures, P&A of wells on the OCS,
calculation of royalty payments and the valuation of production for this purpose, and removal of facilities.
These rules are frequently subject to change. For example, in 2016, BSEE published a final rule on well
control that, among other things, imposes rigorous standards relating to the design, operation and maintenance of
blow-out preventers, real-time monitoring of deepwater, high temperature, high pressure drilling activities, and
enhanced reporting requirements. Pursuant to President Trump’s Executive Orders dated March 28, 2017, and
April 28, 2017 (the “Executive Orders”), BSEE initiated a review of the well control regulations to determine
whether the rules are consistent with the stated policy of encouraging energy exploration and production, while
ensuring that any such activity is safe and environmentally responsible. In October 2017, BSEE announced, in a
report published by the DOI, that it is considering several revisions to the regulations and that it is in the process of
determining the most effective way to engage stakeholders in the process. In another example, the BSEE published
a final rule in September 2018 amending its production safety systems regulations, which includes the imposition
of operational and design standards and the removal of the requirement of offshore operators to certify through an
independent third party that their critical safety and pollution prevention equipment (e.g. subsea safety equipment,
including blowout preventers) is operation and functioning as designed in the most extreme conditions.
In a third example, BOEM published a proposed rule in April 2016 that would update existing air emissions
requirements relating to offshore oil and natural gas activity on the OCS. BOEM regulates these air emissions in
connection with its review of exploration and development plans, rights of way (“ROWs”) and rights of use
(“RUEs”) applications. The proposed rule would bolster existing air emissions requirements by, among other
things, requiring the reporting and tracking of the emissions of all pollutants defined by the EPA to affect human
health and public welfare. Pursuant to the Executive Orders, BOEM is reviewing the proposed air quality rule. In
October 2017, the DOI announced that it is currently reviewing recommendations on how to proceed, including
promulgating final rules for certain necessary provisions and issuing a new proposed rule that may withdraw
certain provisions and seek additional input on others.
Compliance with new and future regulations could result in significant costs, including increased capital
expenditures and operating costs, and could adversely impact our business. In addition, under certain
circumstances, BSEE may require our operations on federal leases to be suspended or terminated. Any such
suspension or termination could adversely affect our financial condition and operations.
Furthermore, hurricanes in the Gulf of Mexico can have a significant impact on oil and natural gas
operations. The effects from past hurricanes have included structural damage to fixed production facilities, semi-
submersibles and jack-up drilling rigs. BOEM and BSEE continue to be concerned about the loss of these facilities
and rigs as well as the potential for catastrophic damage to key infrastructure and the resultant pollution from future
storms. In an effort to reduce the potential for future damage, BOEM and BSEE have periodically issued guidance
aimed at improving platform survivability by taking into account environmental and oceanic conditions in the
design of platforms and related structures. It is possible that similar, if not more stringent, requirements will be
issued by BOEM and BSEE for future hurricane seasons. New requirements, if any, could increase our operating
costs and/or capital expenditures.
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In addition, in order to cover the various decommissioning obligations of lessees on the OCS, BOEM
generally requires that lessees post some form of acceptable financial assurances that such obligations will be met,
such as surety bonds. The cost of such bonds or other financial assurance can be substantial, and we can provide no
assurance that we can continue to obtain bonds or other surety in all cases. For example, in the Notice to Lessees
and operators (“NTL”) #2016-N01 (the “2016 NTL”), BOEM announced updated financial assurance and risk
management requirements for offshore leases. The 2016 NTL details procedures to determine a lessee’s ability to
carry out its lease obligations—primarily the decommissioning of facilities—and whether to require lessees to
furnish additional financial assurance to meet BOEM’s estimate of the lessees decommissioning obligations. The
2016 NTL supersedes the agency’s prior practice of allowing operators of a certain net worth to waive the need for
supplemental bonds and provides updated criteria for determining a lessee’s ability to self-insure only a small
portion of its OCS liabilities based upon the lessee’s financial capacity and financial strength. The 2016 NTL also
allows lessees to meet their additional financial security requirements pursuant to an individually approved tailored
plan, whereby an operator and BOEM agree to set a timeframe for the posting of additional financial assurances.
The 2016 NTL became effective in September 2016, but the BOEM has since extended indefinitely beyond June
30, 2017 the start date for implementation of this NTL, except for certain circumstances where there is a substantial
risk of nonperformance of the interest holder’s decommissioning liabilities, so as to provide BOEM with time to
review its complex financial assurance program.
In late 2016, we received orders from BOEM to provide additional financial assurance in material amounts
relating to our OCS properties (the “BOEM 2016 Orders”). We entered into discussions with BOEM regarding the
requested additional financial security and submitted a proposed tailored plan for the posting of additional financial
security to the agency for review. However, the BOEM has indefinitely delayed beyond June 30, 2017
implementation of the 2016 NTL, has rescinded the BOEM 2016 Orders while BOEM reviews its financial
assurance program and, to date, has taken no action with respect to our previously submitted proposed tailored
plan.
We remain in active discussions with our government regulators and our industry peers with regard to any
future rule making and financial assurance requirements. The BOEM is continuing to review and reconsider its
financial assurance program and thus the amounts of any financial assurance that may be demanded by the agency
is uncertain at this time. Notwithstanding the 2016 NTL, BOEM may also bolster its financial assurance
requirements mandated by rule for all companies operating in federal waters. The BOEM could also make new
demands for additional financial assurance in material amounts in the event the agency chooses to implement the
2016 NTL. Such demands could exceed our ability to provide any additional financial assurance that may be
required by BOEM in the future. The future cost of compliance with our existing supplemental bonding
requirements, including the obligations imposed upon us as a result of the 2016 NTL, to the extent implemented, as
well as any other future BOEM directives, or any other changes to BOEM’s rules applicable to our or our
subsidiaries’ properties, could materially and adversely affect our financial condition, cash flows, and results of
operations.
Regulation in Shallow Waters Off the Coast of Mexico. Our operations on oil and natural gas blocks in
shallow waters off the coast of Mexico’s Veracruz and Tabasco states, and in other Mexican offshore areas where
we are assessing other exploration opportunities, are subject to regulation by SENER, the CNH and other Mexican
regulatory bodies. The CNH is responsible for, among other things, overseeing the tender procedures for awarding
contracts for the exploration and production of oil and natural gas in Mexican waters, managing and supervising
contracts that have been awarded, and approving exploration and production plans. The PSCs that we and our
consortium partners have entered into for the development of these acreages contain terms that impose on us the
duty to comply with various laws and regulations. These laws and regulations govern, among other things, the
exploration and exploitation of hydrocarbons (including certain national content requirements), the treatment,
conveyance, marketing, transport and storage of petroleum, and requirements for industrial safety, operational
security, and facility decommissioning. Failure to comply can result in the imposition of monetary penalties,
revocation of permits, rescission of the relevant PSC, suspension of operations, and ordered decommissioning of
offshore facilities and systems. The laws and regulations governing activities in the Mexican energy sector are
relatively new, having been significantly reformed in 2013, and the legal regulatory framework continues to evolve
as SENER, the CNH and other Mexican regulatory bodies issue new regulations and guidance. Such regulations
are subject to change, and it is possible that SENER, the CNH or other Mexican regulatory bodies may impose new
or revised requirements that could increase our operating costs and/or capital expenditures for operations in
Mexican offshore waters.
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Environmental Regulations
We are subject to various federal, state, local and foreign regulations concerning occupational safety and
health as well as the discharge of materials into, and the protection of, the environment. Environmental laws and
regulations relate to, among other things:
• assessing the environmental impact of seismic acquisition, drilling or construction activities;
•
•
•
the generation, storage, transportation and disposal of waste materials;
the emission of certain gases into the atmosphere;
the monitoring, abandonment, reclamation and remediation of well and other sites, including sites of
former operations;
• various environmental permitting requirements, such as permits for wastewater discharges;
•
the development of emergency response and spill contingency plans; and
• protection of private and public surface and ground water supplies.
Based on regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses
related to the protection of the environment and safety and health compliance have increased over the years and it
is possible such expenses will continue to increase. We cannot predict with any reasonable degree of certainty our
future exposure concerning such matters and the cost of compliance could be significant. Failure to comply with
these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the
imposition of remedial obligations, natural resource damages or the issuance of injunctive relief (including orders
to cease operations). Both onshore and offshore drilling in certain areas has been opposed by environmental groups
and, in certain areas, has been restricted. Moreover, some environmental laws and regulations may impose strict
liability, which could subject us to liability for conduct that was lawful at the time it occurred or conduct or
conditions caused by prior operators or third parties. To the extent laws are enacted or other governmental action is
taken that prohibits or restricts onshore or offshore drilling or imposes environmental protection requirements that
result in increased costs to the oil and gas industry in general, our business and financial results could be adversely
affected.
We expect to continue making expenditures on a regular basis relating to environmental compliance. We
maintain insurance coverage for spills, pollution and certain other environmental risks, although we are not fully
insured against all such risks. Our insurance coverage provides for the reimbursement to us of certain costs
incurred for the containment and clean-up of materials that may be suddenly and accidentally released in the course
of our operations, but such insurance does not fully insure against pollution and similar environmental risks. We do
not anticipate that we will be required under current environmental laws and regulations to expend amounts that
will have a material adverse effect on our consolidated financial position or our results of operations. However,
since environmental costs and liabilities are inherent in our operations and in the operations of companies engaged
in similar businesses and since regulatory requirements frequently change and may become more stringent, there
can be no assurance that material costs and liabilities will not be incurred in the future. Such costs may result in
increased costs of operations and acquisitions and decreased production.
Water Discharges. Our discharges into waters of the United States are limited by the federal Clean Water Act
(“CWA”) and analogous state laws. The CWA prohibits any discharge of pollutants, including spills and leaks of
oil and other substances, into waters of the United States, except in compliance with permits issued by federal and
state governmental agencies. These discharge permits also include monitoring and reporting obligations. Failure to
comply with the CWA, including discharge limits set by permits issued pursuant to the CWA, may also result in
administrative, civil or criminal enforcement actions. Violations of the CWA can result in suspension, debarment
or the imposition of statutory disability, each of which prevents companies and individuals from participating in
government contracts and receiving some non-procurement government benefits. The CWA also requires the
preparation of oil spill response plans and spill prevention, control and countermeasure plans.
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Oil Pollution Act. The Oil Pollution Act of 1990 (“OPA”) holds owners and operators of offshore oil
production or handling facilities, including the lessee or permittee of the area where an offshore facility is located,
strictly liable for the costs of removing oil discharged into waters of the United States and for certain damages from
such spills. OPA assigns joint and several strict liability, without regard to fault, to each liable party for all
containment and oil removal costs and a variety of public and private damages including, but not limited to, the
costs of responding to a release of oil, natural resource damages and economic damages suffered by persons
adversely affected by an oil spill. Although defenses exist to the liability imposed by OPA, they are limited. In
addition, in January 2018, BOEM raised OPA’s damages liability cap to $137.7 million; however, a party cannot
take advantage of liability limits if a spill was caused by gross negligence or willful misconduct, resulted from
violation of a federal safety, construction or operating regulation, or if the party failed to report a spill or cooperate
fully in the clean-up. OPA also requires responsible parties to maintain evidence of financial responsibility in
prescribed amounts. OPA currently requires a minimum financial responsibility demonstration of between
$35 million to $150 million for companies operating on the OCS, although BOEM may increase this amount in
certain situations. From time to time, the United States Congress has proposed amendments to OPA raising the
financial responsibility requirements. If OPA is amended to increase the minimum level of financial responsibility,
we may experience difficulty in providing financial assurances sufficient to comply with this requirement. We
cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required
for companies operating on the OCS will be increased. In any event, if an oil discharge or substantial threat of
discharge were to occur, we may be liable for costs and damages, which costs and liabilities could be material to
our results of operations and financial position.
National Environmental Policy Act. The National Environmental Policy Act (“NEPA”) requires federal
agencies, including the DOI, to consider the impacts their actions have on the human environment, and to prepare
detailed statements for major federal actions having the potential to significantly impact the environment. These
requirements can lead to additional costs and delays in permitting for operators as the DOI or its bureaus may need
to prepare Environmental Assessments (“EA”) and more detailed Environmental Impact Statements (“EIS”) in
support of its leasing and other activities that have the potential to significantly affect the quality of the
environment. If the EA indicates that no significant impact is likely, then the agency can release a finding of no
significant impact and carry on with the proposed action. Otherwise, the agency must then conduct a full-scale EIS.
The NEPA process involves public input through comment. These comments, as well as the agency’s analysis of
the proposed project, can result in changes to the nature of a proposed project, such as by limiting the scope of the
project or requiring resource-specific mitigation. The adequacy of the agency’s NEPA process can be challenged in
federal court by process participants. This process may result in delaying the permitting and development of
projects, and result in increased costs.
Endangered Species Act. The Endangered Species Act (“ESA”) restricts activities that may affect federally
identified endangered and threatened species or their habitats. Additionally, the Migratory Bird Treaty Act
(“MBTA”) implements various treaties and conventions between the United States and certain other nations for the
protection of migratory birds. Under the MBTA, the taking, killing or possessing of migratory birds is unlawful
without a permit. The Marine Mammal Protection Act similarly prohibits the taking of marine mammals without
authorization. We conduct operations on oil and natural gas leases in areas where certain species that are protected
by the ESA, MBTA and Marine Mammal Protection Act are known to exist and where other species that
potentially could be protected under these statutes. The U.S. Fish and Wildlife Service or the National Marine
Fisheries Service may designate critical habitat that it believes is necessary for survival of a threatened or
endangered species. A critical habitat designation could result in further material restrictions to federal land use and
may materially delay or prohibit access to protected areas for oil and natural gas development. These statutes may
result in operating restrictions or a temporary, seasonal or permanent ban in affected areas.
Hazardous Substances and Waste Management. The Resource Conservation and Recovery Act (“RCRA”)
generally regulates the disposal of solid and hazardous wastes and imposes certain environmental cleanup
obligations. Although RCRA specifically excludes from the definition of hazardous waste “drilling fluids,
produced waters and other wastes associated with the exploration, development or production of crude oil, natural
gas or geothermal energy,” the EPA and state agencies may regulate these wastes as solid wastes. However,
pursuant to a consent decree issued by the U.S. District Court for the District of Columbia in 2016, the EPA is
required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria
regulations that could result in oil and natural gas exploration and production wastes being regulated as hazardous
wastes, or sign a determination that revision of the regulations is unnecessary. If EPA proposes rulemaking for
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revised oil and gas regulations, the consent decree requires that the EPA take final action following notice and
comment rulemaking no later than July 15, 2021. A loss of the RCRA exclusion for drilling fluids, produced waters
and related wastes could result in increased costs to manage and dispose of generated wastes. Also, ordinary
industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as
hazardous waste.
Comprehensive Environmental Response, Compensation and Liability Act. Comprehensive Environmental
Response, Compensation and Liability Act (“CERCLA”) and comparable state laws impose liability, without
regard to fault or the legality of the original conduct, on persons that are considered to have contributed to the
release of a “hazardous substance” into the environment. Such “responsible persons” may be subject to joint and
several liability under CERCLA for the costs of cleaning up the hazardous substances that have been released into
the environment and for damages to natural resources. Further, it is not uncommon for coastal landowners or other
third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances
released into the environment.
Air Emissions. The Clean Air Act (“CAA”) and comparable state statutes restrict the emission of air
pollutants and affect both onshore and offshore oil and natural gas operations. New facilities may be required to
obtain separate construction and operating permits before construction work can begin or operations may start, and
existing facilities may be required to incur capital costs in order to remain in compliance. Also, the EPA has
developed, and continues to develop, more stringent regulations governing emissions of toxic air pollutants, and is
considering the regulation of additional air pollutants and air pollutant parameters. For example, in October 2015,
the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion.
State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our
ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of
which could be significant.
Worker Health and Safety. The Occupational Safety and Health Act (“OSHA”) and comparable state statutes
regulate the protection of the health and safety of workers. The OSHA hazard communication standard requires
maintenance of information about hazardous materials used or produced in operations and provision of such
information to employees. Other OSHA standards regulate specific worker safety aspects of our operations. Failure
to comply with OSHA requirements can lead to the imposition of penalties.
Climate Change. From time to time, the United States Congress has considered a variety of tax, energy-
related or environmental market-based mechanisms to promote or induce the reduction of emissions of Green
House Gasses (“GHG”s) by several commercial or industrial sectors. In addition, more than one half of the states
already have begun implementing legal measures such as renewable energy requirements or cap and trade
programs to reduce emissions of GHGs.
Additionally, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris
Agreement, an international climate change agreement in Paris, France that calls for countries to set their own
GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions
targets. The Paris Agreement entered into force on November 4, 2016. In June 2017, President Trump stated that
the United States would withdraw from the Paris Agreement, but may enter into a future international agreement
related to GHGs. The Paris Agreement provides for a four-year exit process beginning when it took effect in
November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to
the exit process is uncertain and/or the terms on which the United States may reenter the Paris Agreement or a
separately negotiated agreement are unclear at this time.
In addition, the EPA has determined that emissions of carbon dioxide, methane and other GHGs present an
endangerment to public health and the environment because emissions of such gases contribute to warming of the
earth’s atmosphere and other climatic changes. Based on these findings, the EPA began adopting and implementing
regulations to restrict emissions of GHGs under existing provisions of the federal CAA. The EPA has adopted rules
regulating GHG emissions under the existing CAA, including a rule regulating emissions of GHGs from certain
large stationary sources through preconstruction and operating permit requirements. The EPA has also adopted
rules requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, on
an annual basis. Currently, our operations include one active floating production unit (the HP-I,) and our facilities
at the Ram Powell and Pompano Fields are subject to those EPA GHG reporting requirements.
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The EPA has also taken steps to limit methane emissions, a GHG, from certain new modified or
reconstructed facilities in the oil and natural gas sector through the adoption of a final rule in June 2016
establishing Subpart OOOOa standards for methane emissions. However, in 2017, the EPA published a proposed
rule to stay certain portions of these Subpart OOOOa standards for two years but the rule was not finalized. Rather,
in February 2018, the EPA finalized amendments to certain requirements of the June 2016 final rule, and in
September 2018 the EPA proposed additional amendments, including rescission of certain requirements and
revisions to other requirements, such as fugitive emission monitoring frequency. In the event that the EPA’s June
2016 rule should remain or be placed in effect, or should any other new methane emission standards be imposed on
the oil and natural gas sector, such requirements could result in increased costs to our operations as well as result in
restrictions, delays or cancellations in such operations, which costs, restrictions, delays or cancellations could
adversely affect our business.
Environmental Regulation in Shallow Waters Off the Coast of Mexico. Our operations on oil and natural gas
blocks in shallow waters off the coast of Mexico’s Veracruz and Tabasco states, and in other Mexican offshore
areas where we are assessing other exploration opportunities, are subject to regulation by the Mexican National
Agency of Industrial Safety and Environmental Protection of the Hydrocarbons Sector (“ASEA”). We must obtain
ASEA-issued permits and comply with ASEA regulations governing hydrocarbon activities, including
requirements for environmental impact and risk assessments, industrial safety, waste management, water and air
emissions, operational security, and facility decommissioning. Failure to comply with applicable laws and
regulations can result in the imposition of monetary penalties, revocation of permits, suspension of operations, and
ordered decommissioning of offshore facilities and systems. The laws and regulations governing the protection of
health, safety, and the environment from activities in the Mexican energy sector are relatively new, having been
significantly reformed in 2013 and 2014, and the legal regulatory framework continues to evolve as ASEA and
other Mexican regulatory bodies issue new regulations and guidance. Such regulations are subject to change, and it
is possible that ASEA or other Mexican regulatory bodies may impose new or revised requirements that could
increase our operating costs and/or capital expenditures for operations in Mexican offshore waters.
Under the PSCs, we are jointly and severally liable, along with Sierra and Premier, for the performance of all
obligations under the PSCs, including exploration, appraisal, extraction, and abandonment activities and
compliance with all environmental regulations, and failure to perform such obligations could result in contractual
recession of the PSCs.
Federal Regulation of Sales and Transportation of Natural Gas
Our sales of natural gas are affected directly or indirectly by the availability, terms and cost of natural gas
transportation. The prices and terms for access to pipeline transportation of natural gas are subject to extensive
federal and state regulation. The transportation and sale for resale of natural gas in interstate commerce is regulated
primarily under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”) and by
regulations and orders promulgated under the NGA and/or NGPA by the Federal Energy Regulatory Commission
(“FERC”). In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be
affected directly or indirectly by laws enacted by the United States Congress and by FERC regulations. However,
certain offshore gathering and transportation services we rely upon are subject to limited FERC regulation and are
regulated by the states.
Pursuant to authority delegated to it by the Energy Policy Act of 2005 (“EPAct 2005”), the FERC
promulgated anti-manipulation regulations establishing violation enforcement mechanisms that make it unlawful
for any entity, directly or indirectly, in connection with the purchase or sale of natural gas or the purchase or sale of
transportation services subject to the jurisdiction of FERC to (i) use or employ any device, scheme or artifice to
defraud, (ii) make any untrue statement of a material fact or to omit to state a material fact necessary in order to
make the statements made, in the light of the circumstances under which they were made, not misleading, or
(iii) engage in any act, practice or course of business that operates or would operate as a fraud or deceit upon any
entity. The EPAct 2005 also amended the NGA and the NGPA to give FERC authority to impose civil penalties for
violations of these statutes and regulations, up to $1,269,500 per violation, per day for 2019 (this amount is
adjusted annually for inflation). The FERC may also order disgorgement of profits and corrective action. The anti-
market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or
gathering, but does apply to activities of natural gas pipelines and storage companies that provide interstate
services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection
with” natural gas sales, purchases or transportation subject to FERC jurisdiction, which includes annual reporting
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requirements for entities that purchase or sell a certain volume of natural gas in a given calendar year. We believe,
however, that neither the EPAct 2005 nor the regulations promulgated by FERC as a result of the EPAct 2005 will
affect us in a way that materially differs from the way they affect other natural gas producers, gatherers and
marketers with which we compete.
Our sales of oil and natural gas are also subject to market manipulation and anti-disruptive requirements
under the Commodity Exchange Act (“CEA”) as amended by the Dodd-Frank Wall Street Reform and Consumer
Protection Act (the “Dodd-Frank Act”), and regulations promulgated thereunder by the U.S. Commodity Futures
Trading Commission (the “CFTC”). The CFTC prohibits any person from manipulating or attempting to
manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also
prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports
concerning market information or conditions that affect or tend to affect the price of a commodity.
The current statutory and regulatory framework governing interstate natural gas transactions is subject to
change in the future, and the nature of such changes is impossible to predict. We cannot predict whether new
legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by the
United States Congress, the applicable federal agencies, or the various state legislatures, and what effect, if any, the
proposals might have on our operations. The natural gas industry historically has been very heavily regulated. In
the past, the federal government regulated the prices at which natural gas could be sold. Since 1978, various federal
laws have been enacted that have resulted in the complete removal of all price and non-price controls for sales of
domestic natural gas sold in “first sales,” which include all of our sales of our own production. However, we are
subject to reporting requirements imposed by FERC. There is always some risk, however, that the United States
Congress may reenact price controls in the future. Changes in law and to FERC policies and regulations may
adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate
pipelines or impose additional reporting or other requirements upon our operations, and we cannot predict what
future action the FERC will take. Therefore, there is no assurance that the current regulatory approach recently
pursued by the FERC and the United States Congress will continue. We do not believe, however, that any
regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas
producers, gatherers and marketers with which we compete.
Federal Regulation of Sales and Transportation of Crude Oil
The FERC regulates the interstate pipeline of crude oil, petroleum products, and other liquids, such as NGLs.
Our sales of crude oil and condensate are currently not regulated and are made at negotiated prices. There is always
some risk, however, that the United States Congress may reenact crude oil, petroleum products and NGL price
controls in the future. We cannot predict whether new legislation to regulate crude oil, or the prices charged for
crude oil might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the
various state legislatures and what effect, if any, the proposals might have on our operations. Additionally, such
sales may be subject to certain state, and potentially federal, reporting requirements.
Our ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of
service are subject to FERC jurisdiction under the Interstate Commerce Act (“ICA”), and intrastate oil pipeline
transportation rates are subject to regulation by state regulatory commissions. Certain regulations implemented by
the FERC in recent years and certain pending rulemaking and other proceedings could result in an increase in the
cost of transportation service on certain petroleum products pipelines. The basis for intrastate oil pipeline
regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from
state to state. We do not believe, however, that any regulatory changes will affect us in a way that materially differs
from the way they will affect other crude oil and condensate producers with which we compete.
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory
basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the
same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by
prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil
pipeline transportation services generally will be available to us to the same extent as to other crude oil and
condensate producers with which we compete.
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Our SP 49 Pipeline LLC system is subject to regulation by FERC under the ICA, the Energy Policy Act of
1992, and the rules and orders promulgated thereunder. The ICA requires that tariff rates for liquids pipelines,
which include both crude oil pipelines and refined products pipelines, be just and reasonable and non-
discriminatory. FERC-regulated liquids pipelines, including SP 49 Pipeline LLC, typically use the FERC indexing
methodology to change its rates. The FERC, however, retained cost-of-service ratemaking, market-based rates and
settlement rates as alternatives to the indexing approach that may be used in certain specified circumstances. The
FERC reviews the index formula every five years. Effective July 1, 2016, the annual index adjustment for the five-
year period ending June 30, 2021, will equal the producer price index for finished goods for the applicable year
plus an adjustment factor of 1.23%. Pipelines may raise their rates to the rate ceiling level generated by application
of the annual index adjustment factor each year; however, a shipper may challenge such increase if the increase in
the pipeline’s rates was substantially in excess of the actual cost increases incurred by the pipeline during the
relevant year. Because the indexing methodology for the next five-year period is tied to an inflation index and is
not based on pipeline-specific costs, the indexing methodology could hamper our ability to recover cost increases.
On March 15, 2018, FERC issued a Revised Policy Statement on Treatment of Income Taxes (“Revised Policy
Statement”) stating, among other things, that with respect to oil and refined products pipelines subject to FERC
jurisdiction, the impacts of the Revised Policy Statement and the Tax Cuts and Jobs Act of 2017 on the costs of
FERC-regulated oil and NGL pipelines will be reflected in FERC’s next five-year review of the oil pipeline index,
which will generate the index level to be effective July 1, 2021. FERC’s establishment of a just and reasonable rate,
including the determination of the appropriate oil pipeline index, is based on many components, and tax-related
changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred
income taxes, while other pipeline costs also will continue to affect FERC’s determination of the appropriate
pipeline index. Accordingly, depending on FERC’s application of its indexing rate methodology for the next five-
year term of index rates, the Revised Policy Statement and tax effects related to the Tax Cuts and Jobs Act of 2017
may impact our revenues associated with any transportation services we may provide pursuant to cost-of-service
based rates in the future, including indexed rates.
FERC historically has not investigated rates of liquids pipelines on its own initiative when those rates have
not been the subject of a protest or complaint by a shipper. FERC issued an Advance Notice of Proposed
Rulemaking on October 20, 2016, that addressed issues related to FERC’s indexing methodology and liquids
pipeline reporting practices. If implemented, the proposals in this rulemaking could affect the profitability of
certain liquids pipelines.
We have an undivided interest in a pipeline owned by CKB Petroleum, Inc. that is subject to FERC
jurisdiction under the ICA, but FERC has granted us a temporary waiver of the filing and reporting requirements.
This pipeline is still subject to FERC’s jurisdiction under the ICA and is still subject to the other requirements of
the ICA. If the facts upon which the waiver was granted change materially, we are required to inform the FERC,
which may result in revocation of the waiver. If conditions change such that the pipeline no longer qualifies for a
waiver, we may be subject to regulation by FERC of the rates, terms, and conditions of service on the CKB
Petroleum, Inc. pipeline, however these burdens generally would not affect us any differently or to any greater or
lesser extent than they affect others in our industry with similar pipelines.
The FERC also implements the OCSLA pertaining to transportation and pipeline issues, which requires that
all pipelines operating on or across the OCS provide nondiscriminatory transportation service. We own and operate
pipelines that are located in the OCS and are subject to the non-discrimination requirements in the OCSLA.
Employees
We had 374 employees as of March 6, 2019.
Available Information
We make our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-
K, all amendments to those reports, and all other information filed with or furnished to the SEC available, free of
charge, through our website, https://www.talosenergy.com, as soon as reasonably practicable after those reports
and other information are electronically filed with or furnished to the SEC. The filings are also available by
accessing the SEC’s website at https://www.sec.gov.
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Item 1A. Risk Factors
Certain factors may have a material adverse effect on our business, financial condition, and results of
operations. You should consider carefully the risks and uncertainties described below, in addition to other
information contained in this Annual Report on Form 10-K, including our consolidated financial statements and
related notes. The risks and uncertainties described below are not the only ones we face. Additional risks and
uncertainties that we are unaware of, or that we currently believe are not material, may also become important
factors that adversely affect our business. If any of the following risks actually occur, our business, financial
condition, results of operations and future prospects could be materially and adversely affected. In that event, the
trading price of our common stock could decline, and you could lose part or all of your investment.
Oil and natural gas prices are volatile. Significant declines in commodity prices in the future may adversely
affect our financial condition and results of operations, cash flows, access to the capital markets, and ability to
grow.
Our revenues, cash flows, profitability, and future rate of growth substantially depend upon the market prices
of oil and natural gas. Prices affect our cash flows available for capital expenditures and our ability to access funds
under our Bank Credit Facility and through the capital markets. The amount available for borrowing under our
Bank Credit Facility is subject to a borrowing base, which is determined by the lenders taking into account our
estimated proved reserves, and is subject to periodic redeterminations based on pricing models to be determined by
the lenders at such time. Oil and natural gas prices significantly declined in the second half of 2014, with sustained
lower prices continuing throughout 2015, 2016 and 2017. Despite a modest recovery from late 2017 to mid-2018,
commodity prices could remain suppressed or decline further in the future, which will likely have material adverse
effects on our proved reserves and borrowing base. Further, because we use the full cost method of accounting for
our oil and gas operations, we perform a ceiling test each quarter, which is impacted by declining prices.
Significant price declines could cause us to take ceiling test write-downs, which would be reflected as non-cash
charges against current earnings. See the Risk Factor entitled “Lower oil and natural gas prices and other factors in
the future may result in ceiling test write-downs and other impairments of our asset carrying values” for further
discussion.
In addition, significant or extended price declines may also adversely affect the amount of oil and natural gas
that we can produce economically. A reduction in production could result in a shortfall in our expected cash flows
and require us to reduce our capital spending or borrow funds to cover any such shortfall. Any of these factors
could negatively impact our ability to replace our production and our future rate of growth.
The markets for oil and natural gas have been volatile historically and are likely to remain volatile in the
future. For example, during the period January 1, 2016 through December 31, 2018, the NYMEX WTI crude oil
price per Bbl ranged from a low of $30.62 to a high of $70.76, and the NYMEX natural gas price per MMBtu
ranged from a low of $1.71 to a high of $4.72. The high, low and average prices for NYMEX WTI and NYMEX
Henry Hub are monthly contract prices. The prices we receive for our oil and natural gas depend upon many factors
beyond our control, including, among others:
• changes in the supply of and demand for oil and natural gas;
• market uncertainty;
•
level of consumer product demands;
• hurricanes and other adverse weather conditions;
• domestic and foreign governmental regulations and taxes;
• price and availability of alternative fuels;
• political and economic conditions in oil-producing countries, particularly those in the Middle East, Russia,
South America and Africa;
• actions by the Organization of Petroleum Exporting Countries and other state-controlled oil companies
relating to oil and natural gas price and production controls;
• U.S. and foreign supply of oil and natural gas;
• price and quantity of oil and natural gas imports and exports;
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•
•
•
the level of global oil and natural gas exploration and production;
the level of global oil and natural gas inventories;
localized supply and demand fundamentals and transportation availability;
• speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;
• price and availability of competitors’ supplies of oil and natural gas;
•
technological advances affecting energy consumption; and
• overall domestic and foreign economic conditions.
These factors make it very difficult to predict future commodity price movements with any certainty.
Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot
market prices and are not long-term fixed price contracts. Further, oil prices and natural gas prices do not
necessarily fluctuate in direct relation to each other. Because oil, natural gas, and NGLs accounted for
approximately 74%, 19%, and 7%, respectively, of our estimated proved reserves as of December 31, 2018, and
approximately 70%, 23%, and 7%, respectively, of our 2018 production on an MBoe basis, our financial results are
sensitive to movements in oil, natural gas, and NGL prices.
We are required to meet a minimum work program expressed in work units during a four-year exploration
period according to our PSCs with the CNH.
On September 11, 2018, we entered into a transaction with Hokchi, a subsidiary of PAE, to cross assign 25%
PIs in Block 2 and Block 31, both in the Sureste Basin off the coast of Mexico. Our assignment of a 25% PI in
Block 2 to Hokchi closed on December 21, 2018, and Hokchi has assumed operator responsibilities with respect to
Block 2. Hokchi’s assignment of Block 31 to us will be completed upon final approval by the CNH. In addition,
Premier exercised its option to reduce its PI in Block 2 to zero and assign a 5% PI to each of Sierra and us. Such
assignment is also subject to CNH’s approval. Upon the completion of the Hokchi Cross Assignment and Premier’s
option exercise, Hockchi will be the operator of both blocks, we will own a 25% PI in Block 31 and our PI in Block
2, and our pro rata portion of the minimum work program on Block 2 will decrease from 45% to 25%. We posted
an additional $8.7 million required in letters of credit to cover our pro rata portion of the minimum work program
on Block 31 pursuant to the relevant PSC.
If we or the Consortium is unable to meet a minimum work program, we could be liable along with the other
members in the Consortium for the remaining financial guarantee, and the CNH could rescind the PSC for a
default.
Our debt level and the covenants in our current or future agreements governing our debt, including our Bank
Credit Facility and the indenture for our 11.00% Senior Secured Notes, could negatively impact our financial
condition, results of operations, and business prospects. Our failure to comply with these covenants could result
in the acceleration of our outstanding indebtedness.
The terms of the agreements governing our debt impose significant restrictions on our ability to take a
number of actions that we may otherwise desire to take, including:
•
incurring additional debt;
• paying dividends on stock, redeeming stock, or redeeming subordinated debt;
• making investments;
• creating liens on our assets;
• selling assets;
• guaranteeing other indebtedness;
• entering into agreements that restrict dividends from our subsidiaries to us;
• merging, consolidating, or transferring all or substantially all of our assets;
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• hedging future production; and
• entering into transactions with affiliates.
Our level of indebtedness, and the covenants contained in the agreements governing our debt, including the
Bank Credit Facility and the indenture for our 11.00% Senior Secured Notes, have important consequences on our
operations, including:
•
•
•
requiring that we dedicate a substantial portion of our cash flow from operating activities to required
payments on debt, thereby reducing the availability of cash flow for working capital, capital expenditures,
and other general business activities;
limiting our ability to obtain additional financing in the future for working capital, capital expenditures,
acquisitions, and other general business activities;
limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we
operate;
• detracting from our ability to successfully withstand a downturn in our business or the economy generally;
• placing us at a competitive disadvantage against other less leveraged competitors; and
• making us vulnerable to increases in interest rates because debt under our Bank Credit Facility is at
variable rates.
We may be required to repay all or a portion of our debt on an accelerated basis in certain circumstances. If
we fail to comply with the covenants and other restrictions in the agreements governing our debt, it could lead to an
event of default and the acceleration of repayment of outstanding debt. Our ability to comply with these covenants
and other restrictions may be affected by events beyond our control, including prevailing economic and financial
conditions. Sustained low oil and natural gas prices have a material and adverse effect on our liquidity position.
Our cash flow is highly dependent on the prices we receive for oil and natural gas, which have declined
significantly as compared to mid-2014.
We depend on our Bank Credit Facility for a portion of our future capital needs. We are required to comply
with certain debt covenants and certain financial ratios under the Bank Credit Facility. Our borrowing base under
the Bank Credit Facility, which is redetermined semi-annually, is based on an amount established by the lenders
after their evaluation of our proved oil and natural gas reserve values. If, due to a redetermination of our borrowing
base, our outstanding borrowings plus outstanding letters of credit exceed our redetermined borrowing base
(referred to as a borrowing base deficiency), we could be required to repay such borrowing base deficiency. Our
Bank Credit Facility allows us to cure a borrowing base deficiency through any combination of the following
actions: (i) repay amounts outstanding sufficient to cure the borrowing base deficiency within 30 days after the
existence of such deficiency; (ii) add additional oil and gas properties acceptable to the banks to the borrowing base
and take such actions necessary to grant the banks a mortgage in such oil and gas properties within 30 days after
the existence of such deficiency; (iii) pay the deficiency in four equal monthly installments with the first
installment due within 30 days after the existence of such deficiency; or (iv) any combination of the above. We are
required to elect one of the foregoing options within 10 days after the existence of such deficiency.
We may not have sufficient funds to make such repayments. If we do not repay our debt out of cash on hand,
we could attempt to restructure or refinance such debt, reduce or delay investments and capital expenditures, sell
assets, or repay such debt with the proceeds from an equity offering. We cannot assure you that we will be able to
generate sufficient cash flows from operating activities to pay the interest on our debt or that future borrowings,
equity financings, or proceeds from the sale of assets are available to pay or refinance such debt. Any refinancing
of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which
could further restrict business operations. The terms of our debt, including our Bank Credit Facility and the
indenture for our 11.00% Senior Secured Notes, may also prohibit us from taking such actions. Factors that affect
our ability to raise cash through offerings of our capital stock, a refinancing of our debt, or a sale of assets include
financial market conditions and our market value and operating performance at the time of such offerings,
refinancing, or sale of assets. We cannot assure you that any such offerings, restructuring, refinancing, or sale of
assets would be successfully completed.
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Regulatory requirements and permitting procedures imposed by the BOEM and the BSEE could significantly
delay our ability to obtain permits to drill new wells in offshore waters.
BSEE and BOEM have imposed new and more stringent permitting procedures and regulatory safety and
performance requirements for new wells to be drilled in federal waters. Compliance with these added and more
stringent regulatory requirements and with existing environmental and spill regulations, together with uncertainties
or inconsistencies in decisions and rulings by governmental agencies and delays in the processing and approval of
drilling permits and exploration, development, oil spill response, and decommissioning plans and possible
additional regulatory initiatives could result in difficult and more costly actions and adversely affect or delay new
drilling and ongoing development efforts. Moreover, these governmental agencies are continuing to evaluate
aspects of safety and operational performance in the Gulf of Mexico and, as a result, are continuing to develop and
implement new, more restrictive requirements. For example, in April 2016, BSEE published a final rule on well
control that, among other things, imposes rigorous standards relating to the design, operation, and maintenance of
blow-out preventers, real-time monitoring of deepwater, high temperature, high pressure drilling activities, and
enhanced reporting requirements. Pursuant to the Executive Orders, BSEE initiated a review of the well control
regulations to determine whether the rules are consistent with the stated policy of encouraging energy exploration
and production, while ensuring that any such activity is safe and environmentally responsible. One consequence of
this review is that in September 2018, BSEE published final revisions to its regulations regarding offshore drilling
safety equipment, which includes the removal of the requirement for offshore operators to certify through an
independent third party that their critical safety and pollution prevention equipment (e.g., subsea safety equipment,
including blowout preventers) is operational and functioning as designed in the most extreme conditions.
Also, in April 2016, BOEM published a proposed rule that would update existing air emissions requirements
relating to offshore oil and natural gas activity on the OCS. BOEM regulates these air emissions in connection with
its review of exploration and development plans, rights of way and rights of use, and/or easement applications. The
proposed rule would bolster existing air emissions requirements by, among other things, requiring the reporting and
tracking of the emissions of all pollutants defined by the EPA to affect human health and public welfare. Pursuant
to the Executive Orders, BOEM has ceased rulemaking activities for and is reviewing the proposed air quality rule.
In October 2017, the DOI announced that it is currently reviewing recommendations on how to proceed, including
promulgating final rules for certain necessary provisions and issuing a new proposed rule that may withdraw
certain provisions and seek additional input on others.
Compliance with new and future regulations could result in significant costs, including increased capital
expenditures and operating costs, and could adversely impact our business. Furthermore, among other adverse
impacts, to the extent that BOEM and BSEE do not reduce the stringency of existing oil and gas safety and
performance-related regulations and other regulatory initiatives, the regulatory requirements imposed by such
existing or future, more stringent regulations or other regulatory initiatives could delay operations, disrupt our
operations, or increase the risk of leases expiring before exploration and development efforts have been completed
due to the time required to develop new technology. Additionally, if left unchanged, the existing, or future, more
stringent oil and gas safety and performance-related regulations and other regulatory initiatives imposed by BOEM
and BSEE could result in incurrence of associated added costs, limit operational activities in certain areas, or cause
us to incur penalties or shut-in production at one or more of our facilities. Also, if material spill incidents were to
occur in the future, the United States or other countries where such an event may occur could elect to issue
directives to temporarily cease drilling activities and, in any event, may from time to time issue further safety and
environmental laws and regulations regarding offshore oil and natural gas exploration and development, any of
which could have a material adverse effect on our business. We cannot predict with any certainty the full impact of
any new laws or regulations on our drilling operations or on the cost or availability of insurance to cover some or
all of the risks associated with such operations.
New guidelines issued by BOEM related to financial assurance requirements to cover decommissioning
obligations for operations on the OCS may have a material adverse effect on our business, financial condition,
or results of operations.
BOEM requires that lessees demonstrate financial strength and reliability according to its regulations or
provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning
activities on the OCS. In July 2016, BOEM issued the 2016 NTL to clarify the procedures and guidelines that
BOEM Regional Directors use to determine if and when additional financial assurances may be required for OCS
leases, ROWs or RUEs. The 2016 NTL became effective in September 2016, but BOEM has since extended
indefinitely beyond June 30, 2017 the start date for implementing this NTL, except in certain circumstances where
there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities, so as to provide
BOEM with time to review its complex financial assurance program.
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In late 2016, we received orders from BOEM to provide additional financial assurance in material amounts
relating to our OCS properties (the “BOEM 2016 Orders”). We entered into discussions with BOEM regarding the
requested additional financial security and submitted a proposed tailored plan for the posting of additional financial
security to the agency for review. However, as noted, BOEM has indefinitely delayed beyond June 30, 2017
implementation of the 2016 NTL, has rescinded the BOEM 2016 Orders while BOEM reviews its financial
assurance program and, to date, has taken no action with respect to our previously submitted proposed tailored
plan.
As of the filing date of this Annual Report on Form 10-K, we have no outstanding BOEM orders for
financial assurance obligations, although we are in discussions with the agency regarding providing financial
assurance in what we view as the normal course of business for one well, Mount Providence, that was completed
July 2018. Following completion of its review of its financial assurance program, BOEM may elect to retain the
2016 NTL in its current form or may make revisions thereto. Thus, until the review is completed and BOEM
determines what additional financial assurance may be required by us, we cannot provide any assurance of the
amount of any additional financial assurance, which may be material, that may be ordered by BOEM and required
in any proposed tailored plan that we may submit to BOEM in the future for approval, or that such additional
financial assurance amounts can be obtained. Moreover, BOEM could in the future make new demands for
additional financial assurances in material amounts relating to the decommissioning of our OCS properties. BOEM
may reject our proposals to satisfy any such additional financial assurance coverage and make demands that exceed
our capabilities.
If we fail to comply with the current or future orders of BOEM to provide additional surety bonds or other
financial assurances, BOEM could commence enforcement proceedings or take other remedial action, including
assessing civil penalties, suspending operations or production, or initiating procedures to cancel leases, which, if
upheld, would have a material adverse effect on our business, properties, results of operations and financial
condition.
In addition, if fully implemented, the 2016 NTL is likely to result in the loss of supplemental bonding
waivers for a large number of operators on the OCS, which could in turn force these operators to seek additional
surety bonds and could, consequently, challenge the surety bond market’s capacity for providing such additional
financial assurance. Operators who have already leveraged their assets as a result of the declining oil market could
face difficulty obtaining surety bonds because of concerns the surety companies may have about the priority of
their lien on the operator’s collateral. Moreover, depressed oil prices could result in sureties seeking additional
collateral to support existing bonds, such as cash or letters of credit, and we cannot provide assurance that we will
be able to satisfy collateral demands for future bonds to comply with supplemental bonding requirements of
BOEM. If we are required to provide collateral in the form of cash or letters of credit, our liquidity position could
be negatively impacted and we may be required to seek alternative financing. To the extent we are unable to secure
adequate financing, we may be forced to reduce our capital expenditures. All of these factors may make it more
difficult for us to obtain the financial assurances required by BOEM to conduct operations on the OCS. These and
other changes to BOEM bonding and financial assurance requirements could result in increased costs on our
operations and consequently have a material adverse effect on our business and results of operations.
We have a subsidiary that is subject to a plea agreement with the Department of Justice (“DOJ”) pursuant to
which certain exploration and production activities must comply with a Safety and Environmental Compliance
Program (“SECP”). Noncompliance with the SECP could result in a violation of the plea agreement and
provide a basis for revocation or modification of probation.
In February 2014, we received a grand jury subpoena from the DOJ addressing activities that occurred on the
Ship Shoal 225A production platform operated by one of our subsidiaries, ERT. On November 30, 2015, ERT was
charged with two violations of the OCSLA in connection with hot work and blowout preventer testing activities,
and with two violations of the CWA for self-reported activities surrounding overboard discharge sampling and
unpermitted discharges. On January 6, 2016, ERT pled guilty to these charges. On April 6, 2016, the United States
District Court for the Eastern District of Louisiana (the “Court”) accepted ERT’s plea and sentenced ERT,
consistent with the plea agreement, to pay a penalty of $4.2 million, which ERT has paid. The Court placed ERT
on probation for three years. The conditions of probation include compliance with an agreed SECP, pursuant to
which ERT and another subsidiary of ours must implement enhanced safety and environmental compliance
inspections, reviews and audits, implement a comprehensive training program, implement enhanced operational
controls to better manage, detect and prevent safety and environmental violations, and preparation and
implementation of a schedule for decommissioning. Any failure to comply with the SECP could result in a
violation of the plea agreement and provide a basis for revocation or modification of probation, which could
adversely our financial condition and operations.
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A financial crisis may impact our business and financial condition and may adversely impact our ability to
obtain funding under our Bank Credit Facility or in the capital markets.
We use our cash flows from operating activities and borrowings under our Bank Credit Facility to fund our
capital expenditures, and we rely on the capital markets and asset monetization transactions to provide us with
additional capital for large or exceptional transactions. However, we may not be able to access adequate funding
under our Bank Credit Facility as a result of (i) a decrease in our borrowing base due to the outcome of a borrowing
base redetermination or a breach or default under our Bank Credit Facility, including a breach of a financial
covenant or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding
obligations. In addition, we may face limitations on our ability to access the debt and equity capital markets and
complete asset sales, an increased counterparty credit risk on our derivatives contracts, and the requirement by our
contractual counterparties to post collateral guaranteeing performance.
We require substantial capital expenditures to conduct our operations and replace our production, and we may
be unable to obtain needed financing on satisfactory terms necessary to fund our planned capital expenditures.
We spend a substantial amount of capital for the acquisition, exploration, exploitation, development, and
production of oil and natural gas reserves. We fund our capital expenditures primarily through operating cash
flows, cash on hand and borrowings under our Bank Credit Facility, if necessary. The actual amount and timing of
our future capital expenditures may differ materially from our estimates as a result of, among other things, oil and
natural gas prices, actual drilling results, the availability of drilling rigs and other services and equipment, and
regulatory, technological and competitive developments. A further reduction in commodity prices may result in a
further decrease in our actual capital expenditures, which would negatively impact our ability to grow production.
Our cash flow from operations and access to capital is subject to a number of variables, including:
• our proved reserves;
•
•
the level of hydrocarbons we are able to produce from our wells;
the prices at which our production is sold;
• our ability to acquire, locate, and produce new reserves; and
• our ability to borrow under our Bank Credit Facility.
If low oil and natural gas prices, operating difficulties, declines in reserves or other factors, many of which
are beyond our control, cause our revenues, cash flows from operating activities, and the borrowing base under our
Bank Credit Facility to decrease, we may be limited in our ability to fund the capital necessary to complete our
capital expenditure program. After utilizing our available sources of financing, we may be forced to raise additional
debt or equity proceeds to fund such capital expenditures. We cannot be sure that additional debt or equity
financing will be available, and we cannot be sure that cash flows provided by operations will be sufficient to meet
these requirements. For example, the ability of oil and gas companies to access the equity and high yield debt
markets has been significantly limited since the significant decline in commodity prices as compared to mid-2014.
Access to the equity and high yield debt markets continue to be limited.
We are a holding company that has no material assets other than our ownership of the equity interests of Talos
Production. Accordingly, we are dependent upon distributions from Talos Production to pay taxes, cover our
corporate and other overhead expenses and pay dividends, if any, on our common stock.
We are a holding company that has no material assets other than our ownership of the equity interests of
Talos Production. We have no independent means of generating revenue. To the extent Talos Production has
available cash, we will cause Talos Production to make distributions of cash to us, directly and indirectly through
our wholly owned subsidiaries, to pay taxes, cover our corporate and other overhead expenses and pay dividends, if
any, on our common stock. As we have never declared or paid any cash dividends on our common stock, we
anticipate that any available cash, other than the cash distributed to us to pay taxes and cover our corporate and
other overhead expenses, will be retained by Talos Production to satisfy its operational and other cash needs.
Accordingly, we do not anticipate paying any cash dividends on our common stock in the foreseeable future.
Although we do not expect to pay dividends on our common stock, if our board of directors decides to do so in the
future, our ability to do so may be limited to the extent Talos Production is limited in its ability to make
distributions to us, including the significant restrictions the agreements governing Talos Production’s debt impose
on the ability of Talos Production to make distributions and other payments to us. To the extent that we need funds
and Talos Production is restricted from making such distributions under applicable law or regulation or under the
terms of our financing agreements, or is otherwise unable to provide such funds, it could materially adversely affect
our liquidity and financial condition.
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Our production, revenue and cash flow from operating activities are derived from assets that are concentrated in
a single geographic area, making us vulnerable to risks associated with operating in one geographic area.
Our production, revenue, and cash flow from operating activities are derived from assets that are
concentrated in a single geographic area, the Gulf of Mexico and in the shallow waters off the coast of Mexico.
Unlike other entities that are geographically diversified, we may not have the resources to effectively diversify our
operations or benefit from the possible spreading of risks or offsetting of losses. Our lack of diversification may
subject us to numerous economic, competitive and regulatory developments, any or all of which may have an
adverse impact upon the particular industry in which we operate, and result in our dependency upon a single or
limited number of hydrocarbon basins. In addition, the geographic concentration of our properties in the Gulf of
Mexico and in the shallow waters off the coast of Mexico means that some or all of our properties could be affected
should the region experience:
• severe weather, such as hurricanes and other adverse weather conditions;
• delays or decreases in production, the availability of equipment, facilities or services;
• delays or decreases in the availability or capacity to transport, gather or process production;
• changes in the status of pipelines that we depend on for transportation of our production to the
marketplace;
• extensive governmental regulation (including regulations that may, in certain circumstances, impose strict
liability for pollution damage or require posting substantial bonds to address decommissioning and P&A
costs) and interruption or termination of operations by governmental authorities based on environmental,
safety or other considerations; and/or
• changes in the regulatory environment such as the guidelines issued by BOEM related to financial
assurance requirements to cover decommissioning obligations for operations on the OCS.
Because all or a number of our properties could experience many of the same conditions at the same time,
these conditions may have a relatively greater impact on our results of operations than they might have on other
producers who have properties over a wider geographic area.
We may experience significant shut-ins and losses of production due to the effects of hurricanes in the Gulf of
Mexico and in the shallow waters off the coast of Mexico.
Our production is primarily associated with our properties in the Gulf of Mexico and in the shallow waters
off the coast of Mexico. Accordingly, if the level of production from these properties substantially declines, it
could have a material adverse effect on our overall production level and our revenue. We are particularly
vulnerable to significant risk from hurricanes and tropical storms in the Gulf of Mexico. We are unable to predict
what impact future hurricanes and tropical storms might have on our future results of operations and production.
A significant portion of our production, revenue and cash flow is concentrated in our Phoenix Field and our
Pompano Field. Because of this concentration, any production problems, impacts of adverse weather or
inaccuracies in reserve estimates could have a material adverse impact on our business.
For the year ended December 31, 2018, approximately 39% and 15% of our historical production and 41%
and 17% of our historical oil, natural gas, and NGL revenue was attributable to our Phoenix Field and our Pompano
Field, respectively, both of which are located in the federal waters offshore in the Gulf of Mexico. This
concentration in these fields means that any impact on our production from these fields, whether because of
mechanical problems, adverse weather, well containment activities, changes in the regulatory environment, or
otherwise, could have a material effect on our business. We produce the Phoenix Field through the HP-I, a
dynamically positioned floating production facility that is operated by Helix. The HP-I interconnects the Phoenix
Field through a production buoy that can be disconnected if the HP-I cannot maintain its position on station, such
as in the event of a mechanical problem with the dynamic positioning system or the approach of a hurricane.
Because the HP-I may have to be disconnected from the Phoenix Field if circumstances require, our production
from the Phoenix Field may be subject to more frequent interruptions than if the Phoenix Field was produced by a
more conventional platform. We are also required to disconnect and dry-dock the HP-I every two to three years for
inspection as required by the United States Coast Guard, during which time we are unable to produce the Phoenix
Field. As of the filing date of this Annual Report on Form 10-K, Helix has dry-docked the HP-I, and the shut-in is
estimated to through March 2019. On September 10, 2016, the HP-I was disconnected from the production buoy
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and released for dry dock for 28 days. Upon completion of the dry dock, the HP-I remained disconnected from the
buoy connecting it to the Phoenix Field due to Federal Emergency Management Agency testing of test upgrades to
the power management system, preventing us from reconnecting the HP-I to the Phoenix Field for a further five
days. Once the buoy was connected, Phoenix Field production remained shut-in for an additional five days to
conduct buoy remediation of the swivel piping. In addition, for 25 days in March 2015, we were required to
disconnect the HP-I from the production buoy due to upgrades to the power management system of the vessel,
which is an integral part of the dynamic positioning system. The upgrade work was followed by sea trials that
tested the dynamic positioning system and were required by various regulatory groups, including the United States
Coast Guard.
The HP-I is part of the Helix Well Containment Group (“HWCG”), which is a consortium that is available to
respond to any deepwater well control event, such as the Macondo well oil spill. If such an event were to occur and
the HWCG was to be utilized for well control, the HP-I, which is the vessel that would be used to respond to the
deepwater well control event, would be required to disconnect from the Phoenix Field until such time as the well
control event was resolved and the HP-I could return to the Phoenix Field. During such time period, we would not
be able to produce the Phoenix Field. In the event the HP-I has to disconnect from the Phoenix Field, our
production, revenue, and cash flow could be adversely affected, which could have a material adverse effect on our
business, financial condition, results of operations and cash flows.
In addition, all of our production from the Phoenix Field flows through the Green Canyon 19 connection
facility operated by Shell GOM Pipeline Company LLC. To the extent Shell GOM Pipeline Company LLC
temporarily shuts in its Green Canyon 19 connection facility, whether for maintenance or otherwise, we would not
able to produce the Phoenix Field during this period of time, which may have a material adverse effect on our
business, financial condition, results of operations and cash flows.
If the actual reserves associated with the Phoenix Field are less than our estimated reserves, such a reduction
of reserves could have a material adverse effect on our business, financial condition, results of operations and cash
flows.
In addition, all of our production from the Pompano Field flows through the Pompano Pipeline System
operated by Crimson Gulf LLC. To the extent Crimson Gulf LLC temporarily shuts in the Pompano Pipeline
System, whether for maintenance or otherwise, we would not be able to produce the Pompano Field during this
period of time, which may have a material adverse effect on our business, financial condition, results of operations
and cash flows.
If the actual reserves associated with the Pompano Field are less than our estimated reserves, such a
reduction of reserves could have a material adverse effect on our business, financial condition, results of operations
and cash flows.
We are not insured against all of the operating risks to which our business is exposed.
In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks
to which our business is exposed. We insure some, but not all, of our properties from operational loss-related
events. We have insurance policies that include coverage for general liability, physical damage to our oil and gas
properties, operational control of well, named Gulf of Mexico windstorm, oil pollution, construction all risk,
workers’ compensation and employers’ liability and other coverage. Our insurance coverage includes deductibles
that have to be met prior to recovery, as well as sub-limits or self-insurance. Additionally, our insurance is subject
to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against
liability from all potential consequences, damages or losses.
We have general liability insurance coverage with an annual aggregate limit of $500 million. We selectively
purchase physical damage insurance coverage for our pipelines, platforms, facilities and umbilicals for losses
resulting from named windstorms and operational activities.
Our operational control of well coverage is expected to provide limits that vary by well location and depth
and range from a combined single limit of $25 million to $500 million per occurrence. Exploratory deepwater wells
have a coverage limit of up to $500 million per occurrence. Additionally, we maintain up to $150 million in oil
pollution liability coverage. Our operational control of well and physical damage policy limits is scaled
proportionately to our working interests. Our general liability program utilizes a combination of assured’s interest
and scalable limits. All of our policies described above are subject to deductibles, sub-limits, or self-insurance.
Under our service agreements, including drilling contracts, generally we are indemnified for injuries and death of
the service provider’s employees as well as contractors and subcontractors hired by the service provider, subject to
the application of various states’ laws.
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An operational or hurricane or other adverse weather-related event may cause damage or liability in excess of
our coverage that might severely impact our financial position. We may be liable for damages from an event
relating to a project in which we own a non-operating working interest. Such events may also cause a significant
interruption to our business, which might also severely impact our financial position. We may experience
production interruptions for which we do not have production interruption insurance.
We reevaluate the purchase of insurance, policy limits and terms annually. Future insurance coverage for our
industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of
insurance may become unavailable in the future or unavailable on terms that we believe are economically
acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we
consider reasonable, and we may elect to maintain minimal or no insurance coverage. We may not be able to secure
additional insurance or bonding that might be required by new governmental regulations. This may cause us to
restrict our operations in the Gulf of Mexico, which might severely impact our financial position. The occurrence
of a significant event, not fully insured against, could have a material adverse effect on our financial condition and
results of operations.
Lower oil and natural gas prices and other factors in the future may result in ceiling test write-downs and other
impairments of our asset carrying values.
We use the full cost method of accounting for our oil and gas operations. Accordingly, we capitalize the costs
to acquire, explore for and develop oil and gas properties. Under the full cost method of accounting, we compare, at
the end of each financial reporting period for each cost center, the present value of estimated future net cash flows
from proved reserves (based on a trailing 12-month average, hedge-adjusted commodity price and excluding cash
flows related to estimated abandonment costs), to the net capitalized costs of proved oil and gas properties, net of
related deferred taxes. We refer to this comparison as a ceiling test. If the net capitalized costs of proved oil and gas
properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write
down the value of our oil and gas properties to the value of the estimated discounted future net cash flows. A write-
down of oil and gas properties does not impact cash flows from operating activities, but does reduce net income.
The risk that we are required to write-down the carrying value of oil and gas properties increases when oil and
natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward
adjustments to our estimated proved reserves or our undeveloped property values, or if estimated future
development costs increase. Volatility in commodity prices, poor conditions in the global economic markets and
other factors could cause us to record additional write-downs of our oil and natural gas properties and other assets
in the future, and incur additional charges against future earnings. Any required write-downs or impairments could
materially affect the quantities and present value of our reserves, which could adversely affect our business, results
of operations and financial condition.
Our oil and gas operations are subject to various international, foreign and U.S. federal, state and local
governmental regulations that materially affect our operations.
Our oil and gas operations are subject to various international, foreign and U.S. federal, state and local laws
and regulations. These laws and regulations may be changed in response to economic or political conditions.
Regulated matters include: permits for exploration, development and production operations; limitations on our
drilling activities in environmentally sensitive areas, such as marine habitats, and restrictions on the way we can
discharge materials into the environment; bonds or other financial responsibility requirements to cover drilling
contingencies and well P&A and other decommissioning costs; reports concerning operations, the spacing of wells
and unitization and pooling of properties; regulations regarding the rate, terms and conditions of transportation
service or the price, terms, and conditions related to the purchase and sale of oil and natural gas; and taxation.
Failure to comply with these laws and regulations can result in the assessment of administrative, civil or criminal
penalties, the issuance of remedial obligations and the imposition of injunctions limiting or prohibiting certain of
our operations. In addition, because we hold federal leases, the federal government requires that we comply with
numerous additional regulations applicable to government contractors.
In July 2017, we, along with partners Sierra and Premier, reported the discovery of a significant reservoir of
crude oil in the Sureste basin offshore Mexico through the Zama-1 well. Data from the Zama-1 well indicates that
it is possible the deposit could be part of a field that extends into an exploration block in which the state entity
Pemex holds exploration and development rights.
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The Ministry of Energy of Mexico has promulgated guidelines to establish procedures for conducting the
unitization of shared reservoirs and approving the terms and conditions of unitization and unit operating
agreements, as well as the authority to direct parties holding rights in a potentially shared reservoir to appraise and
potentially form a unit for development of such reservoir.
Even with the final regulations in place, there are still some uncertainties regarding the unitization process,
including the selection of a unit operator and the exact length of time that will take to obtain approvals of any unit
agreements. Any unit operating agreement eventually agreed to by the relevant parties or any unit order issued by a
governmental entity in Mexico could be adverse to us and affect the value that we are able to recognize from the
reservoir discovery, including but not limited to an agreement or unit order that would require us to allow a third
party to develop and produce the crude oil reservoir identified through the Zama-1 well.
In addition, the OPA requires operators of U.S. offshore facilities to prove that they have the financial
capability to respond to costs that may be incurred in connection with potential oil spills. Under the OPA and other
environmental statutes such as the CERCLA, the RCRA and analogous state laws, owners and operators of certain
defined onshore and offshore facilities are strictly liable for spills of oil and other regulated substances, subject to
certain limitations. Consequently, a spill from one of our facilities subject to laws such as the OPA, CERCLA and
RCRA could require the expenditure of additional, and potentially significant, amounts of capital, or could have a
material adverse effect on our earnings, results of operations, competitive position or financial condition. We
cannot predict the ultimate cost of compliance with these requirements or their impact on our earnings, operations
or competitive position.
In September 2015, we, together with the Consortium executed a PSC with the CNH for each of Blocks 2
and 7 of Round 1. The PSCs require that the Consortium execute a minimum work program expressed in work
units during a four-year exploration period. The work units represent the performance of exploration studies and
seismic and drilling activities. The aggregate value of the minimum work program under the PSCs is approximately
$143.0 million (gross), of which we are responsible for a pro rata portion based on our PI. In order to guarantee the
execution of the minimum work program under the PSCs, the Consortium was required to post a financial
guarantee to the CNH of approximately $143.0 million (gross), of which our share was $48.7 million. We satisfied
our share through a performance bond. As the Consortium completes the minimum work program under the PSCs,
the amount of the financial guarantee will be reduced accordingly beginning after the second anniversary of
entering into the PSCs. Effective January 23, 2018, the activities already performed on Block 7 have satisfied the
minimum work program on Block 7, reducing the $143.0 million (gross) in outstanding letters of credit by $65.7
million (gross). Activities on Block 2 are in the planning phase and we are on schedule to satisfy the minimum
work program on Block 2 by September 4, 2019.
Our Mexican operations are subject to certain offshore regulatory and environmental laws and regulations
promulgated by Mexico.
Our operations on oil and natural gas blocks in shallow waters off the coast of Mexico’s Veracruz and
Tabasco states, and in other Mexican offshore areas where we are assessing other exploration opportunities, are
subject to regulation by the SENER, the CNH and other Mexican regulatory bodies. The CNH is responsible for,
among other things, overseeing the tender procedures for awarding contracts for the exploration and production of
oil and natural gas in Mexican waters, managing and supervising contracts that have been awarded, and approving
exploration and production plans. The PSCs that we and our consortium partners have entered into for the
development of these acreages contain terms that impose on us the duty to comply with various laws and
regulations. These laws and regulations govern, among other things, the exploration and exploitation of
hydrocarbons (including certain national content requirements), the treatment, conveyance, marketing, transport
and storage of petroleum, requirements for industrial safety, operational security, and facility decommissioning.
Failure to comply can result in the imposition of monetary penalties, revocation of permits, rescission of the
relevant PSC, suspension of operations, and ordered decommissioning of offshore facilities and systems. The laws
and regulations governing activities in the Mexican energy sector are relatively new, having been significantly
reformed in 2013, and the legal regulatory framework continues to evolve as SENER, the CNH and other Mexican
regulatory bodies issue new regulations and guidance. Such regulations are subject to change, and it is possible that
SENER, the CNH or other Mexican regulatory bodies may impose new or revised requirements that could increase
our operating costs and/or capital expenditures for operations in Mexican offshore waters.
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In addition, our operations on oil and natural gas blocks in shallow waters off the coast of Mexico’s Veracruz
and Tabasco states, and in other Mexican offshore areas where we are assessing other exploration opportunities, are
subject to regulation by the ASEA. We must obtain ASEA-issued permits and comply with ASEA regulations
governing hydrocarbon activities, including requirements for environmental impact and risk assessments, industrial
safety, waste management, water and air emissions, operational security and facility decommissioning. Failure to
comply with applicable laws and regulations can result in the imposition of monetary penalties, revocation of
permits, suspension of operations, and ordered decommissioning of offshore facilities and systems. The laws and
regulations governing the protection of health, safety and the environment from activities in the Mexican energy
sector are relatively new, having been significantly reformed in 2013 and 2014, and the legal regulatory framework
continues to evolve as ASEA and other Mexican regulatory bodies issue new regulations and guidance. Such
regulations are subject to change, and it is possible that ASEA or other Mexican regulatory bodies may impose new
or revised requirements that could increase our operating costs and/or capital expenditures for operations in
Mexican offshore waters.
Under the PSCs, we are also jointly and severally liable, along with Sierra, Premier and Hokchi, for the
performance of all obligations under the PSCs, including exploration, appraisal, extraction and abandonment
activities and compliance with all environmental regulations, and failure to perform such obligations could result in
contractual rescission of the PSCs.
Production periods or reserve lives for Gulf of Mexico properties may subject us to higher reserve replacement
needs and may impair our ability to reduce production during periods of low oil and natural gas prices.
Substantially all of our operations are in the Gulf of Mexico. As a result, our reserve replacement needs from
new prospects may be greater than those of other oil and gas companies with longer-life reserves in other
producing areas. Our future oil and natural gas production is highly dependent upon our level of success in finding
or acquiring additional reserves at a unit cost that is sustainable at prevailing commodity prices.
Exploring for, developing or acquiring reserves is capital intensive and uncertain. We may not be able to
economically find, develop or acquire additional reserves or make the necessary capital investments if our cash
flows from operations decline or external sources of capital become limited or unavailable. Our need to generate
revenues to fund ongoing capital commitments or repay debt may limit our ability to slow or shut-in production
from producing wells during periods of low prices for oil and natural gas. We cannot assure you that our future
exploitation, exploration, development and acquisition activities will result in additional proved reserves or that we
will be able to drill productive wells at acceptable costs. Further, current market conditions may adversely impact
our ability to obtain financing to fund acquisitions, and they have lowered the level of activity and depressed values
in the oil and natural gas property sales market.
Our actual recovery of reserves may substantially differ from our proved reserve estimates.
Estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such
reserves are based upon various assumptions, including assumptions required by the SEC relating to oil and natural
gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of
estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in
the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is
therefore inherently imprecise. Additionally, our interpretations of the rules governing the estimation of proved
reserves could differ from the interpretation of staff members of regulatory authorities resulting in estimates that
could be challenged by these authorities.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating
expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. Any
significant variance could materially affect the estimated quantities and present value of reserves. Our properties
may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In
addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and
development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
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You should not assume that any present value of future net cash flows from our proved reserves represents
the market value of our estimated oil and natural gas reserves. We base the estimated discounted future net cash
flows from our proved reserves at December 31, 2018 on historical 12-month average prices and costs as of the
date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net
revenues are affected by factors such as:
•
•
the amount and timing of capital expenditures and decommissioning costs;
the rate and timing of production;
• changes in governmental regulations or taxation;
• volume, pricing and duration of our oil and natural gas hedging contracts;
• supply of and demand for oil and natural gas;
• actual prices we receive for oil and natural gas; and
• our actual operating costs in producing oil and natural gas.
The timing of both our production and our incurrence of expenses in connection with the development and
production of oil and natural gas properties affects the timing of actual future net cash flows from reserves, and
thus their actual present value. In addition, the 10% discount factor that we use to calculate the net present value of
future net revenues and cash flows may not necessarily be the most appropriate discount factor based on our cost of
capital in effect from time to time and the risks associated with our business and the oil and gas industry in general.
At December 31, 2018, approximately 24% of our estimated proved reserves (by volume) were undeveloped
and approximately 25% were non-producing. Any or all of our PUD or proved developed non-producing reserves
may not be ultimately developed or produced. Furthermore, any or all of our undeveloped and developed non-
producing reserves may not be ultimately produced during the time periods we plan or at the costs we budget,
which could result in the write-off of previously recognized reserves. Recovery of undeveloped reserves generally
requires significant capital expenditures and successful drilling operations. Our reserve estimates include the
assumptions that we incur capital expenditures to develop these undeveloped reserves and the actual costs and
results associated with these properties may not be as estimated. Any material inaccuracies in these reserve
estimates or underlying assumptions materially affects the quantities and present value of our reserves, which could
adversely affect our business, results of operations and financial condition.
Three-dimensional seismic interpretation does not guarantee that hydrocarbons are present or if present
produce in economic quantities.
We rely on 3D seismic studies to assist us with assessing prospective drilling opportunities on our properties,
as well as on properties that we may acquire. Such seismic studies are merely an interpretive tool and do not
necessarily guarantee that hydrocarbons are present or, if present, produce in economic quantities, and seismic
indications of hydrocarbon saturation are generally not reliable indicators of productive reservoir rock. These
limitations of 3D seismic data may impact our drilling and operational results, and consequently our financial
condition.
SEC rules could limit our ability to book additional PUD reserves in the future.
SEC rules require that, subject to limited exceptions, PUD reserves may only be booked if they relate to
wells scheduled to be drilled within five years after the date of booking. This requirement may limit our ability to
book additional PUD reserves as we pursue our drilling program. Moreover, we may be required to write down our
PUD reserves if we do not drill those wells within the required five-year timeframe.
Our acreage has to be drilled before lease expiration in order to hold the acreage by production. If commodity
prices become depressed for an extended period of time, it might not be economical for us to drill sufficient wells
in order to hold acreage, which could result in the expiry of a portion of our acreage, which could have an
adverse effect on our business.
Unless production is established as required by the leases covering the undeveloped acres, the leases for such
acreage may expire.
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Our drilling plans for areas not held by production are subject to change based upon various factors. Many of
these factors are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of
capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline
transportation constraints and regulatory approvals. On the acreage that we do not operate, we have less control
over the timing of drilling, and therefore there is additional risk of expirations occurring in those sections.
The marketability of our production depends mostly upon the availability, proximity, and capacity of oil and
natural gas gathering systems, pipelines and processing facilities.
The marketability of our production depends upon the availability, proximity, operation and capacity of oil
and natural gas gathering systems, pipelines and processing facilities. The lack of availability or capacity of these
gathering systems, pipelines and processing facilities could result in the shut-in of producing wells or the delay or
discontinuance of development plans for properties. The disruption of these gathering systems, pipelines and
processing facilities due to maintenance and/or weather could negatively impact our ability to market and deliver
our products. Federal, state, and local regulation of oil and natural gas production and transportation, general
economic conditions, and changes in supply and demand could adversely affect our ability to produce and market
our oil and natural gas. If market factors changed dramatically, the financial impact could be substantial. The
availability of markets and the volatility of product prices are beyond our control and represent a significant risk.
Our actual production could differ materially from our forecasts.
From time to time, we may provide forecasts of expected quantities of future oil and gas production. These
forecasts are based on a number of estimates, including expectations of production from existing wells. In addition,
our forecasts may assume that none of the risks associated with our oil and natural gas operations summarized in
this section would occur, such as facility or equipment malfunctions, adverse weather effects or significant declines
in commodity prices or material increases in costs, which could make certain production uneconomical.
Our operations are subject to numerous risks of oil and natural gas drilling and production activities.
Oil and gas drilling and production activities are subject to numerous risks, including the risk that no
commercially productive oil or natural gas reserves are found. The cost of drilling and completing wells is often
uncertain. To the extent we drill additional wells in the Gulf of Mexico deepwater and/or in the Gulf Coast deep
gas, our drilling activities increases capital cost. In addition, the geological complexity of the areas in which we
have oil and natural gas operations make it more difficult for us to sustain the historical rates of drilling success.
Oil and natural gas drilling and production activities may be shortened, delayed or cancelled as a result of a variety
of factors, many of which are beyond our control. These factors include:
• unexpected drilling conditions;
• pressure or irregularities in formations;
• equipment failures or accidents;
• hurricanes and other adverse weather conditions;
• shortages in experienced labor; and
• shortages or delays in the delivery of equipment.
The prevailing prices of oil and natural gas also affect the cost of and the demand for drilling rigs, production
equipment and related services. We cannot assure you that the wells we drill will be productive or that we will
recover all or any portion of our investment. Drilling for oil and natural gas may be unprofitable. Drilling activities
can result in dry holes and wells that are productive but do not produce sufficient cash flows to recoup drilling
costs.
Our industry experiences numerous operating risks.
The exploration, development and production of oil and gas properties involves a variety of operating risks,
including the risk of fire, explosions, blowouts, pipe failure, abnormally pressured formations and environmental
hazards. Environmental hazards include oil spills, gas leaks, pipeline ruptures or discharges of toxic gases. We are
also involved in completion operations that utilize hydraulic fracturing, which may potentially present additional
operational and environmental risks. Additionally, our offshore operations are subject to the additional hazards of
marine operations, such as capsizing, collisions and adverse weather and sea conditions, including the effects of
hurricanes.
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In addition, an oil spill on or related to our properties and operations could expose us to joint and several
strict liability, without regard to fault, under applicable law for containment and oil removal costs and a variety of
public and private damages, including, but not limited to, the costs of responding to a release of oil, natural
resource damages and economic damages suffered by persons adversely affected by an oil spill. If an oil discharge
or substantial threat of discharge were to occur, we could be liable for costs and damages, which costs and damages
could be material to our results of operations and financial position.
Our business is also subject to the risks and uncertainties normally associated with the exploration for and
development and production of oil and natural gas that are beyond our control, including uncertainties as to the
presence, size and recoverability of hydrocarbons. We may not encounter commercially productive oil and natural
gas reservoirs. We may not recover all or any portion of our investment in new wells. The presence of
unanticipated pressures or irregularities in formations, miscalculations or accidents may cause our drilling activities
to be unsuccessful and/or result in a total loss of our investment, which could have a material adverse effect on our
financial condition, results of operations and cash flows. In addition, we may be uncertain as to the future cost or
timing of drilling, completing and operating wells.
We have an interest in deepwater fields and may attempt to pursue additional operational activity in the
future and acquire additional fields and leases in the deepwaters of the Gulf of Mexico. Exploration for oil or
natural gas in the deepwater of the Gulf of Mexico generally involves greater operational and financial risks than
exploration on the Gulf of Mexico Conventional Shelf. Deepwater drilling generally requires more time and more
advanced drilling technologies, involving a higher risk of technological failure and usually higher drilling costs.
For example, the drilling of deepwater wells requires specific types of drilling rigs with significantly higher day
rates and limited availability as compared to the rigs used in shallower water. Deepwater wells often use subsea
completion techniques with subsea trees tied back to host production facilities with flow lines. The installation of
these subsea trees and flow lines requires substantial time and the use of advanced remote installation mechanics.
These operations may encounter mechanical difficulties and equipment failures that could result in cost overruns.
Furthermore, the deepwater operations generally lack the physical and oilfield service infrastructure present on the
Gulf of Mexico Conventional Shelf. As a result, a considerable amount of time may elapse between a deepwater
discovery and the marketing of the associated oil or natural gas, increasing both the financial and operational risk
involved with these operations. Because of the lack and high cost of infrastructure, some reserve discoveries in the
deepwater may never be produced economically.
If any of these industry operating risks occur, we could have substantial losses. Substantial losses may be
caused by injury or loss of life, severe damage to or destruction of property, natural resources and equipment,
pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties,
suspension of operations and production and repairs to resume operations. Any of these industry operating risks
could have a material adverse effect on our business, results of operations and financial condition.
Our business could be negatively affected by security threats, including cybersecurity threats, terrorist
attacks and other disruptions.
As an oil and gas producer, we have various security threats, including cybersecurity threats to gain
unauthorized access to sensitive information or to render data or systems unusable, threats to the security of our
facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and
threats from terrorist acts. The potential for such security threats subjects our operations to increased risks that
could have a material adverse effect on our business. In particular, the implementation of various procedures and
controls to monitor and mitigate security threats and to increase security for our information, facilities and
infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such
procedures and controls are sufficient to prevent security breaches from occurring. If any of these security breaches
were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to
our operations and could have a material adverse effect on our reputation, financial position, results of operations
or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited
to, malicious software, attempts to gain unauthorized access to data and systems and other electronic security
breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise
protected information and corruption of data. These events could damage our reputation and lead to financial losses
from remedial actions, loss of business or potential liability.
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The U.S. government has issued warnings that U.S. energy assets may be the future targets of terrorist
organizations. These developments subject our operations to increased risks. Any future terrorist attack at our
facilities, or those of our purchasers or vendors, could have a material adverse effect on our financial condition and
operations.
Our estimates of future asset retirement obligations may vary significantly from period to period and
unanticipated decommissioning costs could materially adversely affect our future financial position and results
of operations.
We are required to record a liability for the discounted present value of our asset retirement obligations to
plug and abandon inactive, non-producing wells, to remove inactive or damaged platforms, facilities and
equipment, and to restore the land or seabed at the end of oil and natural gas operations. These costs are typically
considerably more expensive for offshore operations as compared to most land-based operations due to increased
regulatory scrutiny and the logistical issues associated with working in waters of various depths. Estimating future
restoration and removal costs in the Gulf of Mexico is especially difficult because most of the removal obligations
may be many years in the future, regulatory requirements are subject to change or more restrictive interpretation,
and asset removal technologies are constantly evolving, which may result in additional or increased or decreased
costs. As a result, we may significantly increase or decrease our estimated asset retirement obligations in future
periods. For example, because we operate in the Gulf of Mexico, platforms, facilities and equipment are subject to
damage or destruction as a result of hurricanes and other adverse weather conditions. The estimated costs to plug
and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was
anticipated to be performed is damaged or toppled rather than structurally intact. Accordingly, our estimates of
future asset retirement obligations could differ dramatically from what we may ultimately incur as a result of
damage from a hurricane or other natural disaster. Also, a sustained lower commodity price environment may
cause our non-operator partners to be unable to pay their share of costs, which may require us to pay our
proportionate share of the defaulting party’s share of costs.
Moreover, the timing for pursuing restoration and removal activities has accelerated for operators in the U.S
Gulf of Mexico following BSEE’s issuance of an NTL that established a more stringent regimen for the timely
decommissioning of what is known as “idle iron” wells, which are wells, platforms and pipelines that are no longer
producing or serving exploration or support functions with respect to an operator’s lease in the Gulf of Mexico. The
idle iron NTL, which was initially issued in 2010 and re-issued with a more streamline framework in December
2018, requires decommissioning of any well that has not been used during the past five years for exploration or
production on active leases and is no longer capable of producing in paying quantities, which must then be
permanently plugged or temporarily abandoned within three years’ time. Similarly, platforms or other facilities no
longer useful for operations must be removed within five years of the cessation of operations. We may have to
draw on funds from other sources to satisfy decommissioning costs. The use of other funds to satisfy such
decommissioning costs could have a material adverse effect on our financial position and results of operations.
Moreover, as a result of the implementation of the idle iron NTL, there is expected to be increased demand for
salvage contractors and equipment operating in the Gulf of Mexico, resulting in increased estimates of plugging,
abandonment and removal costs and associated increases in operators’ asset retirement obligations.
In addition, we could become responsible for decommissioning liabilities related to offshore facilities we no
longer own or operate. Under existing BOEM rules relating to assignment of offshore leases and other legal
interests on the OCS, assignors of such interest may be held jointly and severally liable, regardless of any
indemnity agreements, for decommissioning of OCS facilities existing at the time the assignment was approved by
the BOEM in the event that the assignee, or any subsequent assignee, is unable or unwilling to conduct required
decommissioning obligations. The costs of performance of required decommissioning obligations, whether our or
any assignees, may be material. Moreover, several onshore and offshore exploration and production companies
have sought bankruptcy protection over the past several years. The government may seek to impose a bankrupt
entity’s P&A obligations on us or other predecessors-in-interest, which could be significant and have a material
adverse effect on our business, results of operations, financial condition and cash flows.
We may not receive payment for a portion of our future production.
We may not receive payment for a portion of our future production. We attempt to diversify our sales and
obtain credit protections, such as parent guarantees, from certain of our purchasers. The tightening of credit in the
financial markets may make it more difficult for customers to obtain financing and, depending on the degree to
which this occurs, there may be a material increase in the nonpayment and nonperformance by customers. We are
unable to predict what impact the financial difficulties of certain purchasers may have on our future results of
operations and liquidity.
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The market price of our common stock may decline as a result of the Stone Combination.
The market price of our common stock may decline as a result of the Stone Combination if, among other
things, we are unable to achieve the expected benefits of the transaction, or if the transaction costs related to the
Stone Combination and integration are greater than expected. The market price also may decline if we do not
achieve the perceived benefits of the Stone Combination as rapidly or to the extent anticipated by financial or
industry analysts or if the effect of the Stone Combination on our financial results is not consistent with the
expectations of financial or industry analysts.
We may not realize all of the anticipated benefits from our future acquisitions, and we may be unable to
successfully integrate future acquisitions.
Our growth strategy will, in part, rely on acquisitions. We have to plan and manage acquisitions effectively
to achieve revenue growth and maintain profitability in our evolving market. We expect to grow in the future by
expanding the exploitation and development of our existing assets, in addition to growing through targeted
acquisitions in the Gulf of Mexico or in other basins. We may not realize all of the anticipated benefits from our
future acquisitions, such as increased earnings, cost savings and revenue enhancements, for various reasons,
including difficulties integrating operations and personnel, higher than expected acquisition and operating costs or
other difficulties, inexperience with operating in new geographic regions, unknown liabilities, inaccurate reserve
estimates and fluctuations in market prices.
In addition, integrating acquired businesses and properties involves a number of special risks and unforeseen
difficulties can arise in integrating operations and systems and in retaining and assimilating employees. These
difficulties include, among other things:
• operating a larger organization;
• coordinating geographically disparate organizations, systems and facilities;
•
integrating corporate, technological and administrative functions;
• diverting management’s attention from regular business concerns;
• diverting financial resources away from existing operations;
•
•
increasing our indebtedness; and
incurring potential environmental or regulatory liabilities and title problems.
Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our
operating results. The process of integrating our operations could cause an interruption of, or loss of momentum in,
the activities of our business. Members of our management may be required to devote considerable amounts of
time to this integration process, which decreases the time they have to manage our business. If our management is
not able to effectively manage the integration process, or if any business activities are interrupted as a result of the
integration process, our business could suffer.
Our future acquisitions could expose us to potentially significant liabilities, including P&A liabilities.
We expect that future acquisitions will contribute to our growth. In connection with potential future
acquisitions, we may only be able to perform limited due diligence.
Successful acquisitions of oil and natural gas properties require an assessment of a number of factors,
including estimates of recoverable reserves, the timing of recovering reserves, exploration potential, future oil and
natural gas prices, operating costs and potential environmental, regulatory and other liabilities, including P&A
liabilities. Such assessments are inexact and may not disclose all material issues or liabilities. In connection with
our assessments, we perform a review of the acquired properties. However, such a review may not reveal all
existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the
properties to fully assess their deficiencies and capabilities.
There may be threatened, contemplated, asserted or other claims against the acquired assets related to
environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could
materially and adversely affect our production, revenues and results of operations. We may be successful in
obtaining contractual indemnification for preclosing liabilities, including environmental liabilities, but we expect
that we will generally acquire interests in properties on an “as is” basis with limited remedies for breaches of
representations and warranties. In addition, even if we are able to obtain such indemnification from the sellers,
these indemnification obligations usually expire over time and could potentially expose us to unindemnified
liabilities, which could materially adversely affect our production, revenues and results of operations.
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We may be exposed to liabilities under the U.S. Foreign Corrupt Practices Act (the “FCPA”).
We are subject to the FCPA and other laws that prohibit improper payments or offers of payments to foreign
governments and their officials and political parties for the purpose of obtaining or retaining business. We may do
business in the future in countries and regions in which we may face, directly or indirectly, corrupt demands by
officials, tribal or insurgent organizations, or private entities. Thus, we face the risk of unauthorized payments or
offers of payments by one of our employees or consultants, given that these parties may not always be subject to
our control. Our existing safeguards and any future improvements may prove to be less than effective, and our
employees and consultants may engage in conduct for which we might be held responsible.
Under the PSCs with the CNH, we work as a consortium with other partners: Sierra, Premier and Hokchi.
Violations of the FCPA, by any consortium partner, may result in severe criminal or civil sanctions, and we may be
subject to other liabilities, which could negatively affect our business, operating results and financial condition. In
addition, the CNH has the authority to rescind the PSCs if these violations occur.
Our operations may be adversely affected by political and economic circumstances in the countries in which we
operate.
Our oil and gas exploration, development and production activities are subject to political and economic
uncertainties (including but not limited to changes, sometimes frequent or marked, in energy policies or the
personnel administering them), expropriation of property, cancellation or modification of contract rights, changes
in laws and policies governing operations of foreign-based companies, unilateral renegotiation of contracts by
governmental entities, redefinition of international boundaries or boundary disputes, foreign exchange restrictions,
currency fluctuations, royalty and tax increases, and other risks arising out of governmental sovereignty over the
areas in which our operations are conducted, as well as risks of loss due to acts of terrorism, piracy, disease, illegal
cartel activities and other political risks, including tension and confrontations among political parties. Some of
these risks may be higher in the developing countries in which we conduct our activities, namely, Mexico.
Mexico’s most recent presidential election was held in July 2018. Presidential reelection is not permitted in
Mexico. President Andrés Manuel López Obrador, took office on December 1, 2018, and his political party,
Movimiento Regeneración Nacional has a majority in both houses of Mexico’s congress. Mr. Lopez Obrador, and
certain members of his cabinet have, in the past, made statements that would call into question the degree of
support their administration will have for Mexico’s energy reforms. However, at this time we cannot predict what
changes (if any) will result from this change in administration. Political events in Mexico could adversely affect
economic conditions and/or the oil and gas industry and, by extension, our results of operations and financial
position.
Our operations may be exposed to risks of illegal cartel activities, local economic conditions, political
disruption, and governmental policies that may:
• disrupt our operations;
•
•
•
restrict the movement of funds or limit repatriation of profits;
in the case of our non-U.S. operations, lead to U.S. government or international sanctions; and
limit access to markets for periods of time.
Disruptions may occur in the future, and losses caused by these disruptions may not be covered by insurance.
Consequently, our exploration, development and production activities may be substantially affected by factors that
could have a material adverse effect on our financial condition and results of operations. Furthermore, in the event
of a dispute arising from non-U.S. operations, we may be subject to the exclusive jurisdiction of courts outside the
United States or may not be successful in subjecting non-U.S. persons to the jurisdiction of courts in the United
States, which could adversely affect the outcome of such dispute.
Our operations are adversely affected by laws and policies of the jurisdictions, including Mexico, the United
States, the Netherlands and other jurisdictions, in which we do business that affect foreign trade and taxation.
Changes in any of these laws or policies or the implementation thereof could have a material adverse effect on our
results of operations and financial position.
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New technologies may cause our current exploration and drilling methods to become obsolete, and we may not
be able to keep pace with technological developments in our industry.
The oil and natural gas industry is subject to rapid and significant advancements in technology, including the
introduction of new products and services using new technologies. As competitors use or develop new
technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to
implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical,
and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to
implement new technologies before we can. We rely heavily on the use of seismic technology to identify low-risk
development and exploitation opportunities and to reduce our geological risk. Seismic technology or other
technologies that we may implement in the future may become obsolete. We cannot be certain that we will be able
to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain
technological advancements consistent with industry standards, our business, results of operations and financial
condition may be materially adversely affected.
We may not be in a position to control the timing of development efforts, the associated costs or the rate of
production of the reserves from our non-operated properties.
As we carry out our drilling program, we may not serve as operator of all planned wells. We may have
limited ability to exercise influence over the operations of some non-operated properties and their associated costs.
Our dependence on the operator and other working interest owners and our limited ability to influence operations
and associated costs of properties operated by others could prevent the realization of anticipated results in drilling
or acquisition activities. The success and timing of development and exploitation activities on properties operated
by others depends upon a number of factors that could be largely outside of our control, including:
•
•
•
the timing and amount of capital expenditures;
the availability of suitable offshore drilling rigs, drilling equipment, support vessels, production and
transportation infrastructure and qualified operating personnel;
the operator’s expertise and financial resources;
• approval of other participants in drilling wells;
•
risk of other non-operator’s failing to pay its share of costs, which may require us to pay our proportionate
share of the defaulting party’s share of costs;
• selection of technology;
•
•
the rate of production of the reserves; and
the timing and cost of P&A operations.
In addition, with respect to oil and natural gas projects that we do not operate, we have limited influence over
operations, including limited control over the maintenance of safety and environmental standards. The operators of
those properties may, depending on the terms of the applicable joint operating agreement:
•
•
refuse to initiate exploration or development projects;
initiate exploration or development projects on a slower or faster schedule than we would prefer;
• delay the pace of exploratory drilling or development; and/or
• drill more wells or build more facilities on a project than we can afford, whether on a cash basis or through
financing, which may limit our participation in those projects or limit the percentage of our revenues from
those projects.
The occurrence of any of the foregoing events could have a material adverse effect on our anticipated
exploration and development activities.
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Competition within our industry may adversely affect our operations.
Competition within our industry is intense, particularly with respect to the acquisition of producing properties
and undeveloped acreage. We compete with major oil and gas companies and other independent producers of
varying sizes, all of which are engaged in the acquisition of properties and the exploration and development of such
properties. Many of our competitors have financial resources and exploration and development budgets that are
substantially greater than our budget, which may adversely affect our ability to compete. If other companies
relocate to the Gulf of Mexico region, levels of competition may increase and our business could be adversely
affected. In the exploration and production business, some of the larger integrated companies may be better able
than we are to respond to industry changes including price fluctuations, oil and gas demand, political change and
government regulations.
We actively compete with other companies when acquiring new leases or oil and gas properties. For
example, new leases acquired from BOEM are acquired through a “sealed bid” process and are generally awarded
to the highest bidder. These additional resources can be particularly important in reviewing prospects and
purchasing properties. The competitors may also have a greater ability to continue drilling activities during periods
of low oil and gas prices, such as the current decline in oil prices, and to absorb the burden of current and future
governmental regulations and taxation. Competitors may be able to evaluate, bid for and purchase a greater number
of properties and prospects than our financial or personnel resources permit. Competitors may also be able to pay
more for productive oil and gas properties and exploratory prospects than we are able or willing to pay. Further, our
competitors may be able to expend greater resources on the existing and changing technologies that we believe
impacts attaining success in the industry. If we are unable to compete successfully in these areas in the future, our
future revenues and growth may be diminished or restricted.
The loss of our larger customers could materially reduce our revenue and materially adversely affect our
business, financial condition and results of operations.
We have a limited number of customers that provide a substantial portion of our revenue. The loss of our
larger customers, including Shell Trading (US) Company, could adversely affect our current and future revenue,
and could have a material adverse effect on our business, financial condition and results of operations.
Our business depends on access to oil and natural gas processing, gathering and transportation systems and
facilities.
The marketability of our oil and natural gas production depends in large part on the operation, availability,
proximity, capacity and expansion of processing, gathering and transportation facilities owned by third parties. We
can provide no assurance that sufficient processing, gathering and/or transportation capacity exists or that we will
be able to obtain sufficient processing, gathering and/or transportation capacity on economic terms. A lack of
available capacity on processing, gathering and transportation facilities or delays in their planned expansions could
result in the shut-in of producing wells or the delay or discontinuance of drilling plans for properties. A lack of
availability of these facilities for an extended period of time could negatively impact our revenues. In addition, we
enter into contracts for firm transportation, and any failure to renew those contracts on the same or better
commercial terms could increase our costs and our exposure to the risks described above. In addition, the rates
charged for processing, gathering and transportation services may increase over time.
The loss of key personnel could adversely affect our ability to operate.
Our industry has lost a significant number of experienced professionals over the years due to its cyclical
nature, which is attributable, among other reasons, to the volatility in commodity prices. Our operations are
dependent upon key management and technical personnel. We cannot assure you that individuals will remain with
us for the immediate or foreseeable future. The unexpected loss of the services of one or more of these individuals
could have an adverse effect on us and our operations.
In addition, our exploration, production and decommissioning activities require personnel with specialized
skills and experience. As a result, our ability to remain productive and profitable depends upon our ability to
employ and retain skilled workers. Our ability to expand operations depends in part on our ability to increase the
size of our skilled labor force, including geologists and geophysicists, field operations managers and engineers, to
handle all aspects of our exploration, production and decommissioning activities. The demand for skilled workers
in our industry is high, and the supply is limited. A significant increase in the wages paid by competing employers
or the unionization of our Gulf of Mexico employees could result in a reduction of our labor force, increases in the
wage rates that we will have to pay, or both. If either of these events were to occur, our capacity and profitability
could be diminished and our growth potential could be impaired.
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Resolution of litigation could materially affect our financial position and results of operations.
Resolution of litigation could materially affect our financial position and results of operations. To the extent
that potential exposure to liability is not covered by insurance or insurance coverage is inadequate, we may incur
losses that could be material to our financial position or results of operations in future periods.
We have operations in multiple jurisdictions, including jurisdictions in which the tax laws, their interpretation
or their administration may change. As a result, our tax obligations and related filings are complex and subject
to change, and our after-tax profitability could be lower than anticipated. Additionally, political events in the
United States or Mexico could result in changes to the taxation of our income and operations, which could also
adversely impact our after-tax profitability.
We are subject to income, withholding and other taxes in the United States on a worldwide basis and in
numerous state, local and foreign jurisdictions with respect to our income and operations related to those
jurisdictions. Our after-tax profitability could be affected by numerous factors, including the availability of tax
credits, exemptions and other benefits to reduce our tax liabilities, changes in the relative amount of our earnings
subject to tax in the various jurisdictions in which we operate, the potential expansion of our business into or
otherwise becoming subject to tax in additional jurisdictions, changes to our existing business structure and
operations, the extent of our intercompany transactions and the extent to which taxing authorities in the relevant
jurisdictions respect those intercompany transactions.
Our after-tax profitability may also be affected by changes in the relevant tax laws and tax rates, regulations,
administrative practices and principles, judicial decisions, and interpretations, in each case, possibly with
retroactive effect. The United States recently enacted tax reform legislation in Public Law No. 115-97, commonly
referred to as the Tax Cuts and Jobs Act. Additionally, the Multilateral Convention to Implement Tax Treaty
Related Measures to Prevent BEPS recently entered into force among the jurisdictions that have ratified it. Both of
these recent changes could result in further changes to our global taxation. These tax reforms provided for new and
complex provisions that significantly change how the United States and other jurisdictions tax entities and
operations, and those provisions are subject to further legislative change and administrative guidance and
interpretation, all of which may differ from our interpretation. Additionally, Mexico recently elected a new
president, Andrés Manuel López Obrador, who took office on December 1, 2018. His political party, Movimiento
Regeneración Nacional, has a majority in both houses of Mexico’s congress. However, it is unclear at this time
what changes (if any) to the taxation of our income and operations will result from these political events in Mexico.
Future tax reforms in Mexico as a result of these political events or in any other jurisdictions in which we operate
now or in the future could also adversely impact our after-tax profitability.
Future regulations relating to and interpretations of recently enacted U.S. federal income tax legislation may
vary from our current interpretation of such legislation.
The U.S. federal income tax legislation recently enacted in Public Law No. 115-97, commonly referred to as
the Tax Cuts and Jobs Act, is highly complex and subject to interpretation. The presentation of our financial
condition and results of operations is based upon our current interpretation of the provisions contained in the Tax
Cuts and Jobs Act. In the future, the Treasury Department and the Internal Revenue Service are expected to release
regulations relating to and interpretive guidance of the legislation contained in the Tax Cuts and Jobs Act. Any
significant variance of our current interpretation of such legislation from any future regulations or interpretive
guidance could result in a change to the presentation of our financial condition and results of operations and could
negatively affect our business.
Climate change legislation or regulations restricting emissions of GHGs could result in increased operating
costs and reduced demand for the crude oil and natural gas that we produce.
Climate change continues to attract considerable public and scientific attention. As a result, numerous
proposals have been made and could continue to be made at the international, national, regional and state levels of
government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade
programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions
from certain sources. At the federal level, no comprehensive climate change legislation has been implemented. The
EPA, however, has adopted regulations to restrict emissions of GHGs under existing provisions of the federal
CAA. The EPA has adopted rules regulating GHG emissions under the existing CAA, including a rule requiring
emissions of GHGs from certain large stationary sources through preconstruction and operating permit
requirements.
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The EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG
emission sources in the United States, on an annual basis. Recent regulation of emissions of GHGs has focused on
fugitive methane emissions. The EPA has also taken steps to limit methane emissions, a GHG, from certain new
modified or reconstructed facilities in the oil and natural gas sector through the adoption of a final rule in June
2016 establishing Subpart OOOOa standards for methane emissions. However, in 2017, the EPA published a
proposed rule to stay certain portions of these Subpart OOOOa standards for two years but the rule was not
finalized. Rather, in February 2018, the EPA finalized amendments to certain requirements of the June 2016 final
rule, and in September 2018 the EPA proposed additional amendments, including rescission of certain
requirements and revisions to other requirements, such as fugitive emission monitoring frequency. In the event that
the EPA’s June 2016 rule should remain or be placed in effect, or should any other new methane emission
standards be imposed on the oil and natural gas sector, such requirements could result in increased costs to our
operations as well as result in restrictions, delays or cancellations in such operations, which costs, restrictions,
delays or cancellations could adversely affect our business.
In addition, while the United States Congress has not taken any legislative action to reduce emissions of
GHGs, many states have established GHG cap and trade programs. Most of these cap and trade programs work by
requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries
and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for
purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal.
Additionally, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris
Agreement, an international climate change agreement in Paris, France that calls for countries to set their own
GHG emissions targets and be transparent about the measures each country uses to achieve its GHG emissions
targets. The Paris Agreement entered into force on November 4, 2016. However, in August 2017, the U.S. State
Department officially informed the United Nations of the intent of the United States to withdraw from the Paris
Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November
2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit
process is uncertain and/or the terms on which the United States may reenter the Paris Agreement or a separately
negotiated agreement are unclear at this time.
The adoption of legislation or regulatory programs to reduce emissions of GHG could require us to incur
increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions
allowances or to comply with new regulatory or reporting requirements. Substantial limitations on GHG emissions
could also adversely affect demand for the oil and natural gas we produce and lowers the value of our reserves.
Consequently, legislation and regulatory programs to reduce emissions of GHG could have an adverse effect on our
business, financial condition and results of operations. Additionally, with concerns over GHG emissions, certain
non-governmental activists have recently directed their efforts at advocating the shifting of funding away from
companies with energy-related assets, which could result in limitations or restrictions on certain sources of funding
for the energy sector.
In addition, claims have been made against certain energy companies alleging that GHG emissions from oil
and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private
individuals or public entities may seek to enforce environmental laws and regulations against us and could allege
personal injury, property damage, or other liabilities. While our business is not a party to any such litigation, we
could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly
impact our operations and could have an adverse impact on our financial condition.
Finally, some scientists have concluded that increasing concentrations of GHG in the Earth’s atmosphere
may produce climate changes that have significant physical effects, such as increased frequency and severity of
storms, droughts, floods, and other climatic events. Our offshore operations are particularly at risk from severe
climatic events. If any such climate changes were to occur, they could have an adverse effect on our financial
condition and results of operations.
The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments
to reduce the effect of commodity price, interest rate and other risks associated with our business.
The Dodd-Frank Act, enacted on July 21, 2010, expanded federal oversight and regulation of the over-the-
counter derivatives market and entities that participate in that market. The Dodd-Frank Act requires the CFTC and
the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC and the SEC
have finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to
predict when this is accomplished.
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In one of its rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC issued on
December 5, 2016, re-proposed rules imposing position limits for certain futures and option contracts in various
commodities (including oil and gas) and for swaps that are their economic equivalents. Under the proposed rules on
position limits, certain types of hedging transactions are exempt from these limits on the size of positions that may
be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain enumerated “bona fide
hedging” transactions or positions. As these new position limit rules are not yet final, the impact of those
provisions on us is uncertain at this time.
The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the
associated rules also requires us, in connection with covered derivative activities, to comply with clearing and
trade-execution requirements or to take steps to qualify for an exemption to such requirements. Although we expect
to qualify for the end-user exception from the mandatory clearing requirements for swaps to be entered into to
hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other
market participants, such as swap dealers, may change the cost and availability of the swaps that we use for
hedging. In addition, certain banking regulators and the CFTC have recently adopted final rules establishing
minimum margin requirements for uncleared swaps. Although we expect to qualify for, and to utilize, the end-user
exception from such margin requirements for swaps to be entered into to hedge our commercial risks, the
application of such requirements to other market participants, such as swap dealers, may change the cost and
availability of the swaps that we use for hedging. If any of our swaps do not qualify for the commercial end-user
exception, posting of collateral could impact liquidity and reduce cash available to us for capital expenditures,
therefore reducing our ability to execute hedges to reduce risk and protect cash flows.
The full impact of the Dodd-Frank Act and related regulatory requirements upon our business will not be
known until the regulations are fully implemented and the market for derivatives contracts has adjusted. The Dodd-
Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the
terms of derivative contracts, reduce the availability of derivatives to protect against risks we may encounter, or
reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as
a result of the Dodd-Frank Act and regulations implementing the Dodd-Frank Act, our results of operations may
become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan
for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil
and gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments
related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-
Frank Act and implementing regulations is to lower commodity prices. Any of these consequences could have a
material adverse effect on us, our financial condition and our results of operations.
In addition, the European Union and other non-U.S. jurisdictions have implemented and continue to
implement new regulations with respect to the derivatives market. To the extent we transact with counterparties in
foreign jurisdictions, we may become directly subject to such regulations and in any event the global derivatives
market are affected to the extent that foreign counterparties are affected by such regulations. At this time, the
impact of such regulations is not clear.
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Hedging transactions may limit our potential gains.
In order to manage our exposure to price risks in the marketing of our oil, natural gas and natural gas liquids,
we periodically enter into oil, natural gas and natural gas liquids price hedging arrangements with respect to a
portion of our expected production. Our hedging policy provides that we may enter into hedging arrangements
covering up to the following maximum percentages of volumes: (i) 90% of the reasonably anticipated quarterly
production of oil, natural gas and natural gas liquids of proved developed producing (“PDP”) volumes during
months January through July and November through December, (ii) 65% of the reasonably anticipated quarterly
production of oil, natural gas and natural gas liquids of PDP volumes during months August through October, (iii)
50% of the reasonably anticipated quarterly production of oil, natural gas and natural gas liquids of our proved
developed non-producing volumes during months January through July and November through December and (iv)
0% of the reasonably anticipated quarterly production of oil, natural gas and natural gas liquids of its proved
developed non-producing volumes during months August through October. These arrangements may include
futures contracts on the NYMEX. While intended to reduce the effects of volatile oil and natural gas prices, such
transactions, depending on the hedging instrument used, may limit our potential gains if oil and natural gas prices
were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to
the risk of financial loss in certain circumstances, including instances in which:
• our production is less than expected or is shut-in for extended periods due to hurricanes or other factors;
•
•
there is a widening of price differentials between delivery points for our production and the delivery point
to be assumed in the hedge arrangement;
the counterparties to our futures contracts fails to perform the contracts;
• a sudden, unexpected event materially impacts oil or natural gas prices; or
• we are unable to market our production in a manner contemplated when entering into the hedge contract.
A majority of our outstanding commodity derivative instruments are with certain lenders or affiliates of the
lenders under our Bank Credit Facility. Our derivative agreements with the lenders are secured by the security
documents executed by the parties under the Bank Credit Facility. Future collateral requirements for our
commodity hedging activities are uncertain and depend on the arrangements we negotiate with the counterparty and
the volatility of oil and natural gas prices and market conditions.
We are controlled by Apollo Funds and Riverstone Funds. The interests of Apollo Funds and Riverstone Funds
may differ from the interests of our other stockholders.
Immediately following the closing of the Stone Combination, the Apollo Funds and Riverstone Funds
beneficially owned and possessed voting power over 63% of our common stock. Under the Stockholders’
Agreement, the Apollo Funds and the Riverstone Funds may acquire additional shares of our common stock
without the approval of our Independent Directors as defined in that certain Stockholders’ Agreement, dated as of
May 10, 2018 (the “Stockholders’ Agreement”).
Through their ownership of a majority of our voting power and the provisions set forth in our Amended and
Restated Certificate of Incorporation, Amended and Restated Bylaws and the Stockholders’ Agreement, the Apollo
Funds and the Riverstone Funds have the ability to designate a majority of our directors to be nominated for
election by our stockholders. As a result of the Apollo Funds’ and the Riverstone Funds’ ownership of a majority
of the voting power of our common stock, we are a “controlled company” as defined in NYSE listing rules and,
therefore, we are not subject to NYSE requirements that would otherwise require us to have a majority of
independent directors and nominating and compensation committees composed solely of independent directors. We
have not elected to take advantage of the “controlled company” exemptions available to us, but we may do so in the
future.
The Apollo Funds and the Riverstone Funds also have control over all other matters submitted to
stockholders for approval, including changes in capital structure, transactions requiring stockholder approval under
Delaware law, and corporate governance, subject to the terms of the Stockholders’ Agreement that require the
Apollo Funds and the Riverstone Funds to vote in a specified manner on certain actions, including their agreement
to vote in favor of director nominees not designated by the Apollo Funds and the Riverstone Funds. The Apollo
Funds and the Riverstone Funds may have different interests than other holders of our common stock and may
make decisions adverse to your interests.
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Among other things, the Apollo Funds’ and Riverstone Funds’ control could delay, defer or prevent a sale of
us that our other stockholders support, or, conversely, this control could result in the consummation of such a
transaction that other stockholders do not support. This concentrated control could discourage a potential investor
from seeking to acquire our common stock and, as a result, might harm the market price of our common stock.
If securities or industry analysts do not publish research or reports about our business, if they adversely change
their recommendations regarding our common stock, or if our operating results do not meet their expectations,
the price of our common stock could decline.
The trading market for our common stock will be influenced by the research and reports that industry or
securities analysts publish about us or our business. If one or more of these analysts cease coverage of us or fail to
publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our
stock price or trading volume to decline. Moreover, if one or more of the analysts who cover us downgrades our
common stock or if our operating results do not meet their expectations, our stock price could decline.
Negative publicity may adversely impact us.
Media coverage and public statements that insinuate improper actions by us, regardless of their factual
accuracy or truthfulness, may result in negative publicity, litigation or governmental investigations by regulators.
Addressing negative publicity and any resulting litigation or investigations may distract management, increase
costs and divert resources. Negative publicity may have an adverse impact on our reputation and the morale of our
employees, which could materially adversely affect our business, financial position, results of operations, cash
flows, growth prospects and stock price.
The corporate opportunity provisions in our Amended and Restated Certificate of Incorporation could enable
others to benefit from corporate opportunities that might otherwise be available to us.
Subject to the limitations of applicable law, our Amended and Restated Certificate of Incorporation, among
other things:
• permits us to enter into transactions with entities in which one or more of our officers or directors are
financially or otherwise interested;
• permits the Apollo Funds, the Riverstone Funds, and any of our officers or directors who is also an officer,
director, employee, managing director, or other affiliate of the Apollo Funds or the Riverstone Funds to conduct
business that competes with us and to make investments in any kind of property in which we may make
investments; and
• provides that if the Apollo Funds, the Riverstone Funds, or any of our officers or directors who is also an
officer, director, employee, managing director or other affiliate of the Apollo Funds or the Riverstone Funds
becomes aware of a potential business opportunity, transaction or other matter (other than one expressly offered to
that director or officer in writing solely in his or her capacity as an director or officer of us), that director or officer
will have no duty to communicate or offer that opportunity to us, and will be permitted to communicate or offer
that opportunity to any other entity or individual and that director or officer will not be deemed to have acted in a
manner inconsistent with his or her fiduciary duty to us or our stockholders.
These provisions create the possibility that a corporate opportunity that would otherwise be available to us
may be used for the benefit of others.
Our Amended and Restated Certificate of Incorporation designates the Court of Chancery of the State of
Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by
our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes
with us or our directors, officers, employees or agents.
Our Amended and Restated Certificate of Incorporation provides that, unless we consent in writing to the
selection of an alternative forum, the Court of Chancery of the State of Delaware will be the sole and exclusive
forum for (i) any derivative action or proceeding brought on behalf of us, (ii) any action asserting a claim of breach
of a fiduciary duty owed by any of our current or former directors, officers, employees, agents or stockholders
(including a beneficial owner of stock) to us or our stockholders, (iii) any action asserting a claim arising pursuant
to any provision of the Delaware General Corporation Law, our Amended and Restated Certificate of Incorporation
or Amended and Restated Bylaws, or (iv) any action asserting a claim governed by the internal affairs doctrine, in
each case subject to the Court of Chancery having personal jurisdiction over the indispensable parties named as
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defendants in the case. Any person or entity purchasing or otherwise acquiring any interest in any share of our
capital stock will be deemed to have notice of and consent to these provisions of our Amended and Restated
Certificate of Incorporation. This exclusive forum provision may limit a stockholder’s ability to bring a claim in a
judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may
discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our
Amended and Restated Certificate of Incorporation inapplicable to, or unenforceable in respect of, one or more of
the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters
in other jurisdictions, which could adversely affect our business, financial condition or results of operations.
The Apollo Funds and the Riverstone Funds are prohibited from transferring a portion of their shares of our
common stock until the first anniversary of the Closing Date, after which, subject to restrictions, they will be
permitted to transfer their shares of our common stock, which could have a negative impact on our stock price.
Pursuant to the Stockholders’ Agreement, and unless approved by a majority of our Independent Directors
(as defined in the Stockholders’ Agreement), the Apollo Funds and the Riverstone Funds will be restricted from
transferring, other than to an affiliate, 25% of the respective shares of our common stock held by each on the
Closing Date, until May 10, 2019. Beginning on May 10, 2019, the lock-up will cease to apply and the Apollo
Funds and the Riverstone Funds will be permitted, subject to certain restrictions, to transfer such shares of our
common stock, including in public offerings pursuant to registration rights granted by us. Any such transfer could
significantly increase the number of shares of our common stock available in the market, which could cause a
decrease in the price of our common stock.
Additionally, pursuant to the Stockholders’ Agreement, until the first anniversary of the Closing Date, each
of the Apollo Funds and the Riverstone Funds will be prohibited from transferring any shares of our common stock
in any transaction that would result in the transferee owning more than 35% of the outstanding shares of our
common stock without the prior approval of a majority of our Independent Directors, unless such transferee agrees
in writing to be bound by substantially the same provisions as the stockholders are bound by pursuant to the
Stockholders’ Agreement. Following the first anniversary of the Closing Date, the Apollo Funds and the Riverstone
Funds could sell a significant percentage of our common stock to a third party that is not subject to provisions
similar to the provisions in the Stockholders’ Agreement.
A change in the jurisdictional characterization of our FERC-jurisdictional pipelines, tribal or local regulatory
agencies or a change in policy by those agencies may result in increased regulation of such asset, which may
cause our revenues to decline and operating expenses to increase or delay or increase the cost of expansion
projects.
SP 49 Pipeline LLC is considered a common carrier pipeline subject to regulation by FERC under ICA. The
ICA requires that we maintain a tariff on file with FERC for SP 49 Pipeline LLC that sets forth the rates we charge
for providing transportation service as well as the rules and regulations governing such service. The ICA requires,
among other things, that the rates, terms and conditions of service on interstate common carrier pipelines be “just
and reasonable” and non-discriminatory. In the event a shipper protests the rates, terms or conditions of service in
effect pursuant to the tariff, we may be required to modify such rates, terms, or conditions, which could adversely
affect the results of our operations. With respect to CKB Petroleum, Inc., which has been granted a waiver of
certain portions of the ICA and related regulations by FERC, should the pipeline’s circumstances change, FERC
could, either at the request of other entities or on its own initiative, assert that such pipeline no longer qualifies for a
waiver. In the event that FERC were to determine that CKB Petroleum, Inc. no longer qualified for a waiver, we
would likely be required to file a tariff with FERC, provide a cost justification for the transportation charge, and
provide service to all potential shippers without undue discrimination. Such a change in the jurisdictional status of
transportation on the CKB Pipeline could adversely affect our results of operations.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
Information regarding our properties is included in Part I, Item 1. Business, Part II, Item 8. Financial
Statements and Supplemental Data — Note 3 — Acquisitions and Note 4 — Property, Plant and Equipment.
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Item 3. Legal Proceedings
We are named as a party in certain lawsuits and regulatory proceedings arising in the ordinary course of
business. We do not expect that these matters, individually or in the aggregate, will have a material adverse effect
on our financial condition.
On January 6, 2016, ERT plead guilty to two violations of the Clean Water for self-reported activities
surrounding overboard discharge sampling and unpermitted discharges and two violations of OSCLA. On April 6,
2016, the United States District Court for the Eastern District of Louisiana accepted ERT’s plea and sentenced
ERT, consistent with the plea agreement, to pay a penalty of $4.2 million which ERT has paid. The Court placed
ERT on probation for three years. The conditions of probation include compliance with an agreed Safety and
Environmental Compliance Program. As a result of ERT’s conviction for violations of the CWA, ERT was
debarred and cannot enter into contracts with or receive benefits from the federal government, until the EPA
reinstates ERT by certifying that ERT has corrected the conditions giving rise to the Clean Water convictions. EPA
also imposed discretionary suspension and proposed debarment on Talos Production LLC, Talos Energy Offshore
LLC and Talos Energy LLC as affiliates of ERT. On November 23, 2016, EPA terminated and administratively
closed the suspension as to each of the three entities previously suspended. On August 29, 2017, EPA certified that
the conditions giving rise to ERT’s conviction were corrected, and its debarment was lifted.
The following proceedings represent previous Stone litigation that was assumed as part of the Stone
Combination.
On November 17, 2014, the Pennsylvania Department of Environmental Protection (“PADEP”) issued a
Notice of Violation (“NOV”) to Stone alleging releases of production fluid and an improper closure of a drill
cuttings pit at Stone’s Loomis No. 1 well site in Susquehanna County, Pennsylvania. Prior to this, in September
2014, Stone had transferred ownership of the Loomis No. 1 well site to Southwestern Energy Company
(“Southwestern”). PADEP approved the transfer on November 24, 2014, after issuing the NOV to Stone. Stone
investigated the allegations found in the NOV and responded to PADEP on January 5, 2015. Reclamation of the
site by Southwestern, with the participation of the PADEP and Stone, was completed. The PADEP may impose a
penalty in this matter, but the amount of such penalty cannot be reasonably estimated at this time.
On November 11, 2013, two lawsuits were filed, and on November 12, 2013, a third lawsuit was filed,
against Stone and other named co-defendants, by the Parish of Jefferson (“Jefferson Parish”), on behalf of Jefferson
Parish and the State of Louisiana, in the 24th Judicial District Court for the Parish of Jefferson, State of Louisiana,
alleging violations of the State and Local Coastal Resources Management Act of 1978, as amended, and the
applicable regulations, rules, orders and ordinances thereunder (collectively, the “CRMA”), relating to certain of
the defendants’ alleged oil and gas operations in Jefferson Parish, and seeking to recover alleged unspecified
damages to the Jefferson Parish Coastal Zone and remedies, including unspecified monetary damages and
declaratory relief, restoration of the Jefferson Parish Coastal Zone and related costs and attorney’s fees. In March
and April 2016, the Louisiana Attorney General and the Louisiana Department of Natural Resources, respectively,
intervened in the three lawsuits. In connection with Stone’s filing of bankruptcy in December 2016, Jefferson
Parish dismissed its claims against Stone in two of the three Jefferson Parish Coastal Zone Management lawsuits
without prejudice to refiling; the claims of the Louisiana Attorney General and the Louisiana Department of
Natural Resources were not similarly dismissed. The Jefferson Parish lawsuits have been removed to the United
States District Court for the Eastern District of Louisiana. The plaintiffs have moved to remand the lawsuit to the
state courts.
On November 8, 2013, a lawsuit was filed against Stone and other named co-defendants by the Parish of
Plaquemines (“Plaquemines Parish”), on behalf of Plaquemines Parish and the State of Louisiana, in the 25th
Judicial District Court for the Parish of Plaquemines, State of Louisiana, alleging violations of the CRMA, relating
to certain of the defendants’ alleged oil and gas operations in Plaquemines Parish, and seeking to recover alleged
unspecified damages to the Plaquemines Parish Coastal Zone and remedies, including unspecified monetary
damages and declaratory relief, restoration of the Plaquemines Parish Coastal Zone, and related costs and
attorney’s fees. In March and April 2016, the Louisiana Attorney General and the Louisiana Department of Natural
Resources, respectively, intervened in the lawsuit. In connection with Stone’s filing of bankruptcy in December
2016, Plaquemines Parish dismissed its claims against Stone without prejudice to refiling; the claims of the
Louisiana Attorney General and the Louisiana Department of Natural Resources were not similarly dismissed. The
Plaquemines Parish lawsuit has been stayed pending the conclusion of trials in five other cases, also filed in
Plaquemines Parish and alleging violations of the CRMA, but not involving Stone. The Plaquemines Parish lawsuit
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has been removed to the United States District Court for the Eastern District of Louisiana. The plaintiffs have
moved to remand the lawsuit to the state courts.
Legal proceedings are subject to substantial uncertainties concerning the outcome of material factual and
legal issues relating to the litigation. Accordingly, we cannot currently predict the manner and timing of the
resolution of some of these matters and may be unable to estimate a range of possible losses or any minimum loss
from such matters. See Part II, Item 8. Financial Statements and Supplementary Data — Note 11 — Commitments
and Contingencies for more information.
Item 4. Mine Safety Disclosures.
Not applicable.
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PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuers Purchases of
Equity Securities
Market for Common Stock
Our common stock is listed on the NYSE under the symbol “TALO” since the Closing Date. Prior to the
Closing Date, there was no public market for our equity securities.
Holders of Record
Pursuant to the records of our transfer agent, as of March 6, 2019, there were approximately 308 holders of
record of our common stock.
For additional information about shares authorized for issuance under equity compensation plans, see Part II,
Item 8. Financial Statements and Supplementary Data — Note 7 — Employee Benefits Plans and Share-Based
Compensation.
Stockholder Return Performance Presentation
The following graph is included in accordance with the SEC’s executive compensation disclosure rules. This
historic stock price performance is not necessarily indicative of future stock performance. The graph compares the
change in the cumulative total return of our common stock, the Dow Jones U.S. Exploration and Production Index,
and the S&P 500 Index for since May 10, 2018 through December 31, 2018. The graph assumes that $100 was
invested in our common stock and each index on May 10, 2018 and that dividends were reinvested.
Talos Energy Inc.
S&P 500 Index
Dow Jones U.S. Exploration and Production Index
$
May 10, 2018
December 31, 2018
45
93
71
100 $
100
100
The performance graph and the information contained in this section is not “soliciting material,” is being
“furnished” not “filed” with the SEC and is not to be incorporated by reference into any of our filings under the
Securities Act or the Exchange Act whether made before or after the date hereof and irrespective of any general
incorporation language contained in such filing.
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Item 6. Selected Financial Data
The following table sets forth our selected consolidated historical financial data as of and for the periods
ended on the dates indicated below. The selected historical statement of operations data for the years ended
December 31, 2018, 2017 and 2016 and the selected historical balance sheet data as of December 31, 2018 and
2017, have been derived from our audited consolidated financial statements and related notes for the year ended
December 31, 2018, which are included elsewhere in this report. The selected historical statement of operations
data for the years ended December 31, 2015 and 2014, and the selected historical balance sheet data as of
December 31, 2016, 2015 and 2014 have been derived from our audited consolidated financial statements, which
have not been included in this report. Our consolidated financial statements have been prepared in accordance with
GAAP. Our results of operations in any period may not necessarily be indicative of the results that may be
expected for any future period. See Part I, Item 1A. Risk Factors for additional information.
As previously described, Stone and Talos Energy became our wholly-owned subsidiaries on the Closing Date
in connection with the Stone Combination. Prior to the Closing Date, Talos Energy Inc. had not conducted any
material activities other than those incident to its incorporation and certain matters contemplated by the Transaction
Agreement. Talos Energy is the acquirer of Stone for financial reporting and accounting purposes. Talos Energy
was considered the accounting acquirer in the Transactions under GAAP. Accordingly, the selected consolidated
historical financial data presented in the tables below, which covers periods prior to the Closing Date, reflects the
assets, liabilities and operations of Talos Energy prior to the Closing Date and does not reflect the assets, liabilities
and operations of Stone prior to the Closing Date. In addition, we incurred material costs associated with the
Transactions that are reflected in our historical results of operations for periods prior to the Closing Date, and Talos
Energy did not incur United States federal income tax expense or the incremental expense associated with being a
public company.
The selected consolidated historical financial information should be read in conjunction with our financial
statements and the related notes included elsewhere in this report, as well as Part II, Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations.
Year Ended December 31,
2018(1)
2017(1)
2016(1)
2015
2014
(in thousands)
Consolidated statements of operations data:
Revenues:
Oil revenue
Natural gas revenue
NGL revenue
Other
Total revenue
Operating income (loss)
Net income (loss)
Net income (loss) per common share:
Basic
Diluted
Weighted average common shares
outstanding:
Basic
Diluted
Consolidated balance sheets data
(at period end):
Total assets
Total debt(2)
Stockholders' equity (deficit)
73,610
35,863
—
$ 781,815 $ 344,781 $ 197,583 $ 244,167 $ 473,900
63,201
18,269
6,205
$ 891,288 $ 412,828 $ 258,754 $ 315,606 $ 561,575
$ 253,129 $
45,300 $ (80,679) $ (777,651) $ 109,110
$ 221,540 $ (62,868) $ (208,087) $ (646,685) $ 309,419
42,705
9,532
8,934
48,886
16,658
2,503
55,026
10,523
5,890
$
$
4.81 $
4.81 $
(2.01) $
(2.01) $
(7.99) $
(7.99) $
(26.20) $
(26.20) $
15.20
15.20
46,058
46,061
31,244
31,244
26,036
26,036
24,685
24,685
20,358
20,358
$2,479,986 $1,239,293 $1,212,298 $1,194,842 $1,697,240
$ 655,304 $ 697,558 $ 701,175 $ 690,178 $ 595,492
$1,007,496 $ (54,087) $
6,986 $ 120,895 $ 690,502
(1)
(2)
For more information, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
In April 2015, the FASB issued ASU 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt
Issuance Costs. The amendment changes the presentation of long-term debt issuance costs in the financial statements, and was adopted by
Talos Energy during the first quarter of 2016 and applied retrospectively to December 31, 2015 and 2014 as presented above.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Our Business
We are a technically driven independent exploration and production company with operations in the United
States Gulf of Mexico and offshore Mexico. Our focus in the United States Gulf of Mexico is the acquisition of
deepwater assets with existing infrastructure and the exploration, exploitation and development of such assets in
key geologic trends. Offshore Mexico provides us high impact exploration opportunities in an emerging basin. We
use our access to an extensive seismic database and our deep technical expertise to identify, acquire and exploit
attractive assets with robust economic profiles. Our management and technical teams have a long history working
together and have made significant discoveries in the deep waters of the Gulf of Mexico and offshore Mexico.
On the Closing Date, we acquired Stone, an independent oil and natural gas company engaged in the
acquisition, exploration, exploitation, development and operation of oil and gas properties. The Stone properties
acquired in the Stone Combination are located primarily in the deep water of the Gulf of Mexico, with limited
exposure to Gulf of Mexico conventional shelf and deep gas properties. As of the closing of the Stone
Combination, Stone’s property portfolio consisted primarily of nine active properties and 34 primary term leases in
the Gulf of Mexico Basin. For more information on the Stone Combination, please read Part I, Item 1 and 2.
Business and Properties.
In order to determine the most attractive returns for our drilling program, we employ a disciplined portfolio
management approach to stochastically evaluate all of our drilling prospects, whether they are generated
organically from our existing acreage or are acquisition or joint venture opportunities. We add to and reevaluate
our inventory in order to deploy our capital as efficiently as possible.
We plan to opportunistically expand our asset base by evaluating the robust supply of acquisition
opportunities in the Gulf of Mexico. The acquisition strategy is focused on deep and shallow water assets with a
geological setting which we believe can benefit from our access to an extensive seismic database and our
reprocessing expertise to reevaluate the acquired assets. We expect to target acquisitions involving assets with
physical infrastructure that will allow us to focus on additional drilling opportunities. By applying a disciplined
valuation methodology, we seek to reduce the risk of acquired property underperformance while maintaining
potential for higher returns on our investment. In addition, we may consider acquisition opportunities in other
offshore basins with analogous geologies that are suitable for our operational and technical expertise to the extent
we believe it will increase our reserves and enhance returns on our investment and long-term growth prospects.
Recent Developments
In the fourth quarter of 2018, we spud the Zama-2 well, the first appraisal well to be drilled in the field. The
Zama-2 well confirmed the results of the original Zama-1 exploration well. The Zama appraisal campaign is
expected to be completed by approximately mid-year 2019. If the appraisal of the Zama field confirms our initial
estimates, we expect to announce a Final Investment Decision in 2020, following Mexican government approval of
the development plan. In addition to Zama, other prospects are being analyzed and matured to potentially be drilled
over the next several years.
In September 2018, we entered into a transaction the Hokchi Cross Assignment with Hokchi, to cross assign
25% PIs in Block 2 and Block 31. Our assignment of a 25% PI in Block 2 to Hokchi closed on December 21, 2018,
and Hokchi has assumed operator responsibilities with respect to Block 2. Hokchi’s assignment of Block 31 to us
will be completed upon final approval by the CNH, Mexico’s upstream regulator. In addition, Premier exercised its
option to reduce its PI in Block 2 to zero and assign a 5% PI to each of Sierra and us. Such assignment is also
subject to CNH’s approval. Upon completion of the Hokchi Cross Assignment and Premier’s option exercise, we
will own a 25% PI in each of Block 2 and Block 31, and Hokchi will be the operator of both blocks.
In February 2019, CHN granted approval for drilling in the Acan prospect in Block 2. Hokchi intends to start
drilling in March 2019. Soon thereafter, we plan to participate in two prospects in Block 31. Beyond the Acan
prospects, we believe that Blocks 2 and 31 contain a significant portfolio of compelling prospects with strong
technical ties to offsetting discoveries.
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Factors Affecting the Comparability of our Financial Condition and Results of Operations
Stone Combination
As previously described, Stone and Talos Energy became our wholly-owned subsidiaries on the Closing
Date. Prior to the Closing Date, Talos Energy Inc. had not conducted any material activities other than those
incident to its incorporation and certain matters contemplated by the Transaction Agreement. Talos Energy is the
acquirer of Stone for financial reporting and accounting purposes and considered the accounting acquirer in the
Transactions under GAAP. Accordingly, our historical financial and operating data, which covers periods prior to
the Closing Date, reflects the assets, liabilities and results of operations of Talos Energy prior to the Closing Date
and does not reflect the assets, liabilities and results of operations of Stone prior to the Closing Date. See Part II,
Item 8. Financial Statements and Supplementary Data — Note 3 — Acquisitions for more information.
Whistler Acquisition
On August 31, 2018, we completed the acquisition of all the issued and outstanding membership interests of
Whistler from Whistler Energy II Holdco, LLC for $52.6 million ($14.8 million net of $37.8 million of cash
acquired). See Part II, Item 8. Financial Statements and Supplementary Data — Note 3 — Acquisitions for more
information.
Sojitz Acquisition
On December 20, 2016, we purchased an additional 15% working interest in the Phoenix Field from Sojitz
Energy Venture, Inc. for approximately $85.8 million in cash and the assumption of certain asset retirement
obligations, subject to customary post-closing adjustments. The purchase price was funded by a $93.8 million
($91.9 million, net of $1.9 million of transaction fees) contribution from the Sponsors. Additionally, we entered
into a contingent consideration arrangement in the form of an earn-out equal to 5% of the acquired property’s
monthly net profit if our realized oil price is greater than $65.00 per Bbl in a given month. The maximum payout
under the earn-out is $10.0 million and has an indefinite life pursuant to the purchase and sale agreement. See Part
II, Item 8. Financial Statements and Supplementary Data — Note 3 — Acquisitions for more information.
Transaction Expenses
We have incurred and will continue to incur transaction related and restructuring costs associated with the
Stone Combination and the integration of the businesses of Stone and Talos Energy that are not reflected in our
comparative historical results of operations.
Income Tax Expenses
Prior to the Stone Combination, Talos Energy LLC was a partnership for U.S. federal income tax purposes
and was not subject to U.S. federal income tax or state income tax (in most states) at the entity level. As such,
Talos Energy LLC did not recognize U.S. federal income tax expense or state income tax expense in most states.
Talos Energy LLC’s operations in the shallow waters off the coast of Mexico were conducted under a different
legal form and are subject to foreign income taxes.
In connection with the Stone Combination, Talos Energy LLC was contributed to us. We are subject to
federal and state income taxes. We record current income taxes based on estimates of current taxable income and
provide for deferred income taxes to reflect estimated future income tax payments and receipts.
Third Party Planned Downtime
Since our operations are offshore, we are vulnerable to third party downtime events impacting the
transportation, gathering or processing of production. We produce the Phoenix Field through the HP-I that is
operated by Helix. Helix is required to disconnect and dry-dock the HP-I every two to three years for inspection as
required by the United States Coast Guard, during which time we are unable to produce the Phoenix Field. In
January 2019, Helix dry-docked the HP-I for inspection and the shut-in is expected to last until March 2019. For
the year ended December 31, 2018, the Phoenix Field produced 17.9 MBoepd. The impact of the shut-in on the
first quarter of 2019 production is estimated to be between 9.0 MBoepd and 13.0 MBoepd, whereas the annualized
impact for full year 2019 is expected to be between 2.0 MBoepd and 3.0 MBoepd. In the current commodity price
environment, the shut-in represents an estimated cash flow impact of $35.0 million to $55.0 million, primarily in
the first quarter of 2019.
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Known Trends and Uncertainties
Volatility in Oil, Natural Gas and NGL Prices. Historically, the markets for oil and natural gas have been
volatile. Our revenue, profitability, access to capital and future rate of growth depends upon the price we receive
for our sales of oil, natural gas and NGL production. Oil, natural gas and NGL prices are subject to wide
fluctuations in response to relatively minor changes in supply and demand.
BOEM Bonding Requirements. In order to cover the various decommissioning obligations of lessees on the
OCS, BOEM generally requires that lessees post some form of acceptable financial assurances that such
obligations will be met, such as surety bonds. The cost of such bonds or other financial assurance can be
substantial, and we can provide no assurance that we can continue to obtain bonds or other surety in all cases. As
many BOEM regulations are being reviewed by the agency, we may be subject to additional financial assurance
requirements in the future. For example, in July 2016, BOEM issued the NTL 2016-N01 (“the 2016 NTL”) to
clarify the procedures and guidelines that BOEM Regional Directors use to determine if and when additional
financial assurances may be required for OCS leases, ROWs and RUEs. The 2016 NTL became effective in
September 2016, but BOEM subsequently postponed any implementation of the 2016 NTL and has indicated they
will be issuing a modified or substitute NTL. This extension for implementation currently remains in effect. We
remain in active discussions with government regulators and industry peers with regard to any future rulemaking
and financial assurance requirements. Notwithstanding BOEM’s 2016 NTL, BOEM may also bolster its financial
assurance requirements mandated by rule for all companies operating in federal waters. The future cost of
compliance with respect to supplemental bonding, including the obligations imposed on us as a result of the 2016
NTL, to the extent implemented, as well as any other future BOEM directives, or any other changes to BOEM’s
rules applicable to our or any of our subsidiaries’ properties, could materially and adversely affect our financial
condition, cash flows and results of operations.
Deepwater Operations. We have interests in deepwater fields in the Gulf of Mexico. Operations in the
deepwater can result in increased operational risks as has been demonstrated by the Deepwater Horizon disaster in
2010. Despite technological advances since this disaster, liabilities for environmental losses, personal injury and
loss of life and significant regulatory fines in the event of a disaster could be well in excess of insured amounts and
result in significant current losses on our statements of operations as well as going concern issues.
Oil Spill Response Plan. We maintain a Regional Oil Spill Response Plan that defines our response
requirements, procedures and remediation plans in the event we have an oil spill. Oil Spill Response Plans are
generally approved by BSEE bi-annually, except when changes are required, in which case revised plans are
required to be submitted for approval at the time changes are made. Additionally, these plans are tested and drills
are conducted periodically at all levels.
Hurricanes. Since our operations are in the Gulf of Mexico, we are particularly vulnerable to the effects of
hurricanes on production. Additionally, affordable insurance coverage for property damage to our facilities for
hurricanes has become less effective due to rising retentions and limitations on named windstorm coverage and has
been difficult to obtain at times in recent years. Significant hurricane impacts could include reductions and/or
deferrals of future oil and natural gas production and revenues, increased lease operating expenses for evacuations
and repairs and possible acceleration of P&A costs.
How We Evaluate Our Operations
We use a variety of financial and operational metrics to assess the performance of our oil and natural gas
operations, including:
• production volumes;
•
•
realized prices on the sale of oil, natural gas and NGLs, including the effect of our commodity derivative
contracts;
lease operating expenses;
• capital expenditures; and
• Adjusted EBITDA, which is discussed under—Supplemental Non-GAAP Measure.
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Basis of Presentation
Sources of Revenues
Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs that
are extracted from our natural gas during processing. Our oil, natural gas and NGL revenues do not include the
effects of derivatives, which are reported in price risk management activities income in our consolidated statements
of operations. The following table presents a breakout of each revenue component:
Revenue breakout:
Oil revenue
Natural gas revenue
NGL revenue
Other
Year Ended December 31,
2017
2016
2018
88%
8%
4%
—%
83%
12%
4%
1%
76%
17%
4%
3%
Our revenues may vary significantly from period to period as a result of changes in volumes of production
sold or changes in commodity prices.
Realized Prices on the Sale of Oil, Natural Gas and NGLs. The NYMEX WTI prompt month oil settlement
price is a widely used benchmark in the pricing of domestic oil in the United States. The actual prices we realize
from the sale of oil differ from the quoted NYMEX WTI price as a result of quality and location differentials. For
example, the prices we realize on the oil we produce are affected by the Gulf of Mexico Basin’s proximity to U.S.
Gulf Coast refineries and the quality of the oil production sold in Eugene Island Crude, Louisiana Light Sweet
Crude and Heavy Louisiana Sweet Crude markets.
The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the
United States. Similar to oil, the actual prices we realize from the sale of natural gas differ from the quoted
NYMEX Henry Hub price as a result of quality and location differentials. Currently, the sales points of our gas
production are generally within close proximity to the Henry Hub which creates a minimal differential in the prices
we receive for our production versus average Henry Hub prices.
In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue,
as indicated in the table below, which provides the high, low and average prices for NYMEX WTI and NYMEX
Henry Hub monthly contract prices as well as our average realized oil and natural gas sales prices for the periods
indicated.
Oil:
NYMEX WTI High per Bbl
NYMEX WTI Low per Bbl
Average NYMEX WTI per Bbl
Average Oil Sales Price per Bbl
(including commodity derivatives)
Average Oil Sales Price per Bbl
(excluding commodity derivatives)
Natural Gas:
NYMEX Henry Hub High per MMBtu
NYMEX Henry Hub Low per MMBtu
Average NYMEX Henry Hub per MMBtu
Average Natural Gas Sales Price per Mcf
(including commodity derivatives)
Average Natural Gas Sales Price per Mcf
(excluding commodity derivatives)
NGLs:
Year Ended December 31,
2017
2016
2018
$
$
$
$
70.76
48.98
64.77
57.12
66.42
4.72
2.64
3.09
3.16
3.23
$
$
57.95
45.20
50.95
52.46
48.92
3.93
2.63
3.11
2.93
3.00
52.17
30.62
43.32
68.46
38.55
3.23
1.71
2.46
3.24
2.25
NGL Realized Price as a % of Average NYMEX WTI
47%
46%
36%
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To achieve more predictable cash flow, and to reduce exposure to adverse fluctuations in commodity prices,
from time to time we enter into commodity derivative arrangements for our anticipated production. By removing a
significant portion of price volatility associated with our anticipated production, we believe it will mitigate, but not
eliminate, the potential negative effects of reductions in oil and natural gas prices on our cash flow from operations
for those periods. However, in a portion of our current positions, our price risk management activity may also
reduce our ability to benefit from increases in prices. We will sustain losses to the extent our commodity
derivatives contract prices are lower than market prices and, conversely, we will sustain gains to the extent our
commodity derivatives contract prices are higher than market prices.
We will continue to use commodity derivative instruments to manage commodity price risk in the future. Our
hedging strategy and future hedging transactions will be determined at our discretion and may be different from
what we have done on a historical basis.
Expenses
Direct lease operating expense. Direct lease operating expense consists of the daily costs incurred to bring
oil, natural gas and NGLs out of the underground formation and to the market, together with the daily costs
incurred to maintain our producing properties. Expenses for direct labor, HP-I lease, materials and supplies, rental
and third party costs comprise the most significant portion of our direct lease operating expense. In July 2016, we
executed a new contract for the HP-I accounted for as a capital lease, thus reducing the amount recorded as direct
lease operating expenses going forward.
Insurance expense. Insurance expense consists of the cost of insurance policies to cover some of our risk of
loss associated with our operations, and we maintain the amount of insurance we believe is prudent based on our
estimated loss potential. Our significant domestic and international policies include general liability, physical
damage to our oil and gas properties, operational control of well, named Gulf of Mexico windstorm and oil
pollution.
Production taxes. Production taxes consist of severance taxes levied by the Louisiana Department of
Revenue on production of oil and natural gas from land or water bottoms within the boundaries of the state of
Louisiana.
Workover and maintenance expense. Workover and maintenance expense consists of costs associated with
major remedial operations on completed wells to restore, maintain or improve the well’s production. Because the
amount of workover and maintenance expense is closely correlated to the levels of workover activity, which is not
regularly scheduled, workover and maintenance expense is not necessarily comparable from period to period.
Depreciation, depletion and amortization expense. Depreciation, depletion and amortization expense is the
expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas reserves. We use the
full cost method of accounting for oil and natural gas activities. See Part II, Item 8. Financial Statements and
Supplementary Data — Note 2 — Summary of Significant Accounting Policies for further discussion.
Accretion expense. We have obligations associated with the retirement of our oil and natural gas wells and
related infrastructure. We have obligations to plug wells when production on those wells is exhausted, when we no
longer plan to use them or when we abandon them. We accrue a liability with respect to these obligations based on
our estimate of the timing and amount to replace, remove or retire the associated assets. Accretion of the liability is
recognized for changes in the value of the liability as a result of the passage of time over the estimated productive
life of the related assets as the discounted liabilities are accreted to their expected settlement values.
General and administrative expense. General and administrative expense generally consists of costs incurred
for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of
managing our production operations, bad debt expense, equity based compensation expense, audit and other fees
for professional services and legal compliance.
Interest expense. We finance a portion of our working capital requirements, capital expenditures and
acquisitions with borrowings under our Bank Credit Facility and term based debt. As a result, we incur interest
expense that is affected by both fluctuations in interest rates and our financing decisions. Interest includes interest
incurred under our debt agreements, the amortization of deferred financing costs (including origination and
amendment fees), commitment fees, imputed interest on our capital lease, performance bond premiums and annual
agency fees. Interest expense is net of capitalized interest on expenditures made in connection with exploratory
projects that are not subject to current amortization.
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Price risk management activities. We utilize commodity derivative instruments to reduce our exposure to
fluctuations in the price of oil and natural gas. We recognize gains and losses associated with our open commodity
derivative contracts as commodity prices and the associated fair value of our commodity derivative contracts
change. The commodity derivative contracts we have in place are not designated as hedges for accounting
purposes. Consequently, these commodity derivative contracts are marked-to-market each quarter with fair value
gains and losses recognized currently as a gain or loss in our results of operations. Cash flow is only impacted to
the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the
counterparty.
Results of Operations
Comparison of the Year Ended December 31, 2018 and 2017
The information below provides the financial results and an analysis of significant variances in these results
for the year ended December 31, 2018 and 2017 (in thousands):
Year Ended December 31,
2018
2017
Change
% Change
127%
51%
115%
(100)%
116%
34%
43%
36%
35%
98%
83%
83%
134%
74%
459%
(11)%
319%
208%
457%
(100)%
452%
Revenues:
Oil revenue
Natural gas revenue
NGL revenue
Other
Total revenue
Operating expenses:
$ 781,815 $ 344,781 $ 437,034
24,724
19,205
(2,503)
478,460
48,886
16,658
2,503
412,828
73,610
35,863
—
891,288
109,180
10,743
1,460
121,383
32,825
157,352
19,295
36,673
367,528
45,300
(80,934)
(27,563)
329
36,808
4,599
529
41,936
32,136
131,367
16,049
49,143
270,631
207,829
(9,180)
87,998
683
(62,868) $ 287,330
(2,922)
(62,868) $ 284,408
—
Direct lease operating expense
Insurance
Production taxes
Total lease operating expense
Workover / maintenance expense
Depreciation, depletion and amortization
Accretion expense
General and administrative expense
Total operating expenses
Operating income (loss)
Interest expense
Price risk management activities income (expense)
Other income
Net income (loss) before income taxes
Income tax expense
Net income (loss)
145,988
15,342
1,989
163,319
64,961
288,719
35,344
85,816
638,159
253,129
(90,114)
60,435
1,012
$ 224,462 $
(2,922)
$ 221,540 $
65
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The table below provides additional detail of our oil, natural gas and NGL production volumes and sales
prices per unit.
Oil production volume (MBbls)
Average daily oil production volume (MBblpd)
Oil sales revenue (in thousands)
Average oil sales price per Bbl
(including commodity derivatives)
Average oil sales price per Bbl
(excluding commodity derivatives)
Average NYMEX WTI price per Bbl
Increase in oil sales revenue due to:
Change in net realized prices (in thousands)
Change in production volume (in thousands)
Total increase in oil sales revenue (in thousands)
Natural gas production volume (MMcf)
Average daily natural gas production volume (MMcfpd)
Natural gas sales revenue (in thousands)
Average natural gas sales price per Mcf
(including commodity derivatives)
Average natural gas sales price per Mcf
(excluding commodity derivatives)
Average NYMEX Henry Hub price per MMBtu
Increase in natural gas sales revenue due to:
Change in net realized prices (in thousands)
Change in production volume (in thousands)
Total increase in natural gas sales revenue
(in thousands)
NGL production volume (MBbls)
Average daily NGL production volume (MBblpd)
NGL sales revenue (in thousands)
Average NGL sales price per Bbl
Increase in NGL sales revenue due to:
Change in net realized prices (in thousands)
Change in production volume (in thousands)
Total increase in NGL sales revenue (in thousands)
Total production volume (MBoe)
Average daily total production volume (MBoepd)
Price per Boe (including commodity derivatives)
Price per Boe (excluding commodity derivatives)
Year Ended December 31,
2018
2017
Change
11,771
32.2
781,815 $
7,048
19.3
344,781 $
4,723
12.9
437,034
57.12 $
52.46 $
4.66
66.42 $
64.77 $
48.92 $
50.95 $
17.50
13.82
205,985
231,049
437,034
22,771
62.4
73,610 $
16,308
44.7
48,886 $
6,463
17.7
24,724
3.16 $
2.93 $
0.23
3.23 $
3.09 $
3.00 $
3.11 $
0.23
(0.02)
5,335
19,389
$
$
$
$
$
$
$
$
$
$
$
$
24,724
1,176
3.2
35,863 $
30.50 $
8,118
11,087
19,205
16,742
45.9
46.60 $
53.24 $
$
$
$
$
$
$
706
1.9
16,658 $
23.59 $
470
1.3
19,205
6.91
10,472
28.7
41.46 $
39.18 $
6,270
17.2
5.14
14.06
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The following table highlights operating expense items in total and on a cost per Boe production basis. The
information below provides the financial results and an analysis of significant variances in these results for the year
ended December 31, 2018 and 2017 (in thousands, except per Boe data):
Lease operating expenses:
Direct lease operating expense
Insurance
Production taxes
Total lease operating expenses
Depreciation, depletion and amortization
General and administrative expense
Other operating expenses:
Workover / maintenance expense
Accretion expense
Total other operating expenses
Total operating expenses
Year Ended December 31,
2018
2017
Total
Per Boe
Total
Per Boe
$ 145,988 $
15,342
1,989
163,319
288,719
85,816
8.72 $ 109,180 $
10,743
0.92
0.12
1,460
121,383
9.76
157,352
17.24
36,673
5.13
64,961
35,344
100,305
$ 638,159 $
3.88
32,825
2.11
19,295
52,120
5.99
38.12 $ 367,528 $
10.43
1.03
0.14
11.60
15.03
3.50
3.13
1.84
4.97
35.10
Revenue. Total revenue for the year ended December 31, 2018 was $891.3 million compared to $412.8
million for the year ended December 31, 2017, an increase of approximately $478.5 million or 116%.
Oil revenue increased by approximately $437.0 million, or 127%, during the year ended December 31, 2018
compared to the corresponding period in 2017. This increase was primarily due to an increase of $17.50 per Bbl in
our realized oil sales price and a 12.9 MBblpd increase in oil production volumes. The increase in oil production
volumes was attributable to 11.7 MBblpd from the Stone Combination and the Whistler Acquisition collectively,
and 3.2 MBblpd from the Tornado II well in the Phoenix Field which commenced initial production in December
2017. The increase in production was partially offset by unplanned third party downtime.
Natural gas revenue increased by approximately $24.7 million, or 51%, during the year ended December 31,
2018 compared to the corresponding period in 2017. This increase was due to a 17.7 MMcfpd increase in gas
production volumes, which was attributable to 18.2 MMcfpd from the Stone Combination and Whistler Acquisition
collectively. Natural gas revenue also increased due to a $0.23 per Mcf increase in our realized gas sales price.
NGL revenue increased by approximately $19.2 million, or 115%, during the year ended December 31, 2018
compared to the corresponding period in 2017. This increase was due to an increase of a $6.91 per Bbl increase in
our realized NGL sales price and a 1.3 MBblpd increase in NGL volumes, 1.2 MBblpd of which was attributable to
the Stone Combination and Whistler Acquisition collectively.
Lease operating expense. Total lease operating expense for the year ended December 31, 2018 was $163.3
million compared to $121.4 million for the year ended December 31, 2017 an increase of approximately $41.9
million, or 35%. This increase was primarily related to $40.7 million of lease operating expense in connection with
the Stone Combination and $2.8 million of lease operating expense in connection with the Whistler Acquisition. In
addition, lease operating expense increased due to a more competitive offshore environment, offset by an $8.7
million increase in PHA reimbursements. While total lease operating expense has increased, lease operating
expense decreased $1.84 per Boe to $9.76 per Boe as a result of increased deepwater production from the Stone
Combination and increased production in the Phoenix Field.
Depreciation, depletion and amortization. Depreciation, depletion and amortization expense for the year
ended December 31, 2018 was $288.7 million compared to $157.3 million for the year ended December 31, 2017,
an increase of approximately $131.4 million, or 83%. This increase was primarily due to a $2.22 per Boe, or 15%,
increase in the depletion rate on our proved oil and natural gas properties during the year ended December 31,
2018. Depletion on a per Boe basis increased primarily due to an increase in proved properties related to the Stone
Combination and higher estimated future development costs related to proved undeveloped reserves in the Phoenix
Field.
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General and administrative expense. General and administrative expense for the year ended December 31,
2018 was $85.8 million compared to $36.7 million for the year ended December 31, 2017, an increase of
approximately $49.1 million, or 134%. This increase was primarily attributable to $29.2 million in transaction
related costs related to the Stone Combination and $16.4 million in additional payroll cost and additional general
and administrative expenses as a result of the combined company.
Other operating expense. Other operating expense for the year ended December 31, 2018 was $100.3 million
compared to $52.1 million for year ended December 31, 2017, an increase of approximately $48.2 million, or 92%.
This increase was primarily related to an increase of approximately $32.1 million and an increase of approximately
$16.0 million in workover and maintenance expense and accretion expense, respectively, in connection with the
Stone Combination.
Price risk management activities. Price risk management activities for year ended December 31, 2018
resulted in income of $60.4 million compared to an expense of $27.6 million for the year ended December 31,
2017. The income of $60.4 million for the year ended December 31, 2018 consists of $111.1 million in cash
settlement losses offset by $171.6 million in non-cash gains from the increase in the fair value of our open
derivative contracts. The expense of $27.6 million for the year ended December 31, 2017 consists of cash
settlement gains of $23.8 million offset by a $51.4 million in non-cash losses from the decrease in the fair value of
our open derivatives contracts. These unrealized gains on open derivative contracts relate to production for future
periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on
our consolidated statements of operations at the end of each month. As a result of the derivative contracts we have
on our anticipated production volumes through 2019, we expect these activities to continue to impact net income
(loss) based on fluctuations in market prices for oil and natural gas.
Comparison of the Year Ended December 31, 2017 and 2016
The information below provides the financial results and an analysis of significant variances in these results
for the year ended December 31, 2017 and 2016 (in thousands):
Year Ended December 31,
2017
2016
Change
% Change
Revenues:
Oil revenue
Natural gas revenue
NGL revenue
Other
Total revenue
Operating expenses:
Direct lease operating expense
Insurance
Production taxes
Total lease operating expense
Workover / maintenance expense
Depreciation, depletion and amortization
Accretion expense
General and administrative expense
Total operating expenses
Operating income (loss)
Interest expense
Price risk management activities income (expense)
Other income
Net loss
6696_10K.pdf
74%
14%
75%
(72)%
60%
(12)%
(18)%
(25)%
(13)%
32%
26%
(12)%
28%
8%
156%
15%
52%
(19)%
70%
$ 344,781 $ 197,583 $ 147,198
6,181
7,126
(6,431)
154,074
48,886
16,658
2,503
412,828
42,705
9,532
8,934
258,754
109,180
10,743
1,460
121,383
32,825
157,352
19,295
36,673
367,528
45,300
(80,934)
(27,563)
329
(15,180)
(2,358)
(498)
(18,036)
8,015
32,663
(2,534)
7,987
28,095
125,979
10,519
29,835
(76)
(62,868) $ (208,087) $ 145,219
124,360
13,101
1,958
139,419
24,810
124,689
21,829
28,686
339,433
(80,679)
(70,415)
(57,398)
405
$
68
The table below provides additional detail of our production volumes and sales prices per unit.
Oil production volume (MBbls)
Average daily oil production volume (MBblpd)
Oil sales revenue (in thousands)
Average oil sales price per Bbl
(including commodity derivatives)
Average oil sales price per Bbl
(excluding commodity derivatives)
Average daily NYMEX WTI price per Bbl
Increase in oil sales revenue due to:
Change in prices (in thousands)
Change in production volume (in thousands)
Total increase in oil sales revenue (in thousands)
Natural gas production volume (MMcf)
Average daily natural gas production volume (MMcfpd)
Natural gas sales revenue (in thousands)
Average natural gas sales price per Mcf
(including commodity derivatives)
Average natural gas sales price per Mcf
(excluding commodity derivatives)
Average daily NYMEX Henry Hub price per MMBtu
Increase in natural gas sales revenue due to:
Change in prices (in thousands)
Change in production volume (in thousands)
Total increase in natural gas sales revenue
(in thousands)
NGL production volume (MBbls)
Average daily NGL production volume (MBblpd)
NGL sales revenue (in thousands)
Average NGL sales price per Bbl
(excluding commodity derivatives)
Increase in NGL sales revenue due to:
Change in prices (in thousands)
Change in production volume (in thousands)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
Total increase in NGL sales revenue (in thousands)
$
Total production per Mboe
Average daily total production volume (MBoepd)
Price per Boe (including commodity derivatives)
Price per Boe (excluding commodity derivatives)
$
$
Year Ended December 31,
2016
2017
7,048
19.3
344,781 $
5,126
14.0
197,583 $
Change
1,922
5.3
147,198
52.46 $
68.46 $
(16.00)
48.92 $
50.95 $
38.55 $
43.32 $
10.37
7.63
73,105
74,093
147,198
16,308
44.7
48,886 $
19,001
52.1
42,705 $
(2,693)
(7.4)
6,181
2.93 $
3.24 $
(0.31)
3.00 $
3.11 $
2.25 $
2.46 $
0.75
0.65
12,240
(6,059)
6,181
706
1.9
16,658 $
603
1.7
9,532 $
103
0.2
7,126
23.59 $
15.81 $
7.78
5,498
1,628
7,126
10,472
28.7
41.46 $
39.18 $
8,896
24.4
47.44 $
28.08 $
1,576
4.3
(5.98)
11.10
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The following table highlights operating expense items in total and on a cost per Boe production basis. The
information below provides the financial results and an analysis of significant variances in these results for the
years ended December 31, 2017 and 2016 (in thousands, except per Boe data):
Lease operating expenses:
Direct lease operating expense
Insurance
Production taxes
Total lease operating expenses
Depreciation, depletion and amortization
General and administrative expense
Other operating expenses:
Workover / maintenance expense
Accretion expense
Total other operating expenses
Total operating expenses
Year Ended December 31,
2017
2016
Total
Per Boe
Total
Per Boe(1)
$
$
109,180 $
10,743
1,460
121,383
157,352
36,673
32,825
19,295
52,120
367,528 $
10.43 $
1.03
0.14
11.60
15.03
3.50
3.13
1.84
4.97
35.10 $
124,360 $
13,101
1,958
139,419
124,689
28,686
24,810
21,829
46,639
339,433 $
13.98
1.47
0.22
15.67
14.02
3.22
2.79
2.45
5.24
38.15
Revenue. Total revenue for the year ended December 31, 2017 was $412.8 million compared to
$258.8 million for the year ended December 31, 2016, an increase of $154.0 million, or 60%. Oil revenue increased
by $147.2 million, or 74%, during the year ended December 31, 2017. This increase was primarily due to an
increase of $10.37 per Bbl in our realized oil sales price and 5.3 MBblpd increase in production volumes. The
increase in production volumes primarily related to a 6.2 MBblpd increase from the Tornado well, GC 281 #1ST
(T-9) in the Phoenix Field. Initial production commenced in October 2016.
Natural gas revenue increased by $6.2 million, or 14%, during the year ended December 31, 2017. The
increase in natural gas revenue was due to a $0.75 per Mcf increase in our realized average natural gas sales price.
This increase was offset by a 7.4 MMcfpd decrease in production during the year ended December 31, 2017
primarily due to third party pipeline maintenance and weather related downtime.
Other revenue decreased by $6.4 million, or 72%, during the year ended December 31, 2017 primarily due to
production handling agreements fees, commencing in 2017 from certain working interest partners in the Phoenix
Field which are recorded as a reduction to lease operating expense.
Lease operating expense. Total lease operating expense for the year ended December 31, 2017 was
$121.4 million compared to $139.4 million for the year ended December 31, 2016, a decrease of $18.0 million, or
13%. The decrease was primarily attributed to a $14.3 million decrease in our production facility rental expense as
a result of the newly negotiated seven year lease agreement with Helix for use of the HP-I beginning July 2016
which is accounted for as a capital lease, as well as a $2.4 million decrease in our insurance expense.
Depreciation, depletion and amortization. Depreciation, depletion and amortization expense for the year
ended December 31, 2017 was $157.4 million and $124.7 million for the year ended December 31, 2016, an
increase of $32.7 million, or 26%. The increase is primarily due to a $1.03 per Boe, or 7%, increase in the depletion
rate on our proved oil and natural gas properties during the year ended December 31, 2017. Depletion on a per Boe
basis increased primarily due to inclusion in the full cost pool of the capital lease asset recorded in July 2016 for
use of the HP-I. Since the HP-I is utilized in our oil and natural gas development activities, the asset is included
within proved property and thus depleted as part of the full cost pool.
General and administrative expense. General and administrative expense for the year ended December 31,
2017 was $36.7 million compared to $28.7 million for the year ended December 31, 2016, an increase of
$8.0 million, or 28%. The increase was primarily attributable to $9.7 million in transaction related costs associated
with the Stone Combination and our 2017 debt exchange, partially offset by a decrease in employee related
expenses of $0.7 million.
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Other operating expense. Other operating expense for the year ended December 31, 2017 was $52.1 million
compared to $46.6 million for the year ended December 31, 2016, an increase of $5.5 million, or 12%. This
increase was primarily related to an increase of $7.8 million in facility and major wellwork due to repairs on South
Marsh Island 130. This is partially offset by a decrease of $2.5 million in accretion expense for asset retirement
obligations settled in 2017.
Interest expense. Interest expense for the year ended December 31, 2017 was $80.9 million compared to
$70.4 million for the year ended December 31, 2016, an increase of $10.5 million, or 15%. The change was
primarily due to an increase of $11.5 million from the HP-I capital lease that began in July 2016.
Price risk management activities. Price risk management activities expense for the year ended December 31,
2017 was $27.6 million compared to $57.4 million for the year ended December 31, 2016. The decrease of
$29.8 million was attributable to a $178.2 million increase in fair value of our open derivative contracts offset by a
$148.2 million decrease in cash settlement gains for the year ended December 31, 2017. These unrealized gains on
open derivative contracts relate to production for future periods; however, changes in the fair value of all of our
open derivative contracts are recorded as a gain or loss in our consolidated statements of operations at the end of
each month. As a result of the derivative contracts we have in place on our anticipated production volumes through
2019, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for
oil and natural gas.
Commitments and Contingencies
For a further discussion of our commitments and contingencies, see Part II, Item 8. Financial Statements and
Supplementary Data — Note 11 — Commitments and Contingencies. Additionally, we are party to lawsuits arising
in the ordinary course of our business. We cannot predict the outcome of any such lawsuit with certainty, but our
management believes it is remote that any such pending or threatened lawsuit will have a material adverse impact
on our financial condition. See Part I, Item 3. Legal Proceedings for additional information.
Due to the nature of our business, we are, from time to time, involved in other routine litigation or subject to
disputes or claims related to business activities, including workers’ compensation claims, employment related
disputes and civil penalties by regulators. In the opinion of our management, none of these other pending
litigations, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial
condition, cash flows or results of operation. See Part I, Item 3. Legal Proceedings for additional information.
Supplemental Non-GAAP Measure
Adjusted EBITDA
“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.
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The following tables present a reconciliation of the GAAP financial measure of net income (loss) to Adjusted
EBITDA for each of the periods indicated (in thousands, except for Boe data):
Reconciliation of net income (loss) to Adjusted EBITDA:
Net income (loss)
Interest expense
Income tax expense
Depreciation, depletion and amortization
Accretion expense
Loss on debt extinguishment
Transaction related costs
Derivative fair value (gain) loss(1)
Net cash receipts (payments) on settled derivative
instruments(1)
Non-cash (gain) loss on sale of assets
Non-cash write-down of other well equipment inventory
Non-cash equity-based compensation expense
Adjusted EBITDA
Year Ended December 31,
2018
2017
2016
$
$
221,540 $
90,114
2,922
288,719
35,344
1,764
32,484
(60,435)
(111,147)
(1,710)
244
2,893
502,732 $
(62,868) $
80,934
—
157,352
19,295
—
9,652
27,563
23,834
—
260
875
256,897 $
(208,087)
70,415
—
124,689
21,829
—
135
57,398
172,182
—
218
1,083
239,862
(1)
The adjustments for the derivative fair value (gains) losses and net cash receipts on settled commodity derivative instruments have the
effect of adjusting net 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.
Liquidity and Capital Resources
Overview
Our primary sources of liquidity are cash generated by our operations and borrowings under our Bank Credit
Facility. Our primary uses of cash are for capital expenditures, working capital, debt service and for general
corporate purposes. As of December 31, 2018, our available liquidity (cash plus available capacity under the Bank
Credit Facility) was $460.3 million.
As of December 31, 2018, total debt, net of discount and deferred financing costs, was approximately $655.3
million, comprised of our $381.2 million aggregate principal amount of the New Second Lien Notes and $6.1
million aggregate principal amount of our 7.50% Stone Senior Notes, $257.4 million outstanding under our Bank
Credit Facility, and $10.6 million aggregate principal amount of the Building Loan. We were in compliance with
all debt covenants at December 31, 2018. For additional details on our debt, see Part II, Item 8. Financial
Statements and Supplementary Data — Note 6 — Debt.
Based on our current level of operations and available cash, we believe our cash flows from operations,
combined with availability under the Bank Credit Facility, provide sufficient liquidity to fund our board approved
2019 capital spending project of $465.0 million to $485.0 million. However, our ability to (i) generate sufficient
cash flows from operations or obtain future borrowings under the Bank Credit Facility, and (ii) repay or refinance
any of our indebtedness on commercially reasonable terms or at all for any potential future acquisitions, joint
ventures or other similar transactions, depends on operating and economic conditions, some of which are beyond
our control. To the extent possible, we have attempted to mitigate certain of these risks (e.g. by entering into oil
and natural gas derivative contracts to reduce the financial impact of downward commodity price movements on a
substantial portion of our anticipated production), but we could be required to, or we or our affiliates may from
time to time, take additional future actions on an opportunistic basis. To address further changes in the financial
and/or commodity markets, future actions may include, without limitation, raising debt, including secured debt, or
issuing equity to directly or independently repurchase or refinance our outstanding debt.
As of December 31, 2018, we had obtained performance bonds primarily related to P&A of wells and
removal of facilities in the United States Gulf of Mexico and to guarantee the completion of the minimum work
program under the PSCs totaling approximately $644.1 million. In July 2016, BOEM issued the 2016 NTL to
clarify the procedures and guidelines the BOEM Regional Directors use to determine if and when additional
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financial assurances may be required for OCS leases, ROWs and RUEs to meet BOEM’s estimate of the lessees’
decommissioning obligations. The 2016 NTL became effective in September 2016 and allows qualifying operators
to self-insure for an amount up to 10% of their tangible net worth. The 2016 NTL also provides for operators to
propose a tailored plan subject to BOEM approval that allows the posting of additional financial assurance over
time. However, BOEM has indefinitely delayed beyond June 30, 2017 implementation of the 2016 NTL, except in
certain circumstances where there is a substantial risk of nonperformance of the interest holder’s decommissioning
liabilities, to allow BOEM time to reconsider a number of regulatory initiatives. We received the BOEM 2016
Orders in late 2016 ordering us to secure financial assurances in the form of additional security in material
amounts. We entered into discussions with BOEM regarding the requested security and submitted a proposed
tailored plan for the posting of additional financial security to the agency for review. However, as noted, BOEM
has indefinitely delayed implementation beyond June 30, 2017 of the 2016 NTL, has rescinded the BOEM 2016
Orders while BOEM reviews its financial assurance program and, to date, has taken no action with respect to our
previously submitted proposed tailored plan. We remain in active discussion with our government regulators and
industry peers with regard to any future rule making and financial assurance requirements. Notwithstanding the
2016 NTL, BOEM may also increase its financial assurance requirements mandated by rule for all companies
operating in federal waters. BOEM could also make new demands for additional financial security in material
amounts in the event the agency chooses to implement the 2016 NTL, and such amounts may be material and
exceed our capability to provide additional financial assurance. The future cost of compliance with our existing
supplemental bonding requirements, including with respect to any tailored plan that is subject to approval by
BOEM, the 2016 NTL, as well as any other future directives or any other changes to BOEM’s rules applicable to
us or our subsidiaries’ properties, could materially and adversely affect our financial condition, cash flows and
results of operations.
New Second Lien Notes, 7.50% Stone Senior Notes
In connection with the Stone Combination, we consummated the Transactions contemplated by the Exchange
Agreement, pursuant to which (i) the Apollo Funds and Riverstone Funds contributed $102.0 million in aggregate
principal amount of 9.75% Senior Notes to us in exchange for our common stock; (ii) the holders of 11.00% Bridge
Loans exchanged such 11.00% Bridge Loans for $172.0 million aggregate principal amount of New Second Lien
Notes and (iii) the Franklin Noteholders and the MacKay Noteholders exchanged their 7.50% Stone Senior Notes
for $137.4 million aggregate principal amount of New Second Lien Notes. An additional $81.5 million of 7.50%
Stone Senior Notes held by non-affiliates were also exchanged for New Second Lien Notes pursuant to an
exchange offer and consent solicitation in connection with the Stone Combination.
The exchange of 7.50% Stone Senior Notes for New Second Lien Notes was accounted for as a debt
modification. Under a debt modification, a new effective interest rate that equates the revised cash flows to the
carrying amount of the New Second Lien Notes is computed and applied prospectively. Costs incurred with third
parties directly related to the modification are expensed as incurred. We incurred approximately $4.3 million of
transaction fees related to the exchange of 11.00% Bridge Loans and 7.50% Stone Senior Notes into New Second
Lien Notes, which were expensed and reflected in general and administrative expense during the year ended
December 31, 2018, respectively. We also paid $9.3 million in work fees to debt holders, which are reflected as
debt discount reducing long-term debt on the consolidated balance sheet at December 31, 2018.
11.00% Second-Priority Senior Secured Notes—due April 2022. The New Second Lien Notes were issued
pursuant to an indenture dated as of the Closing Date, between the Talos Issuers, the subsidiary guarantors party
thereto and Wilmington Trust, National Association, as trustee and collateral agent. The New Second Lien Notes
mature April 3, 2022 and have interest payable semi-annually each April 15 and October 15. Prior to May 10,
2019, we may, at our option, redeem all or a portion of the New Second Lien Notes at 100% of the principal
amount plus accrued and unpaid interest and a make-whole premium. Thereafter, we may redeem all or a portion of
the New Second Lien Notes at redemption prices decreasing annually from 105.5% to 100.0% plus accrued and
unpaid interest.
7.50% Senior Secured Notes—due May 2022. The 7.50% Stone Senior Notes represent the remaining
$6.1 million of long-term debt assumed in the Stone Combination that were not exchanged for New Second Lien
Notes pursuant to the exchange offer and consent solicitation, and thus remain outstanding. As a result of the
Exchange Offer and Consent Solicitation, substantially all of the restrictive covenants relating to the 7.50% Stone
Senior Notes have been removed and collateral securing the 7.50% Stone Senior Notes has been released. The
7.50% Stone Senior Notes mature May 31, 2022 and have interest payable semiannually each May 31 and
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November 30. Prior to May 31, 2020, we may, at our option, redeem all or a portion of the 7.50% Stone Senior
Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter,
we may redeem all or a portion of the 7.50% Stone Senior Notes at redemption prices decreasing annually from
105.625% to 100.0% plus accrued and unpaid interest.
Bank Credit Facility
Talos Production, our wholly owned subsidiary, executed the Bank Credit Facility in conjunction with the
Stone Combination with a syndicate of financial institutions with an initial borrowing base of $600.0 million. The
Bank Credit Facility is currently scheduled to mature on May 10, 2022.
The Bank Credit Facility bears interest based on the borrowing base usage, at the applicable London
InterBank Offered Rate, plus applicable margins ranging from 2.75% to 3.75% or an alternate base rate based on
the federal funds effective rate plus applicable margins ranging from 1.75% to 2.75%. In addition, we are obligated
to pay a commitment fee of 0.50% on the unfunded portion of the commitments under the Bank Credit Facility.
The Bank Credit Facility has certain debt covenants, the most restrictive of which requires that we maintain a total
debt to EBITDAX Ratio (as defined in the Bank Credit Facility) of no greater than 3.00 to 1.00 each quarter. We
must also maintain a current ratio no less than 1.00 to 1.00 each quarter. According to the Bank Credit Facility,
undrawn commitments are included in current assets in the current ratio calculation. The Bank Credit Facility is
secured by substantially all of our oil and natural gas assets. The Bank Credit Facility is fully and unconditionally
guaranteed by us and certain of our wholly-owned subsidiaries.
The Bank Credit Facility provides for determination of the borrowing base based on our proved producing
reserves and a portion of our PUD reserves. The borrowing base is redetermined by the lenders at least semi-
annually during the second quarter and fourth quarter each year. On November 16, 2018, the borrowing base was
increased from $600.0 million to $850.0 million. We elected to maintain the $600.0 million commitment based
upon our current liquidity needs. The next redetermination is scheduled for April 2019.
As of December 31, 2018, commitments under our borrowing base was set at $600.0 million, of which no
more than $200 million can be used as letters of credit. The amount that we are able to borrow with respect to the
borrowing base is subject to compliance with the financial covenants and other provisions of the Bank Credit
Facility. We were in compliance with all debt covenants at December 31, 2018. As of December 31, 2018, the
Bank Credit Facility had approximately $320.3 million of undrawn commitments (taking into account $14.7
million letters of credit and $265.0 million drawn from the Bank Credit Facility).
Building Loan
In connection with the Stone Combination, we assumed Stone’s Building Loan maturing on November 20,
2030. The Building Loan bears interest at a rate of 4.20% per annum and is to be repaid in 180 equal monthly
installments of approximately $0.1 million. As of December 31, 2018, the outstanding balance under the Building
Loan totaled $10.6 million. The Building Loan is collateralized by our two office buildings in Lafayette, Louisiana.
Under the financial covenants of the Building Loan, we must maintain a ratio of EBITDA to Net Interest Expense
of not less than 2.00 to 1.00. In addition, the Building Loan contains certain customary restrictions or requirements
with respect to change of control and reporting responsibilities. We are in compliance with all covenants under the
Building Loan as of December 31, 2018.
2018 Senior Notes
9.75% Senior Notes—due February 2018. The 9.75% Senior Notes due 2018 were issued by the Talos
Issuers pursuant to an indenture dated February 6, 2013, among the Talos Issuers, the subsidiary guarantors party
thereto and the trustee. On February 15, 2018, the Talos Issuers redeemed the remaining $25.0 million principal
amount of the 9.75% Senior Notes due 2018 at par.
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Overview of Cash Flow Activities
The following table summarizes cash flows provided by (used in) by type of activity, for the following
periods (in thousands):
Operating activities
Investing activities
Financing activities
Year Ended December 31,
2018
263,445 $
37,495 $
(193,211) $
2017
176,053 $
(157,641) $
(18,412) $
2016
116,123
(198,918)
91,624
$
$
$
Operating Activities. Net cash provided by operating activities increased $87.4 million in 2018 from 2017
primarily attributable to an increase in revenue, offset by a decrease in cash settlements on derivatives and
transaction related cost related to the Stone Combination. Net cash provided by operating activities increased
$59.9 million from 2017 to 2016 primarily due to an increase in revenue, offset by a decrease in cash settlements
gains on our derivative contracts.
Investing Activities. Net cash used in (provided by) investing activities increased $195.1 million in 2018 from
2017 primarily attributable to $280.9 million of cash received from the Stone Combination and Whistler
Acquisition, partially offset by an increase of $85.7 million in capital expenditures. The increase of $41.3 million in
net cash used in investing activities from 2017 to 2016 primarily related to a decrease in capital expenditures.
Financing Activities. Net cash used in (provided by) financing activities increased by $174.8 million in 2018
from 2017 primarily attributable to the repayment of $403.0 million related to the LLC Bank Credit Facility, $54.0
million related to the repayment of the Bank Credit Facility, $25.3 million related to the redemption of our 2018
Senior Notes and other long-term debt, $17.0 million in deferred financing cost, partially offset by proceeds
received from the Bank Credit Facility of $319.0 million. Net cash provided by financing activities decreased
$110.0 million in 2017 from 2016 primarily related to a reduction of $91.9 million net contribution from our
Sponsors.
Capital Expenditures. We fund exploration and development activities primarily through operating cash
flows, cash on hand, and through borrowings under the Bank Credit Facility, if necessary. Historically, we have
funded significant property acquisitions with the issuance of senior notes, borrowings under the Bank Credit
Facility and through additional equity issuances. We occasionally adjust our capital budget in response to changing
operating cash flow forecasts and market conditions, including the prices of oil, natural gas and NGLs, acquisition
opportunities and the results of our exploration and development activities.
The following is a table of our capital expenditures, excluding acquisitions, for the year ended December 31,
2018 (in thousands):
U.S. drilling & completions
Mexico appraisal & exploration
Asset management
Seismic and G&G, land, capitalized G&A and other(1)
Total capital expenditures
Plugging & abandonment
Total capital expenditures and plugging & abandonment
$
$
163,100
14,492
52,452
47,637
277,681
112,946
390,627
(1)
Amount excludes $29.8 million of accrued, but unpaid change of control costs for the seismic acquired as part of the Stone Combination,
$3.6 million of non-cash share-based awards and $9.0 million of reimbursements related to corporate office leasehold improvements.
Off Balance Sheet Arrangements
We did not have any off balance sheet arrangements as of December 31, 2018.
Contractual Obligations
We are party to various contractual obligations. Some of these obligations may be reflected in our
accompanying consolidated financial statements, while other obligations, such as operating leases and capital
commitments, are not reflected on our accompanying consolidated financial statements.
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The following table and discussion summarizes our contractual cash obligations as of December 31, 2018 (in
thousands):
Long-term financing obligations:
Debt Principal
Debt Interest
Vessel Commitments (1)
Derivative liabilities
Operating Lease Obligations
Capital lease (2)
Purchase Obligations
Mexico minimum work program
Total contractual obligations(3)(4)
2019
2020
2021
2022
Thereafter
Total(4)
443 $
462 $
—
—
4,315
482 $ 662,431 $
17,313
—
—
$
59,960 59,941 59,922
—
35,206
—
550
4,016
3,622
45,000 45,000 45,000
7,921
15,562 11,921
—
— 19,277
8,677 $ 672,495
199,265
2,129
35,206
—
550
—
43,476
4,298 27,225
198,750
45,000 18,750
35,404
—
19,277
—
$160,343 $140,916 $ 117,341 $ 729,042 $ 56,781 $1,204,423
—
—
(1)
(2)
(3)
(4)
Includes vessel commitments we will utilize for certain deep water well intervention and decommissioning activities. These commitments
represent gross contractual obligations and accordingly, other joint owners in the properties operated by us will be billed for their working
interest share of such costs. Includes commitments for drilling rigs and Helix’s Q4000 well intervention vessel we will utilize for certain
deep water well intervention and decommissioning activities.
Lease agreement for the HP-I floating production facility in the Phoenix Field.
Includes committed purchase orders to execute planned future drilling and completion activities. Includes seismic use agreements.
This table does not include our estimated discounted liability for dismantlement, abandonment and restoration costs of oil and natural gas
properties of $382.8 million as of December 31, 2018. For additional information regarding these liabilities, please see Part II, Item 8.
Financial Statements and Supplementary Data — Note 4 — Property, Plant and Equipment.
Performance Bonds. As of December 31, 2018 and 2017, we had secured performance bonds primarily
related to P&A of wells and removal of facilities and executing the minimum work program under the PSCs
totaling approximately $644.1 million and $287.8 million, respectively. As of December 31, 2018 and 2017, we
had $14.7 million and $4.9 million, respectively, in letters of credit issued under our Bank Credit Facility and our
previous credit facility primarily for the P&A of wells and the removal of facilities.
For additional information about certain of our obligations and contingencies, see Part II, Item 8. Financial
Statements and Supplementary Data — Note 11 — Commitments and Contingencies.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with GAAP requires our management to make
estimates and assumptions that affect the reported amount of assets, liabilities, revenue and expense, and the
disclosures of contingent assets and liabilities. We consider our critical accounting estimates to be those estimates
that require complex or subjective judgment in the application of the accounting policy and that could significantly
impact our financial results based on changes in those judgments. Changes in facts and circumstances may result in
revised estimates and actual results may differ materially from those estimates. Our management has identified the
following critical accounting estimates. Our significant accounting policies that have been implemented or changed
since December 31, 2017 are described in Part II, Item 8. Financial Statements and Supplementary Data — Note 2
— Summary of Significant Accounting Policies.
Oil and Natural Gas Properties
We follow the full cost method of accounting for oil and natural gas exploration and development activities.
Under the full cost method, substantially all costs incurred in connection with the acquisition, development and
exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the internal costs
directly related to acquisition, development and exploration activities, asset retirement costs and capitalized
interest. Under the full cost method, dry hole costs and geological and geophysical costs are capitalized into the full
cost pool, which is subject to amortization and assessed for impairment on a quarterly basis through a ceiling test
calculation as discussed below.
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Capitalized costs associated with proved reserves are amortized on a country by country basis over the life of
the total proved reserves using the unit of production method, computed quarterly. Conversely, capitalized costs
associated with unproved properties and related geological and geophysical costs, wells currently drilling and
capitalized interest are initially excluded from the amortizable base. We transfer unproved property costs into the
amortizable base when properties are determined to have proved reserves or when we have completed an
evaluation of the unproved properties resulting in an impairment. We evaluate each of these unproved properties
individually for impairment at least quarterly. Additionally, the amortizable base includes future development
costs, dismantlement, restoration and abandonment costs, net of estimated salvage values, and geological and
geophysical costs incurred that cannot be associated with specific unproved properties or prospects in which we
own a direct interest.
Our capitalized costs are limited to a ceiling based on the present value of future net revenues from proved
reserves, discounted at 10%, plus the lower of cost or estimated fair value of unproved oil and natural gas
properties not being amortized. Any costs in excess of the ceiling are recognized as a non-cash impairment expense
on our consolidated statement of operations and an increase to accumulated depreciation, depletion and
amortization on our consolidated balance sheet. The expense will not be reversed in future periods, even though
higher oil, natural gas and NGL prices may subsequently increase the ceiling. We perform this ceiling test
calculation each quarter. In accordance with SEC rules and regulations, we utilize SEC Pricing when performing
the ceiling test. We also hold prices and costs constant over the life of the reserves, even though actual prices and
costs of oil and natural gas are often volatile and may change from period to period. The ceiling test computation
did not result in a write-down of our oil and natural gas properties during the year ended December 31, 2018, 2017
and 2016.
Under the full cost method of accounting for oil and natural gas operations, assets whose costs are currently
being depreciated, depleted or amortized are assets in use in the earnings activities of the enterprise and do not
qualify for capitalization of interest cost. Investments in unproved properties for which exploration and
development activities are in progress and other major development projects that are not being currently
depreciated, depleted or amortized are assets qualifying for capitalization of interest costs.
When we sell or convey interests in oil and natural gas properties, we reduce our oil and natural gas reserves
for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on sales of oil and
natural gas properties, unless those sales would significantly alter the relationship between capitalized costs and
proved reserves. We treat sales proceeds on non-significant sales as reductions to the cost of our oil and natural gas
properties.
We recognize transportation costs as a component of direct lease operating expense when we are the shipper
of the product. Such costs during the year ended December 31, 2018, 2017 and 2016 were $12.5 million,
$10.3 million and $9.1 million, respectively.
Proved Reserve Estimates
We estimate our proved oil, natural gas and NGL reserves in accordance with the guidelines established by
the SEC. Proved oil, natural gas and NGL reserves are those quantities of oil, natural gas and NGLs, which, by
analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically
producible in future periods from known reservoirs and under existing economic conditions, operating methods and
governmental regulations. Prices are determined using SEC pricing.
Our estimates of proved reserves are made using available geological and reservoir data, as well as
production performance data. The estimates of proved reserves are reviewed annually by internal reservoir
engineers and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to
changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions.
Decreases in price, for example, may cause a reduction in some proved reserves due to reaching economic limits at
an earlier projected date. A material adverse change in the estimated volumes of proved reserves could have a
negative impact on depreciation, depletion and amortization or could result in property impairments.
Fair Value Measure of Financial Instruments
Our financial instruments generally consisted of cash and cash equivalents, restricted cash, accounts
receivable, commodity derivatives, accounts payable and debt as of December 31, 2018. The carrying amount of
cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximates fair value due to
the highly liquid nature of these instruments.
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Fair value accounting standards define fair value, establish a consistent framework for measuring fair value
and stipulate the related disclosure requirements for each major asset and liability category measured at fair value
on either a recurring or nonrecurring basis. These standards also clarify fair value as an exit price, presenting the
amount that would be received to sell an asset or paid to transfer a liability, in an orderly transaction between
market participants. We follow a three-level hierarchy, prioritizing and defining the types of inputs used to measure
fair value depending on the degree to which they are observable as follows:
Level 1—Inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities
in active markets.
Level 2—Inputs to the valuation methodology include quoted prices for similar assets and liabilities in active
markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the
full term of the financial statement.
Level 3—Inputs to the valuation methodology are unobservable (little or no market data), which require us to
develop our own assumptions, and are significant to the fair value measurement.
Assets and liabilities measured at fair value are based on one or more of three valuation techniques. The
valuation techniques are as follows:
Market Approach—Prices and other relevant information generated by market transactions involving
identical or comparable assets or liabilities.
Cost Approach—Amount that would be required to replace the service capacity of an asset (replacement
cost).
Income Approach—Techniques to convert expected future cash flows to a single present value amount based
on market expectations (including present value techniques, option-pricing and excess earnings models).
Authoritative guidance on financial instruments requires certain fair value disclosures to be presented. The
estimated fair value amounts have been determined using available market information and valuation
methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value.
The use of different assumptions or valuation methodologies may have a material effect on the estimated fair value
amounts.
Asset Retirement Obligations
We are required to record our asset retirement obligations at fair value in the period such obligations are
incurred with the associated asset retirement costs being capitalized as part of the carrying cost of the asset. Our
asset retirement obligations consist of estimated costs for dismantlement, removal, site reclamation and similar
activities associated with our oil and natural gas properties. The estimate of the asset retirement cost is determined,
inflated to an estimated future value using a ten year average of the Consumer Price Index and discounted to
present value using our credit-adjusted risk-free rate. Accretion of the liability is recognized for changes in the
value of the liability as a result of the passage of time over the estimated productive life of the related assets as the
discounted liabilities are accreted to their expected settlement values.
Revenue Recognition, Imbalances and Production Handling Fees
We record revenues from the sale of oil, natural gas and NGLs based on quantities of production sold to
purchasers under short-term contracts (less than twelve months) at market prices when delivery to the customer has
occurred, title has transferred, prices are fixed and determinable and collection is reasonably assured. This occurs
when production has been delivered to a pipeline or when a barge lifting has occurred.
Under previous accounting guidance, we used the entitlement method to account for sales and production.
Under the entitlement method, revenue was recorded based on our entitled share of production with any difference
recorded as an imbalance on the consolidated balance sheet. Upon the adoption of ASC 606, revenues are recorded
based on the actual sales volumes sold to purchasers. An imbalance receivable or payable is recorded only to the
extent the imbalance is in excess of its share of remaining proved developed reserves in an underlying property.
The change in accounting method from the entitlements method to the sales method resulted in an immaterial
cumulative-effect adjustment to members’ deficit on the date of adoption. Our imbalances are recorded gross on
our consolidated balance sheets. At December 31, 2018, our imbalance receivable was approximately $1.7 million
and imbalance payable was approximately $2.5 million. At December 31, 2017, our imbalance receivable was
approximately $2.1 million and imbalance payable was approximately $2.7 million.
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Under previous accounting guidance, we presented certain reimbursements for costs from certain third
parties as other revenue on the consolidated statement of operations. Upon the adoption of ASC 606, the
reimbursements are presented as a reduction of direct lease operating expense on the consolidated statement of
operations. The impact of the reclassification for the year ended December 31, 2018 was immaterial.
Income Taxes
Our provision for income taxes includes both state, federal and foreign taxes. We record our federal income
taxes in accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax
assets and liabilities for the expected future tax consequences of temporary differences between the book carrying
amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax
rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are
expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is
recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce
deferred tax assets if it is more likely than not that the related tax benefits will not be realized. As of December 31,
2018, we believe it is more likely than not that the net deferred tax asset will not be realized and therefore have
recorded a valuation allowance.
We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes.
During the ordinary course of business, there are many transactions and calculations for which the ultimate tax
determination is uncertain. The actual outcome of these future tax consequences could differ significantly from our
estimates, which could impact our financial position, results of operations and cash flows.
We also account for uncertainty in income taxes recognized in the financial statements in accordance with
GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be
taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that we
recognize the financial statement benefit of a tax position only after determining that the relevant tax authority
would more likely than not sustain the position following an audit. For tax positions meeting the more likely than
not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50%
likelihood of being realized upon ultimate settlement with the relevant tax authority.
Recently Adopted Accounting Standards
See Part II, Item 8. Financial Statements and Supplementary Data — Note 1 — Formation and Basis of
Presentation to the consolidated financial statements included elsewhere in this report for our Recently Adopted
Accounting Standards.
Recently Issued Accounting Standards
See Part II, Item 8. Financial Statements and Supplementary Data — Note 1 — Formation and Basis of
Presentation to the consolidated financial statements included elsewhere in this report for Recently Issued
Accounting Standards applicable to us.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are currently exposed to market risk in two areas: commodity prices and, to a lesser extent, interest rate
risk. Our risk management activities involve the use of derivative financial instruments to mitigate the impact of
market price risk exposures primarily related to our oil and natural gas production. All derivatives are recorded on
the consolidated balance sheet at fair value with settlements of such contracts and changes in the unrealized fair
value recorded as price risk management activities income (expense) on the consolidated statements of operations
in each period.
Commodity Price Risks
Oil and natural gas prices can fluctuate significantly and have a direct impact on our revenues, earnings and
cash flow. During year ended December 31, 2018, our average oil price realizations after the effect of derivatives
increased 9% to $57.12 per Bbl from $52.46 per Bbl in the comparable 2017 period. Our average natural gas prices
realizations after the effect of derivatives increased 8% during the year ended December 31, 2018 to $3.16 per Mcf
from $2.93 per Mcf in the comparable 2017 period.
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Price Risk Management Activities
We have attempted to mitigate commodity price risk and stabilize cash flows associated with our forecasted
sales of oil and natural gas production through the use of oil and natural gas swaps. These contracts will impact our
earnings as the fair value of these derivatives changes. Our derivatives will not mitigate all of the commodity price
risks of our forecasted sales of oil and natural gas production and, as a result, we will be subject to commodity
price risks on our remaining forecasted production.
We had commodity derivative instruments in place to reduce the price risk associated with future production
of 9,146 MBbls of crude oil and 11,133 MMBtu of natural gas at December 31, 2018, with a net derivative liability
position of $74.9 million. For additional information regarding our commodity derivative instruments, see Part II,
Item 8. Financial Statements and Supplementary Data — Note 5 — Financial Instruments, included elsewhere in
this report. The table below presents the hypothetical sensitivity of our commodity price risk management activities
to changes in fair values arising from immediate selected potential changes in oil and natural gas prices at
December 31, 2018 (in thousands):
Oil and Natural Gas Derivatives
10 Percent Increase
10 Percent Decrease
Price impact(1)
Fair Value
Change
$ 74,923 $ 30,174 $ (44,749) $ 119,776 $ 44,853
Fair Value Change
Fair Value
(1)
Presents the hypothetical sensitivity of our commodity price risk management activities to changes in fair values arising from changes in
oil and natural gas prices.
Variable Interest Rate Risks
We had total debt outstanding of $655.3 million at December 31, 2018, net of unamortized original issue
discount and deferred financing costs. Of this, $397.9 million was from our New Second Lien Notes, 7.50% Stone
Senior Notes and Building Loan, which bear interest at fixed rates. The remaining $257.4 million is from
borrowings under our Bank Credit Facility with variable interest rates. We are subject to the risk of changes in
interest rates under our Bank Credit Facility. In addition, the terms of our Bank Credit Facility require us to pay
higher interest rates as we utilize a larger percentage of our available borrowing base. We manage our interest rate
exposure by maintaining a combination of fixed and variable rate debt and monitoring the effect of market changes
in interest rates. We believe our interest rate risk exposure is partially mitigated as a result of fixed interest rates on
61% of our debt. The interest rate on our variable rate debt at December 31, 2018 was 5.46%. A 10% change in the
interest rate on this variable rate debt balance at December 31, 2018 would change interest expense for the year
ended December 31, 2018 by approximately $0.7 million.
Item 8. Financial Statements and Supplementary Data
See the Consolidated Financial Statements and Report of Independent Registered Public Accounting Firm as
of December 31, 2018 and 2017 and for the years ended December 31, 2018, 2017 and 2016, included in Part IV,
Item 15. Exhibits, Financial Statements Schedules.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our chief executive officer and chief financial officer, has
evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a- 15(e) and 15d- 15(e)
under the Exchange Act) as of the end of the period covered by this Annual Report on Form 10-K. Based on such
evaluation, our chief executive officer and chief financial officer have concluded that as of December 31, 2018, our
disclosure controls and procedures are designed at a reasonable assurance level and are effective to provide
reasonable assurance that information we are required to disclose in reports that we file or submit under the
Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and
forms of SEC, and that such information is accumulated and communicated to our management, including our
chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required
disclosures.
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Management’s Annual Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial
reporting as defined in Rule 13a-15(f) under the Exchange Act. Management conducted an assessment of the
effectiveness of our internal control over financial reporting based on the criteria set forth in Internal Control—
Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013
framework). Based on the assessment, management has concluded that its internal control over financial reporting
was effective as of December 31, 2018 to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements in accordance with U.S. GAAP. Our independent registered
public accounting firm, Ernst & Young LLP, has issued an audit report with respect to our internal control over
financial reporting, which is included in this Annual Report on Form 10-K.
Changes in Internal Control over Financial Reporting
There were no changes in our internal controls over financial reporting identified in management's evaluation
pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the fourth quarter of 2018 that materially
affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
None.
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Item 10. Directors, Executive Officers and Corporate Governance.
PART III
The information required by this item is incorporated by reference to our Proxy Statement for the 2019
Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31,
2018.
Our board of directors has adopted a Code of Business Conduct and Ethics applicable to all officers, directors
and employees, which is available on our website (www.talosenergy.com) under “Corporate Governance and Board
Committees.” We intend to satisfy the disclosure requirement under Item 5.05 of Form 8-K regarding amendment
to, or waiver from, a provision of our Code of Business Conduct and Ethics by posting such information on the
website address and location specified above.
Item 11. Executive Compensation
The information required by this item is incorporated by reference to our Proxy Statement for the 2019
Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31,
2018.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters.
The information required by this item is incorporated by reference to our Proxy Statement for the 2019
Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31,
2018.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated by reference to our Proxy Statement for the 2019
Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31,
2018.
Item 14. Principal Accounting Fees and Services
The information required by this item is incorporated by reference to our Proxy Statement for the 2019
Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31,
2018.
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Item 15. Exhibits, Financial Statement Schedules
(a) 1
Financial Statements
PART IV
Refer to the Index to Consolidated Financial Statements on page F-1 for a list of all financial statements
filed as part of this Annual Report on Form 10-K.
(a) 2
Financial Statement Schedules
Financial statement schedules have been omitted because they are either not required, not applicable or the
information required to be presented is included in our Consolidated Financial Statements and related
notes.
(a) 3 Exhibits:
Exhibit
Number
2.1#
3.1
3.2
4.1
4.2
4.3
4.4
4.5
4.6
4.7
Description
Transaction Agreement, dated as of November 21, 2017, by and among Stone Energy Corporation,
Sailfish Energy Holdings Corporation, Sailfish Merger Sub Corporation, Talos Energy LLC and Talos
Production LLC (incorporated by reference to Exhibit 2.1 to Talos Energy Inc.’s Form 8-K12B filed
with the SEC on May 16, 2018).
Amended and Restated Certificate of Incorporation of Talos Energy Inc. (incorporated by reference to
Exhibit 3.1 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).
Amended and Restated Bylaws of Talos Energy Inc. (incorporated by reference to Exhibit 3.2 to Talos
Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).
Form of Stock Certificate for Common Stock of Talos Energy Inc. (incorporated by reference to
Exhibit 4.2 to Talos Energy Inc.’s Amendment No. 1 to the Registration Statement on Form S-4 (File
No. 333-222341) filed with the SEC on February 9, 2018).
Indenture, dated as of May 10, 2018, by and among Talos Production LLC, Talos Production Finance,
Inc., the subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee
and collateral agent (incorporated by reference to Exhibit 4.5 to Talos Energy Inc.’s Form 8-K12B
filed with the SEC on May 16, 2018).
Supplemental Indenture No. 1, dated as of September 12, 2018, by and among Talos Production LLC,
Talos Production Finance, Inc., Talos Energy Inc. and Wilmington Trust, National Association, as
trustee and collateral agent. (incorporated by reference to Exhibit 4.2 to Talos Energy Inc.’s
Registration Statement on Form S-4 (File No. 333-227362) filed with the SEC on September 14,
2018).
Registration Rights Agreement, dated as of May 10, 2018, by and among Talos Production LLC,
Talos Production Finance, Inc., the subsidiary guarantors named therein and each of the holders set
forth on the signature pages thereto (incorporated by reference to Exhibit 4.6 to Talos Energy Inc.’s
Form 8-K12B filed with the SEC on May 16, 2018).
Form of 11.00% Second-Priority Senior Secured Note due 2022 (included in Exhibit 4.2).
Stockholders’ Agreement, dated as of May 10, 2018, by and among Talos Energy Inc. and each of the
other parties set forth on the signature pages thereto (incorporated by reference to Exhibit 4.1 to Talos
Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).
Registration Rights Agreement, dated as of May 10, 2018, by and among Talos Energy Inc. and each
of the other parties set forth on the signature pages thereto (incorporated by reference to Exhibit 4.2 to
Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).
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4.8
4.9
10.1
10.2
10.3†
10.4†
10.5†
10.6†
10.7†
10.8†
10.9
10.10
Warrant Agreement, dated as of February 28, 2017, by and among Stone Energy Corporation,
Computershare Inc. and Computershare Trust Company, N.A. (incorporated by reference to Exhibit
4.3 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).
Amendment No. 1 to Warrant Agreement, dated as of May 10, 2018, by and among Talos Energy
Inc., Stone Energy Corporation, Computershare Inc. and Computershare Trust Company, N.A.
(incorporated by reference to Exhibit 4.4 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on
May 16, 2018).
Credit Agreement, dated as of May 10, 2018, by and among Talos Production LLC, as borrower,
Talos Energy Inc., as holdings, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders
named therein (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 8-K12B/A filed
with the SEC on July 18, 2018).
Intercreditor Agreement, dated as of May 10, 2018, between JPMorgan Chase Bank, N.A., as First
Lien Agent, and Wilmington Trust, National Association, as Second Lien Agent (incorporated by
reference to Exhibit 10.3 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).
Employment Agreement, dated as of February 3, 2012, by and between Talos Energy Operating
Company LLC and Timothy S. Duncan (incorporated by reference to Exhibit 10.10 to Talos Energy
Inc.’s Amendment No. 3 to the Registration Statement on Form S-4 (File No. 333-222341) filed with
the SEC on March 30, 2018).
Employment Agreement, dated as of February 3, 2012, by and between Talos Energy Operating
Company LLC and Stephen E. Heitzman (incorporated by reference to Exhibit 10.11 to Talos Energy
Inc.’s Amendment No. 3 to the Registration Statement on Form S-4 (File No. 333-222341) filed with
the SEC on March 30, 2018).
Employment Agreement, dated as of February 3, 2012, by and between Talos Energy Operating
Company LLC and John A. Parker (incorporated by reference to Exhibit 10.12 to Talos Energy Inc.’s
Amendment No. 3 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the
SEC on March 30, 2018).
Employment Agreement, dated as of March 14, 2016, by and between Talos Energy Operating
Company LLC and Michael L. Harding II (incorporated by reference to Exhibit 10.13 to Talos Energy
Inc.’s Amendment No. 3 to the Registration Statement on Form S-4 (File No. 333-222341) filed with
the SEC on March 30, 2018).
Employment Agreement, dated as of August 30, 2013, by and between Talos Energy Operating
Company LLC and William S. Moss III (incorporated by reference to Exhibit 10.14 to Talos Energy
Inc.’s Amendment No. 3 to the Registration Statement on Form S-4 (File No. 333-222341) filed with
the SEC on March 30, 2018).
Talos Energy Inc. Long Term Incentive Plan (incorporated by reference to Exhibit 10.4 to Talos
Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).
Voting Agreement, dated as of November 21, 2017, by and among Talos Energy LLC, Stone Energy
Corporation, Franklin Advisers, Inc., as investment manager on behalf of the company stockholders
listed therein and, solely for purposes of Section 11, Franklin Advisers, Inc., as investment manager
on behalf of JNL/Franklin Templeton Income Fund and FT Opportunistic Destressed Fund, LTD.
(incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Amendment No. 1 to the
Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on February 9, 2018).
Voting Agreement, dated as of November 21, 2017, by and among Talos Energy LLC, Stone Energy
Corporation and MacKay Shields LLC, in its capacity as investment manager on behalf of certain of
its clients and, to the extent expressly set forth therein, in its individual capacity (incorporated by
reference to Exhibit 10.2 to Talos Energy Inc.’s Amendment No. 1 to the Registration Statement on
Form S-4 (File No. 333-222341) filed with the SEC on February 9, 2018).
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10.11
10.12
10.13
10.14
10.15†
10.16†
10.17†
10.18†
10.19†
10.20†
10.21†
10.22†
10.23†
10.24†
10.25†
10.26†
Support Agreement, dated as of November 21, 2017, by and among Stone Energy Corporation,
Sailfish Energy Holdings Corporation, Apollo Management VII, L.P., Apollo Commodities
Management, L.P., with respect to Series I, and Riverstone Energy Partners V, L.P. (incorporated by
reference to Exhibit 10.3 to Talos Energy Inc.’s Amendment No. 1 to the Registration Statement on
Form S-4 (File No. 333-222341) filed with the SEC on February 9, 2018).
Exchange Agreement, dated as of November 21, 2017, by and among Talos Production LLC, Talos
Production Finance Inc., Stone Energy Corporation, Sailfish Energy Holdings Corporation and the
lenders and noteholders listed on the schedules thereto (incorporated by reference to Exhibit 10.1 to
Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).
Contract for the Exploration and Extraction of Hydrocarbons under Production Sharing Modality
(Contract Area 2), dated as of September 4, 2015, by and among the National Hydrocarbons
Commission, Sierra O&G Exploración y Producción, S. de R.L. de C.V., Talos Energy Offshore
México 2, S. de R.L. de C.V. and Premier Oil Exploration and Production Mexico, S.A. de C.V.
(incorporated by reference to Exhibit 10.8 to Talos Energy Inc.’s Amendment No. 2 to the
Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on March 15, 2018).
Contract for the Exploration and Extraction of Hydrocarbons under Production Sharing Modality
(Contract Area 7), dated as of September 4, 2015, by and among the National Hydrocarbons
Commission, Sierra O&G Exploración y Producción, S. de R.L. de C.V., Talos Energy Offshore
México 7, S. de R.L. de C.V. and Premier Oil Exploration and Production Mexico, S.A. de C.V.
(incorporated by reference to Exhibit 10.9 to Talos Energy Inc.’s Amendment No. 4 to the
Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on April 4, 2018).
Indemnification Agreement (Timothy S. Duncan) (incorporated by reference to Exhibit 10.5 to Talos
Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).
Indemnification Agreement (Stephen E. Heitzman) (incorporated by reference to Exhibit 10.6 to Talos
Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).
Indemnification Agreement (John A. Parker) (incorporated by reference to Exhibit 10.7 to Talos
Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).
Indemnification Agreement (Michael L. Harding II) (incorporated by reference to Exhibit 10.8 to
Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).
Indemnification Agreement (William S. Moss III) (incorporated by reference to Exhibit 10.9 to Talos
Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).
Indemnification Agreement (Olivia C. Wassenaar) (incorporated by reference to Exhibit 10.1 to Talos
Energy Inc.’s Form 8-K filed with the SEC on November 23, 2018).
Indemnification Agreement (Christine Hommes) (incorporated by reference to Exhibit 10.11 to Talos
Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).
Indemnification Agreement (Robert M. Tichio) (incorporated by reference to Exhibit 10.12 to Talos
Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).
Indemnification Agreement (Neal P. Goldman) (incorporated by reference to Exhibit 10.14 to Talos
Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).
Indemnification Agreement (John “Brad” Juneau) (incorporated by reference to Exhibit 10.15 to
Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).
Indemnification Agreement (James M. Trimble) (incorporated by reference to Exhibit 10.16 to Talos
Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).
Indemnification Agreement (Charles M. Sledge) (incorporated by reference to Exhibit 10.17 to Talos
Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).
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10.27†
10.28†
10.29†
10.30†
10.31†
10.32†
10.33†
10.34*
10.35*
21.1*
23.1*
23.2*
24.1*
31.1*
31.2*
32.1**
99.1*
99.2
Indemnification Agreement (Donald R. Kendall, Jr.) (incorporated by reference to Exhibit 10.18 to
Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).
Indemnification Agreement (Rajen Mahagaokar) (incorporated by reference to Exhibit 10.19 to Talos
Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).
Form of Restricted Stock Unit Grant Notice and Restricted Stock Agreement (Directors)
(incorporated by reference to Exhibit 10.20 to Talos Energy Inc.’s Form 10-Q filed with the SEC on
August 9, 2018).
Form of Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Executives)
(incorporated by reference to Exhibit 10.32 to Talos Energy Inc.’s Registration Statement on Form S-
4 (File No. 333-227362) filed with the SEC on September 14, 2018)
Form of Performance Share Unit Grant Notice and Performance Share Unit Agreement (Executives)
(incorporated by reference to Exhibit 10.33 to Talos Energy Inc.’s Registration Statement on Form S-
4 (File No. 333-227362) filed with the SEC on September 14, 2018).
Talos Energy Operating Company LLC Executive Severance Plan (incorporated by reference to
Exhibit 10.1 to Talos Energy Inc.’s Form 8-K filed with the SEC on September 5, 2018).
Form of Participation Agreement pursuant to the Talos Energy Operating Company LLC Executive
Severance Plan (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 8-K filed with
the SEC on September 5, 2018).
First Amendment Agreement to the Contract for the Exploration and Extraction of Hydrocarbons in
the Form of Shared Production, dated as of August 8, 2018, between the National Hydrocarbons
Commission and Talos Energy Offshore México 2, S. de R.L. de C.V., Premier Oil Exploration and
Production México, S.A. de C.V., and Sierra Blanca P&D, S. de R.L. de C.V.
Second Amendment Agreement to the Contract for the Exploration and Extraction of Hydrocarbons in
the Form of Shared Production, dated as of December 20, 2018, between the National Hydrocarbons
Commission and Hokchi Energy, S.A. de C.V., Sierra Blanca P&D, S. de R.L. de C.V., Talos Energy
Offshore México 2, S. de R.L. de C.V., and Premier Oil Exploration and Production México, S.A. de
C.V.
List of Subsidiaries of Talos Energy Inc.
Consent of Ernst & Young LLP.
Consent of Netherland, Sewell & Associates, Inc.
Powers of Attorney (included on signature pages of this Part IV)
Certification of Chief Executive Officer of Talos Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a) of
the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
Certification of Chief Financial Officer of Talos Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a) of
the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
Certification of Chief Executive Officer and Chief Financial Officer of Talos Energy Inc. pursuant to
18 U.S.C. § 1350, as adopted pursuant to the Sarbanes-Oxley Act of 2002.
Netherland, Sewell & Associates, Inc. reserve report for Talos Energy Inc. as of December 31, 2018.
Netherland, Sewell & Associates, Inc. reserve report for Talos Energy LLC as of December 31, 2017
(incorporated by reference to Exhibit 99.12 to Talos Energy Inc.’s Amendment No. 2 to the
Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on March 15, 2018).
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99.3
Netherland, Sewell & Associates, Inc. reserve report for Talos Energy LLC as of December 31, 2016
(incorporated by reference to Exhibit 99.12 to Talos Energy Inc.’s Registration Statement on Form S-
4 (File No. 333-222341) filed with the SEC on December 29, 2017).
101.INS* XBRL Instance Document
101.SCH* XBRL Taxonomy Extension Schema Document
101.CAL* XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF* XBRL Taxonomy Extension Definition Linkbase Document
101.LAB* XBRL Taxonomy Extension Label Linkbase Document
101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document
*
**
†
#
Filed herewith.
Furnished herewith.
Identifies management contracts and compensatory plans or arrangements.
Certain schedules, annexes or exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K,
but will be furnished supplementally to the SEC upon request.
Item 16. Form 10-K Summary
None.
87
6696_10K.pdf
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned thereunto duly authorized.
SIGNATURES
Date:
March 13, 2019
By:
TALOS ENERGY INC.
/s/ MICHAEL L. HARDING II
Michael L. Harding II
Executive Vice President, Chief Financial Officer and
Chief Accounting Officer
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below
constitutes and appoints Timothy S. Duncan and Michael L. Harding II, and each of them, as his or her true and
lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or
her name, place and stead, in any and all capacities, to sign any and all amendments to this report, and to file the
same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange
Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and
perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all
intents and purposes as he or she might or could do in person, hereby ratifying and confirming that all said
attorneys-in-fact and agents, or any of them or their or his or her substitute or substitutes, may lawfully do or cause
to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by
the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Title
Chief Executive Officer
(Principal Executive Officer, Director)
Chief Financial Officer, Chief Accounting Officer
(Principal Financial Officer, Principal Accounting Officer)
Director
Director
Director
Director
Director
Director
Director
Director
Director
88
Date
March 13, 2019
March 13, 2019
March 13, 2019
March 13, 2019
March 13, 2019
March 13, 2019
March 13, 2019
March 13, 2019
March 13, 2019
March 13, 2019
March 13, 2019
Signature
/s/ Timothy S. Duncan
Timothy S. Duncan
/s/ Michael L. Harding II
Michael L. Harding II
/s/ Rajen Mahagaokar
Rajen Mahagaokar
/s/ James M. Trimble
James M. Trimble
/s/ Olivia C. Wassenaar
Olivia C. Wassenaar
/s/ Christine Hommes
Christine Hommes
/s/ Neal P. Goldman
Neal P. Goldman
/s/ Charles M. Sledge
Charles M. Sledge
/s/ Robert M. Tichio
Robert M. Tichio
/s/ John “Brad” Juneau
John “Brad” Juneau
/s/ Donald R. Kendall, Jr.
Donald R. Kendall, Jr.
6696_10K.pdf
Index to Consolidated Financial Statements
Reports of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2018 and 2017
Consolidated Statements of Operations for the years ended December 31, 2018, 2017 and 2016
Consolidated Statements of Changes in Stockholders’ Equity (Deficit) for the years ended December 31,
2018, 2017 and 2016
Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016
Notes to Consolidated Financial Statements
F-2
F-4
F-5
F-6
F-7
F-8
F-1
6696_10K.pdf
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of
Talos Energy Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Talos Energy Inc. (the Company) as of
December 31, 2018 and 2017, the related consolidated statements of operations, changes in stockholders’ equity
(deficit), and cash flows for each of the three years in the period ended December 31, 2018, and the related notes
(collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial
statements present fairly, in all material respects, the financial position of the Company at December 31, 2018 and
2017, and the results of its operations and its cash flows for each of the three years in the period ended December
31, 2018, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2018, based
on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (2013 framework), and our report dated March 13, 2019 expressed an
unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an
opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered
with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S.
federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the
PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial statements are free of material
misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of
material misstatement of the financial statements, whether due to error or fraud, and performing procedures that
respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and
disclosures in the financial statements. Our audits also included evaluating the accounting principles used and
significant estimates made by management, as well as evaluating the overall presentation of the financial
statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2010.
Houston, Texas
March 13, 2019
F-2
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Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of
Talos Energy Inc.
Opinion on Internal Control Over Financial Reporting
We have audited Talos Energy Inc.’s internal control over financial reporting as of December 31, 2018, based on
criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Talos Energy
Inc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of
December 31, 2018, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2018 and 2017, the
related consolidated statements of operations, changes in stockholders’ equity (deficit) and cash flows for each of
the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the
“consolidated financial statements”) and our report dated March 13, 2019 expressed an unqualified opinion
thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and
for its assessment of the effectiveness of internal control over financial reporting included in the accompanying
Report of Management on Internal Control over Financial Reporting. Our responsibility is to express an opinion on
the Company’s internal control over financial reporting based on our audit. We are a public accounting firm
registered with the PCAOB and are required to be independent with respect to the Company in accordance with the
U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission
and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting
was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a
material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on
the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We
believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles. A company’s internal control over financial reporting
includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable
assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company are being made
only in accordance with authorizations of management and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’
s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Houston, Texas
March 13, 2019
F-3
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TALOS ENERGY INC.
CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)
Year Ended December 31,
2017
2018
ASSETS
Current assets:
Cash and cash equivalents
Restricted cash
Accounts receivable
Trade, net
Joint interest, net
Other
Assets from price risk management activities
Prepaid assets
Inventory
Income tax receivable
Other current assets
Total current assets
Property and equipment:
Proved properties
Unproved properties, not subject to amortization
Other property and equipment
Total property and equipment
Accumulated depreciation, depletion and amortization
Total property and equipment, net
Other long-term assets:
Assets from price risk management activities
Other well equipment
Other assets
Total assets
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
Current liabilities:
Accounts payable
Accrued liabilities
Accrued royalties
Current portion of long-term debt
Current portion of asset retirement obligations
Liabilities from price risk management activities
Accrued interest payable
Other current liabilities
Total current liabilities
Long-term debt, net of discount and deferred financing costs
Asset retirement obligations
Liabilities from price risk management activities
Other long-term liabilities
Total liabilities
Commitments and contingencies (Note 11)
Stockholders' Equity:
$
139,914 $
1,248
103,025
20,244
19,686
75,473
38,911
—
10,701
7,644
416,846
3,629,430
108,209
33,191
3,770,830
(1,719,609)
2,051,221
—
9,224
2,695
2,479,986 $
51,019 $
188,650
38,520
443
68,965
550
10,200
22,071
380,418
654,861
313,852
—
123,359
1,472,490
$
$
32,191
1,242
62,871
13,613
12,486
1,563
17,931
840
—
2,148
144,885
2,440,811
72,002
8,857
2,521,670
(1,430,890)
1,090,780
345
2,577
706
1,239,293
72,681
87,973
24,208
24,977
39,741
49,957
8,742
15,188
323,467
672,581
174,992
18,781
103,559
1,293,380
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
Additional paid-in capital
Accumulated deficit
Total stockholders' equity (deficit)
Total liabilities and stockholders' equity
—
—
542
1,334,090
(327,136)
1,007,496
2,479,986 $
312
493,952
(548,351)
(54,087)
1,239,293
$
The accompanying notes are an integral part of these consolidated financial statements.
F-4
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TALOS ENERGY INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per common share amounts)
Revenues:
Oil revenue
Natural gas revenue
NGL revenue
Other
Total revenue
Operating expenses:
Direct lease operating expense
Insurance
Production taxes
Total lease operating expense
Workover and maintenance expense
Depreciation, depletion and amortization
Accretion expense
General and administrative expense
Total operating expenses
Operating income (loss)
Interest expense
Price risk management activities income (expense)
Other income
Net income (loss) before income taxes
Income tax expense
Net income (loss)
Net income (loss) per common share:
Basic
Diluted
Weighted average common shares outstanding:
Basic
Diluted
$
$
$
$
Year Ended December 31,
2018
2017
2016
781,815 $
73,610
35,863
—
891,288
145,988
15,342
1,989
163,319
64,961
288,719
35,344
85,816
638,159
253,129
(90,114)
60,435
1,012
224,462
(2,922)
221,540 $
344,781 $
48,886
16,658
2,503
412,828
109,180
10,743
1,460
121,383
32,825
157,352
19,295
36,673
367,528
45,300
(80,934)
(27,563)
329
(62,868)
—
(62,868) $
197,583
42,705
9,532
8,934
258,754
124,360
13,101
1,958
139,419
24,810
124,689
21,829
28,686
339,433
(80,679)
(70,415)
(57,398)
405
(208,087)
—
(208,087)
4.81 $
4.81 $
(2.01) $
(2.01) $
(7.99)
(7.99)
46,058
46,061
31,244
31,244
26,036
26,036
The accompanying notes are an integral part of these consolidated financial statements.
F-5
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TALOS ENERGY INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (DEFICIT)
(In thousands)
$
Balance at January 1, 2016
Contributions from Sponsors, net
Equity based compensation
Net loss
Balance at December 31, 2016
Equity based compensation
Net loss
Balance at December 31, 2017
Cumulative effect adjustment (Note 1)
Sponsor Debt Exchange
Stone Combination
Equity based compensation
Net income
Balance at December 31, 2018
$
Common
Stock
Retained
Earnings
(Accumulated
Deficit)
Total
Stockholders'
Equity
(Deficit)
Additional
Paid-In
Capital
$ 398,033
91,837
2,287
—
—
—
$ (277,396) $
(208,087)
(485,483)
492,157
1,795
—
120,895
258
91,891
54
2,287
—
(208,087)
—
6,986
312
1,795
—
(62,868)
—
(54,087)
312
(325)
—
102,000
29
731,964
201
6,404
—
—
221,540
542 $ 1,334,090 $ (327,136) $ 1,007,496
(62,868)
(548,351)
(325)
—
—
—
221,540
493,952
—
101,971
731,763
6,404
—
—
The accompanying notes are an integral part of these consolidated financial statements.
F-6
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TALOS ENERGY INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Cash flows from operating activities:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities
Depreciation, depletion, amortization and accretion
expense
Impairment
Amortization of deferred financing costs and original issue
discount
Equity based compensation, net of amounts capitalized
Price risk management activities (income) expense
Net cash received (paid) on settled derivative instruments
Settlement of asset retirement obligations
Changes in operating assets and liabilities:
Accounts receivable
Other current assets
Accounts payable
Other current liabilities
Other non-current assets and liabilities, net
Net cash provided by operating activities
Cash flows from investing activities:
Exploration, development and other capital expenditures
Cash (paid) received for acquisitions, net of cash acquired
Net cash provided by (used in) investing activities
Cash flows from financing activities:
Redemption of Senior Notes and other long-term debt
Proceeds from Bank Credit Facility
Repayment of Bank Credit Facility
Repayment of LLC Bank Credit Facility
Deferred financing costs
Payments of capital lease
Contributions from Sponsors
Distributions to Sponsors
Net cash provided by (used in) financing activities
Net increase (decrease) in cash, cash equivalents and restricted
cash
Cash, cash equivalents and restricted cash:
Balance, beginning of period
Balance, end of period
Supplemental Non-Cash Transactions:
Capital expenditures included in accounts payable and accrued liabilities
Supplemental Cash Flow Information:
Interest paid, net of amounts capitalized
Year Ended December 31,
2017
2016
2018
$
221,540 $
(62,868) $
(208,087)
324,063
244
4,253
2,893
(60,435)
(111,147)
(112,946)
(786)
(2,624)
(48,825)
32,044
15,171
263,445
(240,914)
278,409
37,495
(25,257)
319,000
(54,000)
(403,000)
(17,002)
(12,952)
—
—
(193,211)
176,647
260
2,383
875
27,563
23,834
(32,573)
(9,132)
(4,441)
2,409
46,364
4,732
176,053
(155,177)
(2,464)
(157,641)
(1,000)
10,000
—
(15,000)
—
(12,412)
—
—
(18,412)
146,518
218
5,996
1,083
57,398
172,182
(23,689)
(20,096)
(3,040)
(68,042)
51,240
4,442
116,123
(113,032)
(85,886)
(198,918)
—
15,000
—
(10,000)
—
(5,267)
93,750
(1,859)
91,624
107,729
—
8,829
33,433
141,162 $
33,433
33,433 $
24,604
33,433
100,664 $
40,626 $
13,832
53,476 $
47,994 $
55,254
$
$
$
The accompanying notes are an integral part of these consolidated financial statements.
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TALOS ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2018
Note 1 — Formation and Basis of Presentation
Formation and Nature of Business
Talos Energy Inc. (“Talos” or the “Company”) is a technically driven independent exploration and
production company with operations in the United States (“U.S.”) Gulf of Mexico and offshore Mexico. The
Company’s focus in the U.S. Gulf of Mexico is the acquisition of deep water assets with existing infrastructure and
the exploration, exploitation and development of such assets in key geological trends. Offshore Mexico provides
high impact exploration opportunities in an oil rich emerging basin. The Company uses access to an extensive
seismic database and its deep technical expertise to identify, acquire and exploit attractive assets with robust
economic profiles.
Talos Energy Inc. was formed in connection with the previously disclosed business combination between
Talos Energy LLC and Stone Energy Corporation (“Stone”) that occurred on May 10, 2018, pursuant to which
Talos Energy LLC and Stone became indirect wholly owned subsidiaries of Talos Energy Inc.
Talos Energy LLC
Talos Energy LLC was formed in 2011 and commenced commercial operations on February 6, 2013. Prior to
February 6, 2013, Talos Energy LLC had incurred certain general and administrative expenses associated with the
start-up of its operations.
On February 3, 2012, Talos Energy LLC completed a transaction with funds and other alternative investment
vehicles managed by Apollo Management VII, L.P. and Apollo Commodities Management, L.P., with respect to
Series I (“Apollo Funds”), and entities controlled by or affiliated with Riverstone Energy Partners V, L.P.
(“Riverstone Funds”, and together with the Apollo Funds, the “Sponsors”) and members of management pursuant
to which the Company received a private equity capital commitment.
Stone Combination
On May 10, 2018 (the “Closing Date”), the Company (f/k/a Sailfish Energy Holdings Corporation)
consummated the transactions contemplated by that certain Transaction Agreement, dated as of November 21,
2017 (the “Transaction Agreement”), by and among Stone, the Company, Sailfish Merger Sub Corporation
(“Merger Sub”), Talos Energy LLC and Talos Production LLC, pursuant to which, among other items, each of
Stone, Talos Production LLC and Talos Energy LLC became wholly-owned subsidiaries of the Company (the
“Stone Combination”). Prior to the Closing Date, the Company did not conduct any material activities other than
those incident to its formation and the matters contemplated by the Transaction Agreement.
On Closing Date, the following transactions, among others, occurred: (i) Stone underwent a reorganization
pursuant to which Merger Sub merged with and into Stone, with Stone continuing as the surviving corporation and
a direct wholly-owned subsidiary of the Company (the “Merger”) and each share of Stone’s common stock
outstanding immediately prior to the Merger (other than treasury shares held by Stone, which were cancelled for no
consideration) was converted into the right to receive one share of the Company’s common stock, par value $0.01
(the “Common Stock”) and (ii) the Sponsors contributed all of the equity interests in Talos Production LLC (which
at that time owned 100% of the equity interests in Talos Energy LLC) to the Company in exchange for an
aggregate of 31,244,085 shares of Common Stock (the “Sponsor Equity Exchange”).
Concurrently with the consummation of the Transaction Agreement, the Company consummated the
transactions contemplated by that certain Exchange Agreement, dated as of November 21, 2017 (the “Exchange
Agreement”), among the Company, Stone, the Talos Issuers (defined below), the various lenders and noteholders
of the Talos Issuers listed therein, certain funds controlled by Franklin Advisers, Inc. (“Franklin”) (such controlled
noteholders, the “Franklin Noteholders”), and certain clients of MacKay Shields LLC (“MacKay Shields”) (such
noteholders, the “MacKay Noteholders”), pursuant to which (i) the Apollo Funds and Riverstone Funds contributed
$102.0 million in aggregate principal amount of 9.75% Senior Notes due 2022 (“9.75% Senior Notes”) issued by
Talos Production LLC and Talos Production Finance, Inc. (together, the “Talos Issuers”) to the Company in
exchange for an aggregate of 2,874,049 shares of Common Stock (the “Sponsor Debt Exchange”); (ii) the holders
of second lien bridge loans (“11.00% Bridge Loans”) issued by the Talos Issuers exchanged such 11.00% Bridge
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Loans for $172.0 million aggregate principal amount of 11.00% Second-Priority Senior Secured Notes due 2022 of
the Talos Issuers (“11.00% Senior Secured Notes”) and (iii) Franklin Noteholders and MacKay Noteholders
exchanged their 7.50% Senior Secured Notes due 2022 issued by Stone (“7.50% Stone Senior Notes”) for $137.4
million aggregate principal amount of 11.00% Senior Secured Notes.
Substantially concurrent therewith, the Company consummated an exchange offer and consent solicitation,
pursuant to which the holders of the 7.50% Stone Senior Notes, excluding the 7.50% Stone Senior Notes held by
the Franklin Noteholders and the MacKay Noteholders, exchanged their 7.50% Stone Senior Notes for 11.00%
Senior Secured Notes and a cash payment, and a solicitation of consents to proposed amendments to the 7.50%
Stone Senior Notes. Approximately $81.5 million in aggregate principal amount of the 7.50% Stone Senior Notes
were validly tendered, and approximately $6.1 million in aggregate principal amount of 7.50% Stone Senior Notes
remained outstanding as of the Closing Date.
As a result of the closing of the transactions contemplated by the Transaction Agreement and the Exchange
Agreement (the “Transactions”) the former stakeholders of Talos Energy LLC held approximately 63% of the
Company’s outstanding Common Stock and the former stockholders of Stone held approximately 37% of the
Company’s outstanding Common Stock as of the Closing Date.
Basis of Presentation and Consolidation
The consolidated financial statements have been prepared in accordance with accounting principles generally
accepted in the United States of America (“GAAP”) and include each subsidiary from the date of inception. All
intercompany transactions have been eliminated. All adjustments are of a normal, recurring nature and are
necessary to fairly present the financial position, results of operations and cash flows for the periods are reflected
herein. The Company has evaluated subsequent events through the date the consolidated financial statements were
issued.
Talos Energy LLC was considered the accounting acquirer in the Stone Combination under GAAP.
Accordingly, the historical financial and operating data of Talos Energy Inc., which covers periods prior to the
Closing Date, reflects the assets, liabilities and results of operations of Talos Energy LLC and does not reflect the
assets, liabilities and results of operations of Stone. For the periods prior to May 10, 2018, the Company
retrospectively adjusted its Statement of Changes in Stockholders’ Equity and the weighted average shares used in
determining earnings per share to reflect the number of shares Talos Energy LLC received in the Stone
Combination. Beginning on May 10, 2018, common stock is presented to reflect the legal capital of Talos Energy
Inc.
The preparation of financial statements in conformity with GAAP requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and
liabilities as of the date of the financial statements, the reported amounts of revenues and expenses during the
reporting periods and the reported amounts of proved oil and natural gas reserves. Actual results could differ from
those estimates.
The Company has one reportable segment, which is the exploration and production of oil and natural gas.
Substantially all the Company’s long-lived assets, proved reserves and production sales are related to the
Company’s operations in the United States.
Recently Adopted Accounting Standards
Revenue Recognition
On January 1, 2018, the Company adopted Accounting Standards Codification (“ASC”) 606, Revenue from
Contracts with Customers using the modified retrospective approach. ASC 606 supersedes the revenue recognition
requirements in Topic 615, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive
Activities – Oil and Gas – Revenue Recognition. The new standard includes a five-step revenue recognition model
to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the
Company expects to be entitled in exchange for these goods and services.
The Company records revenues from the sale of oil, natural gas and NGLs based on quantities of production
sold to purchasers under short-term contracts (less than twelve months) at market prices when delivery to the
customer has occurred, title has transferred, prices are fixed and determinable and collection is reasonably assured.
This occurs when production has been delivered to a pipeline or when a barge lifting has occurred.
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The Company applied the practical expedient in ASC 606 exempting the disclosure of the transaction price
allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly
unsatisfied performance obligation. Each unit of product typically represents a separate performance obligation,
therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining
performance obligations is not required.
Gas Imbalances. Under previous accounting guidance, the Company used the entitlement method to account
for sales and production. Under the entitlement method, revenue was recorded based on the Company’s entitled
share of production with any difference recorded as an imbalance on the consolidated balance sheet. Upon the
adoption of ASC 606, revenues are recorded based on the actual sales volumes sold to purchasers. An imbalance
receivable or payable is recorded only to the extent the imbalance is in excess of its share of remaining proved
developed reserves in an underlying property. The change in accounting method from the entitlements method to
the sales method resulted in an immaterial cumulative-effect adjustment to stockholders’ deficit on the date of
adoption.
Production Handling Fees. Under previous accounting guidance, the Company presented certain
reimbursements for costs from certain third parties as other revenue on the consolidated statement of operations.
Upon the adoption of ASC 606, the reimbursements are presented as a reduction of direct lease operating expense
on the consolidated statement of operations. The impact of the reclassification for the year ended December 31,
2018 was immaterial.
Recently Issued Accounting Standards
Leases. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). This ASU supersedes the
lease requirements in Topic 840, Leases, and requires that a lessee recognize a right-of-use asset and lease liability
for leases that do not meet the definition of a short-term lease. The right-of-use asset and lease liability are to be
measured on the balance sheet at the present value of the lease payments. For income statement purposes, ASU
2016-02 retains a dual model requiring leases to be classified as either operating or finance within the Company’s
consolidated statements of operations. Lease costs for operating leases are recognized as a single lease cost,
calculated so that the cost of the lease is allocated over the lease term on a straight-line basis. For finance leases,
interest expense is recognized on the lease liability separately from amortization of the right-to-use asset. ASU
2016-02 does not apply to leases for oil and natural gas properties, but does apply to equipment used to explore and
develop oil and natural gas reserves. This ASU is effective for fiscal years beginning after December 15, 2018,
including the first quarter of 2019. The Company will adopt this standard using the modified retrospective method
applied to all leases that exist on January 1, 2019. Talos made certain elections allowing the Company not to
reassess contracts that commenced prior to adoption and to not recognize right-of-use assets or lease liabilities for
short-term leases. Upon adoption, the Company expects the right-to-use asset and lease liability reported on the
consolidated balance sheet to be material. The Company is finalizing the implementation of the changes to business
processes, systems and controls to support accounting and disclosure requirements of this ASU.
Note 2 — Summary of Significant Accounting Policies
Below are the Company’s significant accounting policies.
Cash and Cash Equivalents
The Company presents cash as cash and cash equivalents on the Company’s consolidated balance sheets. The
Company considers all cash, money market funds and highly liquid investments with an original maturity of three
months or less as cash and cash equivalents. Cash and cash equivalents are carried at cost, which approximates fair
value.
Accounts Receivable and Allowance for Uncollectible Accounts
Accounts receivable are stated at the historical carrying amount net of an allowance for uncollectible
accounts of $8.7 million at December 31, 2018 and $5.9 million at December 31, 2017. The Company establishes
provisions for losses on accounts receivable with other parties if it believes that it will not collect all or part of the
outstanding balance. On a quarterly basis, the Company reviews collectability and establishes or adjusts the
Company’s allowance as necessary using the specific identification method.
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Prepaid Assets
Prepaid assets primarily represent deposits with the Office of Natural Resources Revenue (“ONRR”). The
deposits are the Company’s estimated ONRR royalties payable within thirty days of the production rate. On a
monthly basis the Company adjusts the deposit based on actual royalty payments remitted to the ONRR.
Revenue Recognition
Upon the adoption of ASC 606, revenues are recorded based from the sale of oil, natural gas and NGL
quantities sold to purchasers. See Note 1 — Formation and Basis of Presentation for additional information.
Accounting for Oil and Natural Gas Activities
The Company follows the full cost method of accounting for oil and natural gas exploration and development
activities. Under the full cost method, substantially all costs incurred in connection with the acquisition,
development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the
internal costs directly related to acquisition, development and exploration activities, asset retirement costs and
capitalized interest. Under the full cost method, dry hole costs and geological and geophysical costs are capitalized
into the full cost pool, which is subject to amortization and assessed for impairment on a quarterly basis through a
ceiling test calculation as discussed below. In August 2016, the Company entered into a capital lease for the use of
the Helix Producer I (“HP-I”), a dynamically positioned floating production facility that interconnects with the
Phoenix Field through a production buoy, and recorded a $124.3 million capital lease asset. Since the HP-I is
utilized in the Company’s oil and natural gas development activities, the asset is included within proved property
and subject to the ceiling test calculation described below. Due to the inclusion within proved properties, the HP-I
is depleted as part of the full cost pool. See Note 11 — Commitments and Contingencies for additional information.
Capitalized costs associated with proved reserves are amortized on a country by country basis over the life of
the total proved reserves using the unit of production method, computed quarterly. Conversely, capitalized costs
associated with unproved properties and related geological and geophysical costs, exploration wells currently
drilling and capitalized interest are initially excluded from the amortizable base. The Company transfers unproved
property costs into the amortizable base when properties are determined to have proved reserves or when the
Company has completed an unproved properties evaluation resulting in an impairment. The Company evaluates
each of these unproved properties individually for impairment at least quarterly. Additionally, the amortizable base
includes future development costs, dismantlement, restoration and abandonment costs, net of estimated salvage
values, and geological and geophysical costs incurred that cannot be associated with specific unproved properties
or prospects in which the Company owns a direct interest.
The Company’s capitalized costs are limited to a ceiling based on the present value of future net revenues
from proved reserves, computed using a discount factor of 10 percent, plus the lower of cost or estimated fair value
of unproved oil and natural gas properties not being amortized less the related tax effects. Any costs in excess of
the ceiling are recognized as a non-cash impairment expense on the consolidated statement of operations and an
increase to accumulated depreciation, depletion and amortization on the Company’s consolidated balance sheets.
The expense may not be reversed in future periods, even though higher oil, natural gas and NGL prices may
subsequently increase the ceiling. The Company performs this ceiling test calculation each quarter. In accordance
with the SEC rules and regulations, the Company utilize SEC Pricing when performing the ceiling test. The
Company also holds prices and costs constant over the life of the reserves, even though actual prices and costs of
oil and natural gas are often volatile and may change from period to period. The ceiling test computation did not
result in a write-down of the Company’s oil and natural gas properties during the years ended December 31, 2018,
2017 and 2016.
Under the full cost method of accounting for oil and natural gas operations, assets whose costs are currently
being depreciated, depleted or amortized are assets in use in the earnings activities of the enterprise and do not
qualify for capitalization of interest cost. Investments in unproved properties for which exploration and
development activities are in progress and other major development projects that are not being currently
depreciated, depleted or amortized are assets qualifying for capitalization of interest costs.
When the Company sells or conveys interests in oil and natural gas properties, the Company reduces its oil
and natural gas reserves for the amount attributable to the sold or conveyed interest. The Company treats sales
proceeds on non-significant sales as reductions to the cost of the Company’s oil and natural gas properties. The
Company does not recognize a gain or loss on sales of oil and natural gas properties, unless those sales would
significantly alter the relationship between capitalized costs and proved reserves.
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The Company recognizes transportation costs as a component of direct lease operating expense when it is the
shipper of the product. Such costs were $12.5 million, $10.3 million and $9.1 million in the years ended
December 31, 2018, 2017 and 2016, respectively.
Other Property and Equipment
Other property and equipment is recorded at cost and consists primarily of leasehold improvements, office
furniture and fixtures, computer hardware and software. Acquisitions, renewals and betterments are capitalized;
maintenance and repairs are expensed as incurred. Depreciation is provided using the straight-line method over
estimated useful lives of three to ten years.
Other Well Equipment Inventory
Other well equipment inventory primarily represents the cost of equipment to be used in the Company’s oil
and natural gas drilling and development activities such as drilling pipe, tubulars and certain wellhead equipment.
When this inventory is supplied to wells, the cost of this inventory is capitalized in oil and gas properties, and if
such property is jointly owned, the proportionate costs will be reimbursed by third party participants. The
Company’s inventory is stated at the lower of cost or net realizable value. The Company recorded $0.2 million,
$0.3 million, $0.2 million of impairment to adjust inventory to net realizable value, which was expensed and
reflected in workover/maintenance expense, during the years ended December 31, 2018, 2017 and 2016,
respectively.
Fair Value Measure of Financial Instruments
Financial instruments generally consist of cash and cash equivalents, restricted cash, accounts receivable,
commodity derivatives, accounts payable and debt. The carrying amount of cash and cash equivalents, restricted
cash, accounts receivable and accounts payable approximates fair value due to the highly liquid nature of these
instruments.
Current fair value accounting standards define fair value, establish a consistent framework for measuring fair
value and stipulate the related disclosure requirements for each major asset and liability category measured at fair
value on either a recurring or nonrecurring basis. These standards also clarify fair value is an exit price, presenting
the amount that would be received to sell an asset or paid to transfer a liability, in an orderly transaction between
market participants. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used
to measure fair value depending on the degree to which they are observable as follows:
Level 1 – Inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities
in active markets.
Level 2 – Inputs to the valuation methodology include quoted prices for similar assets and liabilities in active
markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially
the full term of the financial statement.
Level 3 – Inputs to the valuation methodology are unobservable (little or no market data), which require the
reporting entity to develop its own assumptions, and are significant to the fair value measurement.
Assets and liabilities measured at fair value are based on one or more of three valuation techniques. The
valuation techniques are as follows:
Market Approach – Prices and other relevant information generated by market transactions involving
identical or comparable assets or liabilities.
Cost Approach – Amount that would be required to replace the service capacity of an asset (replacement
cost).
Income Approach – Techniques to convert expected future cash flows to a single present value amount based
on market expectations (including present value techniques, option-pricing and excess earnings models).
Authoritative guidance on financial instruments requires certain fair value disclosures to be presented. The
estimated fair value amounts have been determined using available market information and valuation
methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value.
The use of different assumptions or valuation methodologies may have a material effect on the estimated fair value
amounts.
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Asset Retirement Obligations
The Company is required to record its asset retirement obligations at fair value in the period such obligations
are incurred with the associated asset retirement costs being capitalized as part of the carrying cost of the asset. The
Company’s asset retirement obligations consist of estimated costs for dismantlement, removal, site reclamation and
similar activities associated with the Company’s oil and natural gas properties. The estimate of the asset retirement
cost is determined, inflated to an estimated future value using a ten year average of the Consumer Price Index and
discounted to present value using the Company’s credit-adjusted risk-free rate. Accretion of the liability is
recognized for changes in the value of the liability as a result of the passage of time over the estimated productive
life of the related assets as the discounted liabilities are accreted to their expected settlement values.
Price Risk Management Activities
The Company uses commodity price derivatives to manage fluctuating oil and natural gas market risks. The
Company periodically enters into commodity derivative contracts, which may require payments to (or receipts
from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil
or natural gas without the exchange of underlying volumes.
Commodity derivatives are recorded on the consolidated balance sheets at fair value with settlements of such
contracts and changes in the unrealized fair value recorded in earnings each period. Realized gains and losses on
the settlement of commodity derivatives and changes in their unrealized gains and losses are reported in price risk
management activities income (expense) in the consolidated statements of operations. The Company classifies cash
flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows
are considered an integral part of the Company’s oil and natural gas operations, they are classified as cash flows
from operating activities. The Company does not enter into derivative agreements for trading or other speculative
purposes.
The commodity derivative’s fair value reflects the Company’s best estimate with priority based upon
exchange or over-the-counter quotations. Quoted valuations may not be available due to location differences or
terms that extend beyond the period for which quotations are available. Where quotes are not available, the
Company then utilizes other valuation techniques or models to estimate market values. These modeling techniques
require the Company to make estimations of future prices, price correlation, market volatility and liquidity. The
Company’s actual results may differ from its estimates, and these differences can be favorable or unfavorable.
Income Taxes
Prior to the Stone Combination, Talos Energy LLC was a partnership for U.S. federal income tax purposes
and was not subject to U.S. federal income tax or state income tax (in most states) at the entity level. As such,
Talos Energy LLC did not recognize U.S. federal income tax expense or state income tax expense in most
states. In connection with the Stone Combination, Talos Energy LLC was contributed to the Company, which is
subject to U.S. federal and state income taxes. The Company records current income taxes based on estimates of
current taxable income and provides for deferred income taxes to reflect estimated future income tax payments and
receipts. Changes in tax laws are recorded in the period they are enacted. Deferred taxes represent the tax impacts
of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year
end. The Company classifies all deferred tax assets and liabilities, along with any related valuation allowance, as
long-term on the consolidated balance sheets.
The realization of deferred tax assets depends on recognition of sufficient future taxable income during
periods in which those temporary differences are deductible. The Company reduces deferred tax assets by a
valuation allowance when, based on estimates, it is more likely than not that a portion of those assets will not be
realized in a future period. The deferred tax asset estimates are subject to revision, either up or down, in future
periods based on new facts or circumstances. In evaluating the Company’s valuation allowances, the Company
considers cumulative book losses, the reversal of existing temporary differences, the existence of taxable income in
carryback years, tax planning strategies and future taxable income for each of its taxable jurisdictions, the latter two
of which involve the exercise of significant judgment. Changes to the Company’s valuation allowances could
materially impact its results of operations.
The Company’s policy is to classify interest and penalties associated with underpayment of income taxes as
interest expense and general and administrative expense, respectively.
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Earnings Per Share
Basic net income per common share (“EPS”) is computed by dividing net income (loss) by the weighted
average number of shares of common stock outstanding during the period. Except when the effect would be
antidilutive, diluted EPS includes the impact of restricted stock units (“RSUs”), performance share units (“PSUs”)
and outstanding warrants. See Note 9 — Earnings Per Share for additional information.
Share-Based Compensation
Certain of the Company’s employees participate in its equity based compensation. The Company measures
all employee equity based compensation awards at fair value as calculated using an option pricing method for
valuing such securities on the date awards are granted to its employees and recognize compensation cost on a
straight-line basis in the Company’s financial statements over the vesting period of each grant according to ASC
718, Compensation—Stock Compensation.
During 2018, the Company issued RSUs and PSUs to certain employees and non-employee directors. The
fair value of the stock-based awards is determined at the date of grant and is not remeasured for awards classified
as equity, but is remeasured at each reporting period for awards classified as a liability. The Company records
share-based compensation, net of actual forfeitures, for the RSUs and PSUs in general and administrative expense
on the consolidated statement of operations, net of amounts capitalized to oil and gas properties. See Note 7 —
Employee Benefits Plans and Share-Based Compensation for additional information.
RSUs. Share-based compensation is based on the market price of the Company’s Common Stock on the grant
date and recognized over the vesting period using the straight-line method as the requisite service period is
fulfilled.
PSUs. Share-based compensation is based on the grant date fair value determined using a Monte Carlo
valuation model and recognized over the vesting period using the straight-line method. Estimates used in the Monte
Carlo valuation model are considered highly-complex and subjective. The number of shares of Common Stock
issuable upon vesting ranges from zero to 200% of the number of PSUs granted based on the Company’s total
shareholder return (“TSR”) relative to the TSR achieved by a specified industry peer group. Share-based
compensation related to PSUs is recognized as the requisite service period is fulfilled, even if the market condition
is not achieved.
Concentration of Credit Risk
Consisting principally of cash and cash equivalents, restricted cash, accounts receivable and commodity
derivatives, the Company is subject to concentrated financial instruments credit risk.
Cash and cash equivalents and restricted cash balances are maintained in financial institutions, which at
times, exceed federally insured limits. The Company monitors the financial condition of these institutions and has
not experienced losses on these accounts.
Commodity derivatives are entered into with registered swap dealers, the majority of which participate in the
Company’s senior reserve-based revolving credit facility (the “Bank Credit Facility”). The Company monitors the
financial condition of these institutions and has not experienced losses due to counterparty default on these
instruments.
The Company markets substantially all of its oil and natural gas production, and all of its revenues are
attributable to the U.S. The majority of the Company’s oil, natural gas and NGL production is sold to customers
under short-term (less than 12 months) contracts at market-based prices. The Company’s customers consist
primarily of major oil and natural gas companies, well-established oil and pipeline companies and independent oil
and gas producers and suppliers. The Company performs ongoing credit evaluations of its customers and provide
allowances for probable credit losses when necessary. The percent of consolidated revenue of major customers,
those whose total represented 10% or more of the Company’s oil, natural gas and NGL revenues, was as follows:
Shell Trading (US) Company
Phillips 66
Chevron U.S.A Inc.
**less than 10%
Year Ended December 31,
2017
2016
2018
65%
18%
**
80%
**
**
68%
**
14%
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The loss of a major customer could have material adverse effect on the Company in the short term. However,
the Company believes it would be able to obtain other customers to market its oil, natural gas and NGL production.
Note 3 — Acquisitions
Business Combination
Combination Between Talos Energy LLC and Stone Energy Corporation
The Stone Combination qualified as a business combination and was accounted for under the acquisition
method of accounting, which requires, among other items, that assets acquired and liabilities assumed be
recognized on the consolidated balance sheet at their fair values as of the acquisition date, May 10, 2018. The fair
value measurements of the oil and natural gas properties acquired and asset retirement obligations assumed were
derived utilizing an income approach and based, in part, on significant inputs not observable in the market. These
inputs represent Level 3 measurements in the fair value hierarchy and include, but are not limited to, estimates of
reserves, future operating and development costs, future commodity prices, estimated future cash flows and
appropriate discount rates. These inputs required significant judgments and estimates at the time of the valuation.
On May 10, 2018, the Company consummated the Transactions contemplated by the Transaction Agreement
and Exchange Agreement, pursuant to which, among other things, Talos Energy LLC and Stone became wholly-
owned subsidiaries of the Company. The combination was executed as an all-stock transaction whereby the former
stakeholders of Talos Energy LLC held approximately 63% of the Company’s outstanding Common Stock and the
former stockholders of Stone held approximately 37% of the Company’s outstanding Common Stock as of the
Closing Date.
The purchase price of $732.0 million is based on the closing price of Stone common stock and common
warrants immediately prior to closing. The following table summarizes the purchase price (in thousands, except per
share data):
Stone Energy common stock - issued and outstanding as of May 9, 2018
Stone Energy common stock price
Common stock value
Stone Energy common stock warrants - issued and outstanding as of May 9, 2018
Stone Energy common stock warrants price
Common stock warrants value
Total purchase price
$
$
$
$
$
20,038
35.49
711,149
3,528
5.90
20,815
731,964
The Company incurred approximately $88.6 million of transaction related costs, of which, $32.5 million was
expensed and reflected in general and administrative expense on the consolidated statement of operations. The
remaining $56.1 million was the result of (i) $9.3 million in work fees paid to holders of the 11.00% Senior
Secured Notes reflected as a debt discount reducing long-term debt on the consolidated balance sheet and (ii) $46.8
million in fees for seismic use agreements for change in control provisions and reflected in proved properties on the
consolidated balance sheet.
While the Company has substantially completed the determination of the fair values of the assets acquired
and liabilities assumed, the Company is still finalizing the fair value analysis related to oil and natural gas
properties acquired by Stone prior to Closing. The Company anticipates finalizing the determination of the fair
values by March 31, 2019.
During the third and fourth quarters of 2018, certain adjustments were recorded to reflect new information
obtained subsequent to recording the preliminary allocation of the purchase price. Income tax receivables decreased
by $5.5 million, trade receivables increased by $1.0 million, other long-term liabilities increased by $2.7 million
and unproved properties increased by $7.2 million. Had these adjustments been recorded as of the acquisition date,
May 10, 2018, there would have been no corresponding impact to net income subsequent to the acquisition. These
adjustments are reflected in the preliminary purchase price allocation table below.
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The following table presents the preliminary allocation of the purchase price to the assets acquired and
liabilities assumed, based on their fair values on May 10, 2018 (in thousands):
Current assets(1)
Property and equipment
Other long-term assets
Current liabilities
Long-term debt
Other long-term liabilities
Allocated purchase price
$
$
372,760
883,490
18,928
(130,062)
(235,416)
(177,736)
731,964
(1)
Includes $293.0 million of cash acquired. The fair values of current assets acquired includes trade receivables and joint interest receivables
of $43.3 million and $3.5 million, respectively, which the Company expects all to be realizable.
Revenue and net income attributable to the assets acquired in the Stone Combination during the year of
December 31, 2018 was $332.9 million $148.5 million, respectively.
Pro Forma Financial Information (Unaudited)
The following supplemental pro forma information (in thousands, except per common share amounts),
presents the consolidated results of operations for the years ended December 31, 2018 and 2017 as if the Stone
Combination had occurred on January 1, 2017. The unaudited pro forma information was derived from historical
statements of operations of the Company and Stone and adjusted to include (i) depletion and accretion expense
applied to the adjusted basis of the oil and natural gas properties acquired, (ii) interest expense to reflect the debt
transactions contemplated by the Exchange Agreement and (iii) general and administrative expense adjusted for
transaction related costs incurred. This information does not purport to be indicative of results of operations that
would have occurred had the Stone Combination occurred on January 1, 2017, nor is such information indicative of
any expected future results of operations.
Revenue
Net income (loss)
Basic and diluted net income (loss) per common share
Year Ended December 31,
2018
2017
1,013,184
274,577
5.07 $
712,648
(100,980)
(1.86)
$
$
$
Material, non-recurring adjustments included in pro forma net income (loss) above consist of historical Stone
results adjusted to exclude a divestiture of oil and natural gas properties during 2017.
Asset Acquisitions
Each of the acquisitions below qualified as an asset acquisition that requires, among other items, that the cost
of the assets acquired and liabilities assumed to be recognized on the balance sheet by allocating the asset cost on a
relative fair value basis. The fair value measurements of the oil and natural gas properties acquired and asset
retirement obligations assumed were derived utilizing an income approach and based, in part, on significant inputs
not observable in the market. These inputs represent Level 3 measurements in the fair value hierarchy and include,
but are not limited to, estimates of reserves, future operating and development costs, future commodity prices,
estimated future cash flows and appropriate discount rates. These inputs required significant judgments and
estimates by the Company’s management at the time of the valuation. Transaction costs incurred on an asset
acquisition are capitalized as a component of the assets acquired and any contingent consideration is recognized as
the contingency is resolved.
Acquisition of Whistler Energy II, LLC
On August 31, 2018, the Company completed the acquisition of all the issued and outstanding membership
interests of Whistler Energy II, LLC (“Whistler”) from Whistler Energy II Holdco, LLC, an affiliate of the Apollo
Funds, for $52.6 million ($14.8 million, net of $37.8 million of cash acquired). The $37.8 million of cash acquired
consists of $30.8 million of cash collateral posted by Whistler and released by third party surety companies at
closing and $7.0 million of cash on hand for working capital purposes. Through the acquisition, the Company
acquired all of Whistler’s oil and natural gas assets located in Green Canyon Block 18, Green Canyon Block 69
and Ewing Bank Block 988, including a fixed production platform on Green Canyon Block 18. The Company also
assumed the associated asset retirement obligations. The Company refers to the acquisition of all the issued and
outstanding membership interests as the “Whistler Acquisition.”
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The following table presents the allocation of the purchase price to the assets acquired and liabilities
assumed, based on their relative fair values, on August 31, 2018 (in thousands):
Current assets(1)
Property and equipment
Other long-term assets
Current liabilities
Asset retirement obligations
Allocated purchase price
$
$
45,337
35,344
66
(4,261)
(23,862)
52,624
(1)
Includes $37.8 million of cash acquired and trade receivables of $3.2 million, which the Company expects all to be realizable.
Acquisition of Additional Working Interest in the Phoenix Field
On December 20, 2016, the Company purchased an additional 15% working interest in the Phoenix Field
from Sojitz Energy Venture Inc. (“Sojitz”) for approximately $85.8 million in cash and the assumption of certain
asset retirement obligations, subject to customary post-closing adjustments. The purchase price was funded by a
$93.8 million ($91.9 million, net of $1.9 million of transaction fees) contribution from the Sponsors. Additionally,
the Company entered into a contingent consideration arrangement in the form of an earn-out equal to 5% of the
acquired property’s monthly net profit if its realized oil price is greater than $65.00 per Bbl in a given month. The
maximum payout under the earn-out is $10.0 million and it has an indefinite life pursuant to the purchase and sale
agreement. The Company refers to the acquisition of assets from Sojitz as the “Sojitz Acquisition.”
Through December 31, 2017, the Company recorded $2.5 million in post-closing adjustments related to
activity between the effective date and closing date of the acquisition. The following table presents the allocation of
the purchase price (inclusive of post-closing adjustments) to the assets acquired and liabilities assumed, based on
their relative fair values, on December 20, 2016 (in thousands):
Proved properties
Unproved properties, not subject to amortization
Other short and long-term assets
Asset retirement obligations
Allocated purchase price
Note 4 — Property, Plant and Equipment
$
$
77,967
11,133
2,380
(3,242)
88,238
Proved Properties. The Company’s interests in oil and natural gas proved properties are located in the United
States, primarily in the Gulf of Mexico deep and shallow waters. The Company follows the full cost method of
accounting for its oil and natural gas exploration and development activities. In August 2016, the Company entered
into a capital lease for the use of the HP-I and recorded a $124.3 million capital lease asset. Since the HP-I is
utilized in its oil and natural gas development activities, the asset is included within proved property, subject to the
ceiling test calculation described below, and is depleted as part of the full cost pool.
Pursuant to SEC Regulation S-X, Rule 4-10, under the full cost method of accounting, the Company’s
capitalized oil and natural gas costs are limited to a ceiling based on the present value of future net revenues from
proved reserves, computed using a discount factor of 10%, plus the lower of cost or estimated fair value of
unproved oil and natural gas properties not being amortized less the related tax effects. The Company performs this
ceiling test calculation each quarter utilizing SEC pricing. During 2018, 2017 and 2016, the Company’s ceiling test
computations did not result in a write-down of its U.S. oil and natural gas properties. At December 31, 2018, its
ceiling test computation was based on SEC pricing of $69.42 per Bbl of oil, $3.08 per Mcf of natural gas and
$29.50 per Bbl of NGLs.
Unproved Properties. Unproved capitalized costs of oil and natural gas properties excluded from
amortization relate to unevaluated properties associated with acquisitions, leases awarded in the U.S. Gulf of
Mexico federal lease sales, certain geological and geophysical costs, costs associated with certain exploratory wells
in progress and capitalized interest. Unproved properties also include costs associated with the two blocks (Block 2
and Block 7) awarded on September 4, 2015 to the Company together with Sierra Oil & Gas S. de R.L de C.V.
(“Sierra”) and Premier Oil Plc (“Premier”), the (“Consortium”), located in the shallow waters off the coast of
Mexico’s Veracruz and Tabasco states, by the National Hydrocarbons Commission (“CNH”), Mexico’s upstream
regulator.
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In September 2018, the Company entered into a transaction (the “Hokchi Cross Assignment”) with Hokchi
Energy, S.A. de C.V. (“Hokchi”), a subsidiary of Pan American Energy (“PAE”), to cross assign 25% participation
interests (“PIs”) in Block 2 and Block 31. The Company’s assignment of a 25% PI in Block 2 to Hokchi closed on
December 21, 2018, and Hokchi has assumed operator responsibilities with respect to Block 2. Hokchi’s
assignment of Block 31 to the Company will be completed upon final approval by the CNH subsequent to
December 31, 2018. In addition, Premier exercised its option to reduce its PI in Block 2 to zero and assign a 5% PI
to each of Sierra and the Company. Such assignment is also subject to CNH’s approval which had not occurred as
of December 31, 2018. Upon completion of the Hokchi Cross Assignment and Premier’s option exercise, the
Company will own a 25% PI in each of Block 2 and Block 31, and Hokchi will be the operator of both blocks.
The following table sets forth a summary of the Company’s oil and natural gas property costs not being
amortized at December 31, 2018, by the year in which such costs were incurred (in thousands):
Year Ended December 31,
Acquisition United States
Exploration United States
Total United States unproved properties, not
subject to amortization
Exploration Mexico
Total Mexico unproved properties, not subject to
amortization
Total unproved properties, not subject to
amortization
$
$
Total
49,777 $
13,327
2018
40,657 $
8,391
2017
2016 2015 and Prior
6,876
1,656
— $ 2,244 $
92
3,188
63,104 $
45,105
49,048 $
14,362
3,188 $ 2,336 $
23,332 6,110
8,532
1,301
$
45,105 $
14,362 $
23,332 $ 6,110 $
1,301
$ 108,209 $
63,410 $
26,520 $ 8,446 $
9,833
The excluded costs will be included in the amortization base as properties are evaluated and proved reserves
are established or impairment is determined. The Company expects this process to occur over the next five years.
Capitalized Overhead. General and administrative expense in the Company’s financial statements is reflected
net of capitalized overhead. The Company capitalizes overhead costs that are directly related to exploration,
acquisition and development activities. Capitalized overhead for the years ended December 31, 2018, 2017 and
2016 was $21.9 million, $13.7 million and $12.5 million, respectively.
Asset Retirement Obligations. The Company has obligations associated with the retirement of its oil and
natural gas wells and related infrastructure. The Company has obligations to plug wells when production on those
wells is exhausted, when the Company no longer plans to use them or when the Company abandons them. The
Company accrues a liability with respect to these obligations based on its estimate of the timing and amount to
replace, remove or retire the associated assets.
In estimating the liability associated with its asset retirement obligations, the Company utilizes several
assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services,
estimated timing of when the work will be performed and a projected inflation rate. Changes in estimate in the
table below represent changes to the expected amount and timing of payments to settle its asset retirement
obligations. Typically, these changes result from obtaining new information about the timing of its obligations to
plug and abandon oil and natural gas wells and the costs to do so. After initial recording, the liability is increased
for the passage of time, with the increase being reflected as accretion expense in the Company’s consolidated
statements of operations. If the Company incurs an amount different from the amount accrued for decommissioning
obligations, the Company recognizes the difference as an adjustment to proved properties.
F-18
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The discounted asset retirement obligations included in the consolidated balance sheets in current and non-
current liabilities, and the changes in that liability during each of the years ended December 31, 2018 and 2017
were as follows (in thousands):
Asset retirement obligations at January 1
Fair value of asset retirement obligations acquired(1)
Obligations settled
Accretion expense
Obligations incurred
Changes in estimate
Asset retirement obligations at December 31
Less: Current portion
Long-term portion
Year Ended December 31,
2017
2018
$
$
$
214,733 $
244,766
(112,946)
35,344
358
562
382,817 $
(68,965)
313,852 $
220,049
699
(32,573)
19,295
4,213
3,050
214,733
(39,741)
174,992
(1)
Includes $220.6 million and $23.9 million of asset retirement obligations assumed in the Stone Combination and the Whistler Acquisition,
respectively.
Note 5 — Financial Instruments
The following table presents the carrying amounts and estimated fair values of the Company’s financial
instruments (in thousands):
December 31, 2018
Fair
Value
Carrying
Amount
December 31, 2017
Fair
Value
Carrying
Amount
11.00% Second-Priority Senior Secured Notes – due
April 2022(1)
7.50% Senior Secured Notes – due May 2022
Bank Credit Facility – due May 2022(1)
11.00% Bridge Loans – due April 2022(1)
9.75% Senior Notes – due July 2022(1)
9.75% Senior Notes – due February 2018
LLC Bank Credit Facility - due February 2019(1)
Oil and Natural Gas Derivatives
6,060 $
— $
— $
— $
$ 381,229 $ 362,168 $
$
5,151 $
$ 257,448 $ 265,000 $
$
$
$
$
$
— $
— $
— $
— $
74,923 $
—
—
—
— $ 169,838 $ 172,023
— $ 100,681 $ 102,000
— $
24,977
24,977 $
— $ 402,062 $ 403,000
(66,830)
(66,830) $
74,923 $
(1)
The carrying amounts are net of discount and deferred financing costs.
As of December 31, 2018 and 2017, the carrying amounts of cash and cash equivalents, accounts receivable,
restricted cash and accounts payable approximate their fair values because of the short-term nature of these
instruments.
11.00% Second-Priority Senior Secured Notes – due April 2022. The $390.9 million aggregate principal
amount of 11.00% Senior Secured Notes is reported on the consolidated balance sheet at its carrying value, net of
original issue discount and deferred financing costs, see Note 6 — Debt. The fair value of the 11.00% Senior
Secured Notes is estimated (representing a Level 1 fair value measurement) using quoted secondary market trading
prices.
7.50% Senior Secured Notes – due May 2022. The $6.1 million aggregate principal amount of 7.50% Stone
Senior Notes is reported on the consolidated balance sheet as of December 31, 2018 at its carrying value, see Note
6 — Debt. The fair value of the 7.50% Stone Senior Notes is estimated (representing a Level 1 fair value
measurement) using quoted secondary market trading prices.
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Bank Credit Facility – due May 2022. On May 10, 2018, in connection with the Stone Combination, the
Talos Energy LLC senior reserve-based revolving credit facility (“LLC Bank Credit Facility”) was repaid and
terminated, and the Company executed a new Bank Credit Facility with an initial borrowing base of $600.0 million
(the “Bank Credit Facility”). The LLC Bank Credit Facility was repaid with borrowings from the Bank Credit
Facility and cash acquired in the Stone Combination. The Company’s Bank Credit Facility is reported on the
consolidated balance sheet as of December 31, 2018 at its carrying value net of deferred financing costs, see Note 6
— Debt. The fair value of the Bank Credit Facility is estimated based on the outstanding borrowings under the
Company’s Bank Credit Facility since it is secured by the Company’s reserves and the interest rates are variable
and reflective of market rates (representing a Level 2 fair value measurement).
Oil and natural gas derivatives. The Company attempts to mitigate a portion of its commodity price risk and
stabilize cash flows associated with sales of oil and natural gas production through the use of oil and natural gas
swaps and costless collars. Swaps are contracts where the Company either receives or pays depending on whether
the oil or natural gas floating market price is above or below the contracted fixed price. Costless collars consist of a
purchased put option and a sold call option with no net premiums paid to or received from counterparties. Collar
contracts typically require payments by the Company if the NYMEX average closing price is above the ceiling
price or payments to the Company if the NYMEX average closing price is below the floor price.
The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly,
commodity derivatives are recorded on the consolidated balance sheet at fair value with settlements of such
contracts, and changes in the unrealized fair value, recorded as price risk management activities income (expense)
on the consolidated statements of operations in each period.
The following table presents the impact that derivatives, not qualifying as hedging instruments, had on its
consolidated statements of operations (in thousands):
Price risk management activities income (expense)(1)
$
60,435 $
2018
2017
(27,563) $
2016
(57,398)
Year Ended December 31,
(1)
The Company paid cash settlements of $111.1 million, and received cash settlements of $23.8 million and $172.2 million for the years
ended December 31, 2018, 2017 and 2016, respectively.
The following table reflects the contracted volumes and weighted average prices the Company will receive
under its derivative contracts as of December 31, 2018:
Production Period
Crude Oil – WTI:
January 2019 – December 2019
Natural Gas – Henry Hub NYMEX:
January 2019 – December 2019
January 2019 – December 2019
Instrument
Type
Swap
Collar
Swaps
Weighted
Average
Put Price
(per Bbl)
Weighted
Average
Swap Price
(per Bbl)
Average
Daily
Volumes
(Bbls)
25,059 $
—
(MMBtu) (per MMBtu) (per MMBtu) (per MMBtu)
3.95
—
Weighted
Average
Call Price
(per Bbl)
8,630 $
21,872 $
3.00 $
— $
— $
2.90 $
55.39 $
— $
Subsequent event. The following table reflects the contracted volumes and weighted average prices the
Company will receive under its derivative contracts entered into subsequent to December 31, 2018, which are not
reflected in the table above:
Production Period
Crude Oil – WTI:
April 2019 – December 2019
January 2020 - December 2020
January 2020 - December 2020
Natural Gas – Henry Hub NYMEX:
April 2019 – December 2019
6696_10K.pdf
Instrument
Type
Average
Daily
Volumes
(Bbls)
Weighted
Average
Swap Price
(per Bbl)
Weighted
Average
Put Price
(per Bbl)
Weighted
Average
Call Price
(per Bbl)
3,444 $
3,746 $
3,000 $
56.94 $
57.07 $
55.00 $
—
—
60.64
(MMBtu) (per MMBtu) (per MMBtu) (per MMBtu)
—
19,418 $
— $
— $
55.00 $
2.89 $
— $
Swap
Swap
Collar
Swap
F-20
The following tables provide additional information related to financial instruments measured at fair value on
a recurring basis (in thousands):
Assets:
Oil and natural gas swaps and costless collars
Liabilities:
Oil and natural gas swaps and costless collars
Total net asset
Assets:
Oil and natural gas swaps and costless collars
Liabilities:
Oil and natural gas swaps and costless collars
Total net liability
December 31, 2018
Level 1
Level 2
Level 3
Total
—
$
75,473
$
—
$
75,473
—
—
$
(550)
$
74,923
—
—
$
(550)
74,923
December 31, 2017
Level 1
Level 2
Level 3
Total
— $
1,908 $
— $
1,908
—
— $
(68,738)
(66,830) $
—
— $
(68,738)
(66,830)
$
$
$
$
Financial Statement Presentation. Derivatives are classified as either current or non-current assets or
liabilities based on their anticipated settlement dates. Although the Company has master netting arrangements with
its counterparties, the Company present its derivative financial instruments on a gross basis in its consolidated
balance sheets. On derivative contracts recorded as assets in the table below, the Company is exposed to the risk
the counterparties may not perform. The following table presents the fair value of derivative financial instruments
at December 31, 2018 and 2017 (in thousands):
Oil and natural gas derivatives:
Current
Non-current
Total
December 31, 2018
December 31, 2017
Assets
Liabilities
Assets
Liabilities
$
$
75,473 $
—
75,473 $
550 $
—
550 $
1,563 $
345
1,908 $
49,957
18,781
68,738
Credit Risk. The Company is subject to the risk of loss on its financial instruments as a result of
nonperformance by counterparties pursuant to the terms of their contractual obligations. The Company entered into
International Swaps and Derivative Association agreements with counterparties to mitigate this risk. The Company
also maintains credit policies with regard to its counterparties to minimize overall credit risk. These policies require
(i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the
regular monitoring of counterparties’ credit exposures; (iii) the use of contract language that affords the Company
netting or set off opportunities to mitigate exposure risk; and (iv) potentially requiring counterparties to post cash
collateral, parent guarantees or letters of credit to minimize credit risk. The Company’s assets and liabilities from
commodity price risk management activities at December 31, 2018 represent derivative instruments from nine
counterparties; all of which are registered swap dealers that have an “investment grade” (minimum Standard &
Poor’s rating of BBB- or better) credit rating, and seven of which are parties under the Company’s Bank Credit
Facility. The Company enters into derivatives directly with these counterparties and, subject to the terms of the
Company’s Bank Credit Facility, is not required to post collateral or other securities for credit risk in relation to the
derivative activities.
F-21
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Note 6 — Debt
A summary of the detail comprising the Company’s debt and the related book values for the respective
periods presented is as follows (in thousands):
$
Description
11.00% Second-Priority Senior Secured Notes – due April 2022
7.50% Senior Secured Notes – due May 2022
Bank Credit Facility – due May 2022
4.20% Building Loan – due November 2030
11.00% Bridge Loans – due April 2022
9.75% Senior Notes – due July 2022
9.75% Senior Notes – due February 2018
LLC Bank Credit Facility – due February 2019
Total debt, before discount and deferred financing cost
Discount and deferred financing cost
Total debt, net of discount and deferred financing costs
Less: Current portion of long-term debt
Long-term debt, net of discount and deferred financing costs
$
December 31,
2018
December 31,
2017
390,868 $
6,060
265,000
10,567
—
—
—
—
672,495
(17,191)
655,304
(443)
654,861 $
—
—
—
—
172,023
102,000
24,977
403,000
702,000
(4,442)
697,558
(24,977)
672,581
In connection with the Stone Combination, the Company consummated the Transactions, pursuant to which
(i) the Apollo Funds and Riverstone Funds contributed $102.0 million in aggregate principal amount of 9.75%
Senior Notes to the Company in exchange for Common Stock; (ii) the holders of 11.00% Bridge Loans exchanged
such 11.00% Bridge Loans for $172.0 million aggregate principal amount of 11.00% Senior Secured Notes and
(iii) Franklin Noteholders and MacKay Noteholders exchanged their 7.50% Stone Senior Notes for $137.4 million
aggregate principal amount of 11.00% Senior Secured Notes. An additional $81.5 million of 7.50% Stone Senior
Notes held by non-affiliates were also exchanged for 11.00% Senior Secured Notes pursuant to an exchange offer
and consent solicitation in connection with the Stone Combination.
The exchanges to 11.00% Senior Secured Notes were accounted for as a debt modification. Under a debt
modification, a new effective interest rate that equates the revised cash flows to the carrying amount of the 11.00%
Senior Secured Notes is computed and applied prospectively. Costs incurred with third parties directly related to
the modification are expensed as incurred. The Company incurred approximately $4.3 million of transaction fees
related to the modification which were expensed and reflected in general and administrative expense on the
consolidated statements of operations during the year ended December 31, 2018. The Company also paid $9.3
million in work fees to holders of the 11.00% Senior Secured Notes, which are reflected as debt discount reducing
long-term debt on the consolidated balance sheet.
11.00% Second-Priority Senior Secured Notes – due April 2022. The 11.00% Senior Secured Notes were
issued pursuant to an indenture dated May 10, 2018, between the Talos Issuers, the subsidiary guarantors party
thereto and Wilmington Trust, National Association, as trustee and collateral agent. The 11.00% Senior Secured
Notes mature April 3, 2022 and have interest payable semi-annually each April 15 and October 15. Prior to May
10, 2019, the Company may, at its option, redeem all or a portion of the 11.00% Senior Secured Notes at 100% of
the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, the Company may
redeem all or a portion of the 11.00% Senior Secured Notes at redemption prices decreasing annually from 105.5%
to 100.0% plus accrued and unpaid interest.
The indenture governing the 11.00% Senior Secured Notes applies certain limitations on the Company’s
ability and the ability of its subsidiaries to, among other things, (i) incur additional indebtedness or issue certain
preferred shares; (ii) pay dividends and make certain other restricted payments; (iii) create restrictions on the
payment of dividends or other distributions to the Company from its restricted subsidiaries; (iv) create liens on
certain assets to secure debt; (v) make certain investments; (vi) engage in sales of assets and subsidiary stock; (vii)
transfer all or substantially all of its assets or enter into merger or consolidation transactions; and (viii) engage in
transactions with affiliates. The 11.00% Senior Secured Notes contain customary quarterly and annual reporting,
financial and administrative covenants. The Company was in compliance with all debt covenants at December 31,
2018.
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7.50% Senior Secured Notes – due May 2022. The 7.50% Stone Senior Notes represent the remaining $6.1
million of long-term debt assumed in the Stone Combination that were not exchanged for 11.00% Senior Secured
Notes pursuant to the Exchange Offer and Consent Solicitation, and thus remain outstanding. As a result of the
exchange offer and consent solicitation, substantially all of the restrictive covenants relating to the 7.50% Stone
Senior Notes have been removed and collateral securing the 7.50% Stone Senior Notes has been released. The
7.50% Stone Senior Notes mature May 31, 2022 and have interest payable semi-annually each May 31 and
November 30. Prior to May 31, 2020, the Company may, at its option, redeem all or a portion of the 7.50% Stone
Senior Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium.
Thereafter, the Company may redeem all or a portion of the 7.50% Stone Senior Notes at redemption prices
decreasing annually from 105.625% to 100.0% plus accrued and unpaid interest.
Bank Credit Facility – due May 2022. Talos Production LLC, a subsidiary of the Company, executed the
Bank Credit Facility in conjunction with the Stone Combination with a syndicate of financial institutions, with an
initial borrowing base of $600.0 million. The Bank Credit Facility is currently scheduled to mature on May 10,
2022.
The Bank Credit Facility bears interest based on the borrowing base usage, at the applicable London
InterBank Offered Rate, plus applicable margins ranging from 2.75% to 3.75% or an alternate base rate, based on
the federal funds effective rate plus applicable margins ranging from 1.75% to 2.75%. In addition, the Company is
obligated to pay a commitment fee of 0.50% on the unfunded portion of the commitments under the Bank Credit
Facility. The Bank Credit Facility has certain debt covenants, the most restrictive of which is that the Company
must maintain a total debt to EBITDAX Ratio (as defined in the Bank Credit Facility) of no greater than 3.00 to
1.00 each quarter. The Company must also maintain a current ratio no less than 1.00 to 1.00 each quarter.
According to the Bank Credit Facility, undrawn commitments are included in current assets in the current ratio
calculation. The Bank Credit Facility is secured by substantially all of the oil and natural gas assets of the
Company. The Bank Credit Facility is fully and unconditionally guaranteed by the Company and certain of its
wholly-owned subsidiaries.
The Bank Credit Facility provides for determination of the borrowing base based on the Company’s proved
producing reserves and a portion of its proved undeveloped reserves. The borrowing base is redetermined by the
lenders at least semi-annually during the second quarter and fourth quarter. On November 16, 2018 the borrowing
base was increased from $600.0 million to $850.0 million. However, the Company elected to maintain the $600.0
million commitment based upon its current liquidity needs. The next redetermination is scheduled for April 2019.
As of December 31, 2018, commitments under the Company’s borrowing base was set at $600.0 million, of
which no more than $200.0 million can be used as letters of credit. The amount the Company is able to borrow with
respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the
Bank Credit Facility. The Company was in compliance with all debt covenants at December 31, 2018. As of
December 31, 2018, the Bank Credit Facility had approximately $320.3 million of undrawn commitments (taking
into account $14.7 million letters of credit and $265.0 million drawn from the Bank Credit Facility).
Building Loan – due November 2030. In connection with the Stone Combination, the Company assumed
Stone’s 4.20% term loan maturing on November 20, 2030 (the “Building Loan”). The Building Loan bears interest
at a rate of 4.20% per annum and is to be repaid in 180 equal monthly installments of approximately $0.1 million.
As of December 31, 2018, the outstanding balance under the Building Loan totaled $10.6 million. The Building
Loan is collateralized by the Company’s two office buildings in Lafayette, Louisiana. Under the financial
covenants of the Building Loan, the Company must maintain a ratio of EBITDA to Net Interest Expense of not less
than 2.00 to 1.00. In addition, the Building Loan contains certain customary restrictions or requirements with
respect to change of control and reporting responsibilities. The Company was in compliance with all covenants
under the Building Loan as of December 31, 2018.
9.75% Senior Notes – due February 2018. The 2018 Senior Notes were issued pursuant to an indenture dated
February 6, 2013 among the Talos Issuers, the subsidiaries, as issuers, the subsidiary guarantors party thereto and
the trustee. On February 15, 2018, the Talos Issuers redeemed the remaining $25.0 million principal amount of the
9.75% Senior Notes at par.
Subsequent Event. On January 22, 2019, the Company borrowed $35.0 million from the Bank Credit Facility
to fund 2019 acquisition activities, see Note 15 — Subsequent Events.
F-23
6696_10K.pdf
Note 7 — Employee Benefits Plans and Share-Based Compensation
Stone Change of Control and Severance Plans
The Company maintains the Stone Energy Corporation Executive Severance Plan and Stone Energy
Corporation Employee Severance Plan, each a legacy plan of Talos Petroleum LLC (f/k/a Stone Energy
Corporation). The plans provide for the payment of severance and change in control benefits to certain individuals
who, prior to the Stone Combination, were executive officers or employees of Talos Petroleum LLC, in each case
upon an involuntary termination within twelve months of Closing. For the year ended December 31, 2018 the
Company incurred $7.8 million of severance expense, reflected in general and administrative expense on the
consolidated statement of operations. Approximately $0.3 million of such expense remained unpaid at
December 31, 2018.
Talos Energy Inc. Long Term Incentive Plan
In connection with the Closing, the Company adopted the Talos Energy Inc. Long Term Incentive Plan (the
“LTIP”), pursuant to which the Company may issue, subject to Board approval, grants of options, stock
appreciation rights, restricted stock, restricted stock units, stock awards, dividend equivalents, other stock-based
awards, cash awards, substitute awards or any combination of the foregoing to employees, directors and
consultants. The LTIP authorizes the Company to grant awards of up to 5,415,576 shares of the Company’s
Common Stock.
Restricted Stock Units – Employees. During the year ended December 31, 2018, the Company granted
116,448 RSUs under the LTIP to employees. These RSUs had a grant date fair value of $3.9 million and vest
ratably over an approximate three year period, which began on May 14, 2018, subject to such employee’s
continued service through each vesting date. Upon vesting, each RSU represents a contingent right to receive one
share of Common Stock. The total unrecognized share-based compensation expense related to these RSUs at
December 31, 2018 was approximately $3.3 million, which is expected to be recognized over a weighted average
period of 2.4 years.
Restricted Stock Units – Non-employee Directors. On May 21, 2018, the Company granted 22,963 RSUs
under the LTIP to non-employee directors. These RSUs had a grant date fair value of $0.8 million and vest on May
19, 2019, subject to such non-employee director’s continued service through the vesting date. Upon vesting, these
RSUs represent a contingent right to receive one share of Common Stock for each RSU for 60% or 13,778 of these
RSUs, and cash for the remaining 40% or 9,185 of these RSUs. The total unrecognized share-based compensation
expense related to these RSUs at December 31, 2018 was approximately $0.2 million, which is expected to be
recognized over a weighted average period of 0.4 years. Of the unrecognized share-based compensation expense,
$0.1 million relates to liability awards and will be subsequently remeasured at each reporting period.
The following table summarizes RSU activity for the year ended December 31, 2018:
Unvested RSUs at December 31, 2017
Granted
Vested
Forfeited
Unvested RSUs at December 31, 2018
Restricted Stock
Units
Weighted Average
Grant Date Fair
Value
— $
139,411
(53)
(654)
138,704 $
—
33.85
32.86
32.86
33.85
Performance Share Units – Employees. During the year ended December 31, 2018, the Company granted
232,891 PSUs to employees with each PSU representing the contingent right to receive one share of Common
Stock. However, the number of Common Stock shares issuable upon vesting ranges from zero to 200% of the
number of PSUs granted based on the total shareholder return (“TSR”) of the Common Stock relative to the TSR
achieved by a specific industry peer group over an approximate three-year performance period, the last day of
which is also the vesting date. The total unrecognized share-based compensation expense related to these PSUs at
December 31, 2018 was approximately $9.2 million, which is expected to be recognized over a weighted average
period of 2.4 years.
F-24
6696_10K.pdf
The following table summarizes PSU activity for the year ended December 31, 2018:
Unvested PSUs at December 31, 2017
Granted
Vested
Forfeited
Unvested PSUs at December 31, 2018
Performance
Share
Units
Weighted Average
Grant Date Fair
Value
— $
232,891
—
(1,349)
231,542 $
—
44.47
—
42.94
44.47
The grant date fair value of the PSUs, calculated using a Monte Carlo simulation, was $10.4 million. The
following table summarizes the assumptions used to calculate the grant date fair value of the PSUs granted August
29, 2018 and September 28, 2018:
Number of simulations
Expected term (in years)
Expected volatility
Risk-free interest rate
Dividend yield
Talos Energy LLC Series B Units
August 29, 2018
Grant Date Fair
Value
Assumptions
September 28, 2018
Grant Date Fair
Value
Assumptions
100,000
2.7
50.6%
2.7%
—%
100,000
2.6
47.4%
2.9%
—%
Prior to the Stone Combination, the Limited Liability Company Agreement of Talos Energy LLC established
Series A, Series B and Series C Units. Series B Units were generally intended to be used as incentives for
Company employees. Series B Units do not participate in distributions prior to vesting or until Series A Units have
received cumulative distributions equal to (i) the original cash contributed to the Company for such Series A Units
and (ii) an 8% return, compounded annually (the “Aggregate Series A Payout”), and Series C Units have received
$25.0 million in distributions. In connection with the Transactions, the Series A, Series B and Series C Units were
exchanged for an equivalent number of units in each of an entity affiliated with the Apollo Funds and an entity
affiliated with the Riverstone Funds, each of which hold Common Stock of the Company. The modification did not
result in incremental value to the Series B Units.
For accounting and financial reporting purposes, the Series B Units are deemed to be equity awards, and the
compensation expense related to these awards is recorded on a straight-line basis over the vesting period in the
Company’s consolidated financial statements and is reflected as a corresponding credit to accumulated deficit on
the consolidated balance sheet.
The Company’s unrecognized compensation expense at December 31, 2018 is approximately $2.7 million.
Of this amount, approximately $0.5 million of the unrecognized compensation expense will continue to be
recognized on a straight-line basis over the remainder of the four year requisite service period. The remaining
$2.2 million will be recognized upon an Aggregate Series A Payout. The weighted-average period over which the
unrecognized compensation expense for the Series B Units will be recognized is 1.7 years.
New Talos Energy LLC Series B Units
In connection with the transactions contemplated in the Exchange Agreement on May 10, 2018, an entity
affiliated with the Apollo Funds and an entity affiliated with the Riverstone Funds, each of which hold Common
Stock in the Company as a result of the Sponsor Debt Exchange, established new Series A Units (“New Series A
Units”) and new Series B Units (“New Series B Units”). The New Series B Units are generally intended to be used
as incentives for Company employees.
The New Series B Units do not participate in distributions prior to vesting or until the New Series A Units
have received cumulative distributions of $102.0 million. After issuance, 80% of the New Series B Units vest on a
monthly basis over a four year period based on the initial vesting schedule of the original Series B Units, subject to
continued employment. All unvested New Series B Units fully vest upon the cumulative distribution of $102.0
million.
F-25
6696_10K.pdf
For accounting and financial reporting purposes, the New Series B Units are deemed to be equity awards, and
the compensation expense related to these awards is recorded on a straight-line basis over the vesting period in the
Company’s consolidated financial statements and is reflected as a corresponding credit to accumulated deficit on
the consolidated balance sheet.
The New Series B Units issued were valued using the option pricing method for valuing securities. In this
method, the rights and claims of each security are modeled as a portfolio of Black-Scholes-Merton call options
written on the total equity of the entities affiliated with the Apollo Funds and Riverstone Funds. The total value of
the equity is calculated in an iterative process that results in the New Series A Units being valued at par. The risk-
free rate of interest is based on the U.S. Treasury yield curve on the grant date. The expected time to a liquidity
event is based on a weighted average calculation of management’s estimate considering market conditions and
expectations. The expected volatility of equity is based on the volatility of the assets of similar publicly traded
companies using a Black-Scholes-Merton model. The discount for lack of marketability is based on the restrictions
on the New Series B Units and the volatility of the New Series B Units using a Black-Scholes-Merton model.
The Company’s unrecognized compensation expense at December 31, 2018 is approximately $1.2 million.
Of this amount, approximately $0.2 million of the unrecognized compensation expense will continue to be
recognized on a straight-line basis over the remainder of the four year requisite service period. The remaining
$1.0 million will be recognized upon the New Series A Units receiving the cumulative distribution. The weighted-
average period over which the unrecognized compensation expense will be recognized is 0.8 months.
Share-based Compensation Expense, net
Share-based compensation expense associated with RSUs, PSUs and Series B Units are reflected as general
administrative expense, net amounts capitalized to oil and gas properties in the consolidated statement of
operations. Because of the non-cash nature of share-based compensation, the expensed portion of share-based
compensation is added back to net income in arriving at net cash used in or provided by operating activities in the
consolidated statement of cash flows.
For the year ended December 31, 2018, share-based compensation expense did not have any associated
income tax benefit. The Company recognized the following share-based compensation expense, net for the
following years (in thousands):
Restricted stock units - Employees
Restricted stock units - Non-employee Directors
Performance share units
Talos Energy LLC Series B Units
New Talos Energy LLC Series B Units
Total share-based compensation expense
Less: amounts capitalized to oil and gas properties
Total share-based compensation expense, net
Note 8 — Income Taxes
Year Ended December 31,
2018
2017
2016
$
$
560 $
402
1,129
666
3,752
6,509
(3,616)
2,893 $
— $
—
—
1,795
—
1,795
(920)
875 $
—
—
—
2,287
—
2,287
(1,204)
1,083
Prior to the Stone Combination, Talos Energy LLC was a partnership for U.S. federal income tax purposes
and was not subject to U.S. federal income tax or state income tax (in most states) at the entity level. As such,
Talos Energy LLC did not recognize U.S. federal income tax expense or state income tax expense in most states.
Talos Energy LLC’s operations in the shallow waters off the coast of Mexico were conducted under a different
legal form and are subject to foreign income taxes.
In connection with the Stone Combination, Talos Energy LLC was contributed to the Company, which is
subject to federal and state income taxes. The Company is also subject to foreign income taxes. Due to the change
in tax status, deferred taxes are recorded for differences in book and tax basis. The Company’s differences in its
book and tax basis in its assets and liabilities is primarily related to different cost recovery periods utilized for book
and tax purposes for the Company’s oil and natural gas properties, asset retirement obligations and net operating
loss carryforwards. A valuation allowance is established to reduce deferred tax assets when it is more likely than
not that some portion or all of the deferred tax asset will not be realized. The Company believes it is more likely
F-26
6696_10K.pdf
than not that the net federal deferred tax asset will not be realized and therefore recorded a valuation allowance.
Due to the valuation allowance, the tax expense resulting from the initial book and tax basis difference from the
change in tax status was zero. The Company accounted for the book and tax basis difference from the Stone
Combination in acquisition method accounting and recorded an estimated state deferred tax liability of $2.7
million.
As part of the Stone Combination, entities related to the Apollo Funds and Riverstone Funds contributed
entities to the Company that were under common control. At December 31, 2018, the Company also estimated a
net deferred tax asset related to tax loss carryforwards and differences in book and tax basis of assets. The net
deferred tax asset and valuation allowance from the contribution is accounted for in stockholder’s equity. The
Company believes it is more likely than not that the net deferred tax asset will not be realized and therefore
recorded a valuation allowance.
As a result of the Stone Combination, the Company acquired a current income tax receivable of $10.7 million
primarily related to the carryback of specified liability losses.
Tax Cuts and Jobs Act. On December 22, 2017, the President signed into law Public Law No. 115-97 (“Tax
Act”), an Act to provide for reconciliation pursuant to titles II and V of the concurrent resolution on the budget for
fiscal year 2018. The Tax Act made broad and complex changes to the U.S. tax code. The SEC issued SAB 118,
which has since been codified into ASC 740, providing guidance on the accounting for the tax effects of the Tax
Act. ASC 740 provides a measurement period that should not extend beyond one year from the Tax Act enactment
date to complete the accounting under ASC 740. In accordance with this pronouncement, the Company completed
its assessment on certain effects of the Tax Act in the financial statements for the period ending December 31,
2018. In assessing the need for a valuation allowance on its deferred tax assets, the Company considered whether it
was more likely than not that some portion or all of them will not be realized. Due to a full valuation allowance
against the Company’s deferred tax assets, the adjustments did not have any net impact on tax expense for 2018.
The components of income tax expense (benefit) were as follows (in thousands):
Current income tax expense (benefit)
United States
Mexico
Total current income tax expense (benefit)
Deferred income tax expense (benefit)
United States
Mexico
Total deferred income tax expense (benefit)
Total income tax expense (benefit)
Year Ended December 31,
2017
2016
2018
$
$
$
$
— $
1,345
1,345 $
1,064 $
513
1,577
2,922 $
— $
—
— $
— $
—
—
— $
—
—
—
—
—
—
—
The reconciliation of income taxes computed at the U.S. federal statutory tax rate to the Company’s income
tax expense is as follows (in thousands, except percentages):
Year Ended December 31,
2017
(22,004) $
22,004
—
—
—
—
—
—
2018
$
47,137
9,980
11,738
1,008
432
417
800
(35,925)
(32,665)
$
2,922
1.30%
2016
(72,830)
72,830
—
—
—
—
—
—
$
—
—%
—
—%
Income tax (benefit) at the federal statutory tax rate
$
Earnings not subject to tax
State income taxes
Foreign income taxes
Foreign rate differential
Prior year taxes
Other adjustments
Change in tax status
Change in valuation allowance
Total income tax
Effective tax rate
6696_10K.pdf
$
F-27
The Company’s effective tax rate for the year ending December 31, 2018, differed from the federal statutory
rate of 21.0% primarily due to recording a valuation allowance for its deferred tax assets. The effective tax rate for
years 2017 and 2016 differed from the federal statutory rate of 35.0% because the Company was not subject to U.S.
federal or state taxation as a partnership and the Company’s Mexico operations did not incur a material income tax
expense.
Deferred Tax Assets and Liabilities
Deferred taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and
liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components
of deferred tax assets and liabilities were as follows (in thousands):
Deferred tax assets:
Federal net operating loss
Foreign tax loss carryforward
State net operating loss
Asset retirement obligations
Tax credits
Interest
Other
Total deferred tax assets
Valuation allowance
Total deferred tax assets, net
Deferred tax liabilities
Oil and gas properties
Hedges
Prepaid
Deferred tax liabilities
Net deferred tax asset (liability)
Year Ended December 31,
2017
2018
$
$
$
117,546 $
2,303
23,542
95,546
12
33,867
5,909
278,725
(94,085)
184,640 $
166,879
18,246
3,371
188,496
(3,856) $
—
4,023
—
—
—
—
—
4,023
(4,007)
16
—
—
—
—
16
Income Tax Receivables and Payables
As of December 31, 2018, the Company recorded current income tax receivables of $10.7 million. As a result
of the Stone Combination, the Company acquired the current income tax receivable primarily related to the
carryback of specified liability losses. The Company has also recorded an income tax payable of $1.3 million
primarily related to estimated taxes for the 2018 Mexico tax returns.
Net Operating Loss
The table below presents the details of the Company’s net operating loss and tax credit carryovers as of
December 31, 2018 (in thousands):
Federal net operating losses
Foreign tax loss carryforward
State net operating losses
Amount
Expiration Year
$
$
$
557,895
8,970
307,629
2034-2038
2025-2028
2019-2038
As of December, 31, 2018, the Company had U.S. federal net operating loss carryforwards (“NOLs”) of
approximately $557.9 million, of which $538.4 million is subject to limitation under Section 382 of the Internal
Revenue Code (“IRC”). IRC Section 382 provides an annual limitation with respect to the ability of a corporation
to utilize its tax attributes, against future U.S. taxable income in the event of a change in ownership. If not utilized,
such carryforwards would begin to expire in 2034.
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6696_10K.pdf
Valuation Allowance
During 2018, the Company recorded a valuation allowance of $94.1 million related to federal, state and
foreign deferred tax assets. Deferred tax assets are recorded related to net operating losses and temporary
differences between the book and tax basis of assets and liabilities expected to produce tax deductions in future
periods. The realization of these assets depends on recognition of sufficient future taxable income in specific tax
jurisdictions in which those temporary differences or net operating losses are deductible. In assessing the need for a
valuation allowance on deferred tax assets, the Company considers whether it is more likely than not that some
portion or all of them will not be realized. As of December 31, 2018, the Company had a valuation allowance
related to federal, state and foreign deferred tax assets. The Company did not record a valuation allowance during
2017 for federal and state deferred tax assets as the Company was not subject to taxation as a partnership during
this period.
Uncertain Tax Positions
The table below sets forth the beginning and ending balance of the total amount of unrecognized tax benefits.
There are no unrecognized benefits that would impact the effective tax rate if recognized. While amounts could
change in the next 12 months, the Company does not anticipate having a material impact on its financial
statements.
Balances in the uncertain tax positions are as follows (in thousands):
Total unrecognized tax benefits, beginning balance
Increases (decreases) in unrecognized tax benefits as a result of:
Tax positions taken during a prior period
Tax positions taken during the current period
Settlements with taxing authorities
Lapse of applicable statute of limitations
Total unrecognized tax benefits, ending balance
Year Ended December 31,
2017
2018
$
— $
360
—
—
—
360 $
$
—
—
—
—
—
—
The Company recognizes interest and penalties related to uncertain tax positions as interest expense and
general and administrative expenses, respectively.
Years open to examination
The 2015 through 2017 tax years remain open to examination by the tax jurisdictions in which the Company
is subject to tax. The statute of limitations with respect to the U.S. federal income tax returns of the Company for
years ending on or before December 31, 2014 are closed.
Note 9 — Earnings Per Share
Basic earnings per common share is computed by dividing net income (loss) by the weighted average number
of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted
earnings per common share includes the impact of RSUs, PSUs and outstanding warrants.
As of December 31, 2018, the Company had approximately 3.5 million outstanding warrants. These
warrants have an exercise price of $42.04 per share and a term of four years ending February 28, 2021. As of
December 31, 2018, the Company had 138,704 and 231,542 outstanding RSUs and PSUs, respectively, which
settle in shares of Common Stock.
For the year ended December 31, 2018, dilutive weighted average shares for RSUs and PSUs totaled 2,819
shares resulting in an increase to the basic weighted average common shares of 46,058,216 to arrive at diluted
weighted average common shares outstanding of 46,061,035. For the year ended December 31, 2018, 419,639
weighted average antidilutive RSUs and PSUs were excluded from the computation of diluted earnings per
common share. Additionally, for the year ended December 31, 2018, all outstanding warrants were considered
antidilutive due to the exercise price of the warrants exceeding the average market price of Common Stock.
F-29
6696_10K.pdf
For the periods prior to May 10, 2018, the Company retrospectively adjusted the weighted average shares
used in determining earnings per share to reflect the number of shares Talos Energy LLC received in the Stone
Combination. There is no impact in fiscal year 2017 and 2016 on diluted earnings per common share from the
RSUs, PSUs and outstanding warrants as these instruments did not exist throughout such periods.
Note 10 — Related Party Transactions
Whistler Acquisition. On August 31, 2018, the Company acquired Whistler from Whistler Energy II Holdco,
LLC, an affiliate of the Apollo Funds, for $52.6 million ($14.8 million, net of $37.8 million of cash acquired).
Included in current assets acquired as of December 31, 2018 is $1.1 million in receivables from an affiliate of the
Apollo Funds to reimburse the Company for certain payments made post closing. See additional details in Note 3 –
Acquisitions.
Equity Registration Rights Agreement. On the Closing Date, the Company entered into an Equity
Registration Rights Agreement with each of the Apollo Funds, Riverstone Funds, Franklin and MacKay Shields
relating to the registered resale of its Common Stock owned by such parties as of Closing. The Company will bear
all of the expenses incurred in connection with the offer and sale, while the Apollo Funds, Riverstone Funds,
Franklin and MacKay Shields are responsible for paying underwriting fees, discounts and commissions or similar
charges. Fees incurred by the Company in conjunction with the Equity Registration Rights Agreement were $1.8
million for the year ended December 31, 2018.
Legal Fees. The Company has engaged the law firm Vinson & Elkins L.L.P. to provide legal services. An
immediate family member of William S. Moss III, the Company’s Executive Vice President and General Counsel
and one of its executive officers, is a partner at Vinson & Elkins L.L.P. For the year ended December 31, 2018,
2017 and 2016, the Company incurred fees of approximately $4.4 million, $4.0 million and $0.7 million,
respectively, of which $1.1 million, $4.0 million and $0.1 million were payable at each respective balance sheet
date for legal services performed by Vinson & Elkins L.L.P.
Contributions and Distributions. During the years ended December 31, 2018 and 2017, the Company did
not receive any cash contributions or make any distributions to Apollo Funds and Riverstone Funds. During the
year ended December 31, 2016, the Company received a $93.8 million ($91.9 million net of $1.9 million of
transaction fees) capital contribution from Apollo Funds and Riverstone Funds primarily to fund the Sojitz
Acquisition. See Note 3 — Acquisitions for further details.
Transaction Fee Agreement. As part of the agreements with Apollo Funds and Riverstone Funds, the
Company paid a transaction fee equal to 2% of capital contributions made by Apollo Funds and Riverstone Funds.
For the years ended December 31, 2018 and 2017, there were no capital contributions and thus the Company did
not incur or pay transaction fees related to capital contributions. For the year ended December 31, 2016 the
Company incurred fees totaling $1.9 million related to the capital contributions received from Apollo Funds and
Riverstone Funds. In connection with the Stone Combination, the Transaction Fee Agreement was terminated on
May 10, 2018.
Service Fee Agreement. The Company entered into service fee agreements with Apollo Funds and
Riverstone Funds for the provision of certain management consulting and advisory services. Under each
agreement, the Company paid a fee equal to the higher of (i) a certain percentage of earnings before interest,
income taxes, depletion, depreciation and amortization and (ii) a fixed fee payable quarterly, provided, however,
such fees did not exceed in each case $0.5 million, in aggregate, for any calendar year. For the year ended
December 31, 2018, 2017 and 2016, the Company incurred approximately $0.5 million, $0.5 million and $0.5
million, respectively, for these services. These fees are recognized in general and administrative expense on the
consolidated statements of operations. In connection with the Stone Combination on May 10, 2018, the Service Fee
Agreement was terminated.
Debt Modification Work Fees. The Company paid $9.3 million in work fees to holders of the 11.00% Bridge
Loans and 7.50% Stone Senior Notes to exchange into 11.00% Senior Secured Notes as a result of the Stone
Combination. The Apollo Funds and Riverstone Funds received $4.1 million and the Franklin Noteholders and
McKay Noteholders received $3.3 million as a result of the work fees paid.
F-30
6696_10K.pdf
Note 11 — Commitments and Contingencies
Capital Lease
On August 2, 2016, the Company executed a seven-year lease agreement (the “Agreement”), effective June
1, 2016, with Helix for use of the HP-I to process hydrocarbons produced from the Phoenix Field. Under the terms
of the Agreement, the Company paid Helix a $49.0 annual fixed demand charge plus a potential $0.5 million
quarterly incentive payment if certain uptime rates were achieved. Thereafter the Company will pay a $45.0 annual
fixed demand charge plus a potential $0.8 million quarterly incentive payment if certain uptime rates are achieved.
The Agreement with Helix is accounted for as a capital lease. The Company initially recorded both a capital
lease asset and obligation of $124.3 million on its consolidated balance sheet. As of December 31, 2018, the
balance of the capital lease obligation on the consolidated balance sheet is $93.6 million, of which $14.1 million is
included in other current liabilities and $79.5 million is included in other long-term liabilities. As a result of the
Agreement being accounted for as a capital lease, the lease payments are reflected as (i) a reduction of the capital
lease obligation, (ii) interest expense and (iii) direct lease operating expense.
As of December 31, 2018, minimum lease commitments for the capital lease in future years are as follows (in
thousands):
2019
2020
2021
2022
2023
Total minimum lease payments
Less amount represented lease operating expenses
Less amount represented interest
Present value of minimum lease payments
Less current maturities of capital lease obligations
Long-term capital lease obligations
Legal Proceedings and Other Contingencies
$
$
45,000
45,000
45,000
45,000
18,750
198,750
(51,864)
(53,218)
93,668
(14,127)
79,541
On January 6, 2016, Energy Resource Technology GOM, LLC (“ERT”) plead guilty to two violations of the
Clean Water for self-reported activities surrounding overboard discharge sampling and unpermitted discharges and
two violations of Outer Continental Shelf Lands Act. On April 6, 2016, the United States District Court for the
Eastern District of Louisiana accepted ERT’s plea and sentenced ERT, consistent with the plea agreement, to pay a
penalty of $4.2 million which ERT has paid. The Court placed ERT on probation for three years. The conditions of
probation include compliance with an agreed Safety and Environmental Compliance Program. As a result of ERT’s
conviction for violations of the Clean Water Act, ERT was debarred and cannot enter into contracts with or receive
benefits from the federal government, until the EPA reinstates ERT by certifying that ERT has corrected the
conditions giving rise to the Clean Water convictions. EPA also imposed discretionary suspension and proposed
debarment on Talos Production LLC, Talos Energy Offshore LLC and Talos Energy LLC as affiliates of ERT. On
November 23, 2016, EPA terminated and administratively closed the suspension as to each of the three entities
previously suspended. On August 29, 2017, EPA certified that the conditions giving rise to ERT’s conviction were
corrected, and its debarment was lifted.
The Company is named as a party in certain lawsuits and regulatory proceedings arising in the ordinary
course of business. The Company does not expect that these matters, individually or in the aggregate, will have a
material adverse effect on its financial condition.
Performance Obligations
Regulations with respect to offshore operations govern, among other things, engineering and construction
specifications for production facilities, safety procedures, plugging and abandonment of wells, removal of facilities
and to guarantee the execution of the minimum work program under the Mexico production sharing contracts. As
of December 31, 2018 and 2017, the Company had secured performance bonds totaling approximately $644.1
million and $287.8 million, respectively. As of December 31, 2018 and 2017, the Company had $14.7 million and
$4.9 million, respectively, in letters of credit issued under its Bank Credit Facility.
F-31
6696_10K.pdf
The table below summarizes the Company’s total minimum commitments associated with long-term, non-
cancelable operating leases, vessel commitments, purchase obligations and the Mexico minimum work program as
of December 31, 2018 (in thousands):
Vessel Commitments(1)
Committed purchase orders(2)
Operating lease obligations(3)
Mexico minimum work program
Total(4)
2020
2021
2022 Thereafter
Total
2019
— $
$ 35,206 $
15,562 11,921
4,315
— 19,277
— $ 35,206
— $ — $
7,921 —
— 35,404
4,016 4,298 27,225 43,476
— 19,277
$ 54,390 $ 35,513 $ 11,937 $4,298 $ 27,225 $133,363
— —
3,622
(1)
(2)
(3)
(4)
Includes vessel commitments the Company will utilize for certain deep water well intervention and decommissioning activities. These
commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will
be billed for their working interest share of such costs.
Includes committed purchase orders to execute planned future drilling and completion activities as well as seismic use agreements the
Company entered into in connection with the Stone Combination.
Amounts include long-term lease payments for office space.
Excludes the capital lease for the HP-I floating production facility in the Phoenix Field discussed above.
The table above includes leases for buildings, facilities and related equipment with varying expiration dates
through 2029. Total rent expense, for continuing operations, included in general and administrative expense for the
years ended December 31, 2018, 2017 and 2016 was $2.9 million, $2.1 million and $2.0 million, respectively.
Note 12 — Condensed Consolidating Financial Information
Talos Energy Inc. owns no operating assets and has no operations independent of its subsidiaries. Talos
Production LLC and Talos Production Finance Inc. issued 11.00% Second-Priority Senior Secured Notes on May
10, 2018, which are fully and unconditionally guaranteed, jointly and severally, by Talos Energy Inc. and certain
100% owned subsidiaries on a senior unsecured basis.
The following condensed consolidating financial information presents the financial information of the
Company on an unconsolidated stand-alone basis and its combined guarantor and combined non-guarantor
subsidiaries as of and for the period indicated. Such financial information may not necessarily be indicative of the
Company’s results of operations, cash flows, or financial position had these subsidiaries operated as independent
entities.
F-32
6696_10K.pdf
TALOS ENERGY INC.
CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 2018
(In thousands)
Current assets:
ASSETS
Cash and cash equivalents
Restricted cash
Accounts receivable
Trade, net
Joint interest, net
Other
Assets from price risk management activities
Prepaid assets
Income tax receivable
Other current assets
Total current assets
Property and equipment:
Proved properties
Unproved properties, not subject to amortization
Other property and equipment
Total property and equipment
Accumulated depreciation, depletion and
amortization
Total property and equipment, net
Other long-term assets:
Other well equipment inventory
Investments in subsidiaries
Other assets
LIABILITIES AND STOCKHOLDERS' EQUITY
(DEFICIT)
Current liabilities:
Accounts payable
Accrued liabilities
Accrued royalties
Current portion of long-term debt
Current portion of asset retirement obligations
Liabilities from price risk management activities
Accrued interest payable
Other current liabilities
Total current liabilities
Long-term debt, net of discount and deferred financing
costs
Asset retirement obligations
Other long-term liabilities
Total liabilities
Commitments and Contingencies (Note 11)
Stockholders' equity (deficit)
Parent
Subsidiary
Issuers
Guarantors
Guarantors Elimination Consolidated
Non-
$
— $
—
13,541 $
—
100,801 $
1,248
25,572 $
—
— $
—
139,914
1,248
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
3,100
75,473
1,225
—
—
93,339
—
—
20,670
20,670
103,025
15,870
9,566
—
37,639
10,701
7,644
286,494
3,629,430
63,104
12,440
3,704,974
—
4,374
7,020
—
47
—
—
37,013
—
45,105
81
45,186
—
—
—
—
—
—
—
—
103,025
20,244
19,686
75,473
38,911
10,701
7,644
416,846
— 3,629,430
108,209
—
—
33,191
— 3,770,830
(8,310)
12,360
(1,711,288)
1,993,686
(11)
45,175
— (1,719,609)
— 2,051,221
—
1,011,359
—
1,011,359
—
1,560,922
364
1,666,985
9,224
—
2,258
2,291,662
—
—
— (2,572,281)
—
73
9,224
—
2,695
82,261 (2,572,281) 2,479,986
144
—
—
—
—
—
—
144
1,242
4,995
—
—
—
550
10,162
—
16,949
—
—
3,719
3,863
638,677
—
—
655,626
42,736
159,491
38,520
443
68,965
—
38
22,071
332,264
16,184
313,852
119,432
781,732
6,897
24,164
—
—
—
—
—
—
31,061
—
—
208
31,269
—
—
—
—
—
—
—
—
—
51,019
188,650
38,520
443
68,965
550
10,200
22,071
380,418
654,861
—
313,852
—
—
123,359
— 1,472,490
1,007,496
$1,011,359 $1,666,985 $ 2,291,662 $
1,509,930
1,011,359
50,992 (2,572,281) 1,007,496
82,261 $(2,572,281) $ 2,479,986
F-33
6696_10K.pdf
TALOS ENERGY INC.
CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 2017
(In thousands)
Current assets:
ASSETS
Cash and cash equivalents
Restricted cash
Accounts receivable, net
Trade, net
Joint interest, net
Other
Assets from price risk management activities
Prepaid assets
Inventory
Other current assets
Total current assets
Property and equipment:
Proved properties
Unproved properties, not subject to
amortization
Other property and equipment
Total property and equipment
Accumulated depreciation, depletion and
amortization
Total property and equipment, net
Other long-term assets:
Assets from price risk management activities
Other well equipment inventory
Investments in subsidiaries
Other assets
Total assets
LIABILITIES AND STOCKHOLDERS' EQUITY
(DEFICIT)
Current liabilities:
Accounts payable
Accrued liabilities
Accrued royalties
Current portion of long-term debt
Current portion of asset retirement
obligations
Liabilities from price risk management
activities
Accrued interest payable
Other current liabilities
Total current liabilities
Long-term debt, net of discount and deferred
financing costs
Asset retirement obligations
Liabilities from price risk management activities
Other long-term liabilities
Total liabilities
Commitments and Contingencies (Note 11)
Stockholders' equity (deficit)
Parent
Subsidiary
Issuers
Guarantors
Non-
Guarantors Elimination Consolidated
$
— $
—
22,315 $
—
7,806 $
1,242
2,070 $
—
— $
—
32,191
1,242
—
—
—
—
—
—
—
—
—
—
938
1,406
—
—
—
24,659
62,871
11,659
5,863
157
17,919
840
2,148
110,505
—
1,954
5,685
—
12
—
—
9,721
—
—
—
—
—
—
—
—
62,871
13,613
12,486
1,563
17,931
840
2,148
144,885
—
—
2,440,811
—
—
2,440,811
—
—
—
—
—
—
7,266
7,266
41,259
1,580
2,483,650
30,743
11
30,754
—
—
—
72,002
8,857
2,521,670
(6,355)
911
(1,424,527)
1,059,123
(8)
30,746
—
—
(1,430,890)
1,090,780
—
—
(54,087)
—
—
2,577
—
326
$ (54,087) $ 723,942 $ 1,172,531 $
345
—
697,663
364
—
—
—
16
—
—
(643,576)
—
40,483 $ (643,576) $
345
2,577
—
706
1,239,293
$
—
—
—
—
—
$
$
1,124
6,516
—
24,977
70,458 $
80,464
24,208
—
1,099 $
993
—
—
— $
—
—
—
72,681
87,973
24,208
24,977
—
39,741
—
—
39,741
—
—
—
—
—
—
—
—
—
46,580
8,742
—
87,939
672,581
—
17,509
—
778,029
3,377
—
15,188
233,436
—
174,992
1,272
103,559
513,259
—
—
—
2,092
—
—
—
—
2,092
—
—
—
—
—
—
—
—
—
49,957
8,742
15,188
323,467
672,581
174,992
18,781
103,559
1,293,380
(54,087)
659,272
(54,087)
$ (54,087) $ 723,942 $ 1,172,531 $
(643,576)
38,391
40,483 $ (643,576) $
(54,087)
1,239,293
F-34
6696_10K.pdf
TALOS ENERGY INC.
CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2018
(In thousands)
Parent
Guarantors
Guarantors Elimination Consolidated
Subsidiary
Issuers
Non-
Revenues:
Oil revenue
Natural gas revenue
NGL revenue
Total revenue
Operating expenses:
Direct lease operating expense
Insurance
Production taxes
Total lease operating expense
Workover and maintenance expense
Depreciation, depletion and amortization
Accretion expense
General and administrative expense
Total operating expenses
Operating income (loss)
Interest expense
Price risk management activities income
Other income (loss)
Income tax expense
Equity earnings (losses) from subsidiaries
Net income (loss)
$
— $
—
—
—
— $
—
—
—
781,815 $
73,610
35,863
891,288
— $
—
—
—
— $
—
—
—
—
—
—
—
—
—
—
—
—
—
1,955
—
—
—
43,841
142
45,796
142
(45,796)
(142)
(58,172)
—
50,025
—
(1,563)
—
—
(1,065)
222,747
278,253
$221,540 $ 222,747 $
145,988
15,342
1,989
163,319
64,961
286,760
35,344
40,035
590,419
300,869
(30,255)
10,410
874
(360)
—
281,538 $
—
—
—
—
—
4
—
1,798
1,802
(1,802)
(1,687)
—
1,701
(1,497)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(501,000)
(3,285) $ (501,000) $
781,815
73,610
35,863
891,288
145,988
15,342
1,989
163,319
64,961
288,719
35,344
85,816
638,159
253,129
(90,114)
60,435
1,012
(2,922)
—
221,540
F-35
6696_10K.pdf
TALOS ENERGY INC.
CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2017
(In thousands)
Parent
Guarantors
Guarantors Elimination Consolidated
Subsidiary
Issuers
Non-
Revenues:
Oil revenue
Natural gas revenue
NGL revenue
Other
Total revenue
Operating expenses:
Direct lease operating expense
Insurance
Production taxes
Total lease operating expense
Workover and maintenance expense
Depreciation, depletion and amortization
Accretion expense
General and administrative expense
Total operating expenses
Operating income (loss)
Interest expense
Price risk management activities expense
Other income (expense)
Equity earnings from subsidiaries
Net income (loss)
$
— $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(62,868)
$(62,868) $
— $
—
—
—
—
—
—
—
—
—
1,401
—
21,882
23,283
(23,283)
(48,236)
(22,998)
600
31,049
(62,868) $
344,781 $
48,886
16,658
2,503
412,828
109,180
10,743
1,460
121,383
32,825
155,947
19,295
14,172
343,622
69,206
(30,252)
(4,565)
(333)
—
34,056 $
— $
—
—
—
—
—
—
—
—
—
4
—
619
623
(623)
(2,446)
—
62
—
(3,007) $
— $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
31,819
31,819 $
344,781
48,886
16,658
2,503
412,828
109,180
10,743
1,460
121,383
32,825
157,352
19,295
36,673
367,528
45,300
(80,934)
(27,563)
329
—
(62,868)
F-36
6696_10K.pdf
TALOS ENERGY INC.
CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2016
(In thousands)
Parent
Guarantors
Guarantors Elimination Consolidated
Subsidiary
Issuers
Non-
Revenues:
Oil revenue
Natural gas revenue
NGL revenue
Other
Total revenue
Operating expenses:
Direct lease operating expense
Insurance
Production taxes
Total lease operating expense
Workover and maintenance expense
Depreciation, depletion and amortization
Accretion expense
General and administrative expense
Total operating expenses
Operating loss
Interest expense
Price risk management activities expense
Other income (expense)
Equity earnings from subsidiaries
Net income (loss)
$
— $
—
—
—
—
— $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,553
—
—
—
13,204
—
14,757
—
(14,757)
—
(47,291)
—
(57,398)
—
—
—
(208,087)
(88,641)
$(208,087) $ (208,087) $
197,583 $
42,705
9,532
8,934
258,754
124,360
13,101
1,958
139,419
24,810
123,132
21,829
15,044
324,234
(65,480)
(19,680)
—
430
—
(84,730) $
—
—
—
—
—
—
—
—
—
—
4
—
438
442
(442)
(3,444)
—
(25)
—
(3,911) $
— $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
296,728
296,728 $
197,583
42,705
9,532
8,934
258,754
124,360
13,101
1,958
139,419
24,810
124,689
21,829
28,686
339,433
(80,679)
(70,415)
(57,398)
405
—
(208,087)
F-37
6696_10K.pdf
TALOS ENERGY INC.
CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2018
(In thousands)
Parent
Subsidiary
Issuers
Non-
Guarantors
Guarantors Elimination Consolidated
Cash flows from operating activities:
Net cash provided by (used in)
operating activities
Cash flows from investing activities:
Exploration, development, and other capital
expenditures
Cash paid for acquisitions, net of cash
acquired
Investments in subsidiaries
Distributions from subsidiaries
Net cash provided by (used in)
investing activities
Cash flows from financing activities:
Redemption of Senior Notes and other
long-term debt
Proceeds from Bank Credit Facility
Repayment of Bank Credit Facility
Repayment of LLC Bank Credit Facility
Deferred financing costs
Payment of capital lease
Capital contributions
Distributions to Subsidiary Issuer
Net cash provided by (used in)
financing activities
Net increase (decrease) in cash, cash
equivalents and restricted cash
Cash, cash equivalents and restricted cash
$ — $ (193,088) $
442,890 $
13,643 $
— $
263,445
—
(13,404)
(227,228)
(282)
—
(240,914)
—
—
— (1,316,588)
— 1,694,460
278,409
—
9
—
—
— 1,316,588
— (1,694,469)
278,409
—
—
—
364,468
51,190
(282)
(377,881)
37,495
—
—
—
—
—
—
—
—
(105)
(25,152)
—
319,000
—
(54,000)
—
(403,000)
—
(17,002)
—
(12,952)
— 1,301,876
— (1,689,898)
—
—
—
—
—
—
—
—
—
—
—
—
14,712 (1,316,588)
(4,571) 1,694,469
(25,257)
319,000
(54,000)
(403,000)
(17,002)
(12,952)
—
—
—
(180,154)
(401,079)
10,141
377,881
(193,211)
—
(8,774)
93,001
23,502
—
107,729
Balance, beginning of period
Balance, end of period
—
$ — $
22,315
13,541 $
9,048
102,049 $
2,070
25,572 $
—
— $
33,433
141,162
F-38
6696_10K.pdf
TALOS ENERGY INC.
CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2017
(In thousands)
Cash flows from operating activities:
Net cash provided by (used in)
operating activities
Cash flows from investing activities:
Exploration, development, and other capital
expenditures
Cash paid for acquisitions, net of cash
acquired
Investments in subsidiaries
Distributions from subsidiaries
Net cash provided by (used in)
investing activities
Cash flows from financing activities:
Redemption of 2018 Senior Notes
Proceeds from Bank Credit Facility
Repayment of Bank Credit Facility
Payments of capital lease
Capital contributions
Distributions to subsidiaries
Net cash provided by (used in)
financing activities
Net increase (decrease) in cash, cash
equivalents and restricted cash
Cash, cash equivalents and restricted cash:
Parent
Subsidiary
Issuers
Non-
Guarantors
Guarantors Elimination Consolidated
$ — $
(30,245) $
204,419 $
1,879 $
— $
176,053
—
(260)
(132,317)
(22,600)
—
(155,177)
—
—
—
—
(577,055)
611,526
(2,464)
—
6,041
—
—
—
—
577,055
(617,567)
(2,464)
—
—
—
34,211
(128,740)
(22,600)
(40,512)
(157,641)
—
—
—
—
—
—
(1,000)
10,000
(15,000)
—
—
—
—
—
—
(12,412)
550,555
(611,526)
—
—
—
—
26,500
(6,041)
—
—
—
—
(577,055)
617,567
(1,000)
10,000
(15,000)
(12,412)
—
—
—
(6,000)
(73,383)
20,459
40,512
(18,412)
—
—
— $
—
33,433
33,433
—
(2,034)
2,296
(262)
Balance, beginning of period
Balance, end of period
—
$ — $
24,349
22,315 $
6,752
9,048 $
2,332
2,070 $
F-39
6696_10K.pdf
TALOS ENERGY INC.
CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2016
(In thousands)
Parent
Guarantors
Guarantors Elimination Consolidated
Subsidiary
Issuers
Non-
Cash flows from operating activities:
Net cash provided by (used in)
operating activities
Cash flows from investing activities:
Exploration, development, and other
capital expenditures
Cash paid for acquisitions, net of cash
acquired
Investments in subsidiaries
Distributions from subsidiaries
Net cash provided by (used in)
investing activities
Cash flows from financing activities:
Proceeds from Bank Credit Facility
Repayment of Bank Credit Facility
Payments of capital lease
Capital contributions
Distributions to subsidiaries
Contributions from Sponsors
Distributions to Sponsors
Net cash provided by (used in)
financing activities
Net increase (decrease) in cash, cash
equivalents and restricted cash
Cash, cash equivalents and restricted cash:
$
— $ 124,698 $
(2,806) $
(5,769)
— $
116,123
—
(301)
(106,647)
(6,084)
—
(113,032)
—
(91,891)
—
—
(524,192)
411,074
(85,886)
—
—
—
—
—
—
616,083
(411,074)
(85,886)
—
—
(91,891)
(113,419)
(192,533)
(6,084)
205,009
(198,918)
—
—
—
—
—
93,750
(1,859)
15,000
(10,000)
—
—
—
—
—
—
—
(5,267)
599,630
(408,050)
—
—
—
—
—
16,453
(3,024)
—
—
—
—
—
(616,083)
411,074
—
—
15,000
(10,000)
(5,267)
—
—
93,750
(1,859)
91,891
5,000
186,313
13,429
(205,009)
91,624
—
16,279
(9,026)
1,576
—
8,829
Balance, beginning of period
Balance, end of period
—
— $
8,070
24,349 $
15,778
6,752 $
756
2,332 $
$
—
— $
24,604
33,433
F-40
6696_10K.pdf
Note 13 —Selected Quarterly Financial Data (Unaudited)
Unaudited quarterly financial data are as follows (in thousands):
Quarter Ended 2018
Revenues
Operating income
Price risk management activities income (expense)
Net income (loss)
Net income (loss) per common share:
Basic
Diluted
Weighted average common shares outstanding:
Basic
Diluted
Quarter Ended 2017
Revenues
Operating income
Price risk management activities income (expense)
Net income (loss)
Net income (loss) per common share:
Basic
Diluted
Weighted average common shares outstanding:
Basic
Diluted
March 31
June 30
September 30 December 31
$
$
$
$
$
$
$
$
145,850 $
48,584
(51,976)
(22,943) $
203,906 $
39,211
(91,176)
(74,912) $
282,868 $ 258,664
73,973
91,361
(53,330) 256,917
13,109 $ 306,286
(0.73) $
(0.73) $
(1.69) $
(1.69) $
0.24 $
0.24 $
5.66
5.66
31,244
31,244
44,336
44,336
54,156
54,164
54,156
54,159
101,824 $
7,287
45,893
34,462 $
95,426 $
6,314
38,995
24,607 $
99,962 $ 115,616
18,370
13,329
(28,086)
(84,365)
(36,177) $ (85,760)
1.10 $
1.10 $
0.79 $
0.79 $
(1.16) $
(1.16) $
(2.74)
(2.74)
31,244
31,244
31,244
31,244
31,244
31,244
31,244
31,244
Note 14 —Supplemental Oil and Gas Disclosures (Unaudited)
Capitalized Costs
Aggregate amounts of capitalized costs relating to oil, natural gas and NGL activities and the aggregate
amount of related accumulated depletion and amortization as of the dates indicated are presented below (in
thousands):
Proved properties
Unproved oil and gas properties, not subject to amortization
Total oil and gas properties
Less: Accumulated depletion and amortization
Net capitalized costs
Depletion and amortization rate per Boe
December 31,
2018
3,629,430 $
108,209
3,737,639
(1,709,614)
2,028,025 $
17.07 $
2017
2,440,811
72,002
2,512,813
(1,423,829)
1,088,984
14.85
$
$
$
Included in the depletable basis of proved oil and gas properties is the estimate of the Company’s
proportionate share of asset retirement costs relating to these properties which are also reflected as asset retirement
obligations in the accompanying consolidated balance sheets. At December 31, 2018 and 2017 the Company’s
liability for oil and gas asset retirement obligations totaled $382.8 million and $214.7 million, respectively.
F-41
6696_10K.pdf
Costs Incurred for Property Acquisition, Exploration and Development Activities
The following table reflects the costs incurred in oil, natural gas and NGL property acquisition, exploration
and development activities during the years indicated (in thousands). Costs incurred also include new asset
retirement obligations established in the current year, as well as increases or decreases to the asset retirement
obligations resulting from changes to cost estimates during the year.
Property acquisition costs:
Proved properties
Unproved properties, not subject to amortization
Total property acquisition costs
Exploration costs
Development costs
Total costs incurred
Year Ended December 31,
2017
2016
2018
$
850,515 $
65,063
915,578
93,780
215,467
$ 1,224,825 $
1,108 $
5,778
6,886
82,887
114,846
204,619 $
77,906
15,919
93,825
27,807
195,869
317,501
Estimated Quantities of Proved Oil, Natural Gas and NGL Reserves
The Company employs full-time experienced reserve engineers and geologists who are responsible for
determining proved reserves in compliance with SEC guidelines. There are numerous uncertainties inherent in
estimating quantities of proved reserves and projecting future rates of production and timing of development
expenditures. The reserve data in the following tables only represent estimates and should not be construed as
being exact. Engineering reserve estimates were prepared based upon interpretation of production performance data
and sub-surface information obtained from the drilling of existing wells. The Company’s Director of Reserves,
internal reservoir engineers and geologists analyzed and prepared reserve estimates on all oil and natural gas fields.
All of the Company’s proved oil, natural gas and NGL reserves are located in the United States primarily offshore
Gulf of Mexico.
At December 31, 2018, 2017 and 2016, 100% of proved oil, natural gas and NGL reserves attributable to all
of the Company’s oil and natural gas properties were estimated and complied for reporting purposes by the
Company’s reservoir engineers and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), independent
petroleum engineers and geologists.
F-42
6696_10K.pdf
The following table presents the Company’s estimated proved reserves at its net ownership interest:
Total proved reserves at December 31, 2015
Revision of previous estimates
Production
Purchases of reserves
Extensions and discoveries
Total proved reserves at December 31, 2016
Revision of previous estimates
Production
Extensions and discoveries
Total proved reserves at December 31, 2017
Revision of previous estimates
Production
Purchases of reserves
Extensions and discoveries
Total proved reserves at December 31, 2018
Total proved developed reserves as of:
December 31, 2016
December 31, 2017
December 31, 2018
Total proved undeveloped reserves as of:
December 31, 2016
December 31, 2017
December 31, 2018
Oil (MBbls)
46,354
(1,712)
(5,126)
11,128
21,722
72,366
(2,673)
(7,048)
10,159
72,804
2,595
(11,771)
44,788
4,123
112,539
Gas (MMcf)
129,224
10,024
(19,001)
11,208
19,149
150,604
(15,860)
(16,308)
9,220
127,656
(37,933)
(22,771)
95,661
8,411
171,024
NGL (MBbls)
4,581
(352)
(603)
950
1,660
6,236
250
(706)
767
6,547
3,187
(1,176)
2,074
64
10,696
45,753
37,460
85,530
26,613
35,344
27,009
96,122
77,577
131,364
54,482
50,079
39,660
4,032
3,315
8,104
2,204
3,232
2,592
Oil
Equivalent
(MBoe)
72,473
(394)
(8,896)
13,946
26,573
103,702
(5,067)
(10,472)
12,462
100,625
(539)
(16,742)
62,806
5,589
151,739
65,805
53,704
115,528
37,897
46,921
36,211
During 2018, the Company added 51.1 MMBoe of estimated proved reserves, which included 62.8 MMBoe
added through purchases of 59.3 MMBoe from the Stone Combination and 3.5 MMBoe from the Whistler
Acquisition. The Company also added 5.6 MMBoe of estimated proved reserves from extensions and discoveries
primarily from an evaluation of Green Canyon Block 18. The increase was partially offset by a decrease of 16.7
MMBoe of production.
During 2017, the Company added 12.5 MMBoe of estimated proved reserves from extensions and
discoveries primarily from drilling the Tornado II exploration prospect in the Phoenix Field. The increase was
offset by a decrease of 10.5 MMBoe of production and 5.1 MMBoe of negative performance revisions.
During 2016, the Company added 13.9 MMBoe of estimated proved reserves through the purchase of
reserves from the Sojitz Acquisition. The Company also added 26.6 MMBoe of estimated proved reserves from
extensions and discoveries from successful drilling of the Tornado exploration well in the Phoenix Field.
F-43
6696_10K.pdf
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL
Reserves
The following table reflects the standardized measure of discounted future net cash flows relating to the
Company’s interest in proved oil, natural gas and NGL reserves (in thousands):
Future cash inflows
Future costs:
Production
Development and abandonment
Future net cash flows before income taxes
Future income tax expense (1)
Future net cash flows after income taxes
Discount at 10% annual rate
Standardized measure of discounted future net cash flows
December 31,
2017
$ 8,654,631 $ 4,308,863 $ 3,390,612
2016
2018
(1,740,850)
(1,349,005)
5,564,776
(862,473)
4,702,303
(1,362,057)
(775,354)
(664,254)
1,951,004
—
1,951,004
(614,969)
$ 3,340,246 $ 1,807,669 $ 1,336,035
(815,509)
(823,164)
2,670,190
—
2,670,190
(862,521)
(1)
For December 31, 2017 and 2016, the standardized measure of discounted future net cash flows did not include the impact of future
federal income taxes because Talos Energy LLC was not subject to federal income taxes prior to the Stone Combination.
Future cash inflows are computed by applying SEC Pricing to year-end quantities of proved reserves. The
discounted future cash flow estimates do not include the effects of derivative instruments. See the following table
for base prices used in determining the standardized measure:
Oil price per Bbl
Natural gas prices per Mcf
NGL price per Bbl
Year Ended December 31,
2017
2016
2018
$
$
$
69.42 $
3.08 $
29.50 $
51.36 $
3.20 $
24.64 $
40.02
2.66
14.96
Future net cash flows are discounted at the prescribed rate of 10%. Actual future net cash flows may vary
considerably from these estimates. Although the Company’s estimates of total proved reserves, development costs
and production rates were based on the best information available, the development and production of oil and gas
reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may
vary significantly from those used. Therefore, such estimated future net cash flow computations should not be
considered to represent the Company’s estimate of the expected revenues or the current value of existing proved
reserves.
F-44
6696_10K.pdf
Changes in Standardized Measure of Discounted Future Net Cash Flows
Principal changes in the standardized measure of discounted future net cash flows attributable to the
Company’s proved oil, natural gas and NGL reserves are as follows (in thousands):
Standardized measure, beginning of year
Changes during the year:
Sales and transfers of oil, net gas and NGLs produced during
the period
Net change in prices and production costs
Changes in estimated future development costs
Previously estimated development costs incurred
Accretion of discount
Net change in income taxes(1)
Purchases of reserves
Extensions and discoveries
Net change due to revision in quantity estimates
Changes in production rates (timing) and other
Total
Standardized measure, end of year
Year Ended December 31,
2017
2018
$ 1,807,669 $ 1,336,035 $
2016
602,981
(727,969)
1,578,330
32,328
45,937
180,767
(585,017)
943,519
148,068
190,853
(274,239)
1,532,577
(114,625)
80,174
2,292
108,484
60,298
—
222,581
479,833
(5,685)
(100,298)
733,054
$ 3,340,246 $ 1,807,669 $ 1,336,035
(288,942)
555,100
(156,282)
146,687
133,603
—
—
328,565
(113,629)
(133,468)
471,634
(1)
For December 31, 2017 and 2016, the standardized measure of discounted future net cash flows did not include the impact of future
federal income taxes because Talos Energy LLC was not subject to federal income taxes prior to the Stone Combination.
Note 15 —Subsequent Events
Gunflint Acquisition
On January 11, 2019, the Company entered into a Purchase Sale Agreement with Samson Offshore
Mapleleaf, LLC to acquire an approximate 9.6% non-operated working interest in the Gunflint Field located in the
Mississippi Canyon area for $29.6 million.
Derivative Contracts
For additional information, see Note 5 — Financial Instruments.
Debt
For additional information, see Note 6 — Debt.
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C O R P O R A T E I N F O R M A T I O N
CORPORATE OFFICERS
Timothy S. Duncan
President and Chief Execu(cid:415) ve Offi cer
Stephen E. Heitzman
Execu(cid:415) ve Vice President
and Chief Opera(cid:415) ng Offi cer
John A. Parker
Execu(cid:415) ve Vice President –
Explora(cid:415) on
Michael L. Harding II
Execu(cid:415) ve Vice President,
Chief Financial Offi cer and Treasurer
William S. Moss III
Execu(cid:415) ve Vice President
and General Counsel
John B. Spath
Senior Vice President –
Drilling and Produc(cid:415) on Opera(cid:415) ons
Robert Sheninger
Vice President –
Health, Safety, Environmental
and Sustainability
C. Gordon Lindsey
Vice President –
Corporate Development
Deborah Huston
Vice President and
Deputy General Counsel
Loren Long
Vice President –
Mexico
BOARD OF DIRECTORS
Neal P. Goldman*
Managing Member, SAGE Capital
Investments, LLC
Timothy S. Duncan
President and Chief Execu(cid:415) ve Offi cer,
Talos Energy Inc.
Chris(cid:415) ne Hommes
Principal, Apollo Global Management, LLC
John Brad Juneau
Sole Manager and General Partner,
Juneau Explora(cid:415) on, L.P.
Donald R. Kendall, Jr.
Director and Chief Execu(cid:415) ve Offi cer,
Kenmont Capital Partners
Rajen Mahagaokar
Principal, Riverstone Holdings LLC
Charles M. Sledge
Investor
Robert M. Tichio
Partner, Riverstone Holdings LLC
James M. Trimble
Chairman, Crestone Peak Resources
Olivia C. Wassenaar
Partner, Apollo Global Management, LLC
* Chairman of the Board
CORPORATE OFFICE
333 Clay St., Suite 3300
Houston, TX 77002
Phone: 713-328-3000
WEBSITE
www.talosenergy.com
STOCK EXCHANGE LISTING
New York Stock Exchange
Symbol: TALO
ANNUAL MEETING
May 6, 2019
10:30 a.m. CT
Three Allen Center
333 Clay Street, Suite 3300
Houston, TX 77002
FORM 10-K
Copies of the corpora(cid:415) on’s 10-K
are available on our website at
www.talosenergy.com
AUDITORS
Ernst & Young
Houston, TX
SHAREHOLDER SERVICES
Computershare
Mailing: P.O. Box 505000
Louisville, KY 40233
1-800-962-4284 (Toll-Free)
1-781-575-3120 (Interna(cid:415) onal)
OVERNIGHT MAIL
462 South 4th Street
Suite 1600
Louisville, KY 40202
INVESTOR RELATIONS
Addi(cid:415) onal corporate informa(cid:415) on
is available on our website at
www.talosenergy.com
66696.indd 9
3/28/19 7:07 AM
CORPORATE OFFICE
333 Clay St., Suite 3300
Houston, TX 77002
Phone: 713-328-3000
www.talosenergy.com
66696.indd 10
3/28/19 7:07 AM