UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
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ANNUAL REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
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For the
fiscal year ended December 31,
2018
OR
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o
TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
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For the
transition period from
to
Commission
File Number 001-5507
Tellurian
Inc.
(Exact name
of registrant as specified in its charter)
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Delaware
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06-0842255
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(State or other
jurisdiction
of incorporation or
organization)
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(I.R.S. Employer
Identification No.)
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1201
Louisiana Street, Suite 3100, Houston, TX
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77002
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(Address of principal
executive offices)
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(Zip Code)
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(832)
962-4000
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(Registrant’s telephone
number, including area code)
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Securities registered
pursuant to Section 12(b) of the Act:
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Title of each
class
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Name of each exchange on
which registered
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Common
stock, $0.01 par value
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NASDAQ
Capital Market
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Securities registered
pursuant to Section 12(g) of the Act: None
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Indicate by check
mark if the registrant is a well-known seasoned issuer, as defined
in Rule 405 of the Securities Act.
Indicate by check
mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act.
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.
Indicate by check
mark whether the registrant has submitted electronically and posted
on its corporate Website, if any, every Interactive Data File
required to be submitted and posted 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 and post such files).
Indicate by check
mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K 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, a 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.
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Large accelerated
filer
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x
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Accelerated
filer
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Non-accelerated
filer
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¨
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Smaller reporting
company
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¨
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Emerging growth
company
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¨
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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. ¨
Indicate by check
mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).
The aggregate
market value of the voting and non-voting stock held by
non-affiliates of the registrant, as of June 29, 2018, the last
business day of the registrant’s most recently completed second
fiscal quarter, was approximately $766,390 thousand, based on the
per share closing sale price of $8.32 on that date.
Solely for purposes of this disclosure, shares of common stock held
by executive officers and directors of the registrant, as well as
certain stockholders, as of such date have been excluded because
such persons may be deemed to be affiliates. This determination of
executive officers and directors as affiliates is not necessarily a
conclusive determination for any other purposes.
240,460,607
shares of common stock were issued and outstanding as of
February 15,
2019 .
DOCUMENTS
INCORPORATED BY REFERENCE
Portions of the
definitive proxy statement related to the 2019 annual
meeting of stockholders, to be filed within 120 days
after December 31, 2018, are incorporated by reference in Part
III of this annual report on Form 10-K.
Tellurian
Inc.
Form
10-K
For the
Fiscal Year Ended December 31,
2018
TABLE OF
CONTENTS
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Page
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Item 1 and 2.
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Our Business and
Properties
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Item 1A.
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Risk Factors
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Item 1B.
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Unresolved Staff
Comments
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Item 3.
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Legal
Proceedings
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Item 4.
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Mine Safety
Disclosures
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Item 5.
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Market for the Registrant’s
Common Equity, Related Stockholder Matters, and Issuer Purchases of
Equity Securities
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Item 6.
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Selected Financial
Data
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Item 7.
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Management’s Discussion and
Analysis of Financial Condition and Results of
Operations
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Item 7A.
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Quantitative and Qualitative
Disclosures About Market Risk
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Item 8.
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Financial Statements and
Supplementary Data
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Item 9.
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Changes in and Disagreements
with Accountants on Accounting and Financial
Disclosure
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Item 9A.
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Controls and
Procedures
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Item 9B.
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Other
Information
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Item 10.
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Directors, Executive Officers
and Corporate Governance
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Item 11.
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Executive
Compensation
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Item 12.
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Security Ownership of Certain
Beneficial Owners and Management and Related Stockholder
Matters
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Item 13.
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Certain Relationships and
Related Transactions, and Director Independence
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Item 14.
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Principal Accounting Fees and
Services
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Item 15.
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Exhibits, Financial Statement
Schedules
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Item 16.
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Form 10-K
Summary
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Signatures
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Cautionary
Information About 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 facts, that address activity, events,
or developments with respect to our financial condition, results of
operations, or economic performance that we expect, believe or
anticipate will or may occur in the future, or that address plans
and objectives of management for future operations, are
forward-looking statements. The words “anticipate,” “assume,”
“believe,” “budget,” “estimate,” “expect,” “forecast,” “initial,”
“intend,” “may,” “plan,” “potential,” “project,” “proposed,”
“should,” “will,” “would” and similar expressions are intended to
identify forward-looking statements. These forward-looking
statements relate to, among other things:
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our businesses and
prospects and our overall strategy;
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planned or
estimated capital expenditures;
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availability of
liquidity and capital resources;
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our ability to
obtain additional financing as needed and the terms of financing
transactions, including at Driftwood Holdings LLC;
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progress in
developing our projects and the timing of that
progress;
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future values of
the Company’s projects or other interests, operations or rights;
and
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government
regulations, including our ability to obtain, and the timing of,
necessary governmental permits and approvals.
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Our
forward-looking statements are based on assumptions and analyses
made by us in light of our experience and our perception of
historical trends, current conditions, expected future developments
and other factors that we believe are appropriate under the
circumstances. These statements are subject to a number of known
and unknown risks and uncertainties, which may cause our actual
results and performance to be materially different from any future
results or performance expressed or implied by the forward-looking
statements. Factors that could cause actual results and performance
to differ materially from any future results or performance
expressed or implied by the forward-looking statements include, but
are not limited to, the following:
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the uncertain
nature of demand for and price of natural gas and LNG;
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risks related to
shortages of LNG vessels worldwide;
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technological
innovation which may render our anticipated competitive advantage
obsolete;
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risks related to a
terrorist or military incident involving an LNG
carrier;
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changes in
legislation and regulations relating to the LNG industry, including
environmental laws and regulations that impose significant
compliance costs and liabilities;
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governmental
interventions in the LNG industry, including increases in barriers
to international trade;
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uncertainties
regarding our ability to maintain sufficient liquidity and attract
sufficient capital resources to implement our
projects;
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our limited
operating history;
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our ability to
attract and retain key personnel;
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risks related to
doing business in, and having counterparties in, foreign
countries;
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our reliance on
the skill and expertise of third-party service
providers;
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the ability of our
vendors to meet their contractual obligations;
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risks and
uncertainties inherent in management estimates of future operating
results and cash flows;
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our ability to
maintain compliance with our senior secured term loan and other
agreements;
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changes in
competitive factors, including the development or expansion of LNG,
pipeline and other projects that are competitive with
ours;
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development risks,
operational hazards and regulatory approvals;
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our ability to
enter and consummate planned financing and other transactions;
and
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risks and
uncertainties associated with litigation matters.
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The
forward-looking statements in this report speak as of the date
hereof. Although we may from time to time voluntarily update our
prior forward-looking statements, we disclaim any commitment to do
so except as required by securities laws.
DEFINITIONS
All defined terms
under Rule 4-10(a) of Regulation S-X shall have their statutorily
prescribed meanings when used in this report. As used in this
document, the terms listed below have the following
meanings:
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ASC
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Accounting Standards
Codification
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ASU
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Accounting Standards
Update
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Bcf
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Billion cubic feet of natural
gas
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Bcf/d
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Billion cubic feet per
day
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Bcfe
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Billion cubic feet of natural
gas equivalent
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Condensate
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Hydrocarbons that exist in a
gaseous phase at original reservoir temperature and pressure, but
when produced, are in the liquid phase at surface pressure and
temperature
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DD&A
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Depreciation, depletion, and
amortization
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DOE/FE
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U.S. Department of Energy,
Office of Fossil Energy
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EPC
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Engineering, procurement, and
construction
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FASB
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Financial Accounting
Standards Board
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FEED
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Front-End Engineering and
Design
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FERC
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U.S. Federal Energy
Regulatory Commission
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FTA countries
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Countries with which the U.S.
has a free trade agreement providing for national treatment for
trade in natural gas
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GAAP
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Generally accepted accounting
principles in the U.S.
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LNG
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Liquefied natural
gas
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LSTK
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Lump Sum Turnkey
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Mcf
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Thousand cubic feet of
natural gas
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MMBtu
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Million British thermal
unit
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MMcf
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Million cubic feet of natural
gas
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MMcf/d
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MMcf per day
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MMcfe
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Million of cubic feet gas
equivalent volumes using a ratio of 6 Mcf to 1 barrel of
liquid.
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Mtpa
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Million tonnes per
annum
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Nasdaq
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Nasdaq Capital
Market
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NGA
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Natural Gas Act of 1938, as
amended
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Non-FTA
countries
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Countries with which the U.S.
does not have a free trade agreement providing for national
treatment for trade in natural gas and with which trade is
permitted
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Oil
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Crude oil and
condensate
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PSD
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Prevention of Significant
Deterioration
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PUD
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Proved undeveloped
reserves
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SEC
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U.S. Securities and Exchange
Commission
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Train
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An industrial facility
comprised of a series of refrigerant compressor loops used to cool
natural gas into LNG
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U.K.
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United Kingdom
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U.S.
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United States
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USACE
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U.S. Army Corps of
Engineers
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With respect to
information relating to our working interest in wells or acreage,
“net” oil and gas wells or acreage is determined by multiplying
gross wells or acreage by our working interest therein. Unless
otherwise specified, all references to wells and acres are
gross.
PART
I
ITEM 1 AND
2. OUR BUSINESS AND PROPERTIES
Overview
Tellurian Inc.
(“Tellurian,” “we,” “us,” “our,” or the “Company”) intends to
create value for shareholders by building
a low-cost, global natural gas business, profitably
delivering natural gas to customers worldwide (the “Business”). We
are developing a portfolio of natural gas production, LNG
marketing, and infrastructure assets that includes an LNG terminal
facility (the “Driftwood terminal”), and three related pipelines
(the “Pipeline Network”). We refer to the Driftwood terminal, the
Pipeline Network and our existing and planned natural gas
production assets collectively as the “Driftwood Project”. We
currently estimate the total cost of the Driftwood Project to be
approximately $28 billion, including owners’ costs, transaction
costs and contingencies but excluding interest costs incurred
during construction of the Driftwood terminal and other financing
costs. Our Business may be developed in phases.
The proposed
Driftwood terminal will have a liquefaction capacity of
approximately 27.6 Mtpa and will be situated on approximately
1,000 acres in Calcasieu Parish, Louisiana. The proposed Driftwood
terminal will include up to 20 liquefaction Trains, three full
containment LNG storage tanks and three marine berths. We have
entered into four LSTK EPC agreements totaling $15.2 billion with
Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for construction
of the Driftwood terminal.
The proposed
Pipeline Network will consist of three pipelines, the Driftwood
pipeline, the Haynesville Global Access Pipeline and the Permian
Global Access Pipeline. The Driftwood pipeline will be
a 96-mile large diameter pipeline that will interconnect
with 14 existing interstate pipelines throughout southwest
Louisiana to secure adequate natural gas feedstock for the
Driftwood terminal. The Driftwood pipeline will be comprised
of 48-inch, 42-inch, 36-inch and 30-inch diameter
pipeline segments and three compressor stations totaling
approximately 274,000 horsepower, all as necessary to provide
approximately 4 Bcf/d of average daily natural gas transportation
service. We estimate construction costs for the Driftwood pipeline
of approximately $2.3 billion before owners’ costs, financing
costs and contingencies.
The Haynesville
Global Access Pipeline is expected to run approximately 200 miles
from northern to southwest Louisiana. The Permian Global Access
Pipeline is expected to run approximately 625 miles from west Texas
to southwest Louisiana. Each of these pipelines is expected to have
a diameter of 42 inches and be capable of delivering approximately
2 Bcf/d of natural gas. We currently estimate that construction
costs will be approximately $1.4 billion for the Haynesville Global
Access Pipeline and approximately $3.7 billion for the Permian
Global Access Pipeline, in each case before owners’ costs,
financing costs and contingencies.
Our current
upstream properties, acquired in a series of transactions during
2017 and 2018, consist of 10,233 net acres and 52 producing wells
(18 operated) located in the Haynesville Shale trend of north
Louisiana. For the year ended December 31, 2018, these wells had
average net production of approximately 3.9 MMcf/d. As of December
31, 2018, our estimate of net proved reserves was approximately 265
Bcfe. We began drilling certain locations on our properties in the
fourth quarter of 2018 using proceeds from the Term Loan (as
described in “2018 Developments — Significant Transactions — Term
Loan” below).
In connection
with the implementation of our Business, we are offering
partnership interests in a subsidiary, Driftwood Holdings LLC
(“Driftwood Holdings”), which will own the Driftwood Project.
Partners will contribute cash in exchange for equity in Driftwood
Holdings and will receive LNG volumes at the cost of production,
including the cost of debt, for the life of the Driftwood terminal.
We plan to retain a portion of the ownership in Driftwood
Holdings and have engaged Goldman Sachs & Co. and Société
Générale to serve as financial advisors for Driftwood Holdings. We
also continue to develop our LNG marketing activities as described
below in “2018 Developments — Significant Transactions — LNG
Marketing.”
2018
Developments
Significant Transactions
Public
Equity Offerings. In connection with our equity
offering in December 2017, the underwriters were granted an option
to purchase up to an additional 1.5 million shares of common stock
within 30 days. The option was exercised in full in January 2018,
resulting in proceeds of approximately $14.5 million, net of
approximately $0.5 million in fees and commissions.
In June 2018, we
completed another offering in which we sold 12.0 million shares of
common stock for proceeds of approximately $115.2 million, net of
approximately $3.6 million in fees and commissions. The
underwriters were granted an option to purchase up to an additional
1.8 million shares of common stock within 30 days, which was not
exercised.
Preferred
Stock Issuance. In March 2018, we entered
into a preferred stock purchase agreement with BDC Oil and Gas
Holdings, LLC (“Bechtel Holdings”), a Delaware limited liability
company and an affiliate of Bechtel, pursuant to which we sold to
Bechtel Holdings approximately 6.1 million
shares of our
Series C convertible preferred stock (the “Preferred Stock”).
In exchange for the Preferred Stock, Bechtel agreed to discharge
approximately $22.7 million
of the
outstanding liabilities associated with the detailed engineering
services for the Driftwood Project, and to apply
approximately $27.3 million
to additional
future
detailed
engineering services. During the year ended December 31, 2018, all
of the approximately $27.3 million of future services were received
and, as such, all $50.0 million has been recognized on our
Consolidated Balance Sheets within deferred engineering
costs.
Term
Loan. On
September 28, 2018 (the “Closing Date”), we entered into a
three-year senior secured term loan credit agreement (the “Term
Loan”) in the principal amount of $60.0 million at a price of 99%
of par, resulting in an original issue discount of $0.6 million.
Fees of $2.6 million were capitalized as deferred financing costs.
Use of proceeds from the Term Loan is predominantly restricted to
capital expenditures associated with certain development and
drilling activities and fees related to the transaction itself and
are presented within non-current restricted cash on our
Consolidated Balance Sheet. Amounts borrowed under the Term Loan
bear interest at a variable rate (three-month LIBOR) plus an
applicable margin. The applicable margin is 5% through the end of
the first year following the Closing Date, 7% through the end of
the second year following the Closing Date and 8% thereafter. If
the Term Loan is terminated within 12 months of the Closing Date,
an early termination fee equal to 1% of the outstanding principal
is required.
LNG
Marketing. In September 2017, we
entered into a vessel charter that enabled us to execute a number
of LNG purchase and sale opportunities, as well as sub-charter
opportunities, that resulted in revenue of approximately $5.9
million for the year ended December 31, 2018. We continue to
implement our marketing strategy by looking for other LNG purchase,
sale and vessel charter opportunities.
Regulatory Developments
Export
Approval. In February 2017, the DOE/FE
issued an order authorizing Tellurian to export 27.6 mtpa of LNG to
FTA countries, on its own behalf and as agent for others, for a
term of 30 years. Our application for authority to export LNG to
non-FTA countries is currently pending before the DOE/FE and is
expected to be ruled upon in the first half of 2019.
FERC
Application. In March 2017, Tellurian
filed an application with FERC for authorization pursuant to
Section 3 of the NGA to site, construct and operate the Driftwood
terminal, and simultaneously sought authorization pursuant to
Section 7 of the NGA for authorization to construct and operate
interstate natural gas pipeline facilities. In December 2017, FERC
issued the notice of schedule for the environmental review of both
the Driftwood terminal and the Driftwood pipeline. In September
2018, we received our draft environmental impact statement (“EIS”)
from FERC for the Driftwood terminal and pipeline. We received our
final EIS from FERC on January 18, 2019. Refer to Note 19,
Subsequent
Events to
the Consolidated Financial Statements included in this report, for
further details.
Environmental
Permits. In March 2017, we submitted
permit applications to the USACE under the Clean Water Act and the
Rivers and Harbors Act for certain dredging and wetland mitigation
activities relating to the Driftwood terminal and pipeline. Also in
March 2017, we submitted Title V and PSD air permit applications to
the Louisiana Department of Environmental Quality under the Clean
Air Act for air emissions relating to the Driftwood terminal and
pipeline, and the associated permits were granted in July 2018. In
addition, in May 2018, we received a Coastal Use Permit from the
Louisiana Department of Natural Resources for the Driftwood
terminal, which approves the placement of dredged material from the
marine berth for beneficial use inside the Louisiana coastal zone.
The regulatory review and approval process for the USACE permit is
expected to be completed in the first half of 2019.
Natural Gas
Properties
Reserves
As discussed in
“Our Business and Properties — Overview,” our upstream properties,
acquired in a series of transactions during 2017 and 2018, consist
of 10,233 net acres and 52 producing wells (18 operated) located in
the Haynesville Shale trend of north Louisiana. For the year ended
December 31, 2018, these wells had average net production of
approximately 3.9 MMcf/d. All of our proved reserves as of December
31, 2018 were associated with those properties. Proved reserves are
the estimated quantities of natural gas and condensate which
geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions (i.e., costs as of
the date the estimate is made). Proved reserves are categorized as
either developed or undeveloped.
Our reserves as
of December 31, 2018 were estimated by Netherland, Sewell &
Associates, Inc. (“NSAI”), an independent petroleum engineering
firm, and are set forth in the following table. Per SEC rules, NSAI
based its estimates on the 12-month unweighted arithmetic average
of the first-day-of-the-month price for each month from January
through December 2018. Prices include consideration of changes in
existing prices provided only by contractual arrangements, but not
on escalations based upon future conditions. The prices used were
$3.10 per MMbtu of natural gas and $65.56 per barrel of condensate,
adjusted for energy content, transportation fees and market
differentials.
The following
table shows our proved reserves as of December 31,
2018:
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Gas
(MMcf)
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Condensate
(Mbbl)
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Gas
Equivalent
(MMcfe)
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Proved
reserves (as of December 31, 2018):
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Developed
producing
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17,007
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7
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17,052
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Developed
non-producing
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515
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—
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515
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Undeveloped
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247,332
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—
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247,332
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Total
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264,854
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7
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264,899
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The standardized
measure of discounted future net cash flow from our proved reserves
(the “standardized measure”) as of December 31, 2018 was
$145.8
million .
As
of December 31, 2018, we had no proved
undeveloped reserves that had remained undeveloped for more than
five years.
Capital
expenditures totaled approximately $17.1
million during 2018. We invested approximately $12.8
million during 2018 developing proved reserves and
approximately $4.3 million on wells still in progress at
year end. During the year ended December 31, 2018, we
converted approximately 9 Bcfe of proved undeveloped reserves to
proved developed reserves.
Refer to
Supplemental Disclosures About Natural Gas Producing Activities,
starting on page 60, for additional details.
Controls Over Reserve Report Preparation, Technical Qualifications
and Technologies Used
Our December 31,
2018 reserve report was prepared by NSAI in accordance with
guidelines established by the SEC. Reserve definitions comply with
the definitions provided by Regulation S‑X of the SEC. NSAI
prepared the reserve report based upon a review of property
interests being appraised, production from such properties, current
costs of operation and development, current prices for production,
agreements relating to current and future operations and sale of
production, geoscience and engineering data, and other information
we provide to them. This information is reviewed by knowledgeable
members of our Company for accuracy and completeness prior to
submission to NSAI.
A letter which
identifies the professional qualifications of the individual at
NSAI who was responsible for overseeing the preparation of our
reserve estimates as of December 31, 2018, has been filed as an
addendum to Exhibit 99.2 to this report and is incorporated by
reference herein.
Internally, a
Senior Vice President is responsible for overseeing our reserves
process. Our Senior Vice President has over 17 years of experience
in the oil and natural gas industry, with the majority of that time
in reservoir engineering and asset management. She is a graduate of
Virginia Polytechnic Institute and State University with dual
degrees in Chemical Engineering and French, and a graduate of the
University of Houston with a Masters of Business Administration
degree. During her career, she has had multiple responsibilities in
technical and leadership roles, including reservoir engineering and
reserves management, production engineering, planning, and asset
management for multiple U.S. onshore and international projects.
She is also a licensed Professional Engineer in the State of
Texas.
Production
For the years
ended December 31, 2018 and 2017, we produced 1,399 MMcf and 190
MMcf of natural gas at an average sales price of $2.97 and $2.42
per MMcf, respectively. For the years ended December 31, 2018 and
2017, we produced 988 barrels and 150 barrels of condensate at an
average sales price of $60.46 per barrel and $57.01 per barrel,
respectively. Natural gas and condensate production and operating
costs for the periods ended December 31, 2018 and 2017, were $1.71
and $1.25 per MMcfe, respectively.
Drilling Activity
As of December
31, 2018, we were in the process of drilling or completing
operations on one operated well and 12 non-operated wells. Of these
12 non-operated wells, as of December 31, 2018, six had been turned
in line. We had no exploratory wells drilled in 2018 or 2017. In
addition, we had no dry development wells in 2018 or
2017.
Wells and Acreage
As of December
31, 2018, we owned interests in 37 gross (18 net) productive
natural gas wells and held by production 10,503 gross (9,074 net)
developed leasehold acreage. Additionally, we hold 1,180 gross
(1,159 net) undeveloped leasehold acreage. The majority of the
undeveloped leasehold acreage is set to expire in 2020 based on two
year contractual extensions granted in 2018, with 111 gross and net
acres set to expire in 2019. As of December 31, 2018, there were 10
gross (4 net) in process wells.
Volume Commitments
We are not
currently subject to any material volume commitments.
Gathering, Processing and Transportation
As part of our
acquisitions of natural gas properties, we also acquired certain
gathering systems that deliver the natural gas we produce into
third-party gathering systems. We believe that these systems and
other available midstream facilities and services in the
Haynesville Shale trend are adequate for our current operations and
near-term growth.
Government
Regulations
Our operations
are and will be subject to extensive federal, state and local
statutes, rules, regulations, and laws that include, but are not
limited to, the NGA, the Energy Policy Act of 2005 (the “EPAct”),
the Oil Pollution Act, the National Environmental Protection Act
(“NEPA”), the Clean Air Act (the “CAA”), the Clean Water Act (the
“CWA”), the Resource Conservation and Recovery Act (“RCRA”), the
Pipeline Safety Improvement Act of 2002 (the “PSIA”), and the
Coastal Zone Management Act (the “CZMA”). These statutes cover
areas related to the authorization, construction and operation of
LNG facilities and natural gas producing properties, including
discharges and releases to the air, land and water, and the
handling, generation, storage and disposal of hazardous materials
and solid and hazardous wastes due to the development, construction
and operation of the facilities. These laws are administered and
enforced by governmental agencies including FERC, the U.S.
Environmental Protection Agency (the “EPA”), the DOE/FE, the U.S.
Department of Transportation (“DOT”), the Louisiana Department of
Natural Resources, and the Texas Railroad Commission. Additionally,
numerous other governmental and regulatory permits and approvals
will be required to build and operate our Business, including, with
respect to the construction and operation of the Driftwood Project,
consultations and approvals by the Advisory Council on Historic
Preservation, USACE, U.S. Department of Commerce, National Marine
Fisheries Services, U.S. Department of the Interior, U.S. Fish and
Wildlife Service, and U.S. Department of Homeland Security. For
example, throughout the life of our liquefaction project, we will
be subject to regular reporting requirements to FERC, the DOT
Pipeline and Hazardous Materials Safety Administration (“PHMSA”)
and other federal and state regulatory agencies regarding the
operation and maintenance of our facilities.
Failure to comply
with applicable federal, state, and local laws, rules, and
regulations could result in substantial administrative, civil
and/or criminal penalties and/or failure to secure and retain
necessary authorizations.
Federal Energy Regulatory Commission
The design,
construction and operation of liquefaction facilities and
pipelines, the export of LNG and the transportation of natural gas
are highly regulated activities. In order to site, construct and
operate our LNG facilities, we are required to obtain
authorizations from FERC under Section 3 of the NGA as well as
several other material governmental and regulatory approvals and
permits. The EPAct amended Section 3 of the NGA to establish or
clarify FERC’s exclusive authority to approve or deny an
application for the siting, construction, expansion or operation of
LNG terminals, although except as specifically provided in the
EPAct, nothing in the EPAct is intended to affect otherwise
applicable law related to any other federal agency’s authorities or
responsibilities related to LNG terminals.
In 2002, FERC
concluded that it would apply light-handed regulation over the
rates, terms and conditions agreed to by parties for LNG
terminalling services, such that LNG terminal owners would not be
required to provide open-access service at non-discriminatory rates
or maintain a tariff or rate schedule on file with FERC, as
distinguished from the requirements applied to FERC-regulated
natural gas pipelines. Although the EPAct codified FERC’s policy,
those provisions expired on January 1, 2015. Nonetheless, we see no
indication that FERC intends to modify its longstanding policy of
light-handed regulation of LNG terminals.
FERC has
authority to approve, and if necessary set, “just and reasonable
rates” for the transportation or sale of natural gas in interstate
commerce. Relatedly, under the NGA, our proposed pipelines will not
be permitted to unduly discriminate or grant undue preference as to
rates or the terms and conditions of service to any shipper,
including our own affiliates. FERC has the authority to grant
certificates authorizing the construction and operation of
facilities, such as pipelines, used in interstate natural gas
transportation and the provision of services. FERC’s jurisdiction
under the NGA generally extends to the transportation of natural
gas in interstate commerce, to the sale in interstate commerce of
natural gas for resale for ultimate consumption for domestic,
commercial, industrial or any other use and to natural gas
companies engaged in such transportation or sale. FERC’s
jurisdiction does not extend to the production, gathering, local
distribution or export of natural gas.
Specifically,
FERC’s authority to regulate interstate natural gas pipelines
includes:
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rates and charges
for natural gas transportation and related services;
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the certification
and construction of new facilities;
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the extension and
abandonment of services and facilities;
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the maintenance
of accounts and records;
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the acquisition
and disposition of facilities;
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the initiation
and discontinuation of services; and
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The EPAct amends
the NGA to make it unlawful for “any entity,” including otherwise
non-jurisdictional producers, to use any deceptive or manipulative
device or contrivance in connection with the purchase or sale of
natural gas or the purchase or sale of transportation services
subject to regulation by FERC, in contravention of rules prescribed
by FERC. The anti-manipulation rule does not apply to activities
that relate only to intrastate or other non-jurisdictional sales,
gathering or production, but does apply to activities of otherwise
non-jurisdictional entities to the extent the activities are
conducted “in connection with” natural gas sales, purchases or
transportation subject to FERC jurisdiction. The EPAct also gives
FERC authority to impose civil penalties for violations of the NGA
or Natural Gas Policy Act of up to $1 million per
violation.
Transportation of
the natural gas we produce, and the prices we pay for such
transportation, will be significantly affected by the foregoing
laws and regulations.
U.S. Department of Energy, Office of Fossil Energy Export
License
Under the NGA,
exports of natural gas to FTA countries are “deemed to be
consistent with the public interest,” and authorization to export
LNG to FTA countries shall be granted by the DOE/FE “without
modification or delay.” FTA countries currently capable of
importing LNG include Canada, Chile, Colombia, Jordan, Mexico,
Singapore, South Korea and the Dominican Republic. Exports of
natural gas to non-FTA countries are authorized unless the DOE/FE
finds that the proposed exportation “will not be consistent with
the public interest.”
Pipeline and Hazardous Materials Safety Administration
The Natural Gas
Pipeline Safety Act of 1968 (the “NGPSA”) authorizes DOT to
regulate pipeline transportation of natural (flammable, toxic, or
corrosive) gas and other gases, as well as the transportation and
storage of LNG. Amendments to the NGPSA include the Pipeline Safety
Act of 1979, which addresses liquids pipelines, and the PSIA, which
governs the areas of testing, education, training, and
communication.
PHMSA administers
pipeline safety regulations for jurisdictional gas gathering,
transmission, and distribution systems under minimum federal safety
standards. PHMSA also establishes and enforces safety regulations
for onshore LNG facilities, which are defined as pipeline
facilities used for the transportation or storage of LNG subject to
such safety standards. Those regulations address requirements for
siting, design, construction, equipment, operations, personnel
qualification and training, fire protection, and security of LNG
facilities. The Driftwood terminal will be subject to such PHMSA
regulations.
Tellurian’s
proposed pipelines will also be subject to regulation by PHMSA,
including those under the PSIA. The PHMSA Office of Pipeline Safety
administers the PSIA, which requires pipeline companies to perform
extensive integrity tests on natural gas transportation pipelines
that exist in high population density areas designated as “high
consequence areas.” Pipeline companies are required to perform the
integrity tests on a seven-year cycle. The risk ratings are based
on numerous factors, including the population density in the
geographic regions served by a particular pipeline, as well as the
age and condition of the pipeline and its protective coating.
Testing consists of hydrostatic testing, internal electronic
testing, or direct assessment of the piping. In addition to the
pipeline integrity tests, pipeline companies must implement a
qualification program to make certain that employees are properly
trained. Pipeline operators also must develop integrity management
programs for natural gas transportation pipelines, which requires
pipeline operators to perform ongoing assessments of pipeline
integrity; identify and characterize applicable threats to pipeline
segments that could impact a high consequence area; improve data
collection, integration and analysis; repair and remediate the
pipeline, as necessary; and implement preventive and mitigation
actions.
In April 2016,
PHMSA issued a notice of proposed rulemaking addressing changes to
the regulations governing the safety of gas transmission pipelines.
Specifically, PHMSA is considering certain integrity management
requirements for “moderate consequence areas,” requiring an
integrity verification process for specific categories of
pipelines, and mandating more explicit requirements for the
integration of data from integrity assessments to an operator’s
compliance procedures. PHMSA is also considering whether to revise
requirements for corrosion control and expanding the definition of
regulated gathering lines. These notices of proposed rulemaking are
still pending at PHMSA and have not been finalized.
Natural Gas Pipeline Safety Act of 1968
Louisiana
administers federal pipeline safety standards under the NGPSA,
which requires certain pipelines to comply with safety standards in
constructing and operating the pipelines and subjects the pipelines
to regular inspections. Failure to comply with the NGPSA may result
in the imposition of administrative, civil and criminal
sanctions.
Other Governmental Permits, Approvals and
Authorizations
The construction
and operation of the Driftwood Project will be subject to
additional federal permits, orders, approvals and consultations
required by other federal and state agencies, including DOT, the
Advisory Council on Historic Preservation, USACE, U.S. Department
of Commerce, National Marine Fisheries Services, U.S. Department of
the Interior, U.S. Fish and Wildlife Service, the EPA and U.S.
Department of Homeland Security.
Three significant
permits that may apply to the Driftwood Project are the USACE
Section 404 of the Clean Water Act/Section 10 of the Rivers and
Harbors Act Permit, the Clean Air Act Title V Operating Permit and
the PSD Permit, of which the latter two permits are issued by the
Louisiana Department of Environmental Quality. The Driftwood
Project will also have to comply with the requirements of
NEPA.
Environmental Regulation
Our operations
are and will be subject to various federal, state and local laws
and regulations relating to the protection of the environment and
natural resources, the handling, generation, storage and disposal
of hazardous materials and solid and hazardous wastes and other
matters. These environmental laws and regulations, which can
restrict or prohibit impacts to the environment or the types,
quantities and concentration of substances that can be released
into the environment, will require significant expenditures for
compliance, can affect the cost and output of operations, may
impose substantial administrative, civil and/or criminal penalties
for non-compliance and can result in substantial
liabilities.
Clean Air
Act. The
CAA and comparable state laws and regulations regulate and restrict
the emission of air pollutants from many sources and impose various
monitoring and reporting requirements, among other requirements.
The Driftwood Project is subject to the federal CAA and comparable
state and local laws. We may be required to incur capital
expenditures for air pollution control equipment in connection with
maintaining or obtaining permits and approvals pursuant to the CAA
and comparable state laws and regulations.
Greenhouse
Gases. In
December 2009, the EPA published its findings that emissions of
carbon dioxide, methane, and other greenhouse gases (“GHGs”)
present an endangerment to public health and the environment
because emissions of GHGs are, according to the EPA, contributing
to warming of the earth’s atmosphere and other climatic changes.
These findings provide the basis for the EPA to adopt and implement
regulations that would restrict emissions of GHGs under existing
provisions of the CAA. In June 2010, the EPA began regulating GHG
emissions from stationary sources, including LNG
terminals.
In the past,
Congress has considered proposed legislation to reduce emissions of
GHGs. Congress has not adopted any significant legislation in this
respect to date, but could do so in the future. In addition, many
states and regions have taken legal measures to reduce emissions of
GHGs, primarily through the planned development of GHG emission
inventories and/or regional GHG cap and trade
programs.
The EPA issued
the Clean Power Plan in 2015, which would have required existing
power plants to reduce their carbon dioxide emissions. The Supreme
Court stayed implementation of the Clean Power Plan in February
2016. In October 2017, the EPA proposed to repeal the Clean Power
Plan. The comment period on the proposed rule closed on April 26,
2018. On August 21, 2018, the EPA proposed the Affordable Clean
Energy (“ACE”) rule, which would establish emission guidelines for
states to develop plans to address greenhouse gas emissions from
existing coal-fired power plants. The ACE would replace the Clean
Power Plan.
The Obama
administration reached an agreement during the December 2015 United
Nations climate change conference in Paris pursuant to which the
U.S. initially pledged to make a 26-28 percent reduction in its GHG
emissions by 2025 against a 2005 baseline and committed to
periodically update this pledge every five years starting in 2020.
In June 2017, President Trump announced that the U.S. would
initiate the formal process to withdraw from the Paris
Agreement.
Coastal
Zone Management Act. The siting and construction
of the Driftwood terminal within the coastal zone may be subject to
the requirements of the CZMA. The CZMA is administered by the
states (in Louisiana, by the Department of Natural Resources). This
program is implemented to ensure that impacts to coastal areas are
consistent with the intent of the CZMA to manage the coastal
areas.
Clean Water
Act. The
Driftwood Project is subject to the CWA and analogous state and
local laws. The CWA and analogous state and local laws regulate
discharges of pollutants to waters of the U.S. or waters of the
state, including discharges of wastewater and storm water runoff
and discharges of dredged or fill material into waters of the U.S.,
as well as spill prevention, control and countermeasure
requirements. Permits must be obtained prior to discharging
pollutants into state and federal waters or dredging or filling
wetland and coastal areas. The CWA is administered by the EPA, the
USACE and by the states. Additionally, the siting and construction
of the Driftwood Project may potentially impact jurisdictional
wetlands, which would require appropriate federal, state and/or
local permits and approval prior to impacting such wetlands. The
authorizing agency may impose significant direct or indirect
mitigation costs to compensate for regulated impacts to wetlands.
The approval timeframe may also be longer than expected and could
potentially affect project schedules.
In June 2015, the
EPA issued a final rule that attempts to clarify the CWA’s
jurisdictional reach over waters of the U.S. In February 2018, the
EPA issued a rule that delays the applicability of the new
definition of the waters of the U.S. until February 2020. On August
16, 2018, the U.S. District Court for South Carolina found that the
EPA and the USACE failed to comply with the Administrative
Procedure Act and struck the 2018 rule that attempted to delay the
applicability date of the 2015 Clean Water Rule. Other district
courts, however, have issued rulings temporarily enjoining the
applicability of the 2015 Clean Water Rule itself. Taken together,
the 2015 Clean Water Rule is currently in effect in 23 states, and
temporarily stayed in the remaining states. In those remaining
states, the 1986 rule and guidance remain in effect. On December
11, 2018, the EPA and the USACE issued a proposed new rule that
would differently revise the definition of “waters of the United
States” and essentially replace both the 1986 rule and the 2015
Clean Water Rule. According to the agencies, the proposed new rule
is “intended to increase CWA program predictability and consistency
by increasing clarity as to the scope of ‘waters of the United
States’ federally regulated under the Act.” If finalized, this new
definition of “waters of the United States” will likely be
challenged and sought to be enjoined in federal court. If and when
a final rule (as issued or revised) goes into effect, it could
expand the scope of the CWA’s jurisdiction, which could result in
increased costs and delays with respect to obtaining permits for
discharges or pollutants or dredge and fill activities in waters of
the U.S., including wetland areas.
Resource
Conservation and Recovery Act. The federal RCRA and
comparable state requirements govern the generation, handling and
disposal of solid and hazardous wastes and require corrective
action for releases into the environment. In the event such wastes
are generated or used in connection with our facilities, we will be
subject to regulatory requirements affecting the handling,
transportation, treatment, storage and disposal of such wastes and
could be required to perform corrective action measures to clean up
releases of such wastes. The EPA and certain environmental groups
have entered into an agreement pursuant to which the EPA is
required to propose, no later than March 15, 2019, a rulemaking for
revision of certain regulations pertaining to oil and natural gas
wastes or sign a determination that revision of the regulations is
not necessary. If the EPA proposes a rulemaking for revised oil and
natural gas waste regulations, the EPA will be required to take
final action following notice and comment rulemaking no later than
July 15, 2021. A loss of the exclusion from RCRA coverage for
drilling fluids, produced waters and related wastes could result in
a significant increase in our costs to manage and dispose of waste
associated with our production operations.
Federal laws
including the CWA require certain owners or operators of facilities
that store or otherwise handle oil and produced water to prepare
and implement spill prevention, control, countermeasure and
response plans addressing the possible discharge of oil into
surface waters. The Oil Pollution Act of 1990 (“OPA”) subjects
owners and operators of facilities to strict and joint and several
liability for all containment and cleanup costs and certain other
damages arising from oil spills, including the government’s
response costs. Spills subject to the OPA may result in varying
civil and criminal penalties and liabilities.
The
Comprehensive Environmental Response, Compensation and Liability
Act (“CERCLA”). CERCLA, often referred to as
Superfund, and comparable state statutes, impose liability that is
generally joint and several and that is retroactive for costs of
investigation and remediation and for natural resource damages,
without regard to fault or the legality of the original conduct, on
specified classes of persons for the release of a “hazardous
substance” (or under state law, other specified substances) into
the environment. So-called potentially responsible parties (“PRPs”)
include the current and certain past owners and operators of a
facility where there has been a release or threat of release of a
hazardous substance and persons who disposed of or arranged for the
disposal of hazardous substances found at a site. CERCLA also
authorizes the EPA and, in some cases, third parties to take
actions in response to threats to the public health or the
environment and to seek to recover from the PRPs the cost of such
action. Liability can arise from conditions on properties where
operations are conducted, even under circumstances where such
operations were performed by third parties and/or from conditions
at disposal facilities where materials from operations were sent.
Although CERCLA currently exempts petroleum (including oil and
natural gas) from the definition of hazardous substance, some
similar state statutes do not provide such an exemption. We cannot
ensure that this exemption will be preserved in any future
amendments of the act. Such amendments could have a material impact
on our costs or operations. Additionally, our operations may
involve the use or handling of other materials that may be
classified as hazardous substances under CERCLA or regulated under
similar state statutes. We may also be the owner or operator of
sites on which hazardous substances have been released and may be
responsible for investigation, management and disposal of
contaminated soils or dredge spoils in connection with our
operations.
Oil and natural
gas exploration and production, and possibly other activities, have
been conducted at a majority of our properties by previous owners
and operators. Materials from these operations remain on some of
the properties and in certain instances may require remediation. In
some instances, we have agreed to indemnify the sellers of
producing properties from whom we have acquired reserves against
certain liabilities for environmental claims associated with the
properties.
Hydraulic
Fracturing. Hydraulic fracturing is
commonly used to stimulate production of crude oil and/or natural
gas from dense subsurface rock formations. We plan to use hydraulic
fracturing extensively in our natural gas production operations.
The process involves the injection of water, sand, and additives
under pressure into a targeted subsurface formation. The water and
pressure create fractures in the rock formations which are held
open by the grains of sand, enabling the natural gas to more easily
flow to the wellbore. The process is generally subject to
regulation by state oil and natural gas commissions but is also
subject to new and changing regulatory programs at the federal,
state and local levels.
Beginning in
2012, the EPA implemented CAA standards (New Source Performance
Standards and National Emission Standards for Hazardous Air
Pollutants) applicable to new and modified hydraulically fractured
natural gas wells and certain storage vessels. The standards
require, among other things, use of reduced emission completions,
or “green” completions, to reduce volatile organic compound
emissions during well completions as well as new controls
applicable to a wide variety of storage tanks and other equipment,
including compressors, controllers, and dehydrators.
In February 2014,
the EPA issued permitting guidance under the Safe Drinking Water
Act (the “SDWA”) for the underground injection of liquids from
hydraulically fractured wells and other wells where diesel is used.
Depending upon how it is implemented, this guidance may create
duplicative requirements in certain areas, further slow the
permitting process in certain areas, increase the costs of
operations, and result in expanded regulation of hydraulic
fracturing activities by the EPA.
In May 2014, the
EPA issued an advance notice of proposed rulemaking under the Toxic
Substances Control Act pursuant to which it will collect extensive
information on the chemicals used in hydraulic fracturing fluid, as
well as other health-related data, from chemical manufacturers and
processors.
The U.S.
Department of the Interior, through the Bureau of Land Management
(the “BLM”), finalized a rule in 2015 requiring the disclosure of
chemicals used, mandating well integrity measures and imposing
other requirements relating to hydraulic fracturing on federal
lands. The BLM rescinded the rule in December 2017; however, the
BLM’s rescission has been challenged by several states in the U.S.
District Court of the District of Northern California.
In June 2016, the
EPA finalized pretreatment standards for indirect discharges of
wastewater from the oil and natural gas extraction industry. The
regulation prohibits sending wastewater pollutants from onshore
unconventional oil and natural gas extraction facilities to
publicly-owned treatment works.
In June 2016, the
EPA finalized additional new source performance standards under the
CAA to reduce methane emissions from new and modified sources in
the oil and natural gas sector. These new regulations impose, among
other things, new requirements for leak detection and repair,
control requirements at oil well completions, and additional
control requirements for gathering, boosting, and compressor
stations. On September 11, 2018, the EPA proposed revisions to the
2016 rules. The proposed amendments address certain technical
issues raised in administrative petitions and include proposed
changes to, among other things, the frequency of monitoring for
fugitive emissions at well sites and compressor
stations.
In November 2016,
the BLM finalized rules to further regulate venting, flaring, and
leaks during oil and natural gas production activities on onshore
federal and Indian leases. On September 28, 2018, the BLM published
a final rule that revises the 2016 rules. The new rule, among other
things, rescinds the 2016 rule requirements related to
waste-minimization plans, gas-capture percentages, well drilling,
well completion and related operations, pneumatic controllers,
pneumatic diaphragm pumps, storage vessels, and leak detection and
repair. The new rule also revised provisions related to venting and
flaring. Environmental groups and the States of California and New
Mexico have filed challenges to the 2018 rule in the United States
District Court for the Northern District of
California.
In December 2016,
the EPA released a report titled “Hydraulic Fracturing for Oil and
Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking
Water Resources.” The report concluded that activities involved in
hydraulic fracturing can have impacts on drinking water under
certain circumstances. In addition, the U.S. Department of Energy
has investigated practices that the agency could recommend to
better protect the environment from drilling using hydraulic
fracturing completion methods. These and similar studies, depending
on their degree of development and nature of results obtained,
could spur initiatives to further regulate hydraulic fracturing
under the SDWA or other regulatory mechanisms .
Endangered
Species Act (“ESA”). Our operations may be
restricted by requirements under the ESA. The ESA prohibits the
harassment, harming or killing of certain protected species and
destruction of protected habitats. Under the NEPA review process
conducted by FERC, we will be required to consult with federal
agencies to determine limitations on and mitigation measures
applicable to activities that have the potential to result in harm
to threatened or endangered species of plants, animals, fish and
their designated habitats.
Regulation of Natural Gas Production
Our natural gas
production operations are subject to a number of additional laws,
rules and regulations that require, among other things, permits for
the drilling of wells, drilling bonds and reports concerning
operations. States, parishes and municipalities in which we operate
may regulate, among other things:
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the location of
new wells;
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the method of
drilling, completing and operating wells;
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the surface use
and restoration of properties upon which wells are
drilled;
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the plugging and
abandoning of wells;
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notice to surface
owners and other third parties; and
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produced water
and waste disposal.
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State laws
regulate the size and shape of drilling and spacing units or
proration units governing the pooling of oil and natural gas
properties. Some states, including Louisiana, allow forced pooling
or integration of tracts to facilitate exploration, while other
states rely on voluntary pooling of lands and leases. In some
instances, forced pooling or unitization may be implemented by
third parties and may reduce our interest in the unitized
properties. In addition, state conservation laws establish maximum
rates of production from oil and natural gas wells and generally
prohibit the venting or flaring of natural gas and require that oil
and natural gas be produced in a prorated, equitable system. These
laws and regulations may limit the amount of oil and natural gas
that we can produce from our wells or limit the number of wells or
the locations at which we can drill. Moreover, most states
generally impose a production, ad valorem or severance tax with
respect to the production and sale of oil and natural gas within
their jurisdictions. Many local authorities also impose an ad
valorem tax on the minerals in place. States do not generally
regulate wellhead prices or engage in other, similar direct
economic regulation, but there can be no assurance they will not do
so in the future.
Anti-Corruption Laws
Our international
operations are subject to one or more anti-corruption laws in
various jurisdictions, such as the U.S. Foreign Corrupt Practices
Act of 1977, as amended (the “FCPA”), the U.K. Bribery Act of 2010
and other anti-corruption laws. The FCPA and these other laws
generally prohibit employees and intermediaries from bribing or
making other prohibited payments to foreign officials or other
persons to obtain or retain business or gain some other business
advantage. We participate in relationships with third parties whose
actions could potentially subject us to liability under the FCPA or
other anti-corruption laws. In addition, we cannot predict the
nature, scope or effect of future regulatory requirements to which
our international operations might be subject or the manner in
which existing laws might be administered or
interpreted.
We are also
subject to other laws and regulations governing our international
operations, including regulations administered by the U.S.
Department of Commerce’s Bureau of Industry and Security, the U.S.
Department of Treasury’s Office of Foreign Assets Control, and
various non-U.S. government entities, including applicable export
control regulations, economic sanctions on countries and persons,
customs requirements, currency exchange regulations, and transfer
pricing regulations (collectively, “Trade Control
laws”).
We are also
subject to new U.K. corporate criminal offenses for failure to
prevent the facilitation of tax evasion pursuant to the Criminal
Finances Act 2017, which imposes criminal liability on a company
where it has failed to prevent the criminal facilitation of tax
evasion by a person associated with the company.
We have
instituted policies, procedures and ongoing training of employees
with regard to business ethics, designed to ensure that we and our
employees comply with the FCPA, other anti-corruption laws, Trade
Control laws and the Criminal Finances Act 2017. However, there is
no assurance that our efforts have been and will be completely
effective in ensuring our compliance with all applicable
anti-corruption laws, including the FCPA or other legal
requirements. If we are not in compliance with the FCPA, other
anti-corruption laws, Trade Control laws or the Criminal Finances
Act 2017, we may be subject to criminal and civil penalties,
disgorgement and other sanctions and remedial measures, and legal
expenses, which could have a material adverse impact on our
business, financial condition, results of operations and liquidity.
Likewise, any investigation of any potential violations of the
FCPA, other anti-corruption laws or the Criminal Finances Act 2017
by the U.S. or foreign authorities could have a material adverse
impact on our reputation, business, financial condition and results
of operations.
Competition
We are subject to
a high degree of competition in all aspects of our business. See
“Item 1A — Risk Factors — Risks Relating to Our Business in General
— Competition
is intense in the energy industry and some of Tellurian’s
competitors have greater financial, technological and other
resources. ”
Production
& Transportation. The natural gas and oil
business is highly competitive in the exploration for and
acquisition of reserves, the acquisition of natural gas and oil
leases, equipment and personnel required to develop and produce
reserves, and the gathering, transportation and marketing of
natural gas and oil. Our competitors include national oil
companies, major integrated natural gas and oil companies, other
independent natural gas and oil companies, and participants in
other industries supplying energy and fuel to industrial,
commercial, and individual consumers, such as operators of
pipelines and other midstream facilities. Many of our competitors
have longer operating histories, greater name recognition, larger
staffs and substantially greater financial, technical and marketing
resources than we currently possess.
Liquefaction.
The Driftwood
terminal will compete with liquefaction facilities worldwide to
supply low-cost liquefaction to the market. There are a number of
liquefaction facilities worldwide that we compete with for
customers. Many of the companies with which we compete have greater
name recognition, larger staffs and substantially greater
financial, technical and marketing resources than we
do.
LNG
Marketing. Tellurian competes with a
variety of companies in the global LNG market, including (i)
integrated energy companies that market LNG from their own
liquefaction facilities, (ii) trading houses and aggregators with
LNG supply portfolios, and (iii) liquefaction plant operators that
market equity volumes. Many of the companies with which we compete
have greater name recognition, larger staffs, greater access to the
LNG market and substantially greater financial, technical, and
marketing resources than we do.
Title to
Properties
With respect to
our natural gas producing properties, we believe that we hold good
and defensible leasehold title to substantially all of our
properties in accordance with standards generally accepted in the
industry. A preliminary title examination is conducted at the time
the properties are acquired. Our natural gas properties are subject
to royalty, overriding royalty, and other outstanding
interests.
We believe that
we hold good title to our other properties, subject to customary
burdens, liens, or encumbrances that we do not expect to materially
interfere with our use of the properties.
Major
Customers
We do not have
any major customers.
Facilities
Certain
subsidiaries of Tellurian have entered into operating leases for
office space in Houston, Texas, Washington, D.C., London, England
and Singapore. The tenors of the leases are three, five, eight and
10 years for Singapore, London, Houston and Washington, D.C.,
respectively.
Employees
As of December
31, 2018, Tellurian had 172 full-time employees worldwide, none of
whom are subject to collective bargaining
arrangements.
Jurisdiction
and Year of Formation
The Company is a
Delaware corporation originally formed in 1967 and formerly known
as Magellan Petroleum Corporation.
Available
Information
We file annual,
quarterly and current reports, proxy statements and other
information with the SEC. Our SEC filings are available free of
charge from the SEC’s website at www.sec.gov or from our website at
www.tellurianinc.com. We also make available free of charge any of
our SEC filings by mail. For a mailed copy of a report, please
contact Tellurian Inc., Investor Relations, 1201 Louisiana Street,
Suite 3100, Houston, Texas 77002.
ITEM 1A.
RISK FACTORS
Our business
activities and the value of our securities are subject to
significant hazards and risks, including those described below. If
any of such events should occur, our business, financial condition,
liquidity, and/or results of operations could be materially harmed,
and holders and purchasers of our securities could lose part or all
of their investments. Our risk factors are grouped into the
following categories:
• Risks
Relating to Financial Matters;
• Risks
Relating to Our Common Stock;
• Risks
Relating to Our LNG Business;
• Risks
Relating to Our Natural Gas and Oil Production Activities;
and
• Risks
Relating to Our Business in General.
Risks
Relating to Financial Matters
Tellurian will be required to seek additional equity and/or debt
financing in the future to complete the Driftwood Project and to
grow its other operations, and may not be able to secure such
financing on acceptable terms, or at all.
Tellurian will be
unable to generate any significant revenue from the Driftwood
Project for multiple years, and expects cash flow from its other
lines of business to be modest for an extended period as it focuses
on the development and growth of these operations. Tellurian will
therefore need substantial amounts of additional financing to
execute its business plan. There can be no assurance that Tellurian
will be able to raise sufficient capital on acceptable terms, or at
all. If such financing is not available on satisfactory terms, or
is not available at all, Tellurian may be required to delay, scale
back or cancel the development of business
opportunities,
and this could adversely affect its operations and financial
condition to a significant extent. Tellurian intends to pursue a
variety of potential financing transactions, including sales of
equity of Driftwood Holdings to purchasers of its LNG. We do not
know whether, and to what extent, LNG purchasers and other
potential sources of financing will find the terms we propose
acceptable.
Debt or preferred
equity financing, if obtained, may involve agreements that include
liens or restrictions on Tellurian’s assets and covenants limiting
or restricting our ability to take specific actions, such as paying
dividends or making distributions, incurring additional debt,
acquiring or disposing of assets and increasing expenses. Debt
financing would also be required to be repaid regardless of
Tellurian’s operating results.
In addition, the
ability to obtain financing for the proposed Driftwood Project may
depend in part on Tellurian’s ability to enter into sufficient
commercial agreements prior to the commencement of construction. To
date, Tellurian has not entered into any definitive third-party
agreements for the proposed Driftwood Project, and it may not be
successful in negotiating and entering into such
agreements.
We have a very limited operating history and expect to incur losses
for a significant period of time.
We only recently
commenced operations. Although Tellurian’s current directors,
managers and officers have prior professional and industry
experience, our business is in an early stage of development.
Accordingly, the prior history, track record and historical
financial information you may use to evaluate our prospects are
limited.
Tellurian has not
yet commenced the construction of the Driftwood Project and expects
to incur significant additional costs and expenses through
completion of development and construction of that project. The
Company also expects to devote substantial amounts of capital to
the growth and development of its other operations. Tellurian
expects that operating losses will increase substantially in 2019
and thereafter, and expects to continue to incur operating losses
and to experience negative operating cash flows for the next
several years.
Tellurian’s exposure to the performance and credit risks of its
counterparties may adversely affect its operating results,
liquidity and access to financing.
Our operations
involve our entering into various construction, purchase and sale,
hedging, supply and other transactions with numerous third parties.
In such arrangements, we will be exposed to the performance and
credit risks of our counterparties, including the risk that one or
more counterparties fail to perform their obligations under the
applicable agreement. Some of these risks may increase during
periods of commodity price volatility. In some cases, we will be
dependent on a single counterparty or a small group of
counterparties, all of whom may be similarly affected by changes in
economic and other conditions. These risks include, but are not
limited to, risks related to the construction of the Driftwood
Project discussed below in “ — Risks Relating to Our LNG Business
— Tellurian
will be dependent on third-party contractors for the successful
completion of the Driftwood Project, and these contractors may be
unable to complete the Driftwood Project .” Defaults by suppliers and
other counterparties may adversely affect our operating results,
liquidity and access to financing.
Our use of hedging arrangements may adversely affect our future
operating results or liquidity.
As we continue to
ramp up our LNG and natural gas marketing activities, in an effort
to reduce our exposure to fluctuations in price and timing risk,
any hedging arrangements entered into would expose us to the risk
of financial loss when (i) the counterparty to the hedging contract
defaults on its contractual obligations or (ii) there is a change
in the expected differential between the underlying price in the
hedging agreement and the actual prices received. Also, commodity
derivative arrangements may limit the benefit we would otherwise
receive from a favorable change in the relevant commodity price. In
addition, regulations issued by the Commodities Futures Trading
Commission, the SEC and other federal agencies establishing
regulation of the over-the-counter derivatives market could
adversely affect our ability to manage our price risks associated
with our LNG and natural gas activity and therefore have a negative
impact on our operating results and cash flows.
Changes in tax laws or exposure to additional income tax
liabilities could have a material impact on our financial
condition, results of operations and liquidity.
Factors that
could materially affect our future effective tax rates include but
are not limited to:
• changes
in the regulatory environment;
• changes
in accounting and tax standards or practices;
• changes
in the composition of operating income by tax jurisdiction;
and
• our
operating results before taxes.
We are subject to
income taxes in the U.S. and several foreign jurisdictions. Our
future effective tax rates could be affected by changes in the
composition of earnings in countries with differing tax rates,
changes in deferred tax assets and liabilities or changes in tax
laws. Foreign jurisdictions have also increased the volume of tax
audits of multinational corporations.
Further, many
countries have either recently changed or are considering changes
to their tax laws. Changes in tax laws could affect the
distribution of our earnings, result in double taxation and
adversely affect our results.
In December 2017,
the budget reconciliation act commonly referred to as the Tax Cuts
and Jobs Act of 2017 (the “Tax Act”) was signed into law, making
significant changes to the Internal Revenue Code of 1986, as
amended. At this time, the U.S. Department of Treasury has not yet
issued final regulations on all provisions of the Tax Act. There
may be future Congressional technical corrections to the Tax Act
and other regulatory guidance and/or administrative interpretations
to the Tax Act that are yet to be issued. We will continue to
examine the impact that new guidance and interpretation of the Tax
Act may have on our business. We urge our stockholders to consult
with their legal and tax advisors with respect to the legislation
and potential tax consequences of investing in our
stock.
In addition to
the impact of the Tax Act on our federal taxes, it may impact
taxation in other jurisdictions such as state income taxes. The
various state legislatures have not had sufficient time to respond
to the Tax Act. Accordingly, it is uncertain as to how the laws
will apply in the various state jurisdictions. Additionally, other
foreign governing bodies may enact changes in their tax laws in
reaction to the Tax Act that could result in changes to our global
tax position and materially affect our financial
position.
We are also
subject to examination by the Internal Revenue Service (the “IRS”)
and other tax authorities, including state revenue agencies and
other foreign governments. While we regularly assess the likelihood
of favorable or unfavorable outcomes resulting from examinations by
the IRS and other tax authorities to determine the adequacy of our
provision for income taxes, there can be no assurance that the
actual outcome resulting from these examinations will not
materially adversely affect our financial condition and operating
results. Additionally, the IRS and several foreign tax authorities
have increasingly focused attention on intercompany transfer
pricing with respect to sales of products and services and the use
of intangibles. Tax authorities could disagree with our
cross-jurisdictional transfer pricing or other matters and assess
additional taxes. If we do not prevail in any such disagreements,
our profitability may be affected.
Tellurian does not expect to generate sufficient cash to pay
dividends until the completion of construction of the Driftwood
Project.
Tellurian’s
directly and indirectly held assets currently consist primarily of
cash held for certain start-up and operating expenses, applications
for permits from regulatory agencies relating to the Driftwood
Project and certain real property and mineral interests related to
that project. Tellurian’s cash flow, and consequently its ability
to distribute earnings, is solely dependent upon the cash flow its
subsidiaries receive from the Driftwood Project and its other
operations. Tellurian’s ability to complete the Driftwood Project,
as discussed further below, is dependent upon its subsidiaries’
ability to obtain necessary regulatory approvals and raise the
capital necessary to fund the development of the project. We expect
that cash flows from our operations will be reinvested in the
business rather than used to fund dividends, that pursuing our
strategy will require substantial amounts of capital, and that the
required capital will exceed cash flows from operations for a
significant period.
Tellurian’s
ability to pay dividends in the future is uncertain and will depend
on a variety of factors, including limitations on the ability of it
or its subsidiaries to pay dividends under applicable law and/or
the terms of debt or other agreements, and the judgment of the
board of directors or other governing body of the relevant
entity.
Tellurian Production Holdings LLC and Tellurian Inc. may be unable
to fulfill their obligations under the credit agreement and related
guarantee.
As described in
“Our Business and Properties — 2018 Developments — Significant
Transactions,” in September 2018, Tellurian Production Holdings LLC
(“Production Holdings”) entered into a credit agreement providing
for the Term Loan, and Tellurian Inc. entered into a parent
guarantee pursuant to which it guaranteed the obligations of
Production Holdings relating to the Term Loan. Production Holdings’
ability to generate cash flows from operations sufficient to pay
interest and principal on its indebtedness will depend on its
future operating performance and financial condition and the
availability of refinancing indebtedness, which will be affected by
prevailing commodity prices and economic conditions and financial,
business and other factors, many of which are beyond its control.
If Production Holdings is unable to satisfy its obligations under
the Term Loan, Tellurian Inc. may be obligated to pay interest
and/or principal on the indebtedness pursuant to the parent
guarantee, and it may not have the financial resources to do so.
Tellurian Inc. does not currently have any material sources of
operating cash flows. An inability on the part of Production
Holdings to generate adequate cash flows from operations could
adversely affect our ability to execute our overall business plan,
and we could be required to sell assets, reduce our capital
expenditures or seek refinancing indebtedness to satisfy the
requirements of the Term Loan and the parent guarantee. These
alternative measures may be unavailable or inadequate and may
themselves adversely affect our overall business
strategy.
Restrictions in the credit agreement could limit the growth and
operations of Production Holdings.
The credit
agreement governing the Term Loan contains restrictions on
Production Holdings’ activities, certain of which are described in
Note 13, Long-Term
Borrowings , to the Consolidated
Financial Statements included in this report.
These covenants
may prevent Production Holdings from taking actions that it
believes would be in the best interest of its business and may make
it difficult for it to successfully execute its business strategy
or effectively compete with companies that are not similarly
restricted.
In addition, the
credit agreement requires Production Holdings to maintain a
commodity hedge position that covers at least a specified minimum,
but does not cover more than a specified maximum, of its
anticipated future production, and these requirements may limit
Production Holdings’ ability to pursue its preferred hedging
strategy. In addition, the entire amount of the Term Loan is
currently deemed to be outstanding, but Production Holdings is
generally prohibited from using the borrowed funds except pursuant
to a specified plan of development approved by the lenders.
Accordingly, there could be circumstances in which Production
Holdings is required to incur interest on funds borrowed but is
unable to use those funds in the way it believes is most
appropriate for its business.
If Production Holdings is unable to comply with the restrictions
and covenants in the credit agreement governing the Term Loan,
there could be a default under the agreement, which could result in
an acceleration of payment of funds borrowed under the
agreement.
The credit
agreement contains financial covenants. If Production Holdings is
unable to satisfy these covenants, it would be in default under the
agreement, and the lenders could elect to declare all the funds
borrowed thereunder to be due and payable, together with accrued
and unpaid interest, and institute foreclosure proceedings with
respect to its assets. The lenders could also seek to enforce the
parent guarantee against Tellurian Inc., which may not have
sufficient funds, or the ability to obtain sufficient funds, to
repay the amounts then due. In those circumstances, Production
Holdings and/or Tellurian Inc. could be forced into bankruptcy or
liquidation.
Risks
Relating to Our Common Stock
The price of our common stock has been and may continue to be
highly volatile, which may make it difficult for shareholders to
sell our common stock when desired or at attractive
prices.
The market price
of our common stock is highly volatile, and we expect it to
continue to be volatile for the foreseeable future. Adverse events
could trigger a significant decline in the trading price of our
common stock, including, among others, failure to obtain necessary
permits, unfavorable changes in commodity prices or commodity price
expectations, adverse regulatory developments, loss of a
relationship with a partner, litigation and departures of key
personnel. Furthermore, general market conditions, including the
level of, and fluctuations in, the trading prices of equity
securities generally could affect the price of our stock. The stock
markets frequently experience price and volume volatility that
affects many companies’ stock prices, often in ways unrelated to
the operating performance of those companies. These fluctuations
may affect the market price of our common stock.
The market price of our common stock could be adversely affected by
sales of substantial amounts of our common stock by us or our major
shareholders.
Sales of a
substantial number of shares of our common stock in the market by
us or any of our major shareholders, or the perception that these
sales may occur, could cause the market price of our common stock
to decline. In addition, the sale of these shares in the public
market, or the possibility of such sales, could impair our ability
to raise capital through the sale of additional equity securities.
Our insider trading policy permits our officers and directors, some
of whom own substantial percentages of our outstanding common
stock, to pledge shares of stock that they own as collateral for
loans subject to certain requirements. Some of our officers and
directors have pledged shares of stock in accordance with this
policy. In some circumstances, such pledges could result in large
amounts of shares of our stock being sold in the market in a short
period, which would be expected to have a significant adverse
effect on the trading price of the common stock. In addition, in
the future, we may issue shares of our common stock in connection
with acquisitions of assets or businesses or for other purposes.
Such issuances could have an adverse effect on the market value of
shares of our common stock, depending on market conditions at the
time, the terms of the issuance, and if applicable, the value of
the business or assets acquired and our success in exploiting the
properties or integrating the businesses we acquire.
Risks
Relating to Our LNG Business
Various economic and political factors could negatively affect the
development, construction and operation of LNG facilities,
including the Driftwood terminal, which could have a material
adverse effect on our business, contracts, financial condition,
operating results, cash flow, liquidity and prospects.
Commercial
development of an LNG facility takes a number of years, requires
substantial capital investment and may be delayed by factors such
as:
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increased
construction costs;
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economic
downturns, increases in interest rates or other events that may
affect the availability of sufficient financing for LNG projects on
commercially reasonable terms;
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decreases in the
price of natural gas or LNG, which might decrease the expected
returns relating to investments in LNG projects;
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the inability of
project owners or operators to obtain governmental approvals to
construct or operate LNG facilities; and
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political unrest
or local community resistance to the siting of LNG facilities due
to safety, environmental or security concerns.
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Our failure to
execute our business plan within budget and on schedule could
materially adversely affect our business, financial condition,
operating results, liquidity and prospects.
Tellurian’s estimated costs for the Driftwood Project and other
projects may not be accurate and are subject to change due to
several factors.
We currently
estimate the total cost of the Driftwood Project to be
approximately $28 billion, including owners’ costs, transaction
costs and contingencies but excluding interest costs incurred
during construction of the Driftwood terminal and other financing
costs. However, cost estimates for these and other projects we may
pursue are only approximations of the actual costs of construction.
Moreover, cost estimates may be inaccurate and may change due to
various factors, such as cost overruns, change orders, delays in
construction, legal and regulatory requirements, site issues,
increased component and material costs, escalation of labor costs,
labor disputes, changes in commodity prices, changes in foreign
currency exchange rates, increased spending to maintain Tellurian’s
construction schedule and other factors. For example, new or
increased tariffs on materials needed in the construction process
have been proposed or may be proposed in the future and such new or
increased tariffs could materially increase construction costs. In
particular, tariffs on imported steel may significantly increase
our construction costs. Similarly, cost overruns could occur as a
result of dredging-related expenditures incurred to comply with
water depth regulations in the Calcasieu Ship Channel. Our estimate
of the cost of construction of the Driftwood terminal is based on
the prices set forth in our LSTK EPC contracts with Bechtel which
are subject to adjustment by change orders, including for
consideration of cost escalation associated with the issuance of a
“notice to proceed” with respect to the Driftwood terminal after
December 31, 2017. Our cost estimates for the Haynesville
Global Access Pipeline and the Permian Global Access Pipeline are
more preliminary than the estimate for the Driftwood
pipeline.
Our failure to
achieve our cost estimates could materially adversely affect our
business, financial condition, operating results, liquidity and
prospects.
If third-party pipelines and other facilities interconnected to our
LNG facilities become unavailable to transport natural gas, this
could have a material adverse effect on our business, financial
condition, operating results, liquidity and prospects.
We will depend
upon third-party pipelines and other facilities that will provide
natural gas delivery options to our natural gas production
operations and our LNG facilities. If the construction of new or
modified pipeline connections is not completed on schedule or any
pipeline connection were to become unavailable for current or
future volumes of natural gas due to repairs, damage to the
facility, lack of capacity or any other reason, our ability to meet
our LNG sale and purchase agreement obligations and continue
shipping natural gas from producing operations or regions to end
markets could be restricted, thereby reducing our revenues. This
could have a material adverse effect on our business, financial
condition, operating results, liquidity and prospects.
Tellurian’s ability to generate cash may depend upon it entering
into contracts with third-party customers and the performance of
those customers under those contracts.
Tellurian has not
yet entered into, and may never be able to enter into, satisfactory
commercial arrangements with third- party customers for products
and services from the Driftwood Project.
Tellurian’s
business strategy may change regarding how and when the proposed
Driftwood Project’s export capacity is marketed. Also, Tellurian’s
business strategy may change due to an inability to enter into
agreements with customers or based on a variety of factors,
including the future price outlook, supply and demand of LNG,
natural gas liquefaction capacity, and global regasification
capacity. If our efforts to market the proposed Driftwood Project
and the LNG it will produce are not successful, Tellurian’s
business, results of operations, financial condition and prospects
may be materially and adversely affected.
We may not be able to purchase, receive or produce sufficient
natural gas to satisfy our delivery obligations under any LNG sale
and purchase agreements, which could have an adverse effect on
us.
Under LNG sale
and purchase agreements with our customers, we may be required to
make available to them a specified amount of LNG at specified
times. However, we may not be able to acquire or produce sufficient
quantities of natural gas or LNG to satisfy those obligations,
which may provide affected customers with the right to terminate
their LNG sale and purchase agreements. Our failure to purchase,
receive or produce sufficient quantities of natural gas or LNG in a
timely manner could have an adverse effect on our business,
contracts, financial condition, operating results, cash flow,
liquidity and prospects.
The construction and operation of the Driftwood Project and the
Pipeline Network remains subject to further approvals, and some
approvals may be subject to further conditions, review and/or
revocation.
The design,
construction and operation of LNG export terminals is a highly
regulated activity. The approval of FERC under Section 3 of the
NGA, as well as several other material governmental and regulatory
approvals and permits, is required to construct and operate an LNG
terminal. Even if the necessary authorizations initially required
to operate our proposed LNG facilities are obtained, such
authorizations are subject to ongoing conditions imposed by
regulatory agencies, and additional approval and permit
requirements may be imposed. Further, Tellurian must obtain and
maintain approvals to export LNG to FTA and non-FTA countries in
order to execute its business strategy. Tellurian and its
affiliates will be required to obtain governmental approvals and
authorizations to implement its proposed business strategy, which
includes the construction and operation of the Driftwood Project.
In particular, authorization from FERC and the DOE/FE is required
to construct and operate our proposed LNG facilities. In addition
to seeking to obtain approval for export to FTA countries,
Tellurian has filed an application to obtain approval for export to
non-FTA countries. Numerous permits and approvals will also be
required in connection with other aspects of the Driftwood Project,
including the construction and operation of the Pipeline Network
and our upstream operations.
There is no
assurance that Tellurian will obtain and maintain these
governmental permits, approvals and authorizations, and failure to
obtain and maintain any of these permits, approvals or
authorizations could have a material adverse effect on its
business, results of operations, financial condition and
prospects.
Tellurian will be dependent on third-party contractors for the
successful completion of the Driftwood terminal, and these
contractors may be unable to complete the Driftwood
terminal.
There is limited
recent industry experience in the U.S. regarding the construction
or operation of large-scale LNG facilities. The construction of the
Driftwood terminal is expected to take several years, will be
confined to a limited geographic area and could be subject to
delays, cost overruns, labor disputes and other factors that could
adversely affect financial performance or impair Tellurian’s
ability to execute its proposed business plan.
Timely and
cost-effective completion of the Driftwood terminal in compliance
with agreed-upon specifications will be highly dependent upon the
performance of Bechtel and other third-party contractors pursuant
to their agreements. However, Tellurian has not yet entered into
definitive agreements with all of the contractors, advisors and
consultants necessary for the development and construction of the
Driftwood terminal. Tellurian may not be able to successfully enter
into such construction contracts on terms or at prices that are
acceptable to it.
Further, faulty
construction that does not conform to Tellurian’s design and
quality standards may have an adverse effect on Tellurian’s
business, results of operations, financial condition and prospects.
For example, improper equipment installation may lead to a
shortened life of Tellurian’s equipment, increased operations and
maintenance costs or a reduced availability or production capacity
of the affected facility. The ability of Tellurian’s third-party
contractors to perform successfully under any agreements to be
entered into is dependent on a number of factors, including force
majeure events and such contractors’ ability to:
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design, engineer
and receive critical components and equipment necessary for the
Driftwood terminal to operate in accordance with specifications and
address any start-up and operational issues that may arise in
connection with the commencement of commercial
operations;
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attract, develop
and retain skilled personnel and engage and retain third-party
subcontractors, and address any labor issues that may
arise;
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post required
construction bonds and comply with the terms thereof, and maintain
their own financial condition, including adequate working
capital;
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adhere to any
warranties the contractors provide in their EPC contracts;
and
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respond to
difficulties such as equipment failure, delivery delays, schedule
changes and failure to perform by subcontractors, some of which are
beyond their control, and manage the construction process
generally, including engaging and retaining third-party
contractors, coordinating with other contractors and regulatory
agencies and dealing with inclement weather
conditions.
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Furthermore,
Tellurian may have disagreements with its third-party contractors
about different elements of the construction process, which could
lead to the assertion of rights and remedies under the related
contracts, resulting in a contractor’s unwillingness to perform
further work on the relevant project. Tellurian may also face
difficulties in commissioning a newly constructed facility. Any
significant delays in the development of the Driftwood terminal
could materially and adversely affect Tellurian’s business, results
of operations, financial condition and prospects. In addition, the
construction of the pipelines in the Pipeline Network and other
infrastructure we build in connection with the Driftwood Project or
otherwise will be subject to substantially all of the foregoing
risks, and the occurrence of any construction-related problem could
have a variety of adverse effects on our operations. In particular,
completion of the Driftwood pipeline will be required for the
long-term operations of the Driftwood terminal.
Tellurian’s construction and operations activities are subject to a
number of development risks, operational hazards, regulatory
approvals and other risks, which could cause cost overruns and
delays and could have a material adverse effect on its business,
results of operations, financial condition, liquidity and
prospects.
Siting,
development and construction of the Driftwood Project will be
subject to the risks of delay or cost overruns inherent in any
construction project resulting from numerous factors, including,
but not limited to, the following:
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difficulties or
delays in obtaining, or failure to obtain, sufficient equity or
debt financing on reasonable terms;
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failure to obtain
all necessary government and third-party permits, approvals and
licenses for the construction and operation of the Driftwood
Project or any other proposed LNG facilities;
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difficulties in
engaging qualified contractors necessary to the construction of the
contemplated Driftwood Project or other LNG
facilities;
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shortages of
equipment, material or skilled labor;
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natural disasters
and catastrophes, such as hurricanes, explosions, fires, floods,
industrial accidents and terrorism;
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unscheduled
delays in the delivery of ordered materials;
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work stoppages
and labor disputes;
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competition with
other domestic and international LNG export terminals;
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unanticipated
changes in domestic and international market demand for and supply
of natural gas and LNG, which will depend in part on supplies of
and prices for alternative energy sources and the discovery of new
sources of natural resources;
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unexpected or
unanticipated need for additional improvements; and
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adverse general
economic conditions.
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Delays beyond the
estimated development periods, as well as cost overruns, could
increase the cost of completion beyond the amounts that are
currently estimated, which could require Tellurian to obtain
additional sources of financing to fund the activities until the
proposed Driftwood terminal is constructed and operational (which
could cause further delays). Any delay in completion of the
Driftwood Project may also cause a delay in the receipt of revenues
projected from the Driftwood Project or cause a loss of one or more
customers. As a result, any significant construction delay,
whatever the cause, could have a material adverse effect on
Tellurian’s business, results of operations, financial condition,
liquidity and prospects. Similar risks may affect the construction
of other facilities and projects we elect to pursue.
Cyclical or other changes in the demand for and price of LNG and
natural gas may adversely affect Tellurian’s LNG business and the
performance of our customers and could lead to the reduced
development of LNG projects worldwide.
Tellurian’s plans
and expectations regarding its business and the development of
domestic LNG facilities and projects are generally based on
assumptions about the future price of natural gas and LNG and the
conditions of the global natural gas and LNG markets. Natural gas
and LNG prices have been, and are likely to remain in the future,
volatile and subject to wide fluctuations that are difficult to
predict. Such fluctuations may be caused by various factors,
including, but not limited to, one or more of the
following:
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competitive
liquefaction capacity in North America;
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insufficient or
oversupply of natural gas liquefaction or receiving capacity
worldwide;
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insufficient or
oversupply of LNG tanker capacity;
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reduced demand
and lower prices for natural gas;
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increased natural
gas production deliverable by pipelines, which could suppress
demand for LNG;
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decreased oil and
natural gas exploration activities, which may decrease the
production of natural gas;
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cost improvements
that allow competitors to offer LNG regasification services or
provide natural gas liquefaction capabilities at reduced
prices;
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changes in
supplies of, and prices for, alternative energy sources such as
coal, oil, nuclear, hydroelectric, wind and solar energy, which may
reduce the demand for natural gas;
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changes in
regulatory, tax or other governmental policies regarding imported
or exported LNG, natural gas or alternative energy sources, which
may reduce the demand for imported or exported LNG and/or natural
gas;
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political
conditions in natural gas producing regions; and
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cyclical trends
in general business and economic conditions that cause changes in
the demand for natural gas.
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Adverse trends or
developments affecting any of these factors could result in
decreases in the price of LNG and/or natural gas, which could
materially and adversely affect the performance of our customers,
and could have a material adverse effect on our business,
contracts, financial condition, operating results, cash flows,
liquidity and prospects.
Technological innovation may render Tellurian’s anticipated
competitive advantage or its processes obsolete.
Tellurian’s
success will depend on its ability to create and maintain a
competitive position in the natural gas liquefaction industry. In
particular, although Tellurian plans to construct the Driftwood
terminal using proven technologies that it believes provide it with
certain advantages, Tellurian does not have any exclusive rights to
any of the technologies that it will be utilizing. In addition, the
technology Tellurian anticipates using in the Driftwood Project may
be rendered obsolete or uneconomical by legal or regulatory
requirements, technological advances, more efficient and
cost-effective processes or entirely different approaches developed
by one or more of its competitors or others, which could materially
and adversely affect Tellurian’s business, results of operations,
financial condition, liquidity and prospects.
Failure of exported LNG to be a competitive source of energy for
international markets could adversely affect our customers and
could materially and adversely affect our business, contracts,
financial condition, operating results, cash flow, liquidity and
prospects.
Operations of the
Driftwood Project will be dependent upon our ability to deliver LNG
supplies from the U.S., which is primarily dependent upon LNG being
a competitive source of energy internationally. The success of our
business plan is dependent, in part, on the extent to which LNG
can, for significant periods and in significant volumes, be
supplied from North America and delivered to international markets
at a lower cost than the cost of alternative energy sources.
Through the use of improved exploration technologies, additional
sources of natural gas may be discovered outside the U.S., which
could increase the available supply of natural gas outside the U.S.
and could result in natural gas in those markets being available at
a lower cost than that of LNG exported to those
markets.
Factors which may
negatively affect potential demand for LNG from our liquefaction
projects are diverse and include, among others:
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increases in
worldwide LNG production capacity and availability of LNG for
market supply;
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increases in
demand for LNG but at levels below those required to maintain
current price equilibrium with respect to supply;
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increases in the
cost to supply natural gas feedstock to our liquefaction
project;
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decreases in the
cost of competing sources of natural gas or alternate sources of
energy such as coal, heavy fuel oil, diesel, nuclear,
hydroelectric, wind and solar;
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decreases in the
price of non-U.S. LNG, including decreases in price as a result of
contracts indexed to lower oil prices;
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increases in
capacity and utilization of nuclear power and related
facilities;
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increases in the
cost of LNG shipping; and
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displacement of
LNG by pipeline natural gas or alternative fuels in locations where
access to these energy sources is not currently
available.
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Political
instability in foreign countries that import natural gas, or
strained relations between such countries and the U.S., may also
impede the willingness or ability of LNG suppliers, purchasers and
merchants in such countries to import LNG from the U.S.
Furthermore, some foreign purchasers of LNG may have economic or
other reasons to obtain their LNG from non-U.S. markets or our
competitors’ liquefaction facilities in the U.S.
As a result of
these and other factors, LNG may not be a competitive source of
energy internationally. The failure of LNG to be a competitive
supply alternative to local natural gas, oil and other alternative
energy sources in markets accessible to our customers could
adversely affect the ability of our customers to deliver LNG from
the U.S. on a commercial basis. Any significant impediment to the
ability to deliver LNG from the U.S. generally, or from the
Driftwood Project specifically, could have a material adverse
effect on our customers and our business, contracts, financial
condition, operating results, cash flow, liquidity and
prospects.
There may be shortages of LNG vessels worldwide, which could have a
material adverse effect on Tellurian’s business, results of
operations, financial condition, liquidity and
prospects.
The construction
and delivery of LNG vessels require significant capital and long
construction lead times, and the availability of the vessels could
be delayed to the detriment of Tellurian’s business and customers
due to a variety of factors, including, but not limited to, the
following:
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an inadequate
number of shipyards constructing LNG vessels and a backlog of
orders at these shipyards;
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political or
economic disturbances in the countries where the vessels are being
constructed;
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changes in
governmental regulations or maritime self-regulatory
organizations;
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work stoppages or
other labor disturbances at the shipyards;
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bankruptcies or
other financial crises of shipbuilders;
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quality or
engineering problems;
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weather
interference or catastrophic events, such as a major earthquake,
tsunami, or fire; or
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shortages of or
delays in the receipt of necessary construction
materials.
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Any of these
factors could have a material adverse effect on Tellurian’s
business, results of operations, financial condition, liquidity and
prospects.
We will rely on third-party engineers to estimate the future
capacity ratings and performance capabilities of the Driftwood
terminal, and these estimates may prove to be
inaccurate.
We will rely on
third parties for the design and engineering services underlying
our estimates of the future capacity ratings and performance
capabilities of the Driftwood terminal. Any of our LNG facilities,
when constructed, may not have the capacity ratings and performance
capabilities that we intend or estimate. Failure of any of our
facilities to achieve our intended capacity ratings and performance
capabilities could prevent us from achieving the commercial start
dates under our future LNG sale and purchase agreements and could
have a material adverse effect on our business, contracts,
financial condition, operating results, cash flow, liquidity and
prospects.
The Driftwood Project will be subject to a number of environmental
laws and regulations that impose significant compliance costs, and
existing and future environmental and similar laws and regulations
could result in increased compliance costs, liabilities or
additional operating restrictions.
We will be
subject to extensive federal, state and local environmental
regulations and laws, including regulations and restrictions
related to discharges and releases to the air, land and water and
the handling, storage, generation and disposal of hazardous
materials and solid and hazardous wastes in connection with the
development, construction and operation of our LNG facilities and
pipelines. These regulations and laws, which include the CAA, the
Oil Pollution Act, the CWA and RCRA, and analogous state and local
laws and regulations, will restrict, prohibit or otherwise regulate
the types, quantities and concentration of substances that can be
released into the environment in connection with the construction
and operation of our facilities. These laws and regulations,
including NEPA, will require us to obtain and maintain permits with
respect to our facilities, prepare environmental impact
assessments, provide governmental authorities with access to our
facilities for inspection and provide reports related to
compliance. Federal and state laws impose liability, without regard
to fault or the lawfulness of the original conduct, for the release
of certain types or quantities of hazardous substances into the
environment. Violation of these laws and regulations could lead to
substantial liabilities, fines and penalties, the denial or
revocation of permits necessary for our operations, governmental
orders to shut down our facilities or capital expenditures related
to pollution control equipment or remediation measures that could
have a material adverse effect on Tellurian’s business, results of
operations, financial condition, liquidity and prospects. As the
owner and operator of the Driftwood Project, we could be liable for
the costs of investigating and cleaning up hazardous substances
released into the environment and for damage to natural resources,
whether caused by us or our contractors or existing at the time
construction commences. Hazardous substances present in soil,
groundwater and dredge spoils may need to be processed, disposed of
or otherwise managed to prevent releases into the environment.
Tellurian or its affiliates may be responsible for investigation,
cleanup, monitoring, removal, disposal and other remedial actions
with respect to hazardous substances on, in or under properties
Tellurian owns or operates, without regard to fault or the origin
of such hazardous substances. Such liabilities may involve material
costs that are unknown and not predictable.
Changes in legislation and regulations could have a material
adverse impact on Tellurian’s business, results of operations,
financial condition, liquidity and prospects.
Tellurian’s
business will be subject to governmental laws, rules, regulations
and permits that impose various restrictions and obligations that
may have material effects on our results of
operations.
In addition, each
of the applicable regulatory requirements and limitations is
subject to change, either through new regulations enacted on the
federal, state or local level, or by new or modified regulations
that may be implemented under existing law. The nature and effects
of these changes in laws, rules, regulations and permits may be
unpredictable and may have material effects on our business. Future
legislation and regulations, such as those relating to the
transportation and security of LNG exported from our proposed LNG
facilities through the Calcasieu Ship Channel, could cause
additional expenditures, restrictions and delays in connection with
the proposed LNG facilities and their construction, the extent of
which cannot be predicted and which may require Tellurian to limit
substantially, delay or cease operations in some circumstances.
Revised, reinterpreted or additional laws and regulations that
result in increased compliance costs or additional operating costs
and restrictions could have a material adverse effect on
Tellurian’s business, results of operations, financial condition,
liquidity and prospects.
Our operations will be subject to significant risks and hazards,
one or more of which may create significant liabilities and losses
that could have a material adverse effect on Tellurian’s business,
results of operations, financial condition, liquidity and
prospects.
We will face
numerous risks in developing and conducting our operations. For
example, the plan of operations for the proposed Driftwood Project
is subject to the inherent risks associated with LNG, pipeline and
upstream operations, including explosions, pollution, leakage or
release of toxic substances, fires, hurricanes and other adverse
weather conditions, leakage of hydrocarbons, and other hazards,
each of which could result in significant delays in commencement or
interruptions of operations and/or result in damage to or
destruction of the proposed Driftwood Project or damage to persons
and property. In addition, operations at the proposed Driftwood
Project and vessels or facilities of third parties on which
Tellurian’s operations are dependent could face possible risks
associated with acts of aggression or terrorism.
In 2005, 2008 and
2017, hurricanes damaged coastal and inland areas located in the
Gulf Coast area, resulting in disruption and damage to certain LNG
terminals located in the area. Future storms and related storm
activity and collateral effects, or other disasters such as
explosions, fires, floods or accidents, could result in damage to,
or interruption of operations at, the Driftwood terminal or related
infrastructure, as well as delays or cost increases in the
construction and the development of the Driftwood terminal or other
facilities. Storms, disasters and accidents could also damage or
interrupt the activities of vessels that we or third parties
operate in connection with our LNG business. Changes in the global
climate may have significant physical effects, such as increased
frequency and severity of storms, floods and rising sea levels. If
any such effects were to occur, they could have an adverse effect
on our coastal operations.
Our LNG business
will face other types of risks and liabilities as well. For
instance, our LNG marketing activities will expose us to possible
financial losses, including the risk of losses resulting from
adverse changes in the index prices upon which contracts for the
purchase and sale of LNG cargoes are based. Our LNG marketing
activities will also be subject to various domestic and
international regulatory and foreign currency risks.
Tellurian does
not, nor does it intend to, maintain insurance against all of these
risks and losses, and many risks are not insurable. Tellurian may
not be able to maintain desired or required insurance in the future
at rates that it considers reasonable. The occurrence of a
significant event not fully insured or indemnified against could
have a material adverse effect on Tellurian’s business, contracts,
financial condition, operating results, cash flow, liquidity and
prospects.
Risks
Relating to Our Natural Gas and Oil Production
Activities
Acquisitions of natural gas and oil properties are subject to the
uncertainties of evaluating reserves and potential liabilities,
including environmental uncertainties.
We expect to
pursue acquisitions of natural gas and oil properties from time to
time. Successful acquisitions require an assessment of a number of
factors, many of which are beyond our control. These factors
include reserves, development potential, future commodity prices,
operating costs, title issues, and potential environmental and
other liabilities. Such assessments are inexact and their accuracy
is inherently uncertain. In connection with our assessments, we
perform due diligence that we believe is generally consistent with
industry practices. However, our due diligence activities are not
likely to permit us to become sufficiently familiar with the
properties to fully assess their deficiencies and capabilities. We
do not inspect every well prior to an acquisition, and our ability
to evaluate undeveloped acreage is inherently imprecise. Even when
we inspect a well, we may not always discover structural,
subsurface, and environmental problems that may exist or arise. In
some cases, our review prior to signing a definitive purchase
agreement may be even more limited. In addition, we may acquire
acreage without any warranty of title except as to claims made by,
through or under the transferor.
When we acquire
properties, we will generally have potential exposure to
liabilities and costs for environmental and other problems existing
on the acquired properties, and these liabilities may exceed our
estimates. We may not be entitled to contractual indemnification
associated with acquired properties. We may acquire interests in
properties on an “as is” basis with limited or no remedies for
breaches of representations and warranties.
Therefore, we
could incur significant unknown liabilities, including
environmental liabilities or losses due to title defects, in
connection with acquisitions for which we have limited or no
contractual remedies or insurance coverage. In addition, the
acquisition of undeveloped acreage is subject to many inherent
risks, and we may not be able to realize efficiently, or at all,
the assumed or expected economic benefits of acreage that we
acquire.
In addition,
acquiring additional natural gas and oil properties, or businesses
that own or operate such properties, when attractive opportunities
arise is a significant component of our strategy, and we may not be
able to identify attractive acquisition opportunities. If we do
identify an appropriate acquisition candidate, we may be unable to
negotiate mutually acceptable terms with the seller, finance the
acquisition or obtain the necessary regulatory approvals. It may be
difficult to agree on the economic terms of a transaction, as a
potential seller may be unwilling to accept a price that we believe
to be appropriately reflective of prevailing economic conditions.
If we are unable to complete suitable acquisitions, it will be more
difficult to pursue our overall strategy.
Natural gas and oil prices fluctuate widely, and lower prices for
an extended period of time may have a material adverse effect on
the profitability of our natural gas or oil production
activities.
The revenues,
operating results and profitability of our natural gas or oil
production activities will depend significantly on the prices we
receive for the natural gas or oil we sell. We will require
substantial expenditures to replace reserves, sustain production
and fund our business plans. Low natural gas or oil prices can
negatively affect the amount of cash available for acquisitions and
capital expenditures and our ability to raise additional capital
and, as a result, could have a material adverse effect on our
revenues, cash flow and reserves. In addition, low natural gas or
oil prices may result in write-downs of our natural gas or oil
properties. Conversely, any substantial or extended increase in the
price of natural gas would adversely affect the competitiveness of
LNG as a source of energy. See risks discussed above in “ — Risks
Relating to Our LNG Business — Failure of
exported LNG to be a competitive source of energy for international
markets could adversely affect our customers and could materially
and adversely affect our business, contracts, financial condition,
operating results, cash flow, liquidity and prospects
.” Part of our
strategy involves adjusting the level of our natural gas
development activities based on our judgment as to whether it will
be most cost-effective to source natural gas for the Driftwood
terminal from our own production or, instead, from natural gas
produced by third parties. In some circumstances, making these
adjustments may involve costs. For example, a decrease in our
activities may result in the expiration of leases or an increase in
costs on a per-unit basis.
Historically, the
markets for natural gas and oil have been volatile, and they are
likely to continue to be volatile. Wide fluctuations in natural gas
or oil prices may result from relatively minor changes in the
supply of or demand for natural gas or oil, market uncertainty and
other factors that are beyond our control. The volatility of the
energy markets makes it extremely difficult to predict future
natural gas or oil price movements, and we will be unable to fully
hedge our exposure to natural gas or oil prices.
Significant capital expenditures will be required to grow our
natural gas or oil production activities in accordance with our
plans.
Our planned
development and acquisition activities will require substantial
capital expenditures. We intend to fund our capital expenditures
for our natural gas and oil production activities through cash on
hand and financing transactions that may include public or private
equity or debt offerings or borrowings under additional debt
agreements. We expect to generate only modest cash flows for a
significant period of time from our producing properties. Our
ability to generate operating cash flow in the future will be
subject to a number of risks and variables, such as the level of
production from existing wells, the price of natural gas or oil,
our success in developing and producing new reserves and the other
risk factors discussed in this section. If we are unable to fund
our capital expenditures for natural gas or oil production
activities as planned, we could experience a curtailment of our
development activity and a decline in our natural gas or oil
production, and that could affect our ability to pursue our overall
strategy.
We have limited control over the activities on properties we do not
operate.
Some of the
properties in which we have an interest are operated by other
companies and involve third-party working interest owners. As a
result, we have limited ability to influence or control the
operation or future development of such properties, including
compliance with environmental, safety and other regulations, or the
amount of capital expenditures that we will be required to fund
with respect to such properties. Moreover, we are dependent on the
other working interest owners of such projects to fund their
contractual share of the capital expenditures of such projects. In
addition, a third-party operator could also decide to shut-in or
curtail production from wells, or plug and abandon marginal wells,
on properties owned by that operator during periods of lower
natural gas or oil prices. These limitations and our dependence on
the operator and third-party working interest owners for these
projects could cause us to incur unexpected future costs, reduce
our production and materially and adversely affect our financial
condition and results of operations.
Drilling and producing operations can be hazardous and may expose
us to liabilities.
Natural gas and
oil operations are subject to many risks, including well blowouts,
explosions, pipe failures, fires, formations with abnormal
pressures, uncontrollable flows of oil, natural gas, brine or well
fluids, leakages or releases of hydrocarbons, severe
weather, natural
disasters, groundwater contamination and other environmental
hazards and risks. For our non-operated properties, we will be
dependent on the operator for regulatory compliance and for the
management of these risks.
These risks could
materially and adversely affect our revenues and expenses by
reducing production from wells, causing wells to be shut in or
otherwise negatively impacting our projected economic performance.
If any of these risks occurs, we could sustain substantial losses
as a result of:
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injury or loss of
life;
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severe damage to
or destruction of property, natural resources or
equipment;
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pollution or
other environmental damage;
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facility or
equipment malfunctions and equipment failures or
accidents;
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clean-up
responsibilities;
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regulatory
investigations and administrative, civil and criminal penalties;
and
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injunctions
resulting in limitation or suspension of operations.
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Any of these
events could expose us to liabilities, monetary penalties or
interruptions in our business operations. In addition, certain of
these risks are greater for us than for many of our competitors in
that some of the natural gas we produce has a high sulphur content
(sometimes referred to as “sour” gas), which increases its
corrosiveness and the risk of an accidental release of hydrogen
sulfide gas, exposure to which can be fatal. We may not maintain
insurance against such risks, and some risks are not insurable.
Even when we are insured, our insurance may not be adequate to
cover casualty losses or liabilities. Also, in the future, we may
not be able to obtain insurance at premium levels that justify its
purchase. The occurrence of a significant event against which we
are not fully insured may expose us to liabilities.
Our drilling efforts may not be profitable or achieve our targeted
returns and our reserve estimates are based on assumptions that may
not be accurate.
Drilling for
natural gas and oil may involve unprofitable efforts from wells
that are productive but do not produce sufficient commercial
quantities to cover drilling, operating and other costs. In
addition, even a commercial well may have production that is less,
or costs that are greater, than we projected. The cost of drilling,
completing and operating a well is often uncertain, and many
factors can adversely affect the economics of a well or property.
Drilling operations may be curtailed, delayed or canceled as a
result of unexpected drilling conditions, equipment failures or
accidents, shortages of equipment or personnel, environmental
issues and for other reasons.
Natural gas and
oil reserve engineering requires estimates of underground
accumulations of hydrocarbons and assumptions concerning future
prices, production levels and operating and development costs. As a
result, estimated quantities of proved reserves and projections of
future production rates and the timing of development expenditures
may be incorrect. Our estimates of proved reserves are determined
at costs at the date of the estimate. Any significant variance from
these costs could greatly affect our estimates of reserves. At
December 31, 2018, approximately 93% of our estimated proved
reserves (by volume) were undeveloped. These reserve estimates
reflected our plans to make significant capital expenditures to
convert our PUDs into proved developed reserves. The estimated
development costs may not be accurate, development may not occur as
scheduled and results may not be as estimated. If we choose not to
develop PUDs, or if we are not otherwise able to successfully
develop them, we will be required to remove the associated volumes
from our reported proved reserves. In addition, under the SEC’s
reserve reporting rules, PUDs generally may be booked only if they
relate to wells scheduled to be drilled within five years of the
date of booking, and we may therefore be required to downgrade to
probable or possible any PUDs that are not developed within this
five-year time frame.
Our production activities are subject to complex laws and
regulations relating to environmental protection that can adversely
affect the cost, manner and feasibility of doing business, and
further regulation in the future could increase costs, impose
additional operating restrictions and cause delays.
Our natural gas
production activities and properties are (and to the extent that we
acquire oil producing properties, these properties will be) subject
to numerous federal, regional, state and local laws and regulations
governing the release of pollutants or otherwise relating to
environmental protection. These laws and regulations govern the
following, among other things:
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conduct of
drilling, completion, production and midstream
activities;
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amounts and types
of emissions and discharges;
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generation,
management, and disposal of hazardous substances and waste
materials;
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reclamation and
abandonment of wells and facility sites; and
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remediation of
contaminated sites.
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In addition,
these laws and regulations may result in substantial liabilities
for our failure to comply or for any contamination resulting from
our operations, including the assessment of administrative, civil
and criminal penalties; the imposition of investigatory, remedial,
and corrective action obligations or the incurrence of capital
expenditures; the occurrence of delays in the development of
projects; and the issuance of injunctions restricting or
prohibiting some or all of our activities in a particular
area.
Environmental
laws and regulations change frequently, and these changes are
difficult to predict or anticipate. Future environmental laws and
regulations imposing further restrictions on the emission of
pollutants into the air, discharges into state or U.S. waters,
wastewater disposal and hydraulic fracturing, or the designation of
previously unprotected species as threatened or endangered in areas
where we operate, may negatively impact our natural gas or oil
production. We cannot predict the actions that future regulation
will require or prohibit, but our business and operations could be
subject to increased operating and compliance costs if certain
regulatory proposals are adopted. In addition, such regulations may
have an adverse impact on our ability to develop and produce our
reserves.
Federal, state or local legislative and regulatory initiatives
relating to hydraulic fracturing could result in increased costs
and additional operating restrictions or delays.
Several states
are considering adopting regulations that could impose more
stringent permitting, public disclosure and/or well construction
requirements on hydraulic fracturing operations. In addition to
state laws, some local municipalities have adopted or are
considering adopting land use restrictions, such as city
ordinances, that may restrict or prohibit the performance of well
drilling in general and/or hydraulic fracturing in particular.
There are also certain governmental reviews either underway or
being proposed that focus on deep shale and other formation
completion and production practices, including hydraulic
fracturing. These studies assess, among other things, the risks of
groundwater contamination and earthquakes caused by hydraulic
fracturing and other exploration and production activities.
Depending on the outcome of these studies, federal and state
legislatures and agencies may seek to further regulate or even ban
such activities, as some state and local governments have already
done. We cannot predict whether additional federal, state or local
laws or regulations applicable to hydraulic fracturing will be
enacted in the future and, if so, what actions any such laws or
regulations would require or prohibit. If additional levels of
regulation or permitting requirements were imposed on hydraulic
fracturing operations, our business and operations could be subject
to delays, increased operating and compliance costs and process
prohibitions. Among other things, this could adversely affect the
cost to produce natural gas, either by us or by third-party
suppliers, and therefore LNG, and this could adversely affect the
competitiveness of LNG relative to other sources of
energy.
We expect to drill the locations we acquire over a multi-year
period, making them susceptible to uncertainties that could
materially alter the occurrence or timing of drilling.
Our management
team has identified certain well locations on our natural gas
properties. Our ability to drill and develop these locations
depends on a number of uncertainties, including natural gas prices,
the availability and cost of capital, drilling and production
costs, availability of drilling services and equipment, drilling
results, lease expirations, gathering system and pipeline
transportation constraints, access to and availability of water
sourcing and distribution systems, regulatory approvals and other
factors. Because of these factors, we do not know if the well
locations we have identified will ever be drilled or if we will be
able to produce natural gas from these or any other potential
locations.
The unavailability or high cost of drilling rigs, equipment,
supplies, personnel and services could adversely affect our ability
to execute our development plans within budgeted amounts and on a
timely basis.
The demand for
qualified and experienced field and technical personnel to conduct
our operations can fluctuate significantly, often in correlation
with hydrocarbon prices. The price of services and equipment may
increase in the future and availability may decrease. In addition,
it is possible that oil prices could increase without a
corresponding increase in natural gas prices, which could lead to
increased demand and prices for equipment, facilities and personnel
without an increase in the price at which we sell our natural gas
to third parties. This could have an adverse effect on the
competitiveness of the LNG produced from the Driftwood Project. In
this scenario, necessary equipment, facilities and services may not
be available to us at economical prices. Any shortages in
availability or increased costs could delay us or cause us to incur
significant additional expenditures, which could have a material
adverse effect on the competitiveness of the natural gas we sell
and therefore on our business, financial condition and results of
operations.
Our natural gas and oil production may be adversely affected by
pipeline and gathering system capacity constraints.
Our natural gas
and oil production activities will rely on third parties to meet
our needs for midstream infrastructure and services. Capital
constraints could limit the construction of new infrastructure by
third parties. We may experience delays in producing and selling
natural gas or oil from time to time when adequate midstream
infrastructure and services are not available. Such an event could
reduce our production or result in other adverse effects on our
business.
Risks
Relating to Our Business in General
We are pursuing a strategy of participating in multiple aspects of
the natural gas business, which exposes us to risks.
We plan to
develop, own and operate a global natural gas business and to
deliver natural gas to customers worldwide. We may not be
successful in executing our strategy in the near future, or at all.
Our management will be required to understand and manage a diverse
set of business opportunities, which may distract their focus and
make it difficult to be successful in increasing value for
shareholders.
Tellurian will be subject to risks related to doing business in,
and having counterparties based in, foreign countries.
Tellurian may
engage in operations or make substantial commitments and
investments, or enter into agreements with counterparties, located
outside the U.S., which would expose Tellurian to political,
governmental, and economic instability and foreign currency
exchange rate fluctuations.
Any disruption
caused by these factors could harm Tellurian’s business, results of
operations, financial condition, liquidity and prospects. Risks
associated with operations, commitments and investments outside of
the U.S. include but are not limited to risks of:
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•
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war or terrorist
attack;
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•
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expropriation or
nationalization of assets;
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•
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renegotiation or
nullification of existing contracts;
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•
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changing
political conditions;
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•
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changing laws and
policies affecting trade, taxation, and investment;
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•
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multiple taxation
due to different tax structures;
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•
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general hazards
associated with the assertion of sovereignty over areas in which
operations are conducted; and
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•
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the unexpected
credit rating downgrade of countries in which Tellurian’s LNG
customers are based.
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Because
Tellurian’s reporting currency is the U.S. dollar, any of the
operations conducted outside the U.S. or denominated in foreign
currencies would face additional risks of fluctuating currency
values and exchange rates, hard currency shortages and controls on
currency exchange. In addition, Tellurian would be subject to the
impact of foreign currency fluctuations and exchange rate changes
on its financial reports when translating the value of its assets,
liabilities, revenues and expenses from operations outside of the
U.S. into U.S. dollars at then-applicable exchange rates. These
translations could result in changes to the results of operations
from period to period.
Tellurian Investments and certain other Tellurian subsidiaries
(collectively, the “Tellurian Defendants”) are defendants in a
lawsuit that could result in equitable relief and/or monetary
damages that could have a material adverse effect on Tellurian’s
operating results and financial condition.
The Tellurian
Defendants, along with Tellurian director Martin Houston and three
other individuals as well as certain entities in which each of them
owned membership interests, as applicable, have been named as
defendants in a lawsuit as described in “Item 3 — Legal
Proceedings.” Although the Tellurian Defendants believe the
plaintiffs’ claims are without merit, the Tellurian Defendants may
not ultimately be successful and any potential liability they may
incur is not reasonably estimable. Moreover, even if the Tellurian
Defendants are successful in defense of this litigation, they could
incur costs and suffer both an economic loss and an adverse impact
on their reputations, which could have a material adverse effect on
our business. In addition, any adverse judgment or settlement of
the litigation could have an adverse effect on our operating
results and financial condition.
Potential legislative and regulatory actions addressing climate
change, and the physical effects of climate change, could
significantly impact us.
Various state
governments and regional organizations have considered enacting new
legislation and promulgating new regulations governing or
restricting the emission of GHGs, including GHG emissions from
stationary sources such as oil and natural gas production equipment
and facilities. At the federal level, the EPA has already made
findings and issued regulations that will require us to establish
and report an inventory of GHG emissions. Additional legislative
and/or regulatory proposals for restricting GHG emissions or
otherwise addressing climate change could require us to incur
additional operating costs. The potential increase in our operating
costs could include new or increased costs to obtain permits,
operate and maintain our equipment and facilities, install new
emission controls on our equipment and facilities, acquire
allowances to authorize our GHG emissions, pay taxes related to our
GHG emissions and administer and manage a GHG emissions program.
Even without federal legislation or regulation of GHG emissions,
states may impose these requirements either directly or
indirectly.
Some scientists
have concluded that increasing concentrations of GHGs in the
earth’s atmosphere may produce climate changes that have
significant physical effects, such as higher sea levels, increased
frequency and severity of storms, droughts, floods, and other
climatic events. If any such effects were to occur, they could
adversely affect our facilities and operations, and have an adverse
effect on our financial condition and results of operations.
Further, adverse weather events may accelerate changes in law and
regulations aimed at reducing GHG emissions, which could result in
declining demand for natural gas and LNG, and could adversely
affect our business generally.
A major health and safety incident relating to our business could
be costly in terms of potential liabilities and reputational
damage.
Tellurian will be
subject to extensive federal, state and local health and safety
regulations and laws. Health and safety performance is critical to
the success of all areas of our business. Any failure in health and
safety performance may result in personal harm or injury, penalties
for non-compliance with relevant laws and regulations or
litigation, and a failure that results in a significant health and
safety incident is likely to be costly in terms of potential
liabilities. Such a failure could generate public concern and have
a corresponding impact on our reputation and our relationships with
relevant regulatory agencies and local communities, which in turn
could have a material adverse effect on our business, contracts,
financial condition, operating results, cash flow, liquidity and
prospects.
A terrorist attack or military incident could result in delays in,
or cancellation of, construction or closure of our facilities or
other disruption to our business.
A terrorist or
military incident could disrupt our business. For example, an
incident involving an LNG carrier or LNG facility may result in
delays in, or cancellation of, construction of new LNG facilities,
including our proposed LNG facilities, which would increase
Tellurian’s costs and decrease its cash flows. A terrorist incident
may also result in the temporary or permanent closure of Tellurian
facilities or operations, which could increase costs and decrease
cash flows, depending on the duration of the closure. Our
operations could also become subject to increased governmental
scrutiny that may result in additional security measures at a
significant incremental cost. In addition, the threat of terrorism
and the impact of military campaigns may lead to continued
volatility in prices for natural gas or oil that could adversely
affect Tellurian’s business and customers, including by impairing
the ability of Tellurian’s suppliers or customers to satisfy their
respective obligations under Tellurian’s commercial
agreements.
Cyber-attacks targeting systems and infrastructure used in our
business may adversely impact our operations.
We depend on
digital technology in many aspects of our business, including the
processing and recording of financial and operating data, analysis
of information, and communications with our employees and third
parties. Cyber-attacks on our systems and those of third party
vendors and other counterparties occur frequently, and have grown
in sophistication. A successful cyber-attack on us or a vendor or
other counterparty could have a variety of adverse consequences,
including theft of proprietary or commercially sensitive
information, data corruption, interruption in communications,
disruptions to our existing or planned activities or transactions,
and damage to third parties, any of which could have a material
adverse impact on us. Further, as cyber-attacks continue to evolve,
we may be required to expend significant additional resources to
continue to modify or enhance our protective measures or to
investigate and remediate any vulnerabilities to
cyber-attacks.
Failure to retain and attract key personnel such as Tellurian’s
Chairman, Vice Chairman or other skilled professional and technical
employees could have an adverse effect on Tellurian’s business,
results of operations, financial condition, liquidity and
prospects.
The success of
Tellurian’s business relies heavily on key personnel such as its
Chairman and Vice Chairman. Should such persons be unable to
perform their duties on behalf of Tellurian, or should Tellurian be
unable to retain or attract other members of management,
Tellurian’s business, results of operations, financial condition,
liquidity and prospects could be materially impacted.
Additionally, we
are dependent upon an available labor pool of skilled employees. We
will compete with other energy companies and other employers to
attract and retain qualified personnel with the technical skills
and experience required to construct and operate our facilities and
to provide our customers with the highest quality service. A
shortage of skilled workers or other general inflationary pressures
or changes in applicable laws and regulations could make it more
difficult for us to attract and retain qualified personnel and
could require an increase in the wage and benefits packages that we
offer, or increases in the amounts we are obligated to pay our
contractors, thereby increasing our operating costs. Any increase
in our operating costs could materially and adversely affect our
business, financial condition, operating results, liquidity and
prospects.
Competition is intense in the energy industry and some of
Tellurian’s competitors have greater financial, technological and
other resources.
Tellurian plans
to operate in various aspects of the natural gas and oil business
and will face intense competition in each area. Depending on the
area of operations, competition may come from independent,
technology-driven companies, large, established companies and
others.
For example, many
competing companies have secured access to, or are pursuing
development or acquisition of, LNG facilities to serve the North
American natural gas market, including other proposed liquefaction
facilities in North America. Tellurian may face competition from
major energy companies and others in pursuing its proposed business
strategy to provide liquefaction and export products and services
at its proposed Driftwood Project. In addition, competitors have
developed and are developing additional LNG terminals in other
markets, which will also compete with our proposed LNG
facilities.
As another
example, our business will face competition in, among other things,
buying and selling reserves and leases and obtaining goods and
services needed to operate properties and market natural gas and
oil. Competitors include multinational oil companies, independent
production companies and individual producers and
operators.
Many of our
competitors have longer operating histories, greater name
recognition, larger staffs and substantially greater financial,
technical and marketing resources than Tellurian currently
possesses. The superior resources that some of these competitors
have available for deployment could allow them to compete
successfully against Tellurian, which could have a material adverse
effect on Tellurian’s business, results of operations, financial
condition, liquidity and prospects.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
None.
ITEM 3.
LEGAL PROCEEDINGS
In July 2017,
Tellurian Investments, Driftwood LNG LLC (“Driftwood LNG”), Martin
Houston, and three other individuals were named as third-party
defendants in a lawsuit filed in state court in Harris County,
Texas between Cheniere Energy, Inc. and one of its affiliates, on
the one hand (collectively, “Cheniere”), and Parallax Enterprises
LLC and certain of its affiliates (not including Parallax Services
LLC, now known as Tellurian Services LLC) on the other hand
(collectively, “Parallax”). In October 2017, Driftwood Pipeline LLC
(“Driftwood Pipeline”) and Tellurian Services LLC were also named
by Cheniere as third-party defendants. Cheniere alleges that it
entered into a note and a pledge agreement with Parallax. Cheniere
claims that the third-party defendants tortiously interfered with
the note and pledge agreement and aided in the fraudulent transfer
of Parallax assets. Cheniere is seeking unspecified amounts of
monetary damages and certain equitable relief. We believe that
Cheniere’s claims against Tellurian Investments, Driftwood LNG,
Driftwood Pipeline and Tellurian Services LLC are without merit and
do not expect the resolution of the suit to have a material effect
on our results of operation or financial condition. Trial has been
set for June 2019.
ITEM 4. MINE
SAFETY DISCLOSURE
None.
PART
II
ITEM 5.
MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
Market
Information, Holders and Dividends
Our common stock
trades on the NASDAQ Capital Market (“NASDAQ”) under the symbol
“TELL.” As of February 15, 2019
, there were
approximately 571 record holders of Tellurian’s common stock. The
Company does not intend to pay cash dividends on its common stock
in the foreseeable future.
Recent Sales
of Unregistered Securities
On December 5,
2018, the Company issued 143,500 shares of its common stock,
subject to certain vesting requirements, as consideration under a
management consulting agreement for certain services. The
shares were issued in a private placement under Section 4(a)(2) of
the Securities Act of 1933, as
amended.
Use of
Proceeds from Registered Securities
None.
Purchases of
Equity Securities by the Issuer and Affiliated
Purchasers
None that
occurred during the three months ended December 31,
2018.
Stock
Performance Graph
The information
contained in this Stock Performance Graph section shall not be
deemed to be “soliciting material” or “filed” or incorporated by
reference in future filings with the SEC, or subject to the
liabilities of Section 18 of the Securities Exchange Act of 1934,
except to the extent that we specifically incorporate it by
reference into a document filed under the Securities Act of 1933 or
the Securities Exchange Act of 1934.
The following
graph compares the cumulative total shareholder return, calculated
on a dividend reinvested basis, on $100.00 invested at the closing
of the market on December 31, 2013, through and including the
market close on December 31, 2018, with the cumulative
total return for the same time period of the same amount invested
in the Russell 2000 index and a peer group index. Our peer group
index consists of the following companies: (1) Cheniere Energy
Partners LP (CQP), (2) ONEOK, Inc. (OKE), (3) Golar LNG Limited
(GLNG), (4) Enable Midstream Partners LP (ENBL), (5) Cheniere
Energy, Inc. (LNG), (6) Teekay Lng Partners, L.P. (TGP), (7) Teekay
Corporation (TK), (8) GasLog Ltd (GLOG), (9) Targa Resources
Corporation (TRGP) and (10) Anadarko Petroleum Corporation (APC).
This peer group was selected based on a review of publicly
available information about these companies and our determination
that they met one or more of the following criteria: (i) comparable
industries, (ii) similar market capitalization and (iii)
similar operational characteristics, capital intensity, business
and operating risks.
Shareholder
returns over the indicated period are based on historical data and
should not be considered indicative of future shareholder
returns.
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12/31/2013
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12/31/2014
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12/31/2015
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12/31/2016
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|
12/31/2017
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|
12/31/2018
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|
Tellurian Inc.
|
100
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|
88
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|
7
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|
137
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|
118
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|
84
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|
Russell 2000
|
100
|
|
104
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|
98
|
|
117
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|
132
|
|
116
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Peer Group
|
100
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|
113
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|
56
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|
83
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|
88
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|
79
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ITEM 6.
SELECTED FINANCIAL DATA
The selected
financial data set forth below (in thousands, except per share
amounts) are not necessarily indicative of the results of future
operations and should be read in conjunction with “Management’s
Discussion and Analysis of Financial Condition and Results of
Operations” and our Consolidated Financial Statements and the
related notes.We have derived the selected financial data presented
below as of December 31, 2018 and 2017 and for the years
ended December 31, 2018, 2017 and 2016 (the “Successor”) and
for the period from January 1, 2016 to April 9, 2016 (the
“Predecessor”) from our Consolidated Financial Statements and
related notes included in this report. See Explanatory
Note in
Item 7. We have derived the selected financial data presented below
as of April 9, 2016, December 31, 2015 and 2014 and for
the years ended December 31, 2015 and 2014 from financial
statements that are not included in this report.
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Successor
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Predecessor
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Year Ended December
31,
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For the period from January
1, 2016 through April 9, 2016
|
Year Ended December
31,
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2018
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2017
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2016
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2015
|
2014
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Total revenue
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$
|
10,286
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$
|
5,441
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$
|
—
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|
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$
|
31
|
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$
|
1,686
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$
|
1,460
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Income (loss) from
operations
|
(127,720
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)
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(238,567
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)
|
(93,730
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)
|
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(638
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)
|
105
|
|
631
|
|
Net income
(loss)
|
(125,745
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)
|
(231,459
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)
|
(96,655
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)
|
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(638
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)
|
105
|
|
631
|
|
Net loss per common share -
basic and diluted
|
(0.59
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)
|
(1.23
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)
|
(1.01
|
)
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na*
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|
na*
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na*
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Successor
|
|
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Predecessor
|
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December 31,
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April 9,
|
December 31,
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2018
|
2017
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2016
|
|
|
2016
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2015
|
2014
|
Cash and cash
equivalents
|
$
|
133,714
|
|
$
|
128,273
|
|
$
|
21,398
|
|
|
|
$
|
210
|
|
$
|
589
|
|
$
|
258
|
|
Property, plant and
equipment, net
|
130,580
|
|
115,856
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|
10,993
|
|
|
|
480
|
|
148
|
|
111
|
|
Deferred engineering
costs
|
69,000
|
|
18,000
|
|
—
|
|
|
|
—
|
|
—
|
|
—
|
|
Non-current restricted
cash
|
49,875
|
|
—
|
|
—
|
|
|
|
—
|
|
—
|
|
—
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|
Total assets
|
408,548
|
|
276,823
|
|
39,078
|
|
|
|
1,108
|
|
1,137
|
|
1,515
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|
Long-term
borrowings
|
57,048
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|
—
|
|
—
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|
|
—
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|
—
|
|
—
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* Not
applicable.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Explanatory
Note
In February 2017,
Tellurian Inc., which was formerly known as Magellan Petroleum
Corporation (“Magellan”), completed a merger (the “Merger”) with
Tellurian Investments Inc. (“Tellurian Investments”). At the
effective time of the Merger, a subsidiary of Magellan merged with
and into Tellurian Investments, with Tellurian Investments
continuing as the surviving corporation and a subsidiary of
Magellan. Immediately following the completion of the Merger,
Magellan amended its certificate of incorporation and bylaws to
change its name to “Tellurian Inc.”
In connection
with the Merger, each outstanding share of common stock of
Tellurian Investments was exchanged for 1.3 shares of Magellan
common stock. The Merger is accounted for as a “reverse
acquisition,” with Tellurian Investments being treated as the
accounting acquirer.
Except where the
context indicates otherwise, (i) references to “we,” “us,” “our,”
“Tellurian” or the “Company” refer, for periods prior to the
completion of the Merger, to Tellurian Investments and its
subsidiaries, and for periods following the completion of the
Merger, to Tellurian Inc. and its subsidiaries and (ii) references
to “Magellan” refer to Tellurian Inc. and its subsidiaries prior to
the completion of the Merger.
Introduction
The following
discussion and analysis presents management’s view of our business,
financial condition and overall performance and should be read in
conjunction with our Consolidated Financial Statements and the
accompanying notes. This information is intended to provide
investors with an understanding of our past development activities,
current financial condition and outlook for the future organized as
follows:
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Overview of
Significant Events
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Liquidity and
Capital Resources
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Capital
Development Activities
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•
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Off-balance Sheet
Arrangements
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•
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Commitments and
Contingencies
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•
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Summary of
Critical Accounting Estimates
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•
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Recent Accounting
Standards
|
Our
Business
Tellurian Inc.
(“Tellurian,” “we,” “us,” “our,” or the “Company”) intends to
create value for shareholders by building
a low-cost, global natural gas business, profitably
delivering natural gas to customers worldwide (the “Business”). We
are developing a portfolio of natural gas production, LNG
marketing, and infrastructure assets that includes an LNG terminal
facility (the “Driftwood terminal”), and three related pipelines
(the “Pipeline Network”). We refer to the Driftwood terminal, the
Pipeline Network and our existing and planned natural gas
production assets collectively as the “Driftwood Project”. We
currently estimate the total cost of the Driftwood Project to be
approximately $28 billion, including owners’ costs, transaction
costs and contingencies but excluding interest costs incurred
during construction of the Driftwood terminal and other financing
costs. Our Business may be developed in phases.
The proposed
Driftwood terminal will have a liquefaction capacity of
approximately 27.6 Mtpa and will be situated on approximately
1,000 acres in Calcasieu Parish, Louisiana. The proposed Driftwood
terminal will include up to 20 liquefaction Trains, three full
containment LNG storage tanks and three marine berths. We have
entered into four LSTK EPC agreements totaling $15.2 billion with
Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”) for construction
of the Driftwood terminal.
The proposed
Pipeline Network will consist of three pipelines, the Driftwood
pipeline, the Haynesville Global Access Pipeline and the Permian
Global Access Pipeline. The Driftwood pipeline will be
a 96-mile large diameter pipeline that will interconnect
with 14 existing interstate pipelines throughout southwest
Louisiana to secure adequate natural gas feedstock for the
Driftwood terminal. The Driftwood pipeline will be comprised
of 48-inch, 42-inch, 36-inch and 30-inch diameter
pipeline segments and three compressor stations totaling
approximately 274,000 horsepower, all as necessary to provide
approximately 4 Bcf/d of average daily natural gas transportation
service. We estimate construction costs for the Driftwood pipeline
of approximately $2.3 billion before owners’ costs, financing
costs and contingencies.
The Haynesville
Global Access Pipeline is expected to run approximately 200 miles
from northern to southwest Louisiana. The Permian Global Access
Pipeline is expected to run approximately 625 miles from west Texas
to southwest Louisiana. Each of these pipelines is expected to have
a diameter of 42 inches and be capable of delivering approximately
2 Bcf/d of natural gas. We currently estimate that construction
costs will be approximately $1.4 billion for the Haynesville Global
Access Pipeline and approximately $3.7 billion for the Permian
Global Access Pipeline, in each case before owners’ costs,
financing costs and contingencies.
Our current
upstream properties, acquired in a series of transactions during
2017 and 2018, consist of 10,233 net acres and 52 producing wells
(18 operated) located in the Haynesville Shale trend of north
Louisiana. For the year ended December 31, 2018, these wells had
average net production of approximately 3.9 MMcf/d. As of December
31, 2018, our estimate of net proved reserves was approximately 265
Bcfe. We began drilling certain locations on our properties in the
fourth quarter of 2018 using proceeds from the Term Loan (as
described in “2018 Developments — Significant Transactions — Term
Loan” below).
In connection
with the implementation of our Business, we are offering
partnership interests in a subsidiary, Driftwood Holdings LLC
(“Driftwood Holdings”), which will own the Driftwood Project.
Partners will contribute cash in exchange for equity in Driftwood
Holdings and will receive LNG volumes at the cost of production,
including the cost of debt, for the life of the Driftwood terminal.
We plan to retain a portion of the ownership in Driftwood
Holdings and have engaged Goldman Sachs & Co. and Société
Générale to serve as financial advisors for Driftwood Holdings. We
also continue to develop our LNG marketing activities as described
below in “2018 Developments — Significant Transactions — LNG
Marketing.”
Overview of
Significant Events
Significant Transactions
Public
Equity Offerings. In connection with our equity
offering in December 2017, the underwriters were granted an option
to purchase up to an additional 1.5 million shares of common stock
within 30 days. The option was exercised in full in January 2018,
resulting in proceeds of approximately $14.5 million, net of
approximately $0.5 million in fees and commissions.
In June 2018, we
completed another offering in which we sold 12.0 million shares of
common stock for proceeds of approximately $115.2 million, net of
approximately $3.6 million in fees and commissions. The
underwriters were granted an option to purchase up to an additional
1.8 million shares of common stock within 30 days, which was not
exercised.
Preferred
Stock Issuance. In March 2018, we entered
into a preferred stock purchase agreement with BDC Oil and Gas
Holdings, LLC (“Bechtel Holdings”), a Delaware limited liability
company and an affiliate of Bechtel, pursuant to which we sold to
Bechtel Holdings approximately 6.1 million
shares of our
Series C convertible preferred stock (the “Preferred Stock”).
In exchange for the Preferred Stock, Bechtel agreed to discharge
approximately $22.7 million
of the
outstanding liabilities associated with the detailed engineering
services for the Driftwood Project, and to apply
approximately $27.3 million
to additional
future
detailed
engineering services. During the year ended December 31, 2018, all
of the approximately $27.3 million of future services were received
and, as such, all $50.0 million has been recognized on our
Consolidated Balance Sheets within deferred engineering
costs.
Term
Loan. On
September 28, 2018 (the “Closing Date”), we entered into a
three-year senior secured term loan credit agreement (the “Term
Loan”) in the principal amount of $60.0 million at a price of 99%
of par, resulting in an original issue discount of $0.6 million.
Fees of $2.6 million were capitalized as deferred financing costs.
Use of proceeds from the Term Loan is predominantly restricted to
capital expenditures associated with certain development and
drilling activities and fees related to the transaction itself and
are presented within non-current restricted cash on our
Consolidated Balance Sheet. Amounts borrowed under the Term Loan
bear interest at a variable rate (three-month LIBOR) plus an
applicable margin. The applicable margin is 5% through the end of
the first year following the Closing Date, 7% through the end of
the second year following the Closing Date and 8% thereafter. If
the Term Loan is terminated within 12 months of the Closing Date,
an early termination fee equal to 1% of the outstanding principal
is required.
LNG
Marketing. In September 2017, we
entered into a vessel charter that enabled us to execute a number
of LNG purchase and sale opportunities, as well as sub-charter
opportunities, that resulted in revenue of approximately $5.9
million for the year ended December 31, 2018. We continue to
implement our marketing strategy by looking for other LNG purchase,
sale and vessel charter opportunities.
Regulatory Developments
Export
Approval. In February 2017, the DOE/FE
issued an order authorizing Tellurian to export 27.6 mtpa of LNG to
FTA countries, on its own behalf and as agent for others, for a
term of 30 years. Our application for authority to export LNG to
non-FTA countries is currently pending before the DOE/FE and is
expected to be ruled upon in the first half of 2019.
FERC
Application. In March 2017, Tellurian
filed an application with FERC for authorization pursuant to
Section 3 of the NGA to site, construct and operate the Driftwood
terminal, and simultaneously sought authorization pursuant to
Section 7 of the NGA for authorization to construct and operate
interstate natural gas pipeline facilities. In December 2017, FERC
issued the notice of schedule for the environmental review of both
the Driftwood terminal and the Driftwood pipeline. In September
2018, we received our draft environmental impact statement (“EIS”)
from FERC for the Driftwood terminal and pipeline. We received our
final EIS from FERC on January 18, 2019. Refer to Note 19,
Subsequent
Events to
the Consolidated Financial Statements included in this report, for
further details.
Environmental
Permits. In March 2017, we submitted
permit applications to the USACE under the Clean Water Act and the
Rivers and Harbors Act for certain dredging and wetland mitigation
activities relating to the Driftwood terminal and pipeline. Also in
March 2017, we submitted Title V and PSD air permit applications to
the Louisiana Department of Environmental Quality under the Clean
Air Act for air emissions relating to the Driftwood terminal and
pipeline, and the associated permits were granted in July 2018. In
addition, in May 2018, we received a Coastal Use Permit from the
Louisiana Department of Natural Resources for the Driftwood
terminal, which approves the placement of dredged material from the
marine berth for beneficial use inside the Louisiana coastal zone.
The regulatory review and approval process for the USACE permit is
expected to be completed in the first half of 2019.
Liquidity
and Capital Resources
Capital
Resources
We are currently
funding our operations, development activities and general working
capital needs through our cash on hand. We are funding our specific
development and drilling activities with the proceeds from the Term
Loan. Our current capital resources consist of
approximately $133.7 million
of cash and cash
equivalents as of December 31, 2018
on a consolidated
basis, which are primarily the result of issuances of common stock
in 2017 and in the first half of 2018, and approximately $49.6
million of non-current restricted cash from the Term Loan proceeds.
We consider all highly liquid investments with an original maturity
of three months or less to be cash equivalents.
We also have the
ability to raise funds through common or preferred stock issuances,
debt financings, an at-the-market equity offering program or sale
of assets.
We maintain an
at-the-market equity offering program through Credit Suisse
Securities (USA) LLC under which we may raise aggregate sales
proceeds of up to $189.7 million.
Sources and
Uses of Cash
The following
table summarizes the sources and uses of our cash and cash
equivalents and costs and expenses for the periods presented (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31,
|
|
|
For the
period from January 1, 2016 through April 9, 2016
|
|
|
|
|
|
|
2018
|
|
2017
|
|
2016
|
|
|
Cash used in operating
activities
|
|
$
|
(103,752
|
)
|
|
$
|
(109,229
|
)
|
|
$
|
(50,430
|
)
|
|
|
$
|
(111
|
)
|
Cash used in investing
activities
|
|
(21,687
|
)
|
|
(95,565
|
)
|
|
(10,506
|
)
|
|
|
(268
|
)
|
Cash provided by financing
activities
|
|
180,755
|
|
|
311,669
|
|
|
82,334
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in
cash, cash equivalents and restricted cash
|
|
55,316
|
|
|
106,875
|
|
|
21,398
|
|
|
|
(379
|
)
|
Cash, cash equivalents and
restricted cash, beginning of the period
|
|
128,273
|
|
|
21,398
|
|
|
—
|
|
|
|
589
|
|
Cash, cash equivalents and
restricted cash, end of the period
|
|
$
|
183,589
|
|
|
$
|
128,273
|
|
|
$
|
21,398
|
|
|
|
$
|
210
|
|
|
|
|
|
|
|
|
|
|
|
Net working
capital
|
|
$
|
87,664
|
|
|
$
|
81,393
|
|
|
$
|
17
|
|
|
|
$
|
(784
|
)
|
Cash used in
operating activities for the year ended December 31, 2018 decreased
approximately $5.5 million compared to the same period in 2017. The
decrease in cash used in operating activities primarily relates to
the absence of one-off Merger-related expenses of approximately
$4.9 million.
Cash used in
investing activities for the year ended December 31, 2018 decreased
approximately $73.9 million compared to the same period in 2017,
primarily due to reduced acquisition and development activities
related to natural gas properties. During 2018, we invested
approximately $13.5 million in such activities compared to
approximately $90.1 million paid for acquisitions in
2017.
Cash provided by
financing activities for the year ended December 31, 2018 decreased
approximately $130.9 million compared to the same period in 2017,
primarily due to the issuance of common stock through equity
offerings and through our at-the-market equity program during 2017,
which resulted in aggregate net proceeds of approximately $312.5
million, compared to the common stock issuances during the same
period in 2018, which resulted in net proceeds of approximately
$129.7 million. The comparative decrease of approximately $182.8
million was partially offset by approximately $56.8 million of net
proceeds from the Term Loan.
Cash used in
operating activities for the year ended December 31, 2017
increase
d
approximately $58.8 million
compared to the
same period in 2016, primarily due to one-time payments of
approximately $12.5 million related to our development activities,
approximately $4.9 million of Merger-related expenses and
approximately $41.4 million of disbursements in the normal course
of business. Disbursements increased primarily due to the increased
development activities and a substantial increase in the number of
Tellurian employees, which resulted in an increase of approximately
$21.6 million and $12.3 million, respectively.
Cash used in
investing activities for the year ended December 31, 2017
increase
d
approximately $85.1 million
compared to the
same period in 2016, primarily due to approximately $90.1 million
paid for the acquisition of natural gas properties in northern
Louisiana, net of an accrual of $0.1 million offset by
approximately $4.6 million of proceeds received from the sale of
investment securities.
Cash provided by
financing activities for the year ended December 31, 2017
increase
d
approximately $229.3 million
compared to the
same period in 2016 primarily as a result of net proceeds from the
issuance of common shares.
Long-Term
Borrowings
As of December
31, 2018, we had total indebtedness of $57.0 million
, all of which
was secured indebtedness. At December 31, 2018, we were in
compliance with the covenants under the credit agreement governing
the Term Loan. For additional details regarding our borrowing
activity, refer to Note 13, Long-Term
Borrowings , to the Consolidated
Financial Statements included in this report.
Contractual
Obligations
We are committed
to make cash payments in the future pursuant to certain of our
contracts. The following table summarizes certain contractual
obligations in place as of December 31, 2018 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due
By Period
|
|
Total
|
|
2019
|
|
2020-2021
|
|
2022-2023
|
|
Thereafer
|
Senior secured term
loan (1)
|
$
|
60,000
|
|
|
$
|
—
|
|
|
$
|
60,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Operating lease
obligations (2)
|
$
|
25,848
|
|
|
3,126
|
|
|
6,950
|
|
|
7,711
|
|
|
8,061
|
|
Other obligations
(3)
|
$
|
3,727
|
|
|
2,087
|
|
|
1,158
|
|
|
46
|
|
|
436
|
|
Total
|
$
|
89,575
|
|
|
$
|
5,213
|
|
|
$
|
68,108
|
|
|
$
|
7,757
|
|
|
$
|
8,497
|
|
(1) Includes
future principal on the Term Loan through scheduled maturity date.
Interest payments are excluded as the Term Loan bears interest at a
variable rate. In addition, amortization of debt issuance and other
costs related to indebtedness are also excluded. Refer to Note
13, Long-Term
Borrowings , to the Consolidated
Financial Statements included in this report for further
details.
(2) Represents
the minimum lease payments for non-cancelable operating leases for
various office locations.
(3) Represents
primarily options to lease certain properties for the Driftwood
Project.
Capital
Development Activities
The activities we
have proposed will require significant amounts of capital and are
subject to risks and delays in completion. We expect to receive all
regulatory approvals and commence construction of the Driftwood
terminal and Driftwood pipeline in 2019, produce the first LNG in
2023 and achieve full operations in 2026. As a result, our business
success will depend to a significant extent upon our ability to
obtain the funding necessary to construct assets on a commercially
viable basis and to finance the costs of staffing, operating and
expanding our company during that process.
Tellurian
estimates construction costs of approximately $15.2 billion, or
$550 per tonne, for the Driftwood terminal and approximately $2.3
billion for the Driftwood pipeline, in each case before owners’
costs, financing costs and contingencies. We also are in the
preliminary routing stage of developing the Haynesville Global
Access Pipeline and the Permian Global Access Pipeline, which
combined are estimated to cost approximately $5.1 billion before
owners’ costs, financing costs and contingencies. In addition, the
natural gas production activities we are pursuing will require
considerable capital resources. We anticipate funding our more
immediate liquidity requirements relative to the detailed
engineering work and other developmental and general and
administrative costs through the use of cash from the completed
equity issuances discussed above and future issuances of equity or
debt securities by us.
We currently
expect that our long-term capital requirements will be financed by
proceeds from future debt and equity offerings. In addition, part
of our financing strategy is expected to involve seeking equity
investments by LNG customers at a subsidiary level. If the types of
financing we expect to pursue are not available, we will be
required to seek alternative sources of financing, which may not be
available on acceptable terms, if at all.
Results of
Operations
The following
table summarizes costs and expenses for the periods presented (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
|
|
|
|
For the
period from
January 1,
2016 through April 9, 2016
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31,
|
|
|
|
|
2018
|
|
2017
|
|
2016
|
|
|
Total revenue
|
|
$
|
10,286
|
|
|
$
|
5,441
|
|
|
$
|
—
|
|
|
|
$
|
31
|
|
Cost of sales
|
|
6,115
|
|
|
7,565
|
|
|
—
|
|
|
|
—
|
|
Development
expenses
|
|
44,034
|
|
|
59,498
|
|
|
47,146
|
|
|
|
44
|
|
Depreciation, depletion and
amortization
|
|
1,567
|
|
|
479
|
|
|
69
|
|
|
|
8
|
|
General and administrative
expenses
|
|
81,777
|
|
|
98,874
|
|
|
46,515
|
|
|
|
617
|
|
Impairment charge and loss on
transfer of assets
|
|
4,513
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
Goodwill
impairment
|
|
—
|
|
|
77,592
|
|
|
—
|
|
|
|
—
|
|
Loss from
operations
|
|
(127,720
|
)
|
|
(238,567
|
)
|
|
(93,730
|
)
|
|
|
(638
|
)
|
Gain (loss) on preferred
stock exchange feature
|
|
—
|
|
|
2,209
|
|
|
(3,308
|
)
|
|
|
—
|
|
Interest income,
net
|
|
1,574
|
|
|
1,022
|
|
|
—
|
|
|
|
—
|
|
Other income,
net
|
|
211
|
|
|
4,062
|
|
|
217
|
|
|
|
—
|
|
Income tax benefit
(provision)
|
|
190
|
|
|
(185
|
)
|
|
166
|
|
|
|
—
|
|
Net loss
|
|
$
|
(125,745
|
)
|
|
$
|
(231,459
|
)
|
|
$
|
(96,655
|
)
|
|
|
$
|
(638
|
)
|
Our consolidated
net loss was approximately $125.8 million for the year ended
December 31, 2018, compared to a net loss of approximately $231.5
million for the year ended December 31, 2017. This $105.7 million
decrease in net loss is primarily due to the absence of a goodwill
impairment charge during the current period compared to a $77.6
million charge in 2017. The decrease in our net loss is also a
result of the following:
|
|
•
|
Revenue during
the year ended December 31, 2018 increased approximately $4.8
million compared to the same period in 2017, primarily due to the
increase in natural gas revenue as a result of a full year of
operations and participation in certain wells that became
operational in the current period.
|
|
|
•
|
The $15.5 million
decrease in development expenses is primarily due to the nature of
services related to our largest development vendor, Bechtel. The
services Bechtel provided during the year ended December 31, 2018,
which primarily consisted of detailed engineering services for the
Driftwood terminal, are being capitalized, whereas the FEED studies
on the Driftwood Project were expensed during the same period in
2017. For more information regarding the detailed engineering
services provided by Bechtel, see Note 3, Deferred
Engineering Costs , of our Notes to
Consolidated Financial Statements included in this
report.
|
|
|
•
|
The $17.1 million
decrease in general and administrative expenses is attributable to
a decrease in share-based compensation and share-based payments to
vendors, partially offset by an increase in compensation expense
due to an overall increase in headcount when compared to the same
period in 2017.
|
The decrease in
net loss for the year ended December 31, 2018 was partially offset
by the following:
|
|
•
|
Approximately
$2.7 million and $1.8 million resulting from the impairment of
certain non-producing proved properties and loss on the transfer of
the Australian exploration permit, respectively, both of which are
outlined in Note 5, Property,
Plant and Equipment , of our Notes to the
Consolidated Financial Statements included in this
report.
|
|
|
•
|
Other income, net
for the year ended December 31, 2018 decreased approximately $3.9
million compared to the same period in 2017. The decrease is
primarily attributable to an absence of a gain on sale of
securities of approximately $3.5 million in 2017.
|
Our consolidated
net loss was approximately $231.5 million
for the year
ended December 31, 2017, compared to a net loss of
approximately $96.7 million
for the year
ended December 31, 2016. This $134.8 million
increase in net
loss is primarily a result of the following:
|
|
•
|
Development
expenses for the year ended December 31, 2017 increase d approximately
$12.4
million compared to the same period
in 2016. This increase is due to an overall increase
in activity associated with the permitting process with
FERC.
|
|
|
•
|
General and
administrative expenses during the year ended December 31,
2017 increase d approximately
$52.4
million compared to the same period
in 2016. The increase is attributable to non-cash
share-based payments related
|
to commercial
development and management consulting contractors of approximately
$ 19.4 million which were not
incurred in 2016, an increase in salaries and benefits of
approximately $14.3 million due to a substantial increase in the
number of employees, and an increase in corporate marketing and
investor development activities.
|
|
•
|
Goodwill
impairment during the year ended December 31, 2017
increase
d
approximately $77.6 million
due to goodwill
recognized as a result of the Merger that was subsequently
determined to be unrecoverable.
|
|
|
•
|
Cost of sales
during the year ended December 31, 2017 increase d approximately
$7.6
million compared to the same period
in 2016. This increase is primarily due to LNG marketing
transaction costs of approximately $7.1 million.
|
The increase in
expenses for the year ended December 31, 2017 was partially offset
by the following:
|
|
•
|
Revenue during
the year ended December 31, 2017 increase d approximately
$5.4
million compared to the same period
in 2016. This increase is primarily due to LNG sales revenue of
approximately $3.3 million and LNG sub-charter revenue of
approximately $1.7 million.
|
|
|
•
|
Approximately
$5.5
million was recognized due to an
exchange feature of the Tellurian Investments Series A convertible
preferred stock issued during 2016.
|
|
|
•
|
Other income, net
for the year ended December 31, 2017 increase d approximately
$3.8
million compared to the same period
in 2016. The increase is primarily attributable to
a gain on sale of securities of approximately $3.5
million.
|
Off-Balance
Sheet Arrangements
As of
December 31,
2018 , we
had no transactions that met the definition of off-balance sheet
arrangements that may have a current or future material effect on
our consolidated financial position or operating
results.
Commitments
and Contingencies
The information
set forth in Note 8, Commitments
and Contingencies , to the accompanying
Consolidated Financial Statements included in Part II, Item 8 of
this Form 10-K is incorporated herein by reference.
Summary of
Critical Accounting Estimates
Our accounting
policies are more fully described in Note 1 to the Consolidated Financial
Statements included in this report. As disclosed in Note
1
, the preparation
of financial statements requires the use of judgments and
estimates. We base our estimates on historical experience and on
various other assumptions we believe to be reasonable according to
current facts and circumstances, the results of which form the
basis for making judgments about the carrying values of assets and
liabilities that are not readily apparent from other sources.
Actual results could differ from these estimates. We identified our
most critical accounting estimates to be:
|
|
•
|
valuations of
long-lived assets, including intangible assets and
goodwill;
|
|
|
•
|
purchase price
allocation for acquired businesses;
|
|
|
•
|
forecasting our
effective income tax rate, including the realizability of deferred
tax assets;
|
|
|
•
|
impairment
considerations for tangible and intangible assets; and
|
|
|
•
|
share-based
compensation.
|
We believe the
following discussion addresses our critical accounting policies,
which are those that require our most difficult, subjective or
complex judgments about future events and related estimations that
are fundamental to our results of operations.
Fair
Value
When necessary or
required by GAAP, we estimate the fair value of (i) long-lived
assets for impairment testing, (ii) reporting units for goodwill
impairment testing and (iii) assets acquired and liabilities
assumed in business combinations. When there is not a
market-observable price for the asset or liability or a similar
asset or liability, we use the cost, income, or market valuation
approach, depending on the quality of information available to
support management’s assumptions.
The cost approach
is based on management’s best estimate of the current asset
replacement cost. The income approach is based on management’s best
assumptions regarding expectations of projected cash flows and
discounts the expected cash flows using a commensurate
risk-adjusted discount rate. The market approach is based on
management’s best assumptions regarding prices and other relevant
information from market transactions involving comparable assets.
Such evaluations involve significant judgment, and the results are
based on expected future events or conditions. Assumptions used in
fair value measurement would reflect a market participant’s view of
long-term prices, costs and other factors, and are consistent with
assumptions used in our business plans and investment
decisions.
Income
Taxes
Deferred income
tax assets and liabilities are recognized for temporary differences
between the basis of assets and liabilities for financial reporting
and tax purposes. Deferred tax assets are reduced by a valuation
allowance if, based on all available evidence, it is more likely
than not that some portion or all of the deferred tax asset will
not be realized. In determining the need for a valuation allowance,
we consider current and historical financial results, expectations
for future taxable income and the availability of tax planning
strategies that can be implemented, if necessary, to realize
deferred tax assets. We have recorded a full valuation allowance on
our net deferred tax assets as of December 31, 2018 and 2017. We
intend to maintain a valuation allowance on our net deferred tax
assets until there is sufficient evidence to support the reversal
of these allowances.
Reserves
Estimates
Proved reserves
are the estimated quantities of natural gas and condensate that
geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions. Despite the
inherent imprecision in these engineering estimates, our reserves
are used throughout our financial statements. For example, because
we use the units-of-production method to deplete our natural gas
properties, the quantity of reserves could significantly impact our
DD&A expense. Consequently, material revisions (upward or
downward) to existing reserve estimates may occur from time to
time. Finally, these reserves are the basis for our supplemental
natural gas disclosures. See Item 1 and 2 — Our Business and
Properties, for additional information on
our estimate of proved reserves.
Impairments
When
circumstances indicate that proved natural gas properties may be
impaired, we compare expected undiscounted future cash flows at a
depreciation, depletion and amortization group level to the
unamortized capitalized cost of the asset. If the expected
undiscounted future cash flows, based on our estimates of (and
assumptions regarding) future natural gas prices, operating costs,
development expenditures, anticipated production from proved
reserves and other relevant data, are lower than the unamortized
capitalized cost, the capitalized cost is reduced to fair value.
Fair value is generally calculated using the income approach in
accordance with GAAP. Estimates of undiscounted future cash flows
require significant judgment, and the assumptions used in preparing
such estimates are inherently uncertain. In addition, such
assumptions and estimates are reasonably likely to change in the
future.
We test goodwill
for impairment annually during the fourth quarter, or more
frequently as circumstances dictate. The first step in assessing
whether an impairment of goodwill is necessary is an optional
qualitative assessment to determine the likelihood of whether the
fair value of the reporting unit is greater than its carrying
amount. If we conclude that it is more likely than not that the
fair value of the reporting unit exceeds the related carrying
amount, further testing is not necessary. If the qualitative
assessment is not performed or indicates that it is more likely
than not that the fair value of the reporting unit is less than its
carrying amount, we compare the estimated fair value of the
reporting unit to which goodwill is assigned to the carrying amount
of the associated net assets, including goodwill. An impairment
charge for the amount by which the carrying amount exceeds the
reporting unit’s fair value is then recognized.
See Note
2
,
Merger and
Acquisition ,
to the
Consolidated Financial Statements included in this report for
additional information regarding impairment of
goodwill.
Share-Based
Compensation
Share-based
compensation transactions are measured based on grant-date
estimated fair value. For awards containing only service conditions
or performance conditions deemed probable of occurring, the fair
value is recognized as expense over the requisite service period
using the straight-line method. We recognize compensation cost for
awards with performance conditions if and when we conclude that it
is probable that the performance condition will be achieved. For
awards where the performance or market condition is not considered
probable, compensation cost is not recognized until the performance
or market condition becomes probable. We reassess the probability
of vesting at each reporting period for awards with performance
conditions and adjust compensation cost based on our probability
assessment. We recognize forfeitures as they occur.
Recent
Accounting Standards
For descriptions
of recently issued accounting standards, see Note 18,
Recent
Accounting Standards, to the Consolidated Financial
Statements included in this report.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
We do not believe
that we hold, or are party to, instruments that are subject to
market risks that are material to our business.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO
FINANCIAL STATEMENTS
TELLURIAN
INC.
|
|
|
|
|
|
|
|
|
|
Page
|
Management’s
Report on Internal Control Over Financial Reporting
|
|
Report of Independent
Registered Public Accounting Firm
|
|
Consolidated Financial
Statements:
|
|
|
Consolidated Balance
Sheets
|
|
|
Consolidated Statements of
Operations
|
|
|
Consolidated Statements of
Stockholders’ Equity
|
|
|
Consolidated Statements of
Cash Flows
|
|
|
Notes to the Consolidated
Financial Statements
|
|
Supplementary
Information
|
|
|
Supplemental Disclosures
About Natural Gas Producing Activities (unaudited)
|
|
Schedule I
|
|
|
Condensed Financial
Information of Registrant Tellurian Inc.
|
|
MANAGEMENT’S
REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management,
including the Company’s Chief Executive Officer, Chief Financial
Officer, and Chief Accounting Officer, is responsible for
establishing and maintaining adequate internal control over the
Company’s financial reporting. Management conducted an evaluation
of the effectiveness of internal control over financial reporting
based on criteria established in Internal
Control - Integrated Framework (2013) issued by the Committee
of Sponsoring Organizations of the Treadway Commission. Based on
this evaluation, management concluded that Tellurian Inc.’s
internal control over financial reporting was effective as of
December 31, 2018.
Deloitte &
Touche LLP, an independent registered public accounting firm,
audited the effectiveness of Tellurian Inc.’s internal control over
financial reporting as of December 31, 2018, as stated in
their report on page 38.
|
|
|
|
|
|
|
|
|
/s/ Meg A.
Gentle
|
|
/s/ Antoine J.
Lafargue
|
|
/s/ Khaled A.
Sharafeldin
|
Meg A. Gentle
|
|
Antoine J.
Lafargue
|
|
Khaled A.
Sharafeldin
|
President
and Chief Executive Officer
(as
Principal Executive Officer)
|
|
Senior Vice
President and Chief Financial Officer
(as
Principal Financial Officer)
|
|
Chief
Accounting Officer
(as Principal Accounting Officer)
|
|
|
|
|
|
|
|
|
|
|
Houston, Texas
|
|
|
|
|
|
|
|
February 27,
2019
|
|
|
|
|
|
|
|
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
stockholders and the Board of Directors of Tellurian,
Inc.
Opinion on
the Financial Statements
We have audited
the accompanying consolidated balance sheets of Tellurian, Inc. and
subsidiaries (the "Company") as of December 31, 2018 and 2017, the
related consolidated statements of operations, stockholders’ equity
and cash flows, for each of the three years in the period ended
December 31, 2018 (Successor statements of operations,
stockholders’ equity and cash flows), as well as the consolidated
statements of operations and cash flows for the period from January
1, 2016 through April 9, 2016 (Predecessor statements of operations
and cash flows), and the related notes and the schedule listed in
the Index at Item 8 (collectively referred to as the "financial
statements"). In our opinion, the financial statements present
fairly, in all material respects, the financial position of the
Company as of 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, as well as the period from January
1, 2016 to April 9, 2016, in conformity with accounting principles
generally accepted in the United States of America.
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 (2013) issued by the Committee of
Sponsoring Organizations of the Treadway Commission and our report
dated February 27, 2019, expressed an unqualified opinion on the
Company’s internal control over financial reporting.
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 to 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/ DELOITTE & TOUCHE
LLP
|
|
|
|
Houston, Texas
|
|
|
February 27,
2019
|
|
|
|
|
|
We have served as the
Company’s auditor since 2016.
|
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
stockholders and the Board of Directors of Tellurian,
Inc.
Opinions on
Internal Control over Financial Reporting
We have audited
the internal control over financial reporting of Tellurian, Inc.
and subsidiaries (the "Company") as of December 31, 2018, based on
criteria established in Internal
Control - Integrated Framework (2013) issued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO). In our
opinion, the Company maintained, in all material respects,
effective internal control over financial reporting as of December
31, 2018, based on criteria established in Internal
Control - Integrated Framework (2013) issued by COSO.
We have also
audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States) (PCAOB), the
consolidated financial statements as of and for the year ended
December 31, 2018, of the Company and our report dated February 27,
2019, expressed an unqualified opinion on those financial
statements.
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 Management’s Report 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/ DELOITTE & TOUCHE
LLP
|
|
|
|
Houston, Texas
|
|
|
February 27,
2019
|
|
|
|
|
|
|
|
|
|
|
|
|
TELLURIAN
INC. AND SUBSIDIARIES
|
CONSOLIDATED
BALANCE SHEETS
|
(in
thousands, except share and per share amounts)
|
|
|
|
|
|
December
31,
|
|
|
2018
|
|
2017
|
ASSETS
|
|
|
Current assets:
|
|
|
|
|
Cash and cash
equivalents
|
|
$
|
133,714
|
|
|
$
|
128,273
|
|
Accounts
receivable
|
|
1,498
|
|
|
583
|
|
Accounts receivable due from
related parties
|
|
1,316
|
|
|
1,377
|
|
Prepaids and
other
|
|
3,906
|
|
|
3,458
|
|
Total current
assets
|
|
140,434
|
|
|
133,691
|
|
|
|
|
|
|
Property, plant and
equipment, net
|
|
130,580
|
|
|
115,856
|
|
Deferred engineering
costs
|
|
69,000
|
|
|
18,000
|
|
Non-current restricted
cash
|
|
49,875
|
|
|
—
|
|
Other non-current
assets
|
|
18,659
|
|
|
9,276
|
|
Total assets
|
|
$
|
408,548
|
|
|
$
|
276,823
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS’
EQUITY
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
Accounts payable
|
|
$
|
11,597
|
|
|
$
|
11,462
|
|
Accrued
liabilities
|
|
41,173
|
|
|
39,101
|
|
Other current
liabilities
|
|
—
|
|
|
1,735
|
|
Total current
liabilities
|
|
52,770
|
|
|
52,298
|
|
|
|
|
|
|
Long-term
liabilities:
|
|
|
|
|
Senior secured term
loan
|
|
57,048
|
|
|
—
|
|
Asset retirement
obligation
|
|
796
|
|
|
638
|
|
Total long-term
liabilities
|
|
57,844
|
|
|
638
|
|
|
|
|
|
|
Commitments and contingencies
(Note 8)
|
|
|
|
|
|
|
|
|
|
Stockholders’
equity:
|
|
|
|
|
Preferred stock, $0.01 par
value, 100,000,000 authorized: 6,123,782 and zero shares
outstanding, respectively
|
|
61
|
|
|
—
|
|
Common stock, $0.01 par
value, 400,000,000 authorized: 240,655,607 and 222,749,220 shares
outstanding, respectively
|
|
2,195
|
|
|
2,043
|
|
Additional paid-in
capital
|
|
749,537
|
|
|
549,958
|
|
Accumulated
deficit
|
|
(453,859
|
)
|
|
(328,114
|
)
|
Total stockholders’
equity
|
|
297,934
|
|
|
223,887
|
|
Total liabilities and
stockholders’ equity
|
|
$
|
408,548
|
|
|
$
|
276,823
|
|
The accompanying
notes are an integral part of these consolidated financial
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TELLURIAN
INC. AND SUBSIDIARIES
|
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
(in
thousands, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
|
|
|
|
For
the
period
from
January
1,
2016 through
April 9, 2016
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31,
|
|
|
|
|
2018
|
|
2017
|
|
2016
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
Natural gas
sales
|
|
$
|
4,423
|
|
|
$
|
503
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
LNG sales
|
|
2,689
|
|
|
3,273
|
|
|
—
|
|
|
|
—
|
|
Other LNG
revenue
|
|
3,174
|
|
|
1,665
|
|
|
—
|
|
|
|
—
|
|
Related party
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
31
|
|
Total revenue
|
|
10,286
|
|
|
5,441
|
|
|
—
|
|
|
|
31
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and
expenses:
|
|
|
|
|
|
|
|
|
|
Cost of sales
|
|
6,115
|
|
|
7,565
|
|
|
—
|
|
|
|
—
|
|
Development
expenses
|
|
44,034
|
|
|
59,498
|
|
|
47,146
|
|
|
|
44
|
|
Depreciation, depletion and
amortization
|
|
1,567
|
|
|
479
|
|
|
69
|
|
|
|
8
|
|
General and administrative
expenses
|
|
81,777
|
|
|
98,874
|
|
|
46,515
|
|
|
|
617
|
|
Impairment charge and loss on
transfer of assets
|
|
4,513
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
Goodwill
impairment
|
|
—
|
|
|
77,592
|
|
|
—
|
|
|
|
—
|
|
Total operating costs and
expenses
|
|
138,006
|
|
|
244,008
|
|
|
93,730
|
|
|
|
669
|
|
|
|
|
|
|
|
|
|
|
|
Loss from
operations
|
|
(127,720
|
)
|
|
(238,567
|
)
|
|
(93,730
|
)
|
|
|
(638
|
)
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on preferred
stock exchange feature
|
|
—
|
|
|
2,209
|
|
|
(3,308
|
)
|
|
|
—
|
|
Interest income,
net
|
|
1,574
|
|
|
1,022
|
|
|
—
|
|
|
|
—
|
|
Other income,
net
|
|
211
|
|
|
4,062
|
|
|
217
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income
taxes
|
|
(125,935
|
)
|
|
(231,274
|
)
|
|
(96,821
|
)
|
|
|
(638
|
)
|
Income tax benefit
(provision)
|
|
190
|
|
|
(185
|
)
|
|
166
|
|
|
|
—
|
|
Net loss
|
|
$
|
(125,745
|
)
|
|
$
|
(231,459
|
)
|
|
$
|
(96,655
|
)
|
|
|
$
|
(638
|
)
|
|
|
|
|
|
|
|
|
|
|
Net loss per common
share:
|
|
|
|
|
|
|
|
|
|
Basic and
diluted
|
|
$
|
(0.59
|
)
|
|
$
|
(1.23
|
)
|
|
$
|
(1.01
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares
outstanding:
|
|
|
|
|
|
|
|
|
|
Basic and
diluted
|
|
211,574
|
|
|
188,536
|
|
|
95,795
|
|
|
|
|
The accompanying
notes are an integral part of these consolidated financial
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TELLURIAN
INC. AND SUBSIDIARIES
|
CONSOLIDATED
STATEMENTS OF STOCKHOLDERS’ EQUITY
|
(in
thousands)
|
|
|
Common
Stock
|
|
Treasury
Stock
|
|
Convertible
Preferred Stock
|
|
Preferred
Stock
|
|
|
|
|
|
|
|
|
Shares
|
|
Par Value
Amount
|
|
Shares
|
|
Cost
|
|
Shares
|
|
Par Value
Amount
|
|
Shares
|
|
Par Value
Amount
|
|
Additional
Paid-in
Capital
|
|
Accumulated
Deficit
|
|
Total
Stockholders’ Equity
|
BALANCE AT JANUARY 1, 2016
(Successor)
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Common stock issued for
acquisition
|
|
500
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
999
|
|
|
—
|
|
|
1,000
|
|
Issuance of common
stock
|
|
98,356
|
|
|
98
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
57,276
|
|
|
—
|
|
|
57,374
|
|
Issuance of Series A
preferred stock
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5,468
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
19,380
|
|
|
—
|
|
|
19,385
|
|
Share-based
compensation
|
|
10,753
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
24,493
|
|
|
—
|
|
|
24,495
|
|
Net loss
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(96,655
|
)
|
|
(96,655
|
)
|
BALANCE AT DECEMBER 31, 2016
(Successor)
|
|
109,609
|
|
|
$
|
101
|
|
|
—
|
|
|
$
|
—
|
|
|
5,468
|
|
|
$
|
5
|
|
|
—
|
|
|
—
|
|
|
$
|
102,148
|
|
|
$
|
(96,655
|
)
|
|
$
|
5,599
|
|
Merger
adjustments
|
|
51,540
|
|
|
1,390
|
|
|
(1,209
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
86,533
|
|
|
—
|
|
|
87,923
|
|
Share-based
compensation
|
|
9,350
|
|
|
16
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
23,003
|
|
|
—
|
|
|
23,019
|
|
Issuance of common
stock
|
|
46,373
|
|
|
465
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
311,459
|
|
|
—
|
|
|
311,924
|
|
Share-based
payments
|
|
1,700
|
|
|
17
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
21,148
|
|
|
—
|
|
|
21,165
|
|
Reclass of embedded
derivative
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,544
|
|
|
—
|
|
|
6,544
|
|
Treasury stock
|
|
—
|
|
|
—
|
|
|
(82
|
)
|
|
(828
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(828
|
)
|
Retirement of treasury
stock
|
|
(1,291
|
)
|
|
(1
|
)
|
|
1,291
|
|
|
828
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(827
|
)
|
|
—
|
|
|
—
|
|
Exchange from Series A
preferred stock
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(5,468
|
)
|
|
(5
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(5
|
)
|
Exchange to Series B
preferred stock
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5,468
|
|
|
55
|
|
|
—
|
|
|
—
|
|
|
(50
|
)
|
|
—
|
|
|
5
|
|
Exchange from Series B to
common stock
|
|
5,468
|
|
|
55
|
|
|
—
|
|
|
—
|
|
|
(5,468
|
)
|
|
(55
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Net loss
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(231,459
|
)
|
|
(231,459
|
)
|
BALANCE AT DECEMBER 31, 2017
(Successor)
|
|
222,749
|
|
|
$
|
2,043
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
$
|
549,958
|
|
|
$
|
(328,114
|
)
|
|
$
|
223,887
|
|
Issuance of common
stock
|
|
13,500
|
|
|
135
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
129,575
|
|
|
—
|
|
|
129,710
|
|
Issuance of Series C
preferred stock
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,124
|
|
|
61
|
|
|
49,905
|
|
|
—
|
|
|
49,966
|
|
Share-based
compensation (1)
|
|
4,407
|
|
|
17
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
20,099
|
|
|
—
|
|
|
20,116
|
|
Net loss
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(125,745
|
)
|
|
(125,745
|
)
|
BALANCE AT DECEMBER 31, 2018
(Successor)
|
|
240,656
|
|
|
$
|
2,195
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
6,124
|
|
|
$
|
61
|
|
|
$
|
749,537
|
|
|
$
|
(453,859
|
)
|
|
$
|
297,934
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|