UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
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x
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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,
2017
OR
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o
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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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¨
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Accelerated
filer
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¨
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Non-accelerated
filer
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¨ (Do not check if
smaller reporting company)
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Smaller reporting
company
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x
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Emerging growth
company
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¨
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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 30, 2017, the last
business day of the Registrant’s most recently completed second
fiscal quarter, was approximately $646,384,724. 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.
228,392,249 shares
of common stock were issued and outstanding as of
March 9,
2018 .
DOCUMENTS
INCORPORATED BY REFERENCE
Portions of the
definitive proxy statement related to the 2018 annual
meeting of stockholders, to be filed within 120 days
after December 31, 2017, 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,
2017
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
Disclosures
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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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FORWARD-LOOKING
STATEMENTS AND RISK
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;
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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;
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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
that Tellurian holds; 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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uncertainties
regarding our ability to maintain sufficient liquidity and 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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development
risks, operational hazards and regulatory approvals;
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our ability to
enter and consummate planned 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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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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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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Mcf/d
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Mcf per day
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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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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”).
Tellurian is developing a portfolio of natural gas production, LNG
marketing, and infrastructure assets that includes an LNG terminal
facility (the “Driftwood terminal”) and an associated pipeline (the
“Driftwood pipeline”) in southwest Louisiana (the Driftwood
terminal and the Driftwood pipeline collectively, the “Driftwood
Project”). 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 terminal
facility will include up to 20 liquefaction Trains, three full
containment LNG storage tanks and three marine berths. In
November 2017, we 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
Driftwood pipeline is a new 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. Tellurian estimates construction costs for the Driftwood
pipeline of approximately $2.3 billion before owners’ costs,
financing costs and contingencies.
We intend to
develop the Driftwood pipeline as part of what we refer to as the
“Tellurian Pipeline Network.” In addition to the Driftwood
pipeline, the Tellurian Pipeline Network would include two
pipelines which are currently in the early stages of development.
One, the Haynesville Global Access Pipeline, would run 200 miles
from northern to southwest Louisiana. The other, the Permian Global
Access Pipeline, would run 625 miles from west Texas to southwest
Louisiana. Each would have a diameter of 42 inches and would be
capable of delivering approximately 2 Bcf/d of natural gas. We
currently estimate that construction costs would be approximately
$1.4 billion for the Haynesville Global Access Pipeline and
approximately $3.7 billion for the Permian Global Access
Pipeline.
We have also
initiated natural gas production and LNG marketing and shipping
activities as described below in “— 2017 Developments — Significant
Transactions.”
2017
Developments
Significant Transactions
TOTAL
Investment. In January 2017, TOTAL
Delaware, Inc. (“TOTAL”), a subsidiary of TOTAL, S.A., purchased
approximately 35.4 million shares of Tellurian Investments common
stock for an aggregate purchase price of approximately $207
million. In connection with the merger, described below under “—
Merger with Magellan,” those shares were exchanged for
approximately 46 million shares of Tellurian common stock.
Tellurian and TOTAL entered into a pre-emptive rights agreement
pursuant to which TOTAL was granted a right to purchase its pro
rata portion of any new equity securities that Tellurian
Investments may issue to a third party on the same terms and
conditions as such equity securities are offered and sold to such
party, subject to certain excepted offerings.
Merger with
Magellan. 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.
Initiation
of LNG Marketing. In September 2017, we entered
into a six-month time charter contract with Maran Gas Maritime Inc.
for an LNG tanker, the Maran Gas Mystras. We took delivery of the
tanker at Galle, Sri Lanka contemporaneously with entering into the
contract. The vessel charter enabled Tellurian to execute a number
of LNG purchases and sales opportunities, as well as sub-charter
opportunities while the LNG shipping market was short vessel
capacity, resulting in revenue for 2017 of $4.9
million.
Natural Gas
Property Acquisitions. As of December 31, 2017, we
owned interests in approximately 11,844 net developed and
undeveloped acres of natural gas properties in northern Louisiana.
In November 2017, we acquired 9,119 net developed and
undeveloped acres, including 20 producing operated wells with net
current production of approximately 4 MMcf/d, for
$87.4 million, subject
to customary adjustments. Further, in December 2017, we acquired
2,725 net undeveloped acres in the same area for $2.7
million.
EPC
Agreements. As noted above, in November
2017, we entered into four LSTK EPC agreements with Bechtel for
construction of the Driftwood terminal, each covering one phase of
construction:
• Phase 1
- two LNG plants with expected production capacity up to 11.04
mtpa, two 235,000m 3
full containment
LNG tanks, one marine loading berth, and related utilities,
facilities and appurtenances;
• Phase 2
- an LNG plant with expected production capacity up to 5.52 mtpa,
one marine loading berth, and related utilities, facilities and
appurtenances;
• Phase 3
- an LNG plant with expected production capacity up to 5.52 mtpa,
one 235,000m 3
full containment
LNG tank, one marine loading berth, and related utilities,
facilities and appurtenances; and
• Phase 4
- an LNG plant with expected production capacity up to 5.52 mtpa,
and related utilities, facilities and appurtenances.
Upon issuance of
the notice to proceed with construction of the Driftwood terminal,
the aggregate contract price for the services and equipment to be
provided is $15.2 billion. In addition, we began detailed
engineering work with Bechtel on the Driftwood terminal in July
2017.
Public
Equity Offering. In December 2017, we sold
10.0 million shares of common stock for proceeds of approximately
$94.8 million, net of approximately $5.2 million in fees and
commissions. 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
total proceeds of approximately $109.3 million, net of
approximately $5.7 million in fees and commissions.
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 quarter 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. Based on this
notice, FERC plans to issue its final Environmental Impact
Statement on October 12, 2018 and has established a 90-day federal
authorization decision deadline on January 10, 2019.
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 Project. 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 Project. The
regulatory review and approval process for the USACE permit as well
as the Title V and PSD permits is expected to be completed in the
fourth quarter of 2018.
Natural Gas
Properties
Reserves
We had no natural
gas properties, and no proved reserves, as of December 31, 2016. As
discussed in “— 2017 Developments — Significant Transactions —
Natural Gas Property Acquisitions,” we subsequently acquired 11,844
net developed and undeveloped acres of natural gas properties in
northern Louisiana, including 20 producing operated wells with net
current production of approximately 4 MMcf/d. All of our proved
reserves as of December 31, 2017 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, 2017 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 2017. 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
$2.976 per MMbtu of natural gas and $51.34 per barrel of
condensate, adjusted for energy content, transportation fees and
market differentials.
The following
table shows changes in our proved reserves from December 31, 2016
to December 31, 2017:
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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, 2017):
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Developed
producing
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5,720
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10
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5,782
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Undeveloped
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321,398
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—
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321,398
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Total
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327,118
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10
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327,180
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Proved
reserves:
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December 31,
2016
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—
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—
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—
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Extensions, discoveries and
other additions
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—
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—
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—
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Revisions of previous
estimates
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—
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—
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—
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Production
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(190
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)
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—
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(191
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)
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Sale of
reserves-in-place
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—
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—
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—
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Purchases of
reserves-in-place
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327,308
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10
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327,371
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December 31,
2017
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327,118
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10
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327,180
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The standardized
measure of discounted future net cash flow from our proved reserves
(the “standardized measure”) as of December 31, 2017 was
$88.2
million .
We had no
material capital expenditures relating to our natural gas
properties from the closing of the acquisitions through December
31, 2017.
Controls Over Reserve Report Preparation, Technical Qualifications
and Technologies Used
Our December 31,
2017 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
prepares 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, 2017, 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 16 years’ 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
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
From the closing
of the acquisitions of the natural gas properties through December
31, 2017, we produced 190 MMcf of natural gas at an average sales
price of $2.42 MMcf and 150 barrels of condensate at an average
sales price of $57.01 per barrel. Natural gas and condensate
production and operating costs for the period ended December 31,
2017, was $1.25 per MMcfe.
Drilling Activity
We are not
engaged in any material drilling activities or subject to any
drilling commitments.
Wells and Acreage
As of December
31, 2017, we owned interests in 32 gross (18 net) productive
natural gas wells and held by production 9,435 gross (9,119 net)
developed leasehold acreage. Additionally, we hold 2,854 gross
(2,725 net) undeveloped leasehold acreage. While all of the
undeveloped leasehold acreage is set to expire in 2018, 1,720 gross
(1,653 net) of said acreage allows for two-year contractual
extensions.
Volume Commitments
We are not
currently subject to any 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
either third-party gathering systems or interstate pipelines. The
gathering systems provide the treating and processing necessary to
ensure that the natural gas meets the pipeline quality
specifications. We believe that these systems and other available
midstream facilities and services in the area 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 (“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”), and the Louisiana Department
of Natural Resources. 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. Though 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
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 the 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 agencies, including DOT, 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.
Many of these requirements will apply to the other pipelines in the
Tellurian Pipeline Network as well.
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 and other pipelines will be, and our natural
gas production activities are, 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. It is uncertain whether the EPA will impose any requirements
on existing power plants to reduce carbon dioxide
emissions.
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 our Driftwood Project 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 and other pipelines will be, and our natural gas
producing activities are, 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 and other pipelines 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. The EPA
intends to propose a rule with a new definition of waters of the
U.S.. Until the EPA finalizes a new rule, the definition of waters
of the U.S. from the Supreme Court case Rapanos v.
United States (2006) applies. 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 (“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, 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. These standards are currently effective, although the EPA
has proposed a two-year stay of the effective dates of several
requirements of the standards.
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. The rules became effective in January
2017, but are subject to ongoing litigation. In December 2017, the
BLM published a rule to temporarily suspend or delay certain rule
requirements until January 2019; that rule, however, was enjoined
by the U.S. District Court for the Northern District of California
in February 2018. Accordingly, the 2016 rules are currently in
effect.
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, counties and municipalities in which we operate
may regulate, among other things:
• the
location of new wells;
• the
method of drilling, completing and operating wells;
• the
surface use and restoration of properties upon which wells are
drilled;
• the
plugging and abandoning of wells;
• notice
to surface owners and other third parties; and
• produced
water and waste disposal.
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 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 certain
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 also 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 1.A — 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 undeveloped 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
As we began our
operations in the fourth quarter of 2017, 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, 10 and 11
years for Singapore, London, Houston and Washington, D.C.,
respectively.
Employees
As of December
31, 2017, Tellurian had 126 full-time employees
worldwide.
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. You may also read or copy any document we
file at the SEC’s public reference room in Washington, D.C.,
located at 100 F Street, N.E., Washington, D.C. 20549. Please call
the SEC at (800) SEC-0330 for further information on the public
reference room. 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 may 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 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 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 natural gas production activities
and other operations. Tellurian expects that operating losses will
increase substantially in 2018 and thereafter, and expects to
continue to incur operating losses and to experience negative
operating cash flows through at least 2022.
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
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:
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changes in the
regulatory environment;
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changes in
accounting and tax standards or practices;
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changes in the
composition of operating income by tax jurisdiction;
and
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our operating
results before taxes.
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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. Substantial changes include, but are not limited to, a
corporate tax rate decrease from 35% to 21% effective for tax years
beginning after December 31, 2017 and the partial transition
of U.S. international taxation from a worldwide tax system to a
territorial system, which includes a one-time transition tax on the
mandatory deemed repatriation of cumulative foreign earnings as of
December 31, 2017. Additionally, new provisions were added to
mitigate the potential erosion of the U.S. tax base and to
discourage use of low-tax jurisdictions to own intellectual
property and other valuable intangible assets. While these
provisions were intended to prevent specific perceived taxpayer
abuse, they may have adverse, unexpected consequences to many
taxpayers. At this time, the U.S. Department of Treasury has not
yet issued regulations on how the provisions of the Tax Act should
be applied and how the underlying calculations are to be prepared.
As there is little official guidance at this time regarding the
preparation of these complex
calculations,
estimates and judgment are required in assessing the consequences.
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
intercompany charges, 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, certain real property interests related to that project
and 11,844 net acres of natural gas properties. 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.
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 Project, 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.
Tellurian
currently estimates that construction costs will be approximately
$15.2 billion for the Driftwood terminal, approximately $2.3
billion for the Driftwood pipeline, approximately $1.4 billion
for the Haynesville Global Access Pipeline and approximately
$3.7 billion for the Permian Global Access Pipeline. However,
cost estimates for these and other projects we may pursue are only
approximations of the actual costs of construction and are before
owners’ costs, financing costs and contingencies. 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,
recently announced 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 cost estimates for the Haynesville Global Access Pipeline and
the Permian Global Access Pipeline are more preliminary than the
estimate for the Driftwood pipeline. Substantially all of the risks
discussed in this section that are applicable to the Driftwood
pipeline are equally applicable to the other pipelines comprising
the proposed Tellurian Pipeline Network.
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 is substantially dependent
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 our LNG sale
and purchase agreements, which could have an adverse effect on
us.
Under LNG sale
and purchase agreements with our customers, we will 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
Tellurian 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. Numerous permits and approvals will
also be required in connection with the construction and operation
of the Tellurian Pipeline Network.
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. 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 Project, and these
contractors may be unable to complete the Driftwood
Project.
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 Project 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 Project 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 Project. 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 Project 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 Project
could materially and adversely affect Tellurian’s business, results
of operations, financial condition and prospects.
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 any of our 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 Project 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
Project 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.
Additionally, our
liquefaction projects will be subject to the risk of LNG price
competition at times when we need to replace any existing LNG sale
and purchase contract, whether due to natural expiration, default
or otherwise, or enter into new LNG sale and purchase contracts.
Factors relating to competition may prevent us from entering into a
new or replacement LNG sale and purchase contract on economically
comparable terms as prior LNG sale and purchase contracts, or at
all. 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
projects;
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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
Project, 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 Project. 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 and the Tellurian Pipeline Network 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 operations,
including explosions, pollution, leakage or release of toxic
substances, fires, hurricanes and other adverse weather conditions,
leakage of LNG, 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 Project or related
infrastructure, as well as delays or cost increases in the
construction and the development of the Driftwood Project 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 and various regulatory 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 recoverable 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 recoverable 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.”
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 a revolving credit
facility. 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 prices and costs at the date of the estimate. Any significant
variance from these prices and costs could greatly affect our
estimates of reserves. At December 31, 2017, approximately 98%
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. 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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war or terrorist
attack;
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expropriation or
nationalization of assets;
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renegotiation or
nullification of existing contracts;
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changing
political conditions;
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changing laws and
policies affecting trade, taxation, and investment;
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multiple taxation
due to different tax structures;
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general hazards
associated with the assertion of sovereignty over areas in which
operations are conducted; and
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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, 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, n/k/a Tellurian Services) on the other hand (collectively,
“Parallax”). In October 2017, Driftwood Pipeline LLC (“Driftwood
Pipeline”) and Tellurian Services 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 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 September
2018.
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.” The table below presents the high and low sales prices of
our common stock, as reported by the NASDAQ, for each quarter
during 2017 and 2016. Prior to the Merger, our common stock traded
under the symbol “MPET.”
|
|
|
|
|
|
|
|
|
|
High
|
|
Low
|
Quarter
ended
|
|
|
|
December 31,
2017
|
$
|
13.74
|
|
|
$
|
9.17
|
|
September 30,
2017
|
11.24
|
|
|
8.19
|
|
June 30, 2017
|
12.54
|
|
|
8.27
|
|
March 31, 2017
|
21.74
|
|
|
9.69
|
|
|
|
|
|
Quarter
ended
|
|
|
|
December 31,
2016
|
$
|
11.95
|
|
|
$
|
4.85
|
|
September 30,
2016
|
7.17
|
|
|
1.11
|
|
June 30, 2016
|
1.41
|
|
|
0.80
|
|
March 31, 2016
|
1.49
|
|
|
0.20
|
|
As of
March 9,
2018 ,
there were approximately 540 record holders of Tellurian’s common
stock.
Tellurian has
never paid a cash dividend on its common stock. The Company does
not intend to pay cash dividends on its common stock in the
foreseeable future.
Purchases of
Equity Securities by the Issuer and Affiliated
Purchasers
The following
table summarizes the surrender to the Company of shares of common
stock to pay withholding taxes in connection with the vesting of
employee restricted stock:
|
|
|
|
|
|
|
|
|
Total Number
of Shares Purchased (1)
|
|
Average
Price Paid per Share
|
October 2017
|
—
|
|
|
$
|
—
|
|
November 2017
|
10,488
|
|
11.03
|
|
December 2017
|
—
|
|
|
—
|
|
Total
|
10,488
|
|
|
|
|
|
|
(1) Reflects the surrender to
the Company of shares of common stock to pay withholding taxes in
connection with the vesting of restricted stock issued to employees
pursuant to the Omnibus Plan.
|
ITEM 6.
SELECTED FINANCIAL DATA
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, completed the Merger with Tellurian Investments Inc.
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:
|
|
•
|
Overview of
Significant Events
|
|
|
•
|
Liquidity and
Capital Resources
|
|
|
•
|
Capital
Development Activities
|
|
|
•
|
Off-balance Sheet
Arrangements
|
|
|
•
|
Summary of
Critical Accounting Estimates
|
|
|
•
|
Recent Accounting
Standards
|
Our
Business
Tellurian intends
to create value for shareholders by building
a low-cost, global natural gas business, profitably
delivering natural gas to customers worldwide (the “Business”).
Tellurian is developing a portfolio of natural gas production, LNG
marketing, and infrastructure assets that includes an LNG terminal
facility (the “Driftwood terminal”) and an associated pipeline (the
“Driftwood pipeline”) in southwest Louisiana (the Driftwood
terminal and the Driftwood pipeline collectively, the “Driftwood
Project”). 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 terminal
facility will include up to 20 liquefaction Trains, three full
containment LNG storage tanks and three marine berths. In
November 2017, we 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
Driftwood pipeline is a new 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. Tellurian estimates construction costs for the Driftwood
pipeline of approximately $2.3 billion before owners’ costs,
financing costs and contingencies.
We intend to
develop the Driftwood pipeline as part of what we refer to as the
“Tellurian Pipeline Network.” In addition to the Driftwood
pipeline, the Tellurian Pipeline Network would include two
pipelines which are currently in the early stages of development.
One, the Haynesville Global Access Pipeline, would run 200 miles
from northern to southwest Louisiana. The other, the Permian Global
Access Pipeline, would run 625 miles from west Texas to southwest
Louisiana. Each would have a diameter of 42 inches and would be
capable of delivering approximately 2 Bcf/d of natural gas. We
currently estimate that construction costs would be approximately
$1.4 billion for the Haynesville Global Access Pipeline and
approximately $3.7 billion for the Permian Global Access
Pipeline.
We have also
initiated natural gas production and LNG marketing and shipping
activities as described below in “— Overview of Significant
Events.”
Overview of
Significant Events
Significant Transactions
TOTAL
Investment. In January 2017, TOTAL, a
subsidiary of TOTAL, S.A., purchased approximately 35.4 million
shares of Tellurian Investments common stock for an aggregate
purchase price of approximately $207 million. In connection with
the Merger, those shares were exchanged for approximately 46
million shares of Tellurian common stock. Tellurian and TOTAL
entered into a pre-emptive rights agreement pursuant to which TOTAL
was granted a right to purchase its pro rata portion of any new
equity securities that Tellurian Investments may issue to a third
party on the same terms and conditions as such equity securities
are offered and sold to such party, subject to certain excepted
offerings.
Merger with
Magellan. In February 2017, Tellurian
Inc., which was formerly known as Magellan Petroleum Corporation,
completed the Merger with Tellurian Investments Inc. Immediately
following the completion of the Merger, Magellan amended its
certificate of incorporation and bylaws to change its name to
“Tellurian Inc.” As described in “— Explanatory Note,” in
connection with the Merger, each outstanding share of common stock
of Tellurian Investments was exchanged for 1.3 shares of Magellan
common stock.
Initiation
of LNG Marketing. In September 2017, we entered
into a six-month time charter contract with Maran Gas Maritime Inc.
for an LNG tanker, the Maran Gas Mystras. We took delivery of the
tanker at Galle, Sri Lanka contemporaneously with entering into the
contract. The vessel charter enabled Tellurian to execute a number
of LNG purchases and sales opportunities, as well as sub-charter
opportunities while the LNG shipping market was short vessel
capacity, resulting in revenue for 2017 of $4.9
million.
Natural Gas
Property Acquisitions. As of December 31, 2017, we
owned interests in approximately 11,844 net developed and
undeveloped acres of natural gas properties in northern Louisiana.
In November 2017, we acquired 9,119 net developed and
undeveloped acres, including 20 producing operated wells with net
current production of approximately 4 MMcf/d, for
$87.4 million, subject to customary adjustments. Further, in
December 2017, we acquired 2,725 net undeveloped acres in the same
area for $2.7 million.
EPC
Agreements. As noted above, in November
2017, we entered into four LSTK EPC agreements with Bechtel for
construction of the Driftwood terminal, each covering one phase of
construction:
• Phase 1
- two LNG plants with expected production capacity up to 11.04
mtpa, two 235,000m 3
full containment
LNG tanks, one marine loading berth, and related utilities,
facilities and appurtenances;
• Phase 2
- an LNG plant with expected production capacity up to 5.52 mtpa,
one marine loading berth, and related utilities, facilities and
appurtenances;
• Phase 3
- an LNG plant with expected production capacity up to 5.52 mtpa,
one 235,000m 3
full containment
LNG tank, one marine loading berth, and related utilities,
facilities and appurtenances; and
• Phase 4
- an LNG plant with expected production capacity up to 5.52 mtpa,
and related utilities, facilities and appurtenances.
Upon issuance of
the notice to proceed with construction of the Driftwood terminal,
the aggregate contract price for the services and equipment to be
provided is $15.2 billion. In addition, we began detailed
engineering work with Bechtel on the Driftwood terminal in July
2017.
Public
Equity Offering. In December 2017, we sold
10.0 million shares of common stock for proceeds of approximately
$94.8 million, net of approximately $5.2 million in fees and
commissions. 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
total proceeds of approximately $109.3 million, net of
approximately $5.7 million in fees and commissions.
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 quarter 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. Based on this
notice, FERC plans to issue its final Environmental Impact
Statement on October 12, 2018 and has established a 90-day federal
authorization decision deadline on January 10, 2019.
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 Project. 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 Project. The
regulatory review and approval process for the USACE permit as well
as the Title V and PSD permits is expected to be completed in the
fourth quarter of 2018.
Liquidity
and Capital Resources
Capital
Resources
The Company is
currently funding its development activities and general working
capital needs through its cash on hand. Our current capital
resources consist of approximately $128.3 million
of cash and cash
equivalents as of December 31, 2017
on a consolidated
basis, which are primarily the result of issuances of common stock,
including our December 2017 equity raise and the issuance of common
stock to TOTAL in January 2017. Tellurian considers all highly
liquid investments with an original maturity of three months or
less to be cash equivalents.
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,
|
|
|
|
|
2017
|
|
2016
|
Cash used in operating
activities
|
|
$
|
(109,229
|
)
|
|
$
|
(50,430
|
)
|
Cash used in investing
activities
|
|
(95,565
|
)
|
|
(10,506
|
)
|
Cash provided by financing
activities
|
|
311,669
|
|
|
82,334
|
|
|
|
|
|
|
Net increase in cash and cash
equivalents
|
|
106,875
|
|
|
21,398
|
|
Cash and cash equivalents,
beginning of the period
|
|
21,398
|
|
|
—
|
|
Cash and cash equivalents,
end of the period
|
|
$
|
128,273
|
|
|
$
|
21,398
|
|
|
|
|
|
|
Net working
capital
|
|
$
|
81,393
|
|
|
$
|
17
|
|
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 . The increase in cash used in operating
activities primarily relates 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 in the normal course of business
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 . The increase in cash used in investing
activities primarily relates 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 . The increase in cash provided by financing
activities primarily relates to net proceeds from the issuance of
common shares.
Capital
Development Activities
The activities we
have proposed will require significant amounts of capital and are
subject to risks and delays in completion. Even if successfully
completed, we will not begin to operate and generate significant
cash flows until at least several years from now, which management
currently anticipates being 2023. 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,
|
|
|
|
|
2017
|
|
2016
|
|
|
Total revenue
|
|
$
|
5,441
|
|
|
$
|
—
|
|
|
|
$
|
31
|
|
Cost of sales
|
|
7,565
|
|
|
—
|
|
|
|
—
|
|
Development
expenses
|
|
59,498
|
|
|
47,146
|
|
|
|
44
|
|
Depreciation, depletion and
amortization
|
|
479
|
|
|
69
|
|
|
|
8
|
|
General and administrative
expenses
|
|
98,874
|
|
|
46,515
|
|
|
|
617
|
|
Goodwill
impairment
|
|
77,592
|
|
|
—
|
|
|
|
—
|
|
Loss from
operations
|
|
(238,567
|
)
|
|
(93,730
|
)
|
|
|
(638
|
)
|
Gain (loss) on preferred
stock exchange feature
|
|
2,209
|
|
|
(3,308
|
)
|
|
|
—
|
|
Other income,
net
|
|
5,084
|
|
|
217
|
|
|
|
—
|
|
Income tax benefit
(provision)
|
|
(185
|
)
|
|
166
|
|
|
|
—
|
|
Net loss
|
|
$
|
(231,459
|
)
|
|
$
|
(96,655
|
)
|
|
|
$
|
(638
|
)
|
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.
|
|
|
•
|
A change of
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
$4.9
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,
2017 , 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.
Summary of
Critical Accounting Estimates
Our accounting
policies are more fully described in Note 1 of the Consolidated Financial
Statements. 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
Provisions for
income taxes are based on taxes payable or refundable for the
current year and deferred taxes on temporary differences between
the tax basis of assets and liabilities and their reported amounts
in the Consolidated Financial Statements.
Deferred tax
assets and liabilities are included in the Consolidated Financial
Statements at currently enacted income tax rates applicable to the
period in which the deferred tax assets and liabilities are
expected to be realized or settled. As changes in tax laws or rates
are enacted, deferred tax assets and liabilities are adjusted
through the current period’s provision for income taxes. A full
valuation allowance equal to our net deferred tax asset balance has
been established due to the uncertainty of realizing the tax
benefits related to our net deferred tax assets.
Reserves
Estimates
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. 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. In certain instances, we utilize accepted
offers from third-party purchasers as the basis for determining
fair value. 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 for additional information
regarding impairment of goodwill.
Share-Based
Compensation
Share-based
payment 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 the 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.
Recent
Accounting Standards
For descriptions
of recently issued accounting standards, see Note
14
,
Recent
Accounting Standards ,
of our Notes to
Consolidated Financial Statements.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
Not
applicable.
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
|
|
|
|
1. Basis of Presentation and
Summary of Significant Accounting Policies
|
|
|
|
2. Merger and
Acquisition
|
|
|
|
3. Deferred Engineering
Costs
|
|
|
|
4. Transactions with Related
Parties
|
|
|
|
5. Property, Plant and
Equipment
|
|
|
|
6. Accounts Payable and
Accrued Liabilities
|
|
|
|
7. Commitments and
Contingencies
|
|
|
|
8. Share-Based
Compensation
|
|
|
|
9. Share-Based
Payments
|
|
|
|
10. Income Taxes
|
|
|
|
11. Stockholders'
Equity
|
|
|
|
12. Earnings Per
Share
|
|
|
|
13. Supplemental Cash Flow
Information
|
|
|
|
14. Recent Accounting
Standards
|
|
|
|
15. Subsequent
Events
|
|
Supplementary
Information
|
|
|
Supplemental Disclosures
about Natural Gas Producing Activities (unaudited)
|
|
MANAGEMENT’S
REPORT ON INTERNAL CONTROLS 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, 2017.
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, 2017, as stated in
their report beginning on page 33.
|
|
|
|
|
|
|
|
|
/s/ Meg A.
Gentle
|
|
/s/ Antoine J.
Lafargue
|
|
/s/ Khaled
Sharafeldin
|
Meg A. Gentle
|
|
Antoine J.
Lafargue
|
|
Khaled
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
|
|
|
|
|
|
|
|
March 15,
2018
|
|
|
|
|
|
|
|
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of
Directors and Stockholders of
Tellurian,
Inc.
Houston,
Texas
Opinions on
the Financial Statements and Internal Control over Financial
Reporting
We have audited
the accompanying consolidated balance sheets of Tellurian, Inc. and
subsidiaries (the “Company”) as of December 31, 2017 and 2016, the
related consolidated statements of operations, stockholders’ equity
and cash flows for each of the two years in the period ended
December 31, 2017 (Successor statements of operations,
stockholders’ equity, and cash flows), as well as the consolidated
statement s
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 (collectively referred to as the “financial
statements”). We also have audited the Company’s internal control
over financial reporting as of December 31, 2017, 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 financial statements referred to above present fairly, in all
material respects, the financial position of the Company as of
December 31, 2017 and 2016, and the results of its operations and
its cash flows for each of the two years in the period ended
December 31, 2017, as well as the period from January 1, 2016
through April 9, 2016, in conformity with accounting principles
generally accepted in the United States of America. Also, in our
opinion, the Company maintained, in all material respects,
effective internal control over financial reporting as of December
31, 2017, based on criteria established in Internal
Control - Integrated Framework (2013) issued by COSO.
Basis for
Opinions
The Company’s
management is responsible for these financial statements, 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 these financial
statements and an opinion on the Company’s internal control over
financial reporting based on our audits. We are a public accounting
firm registered with the Public Company Accounting Oversight Board
(United States) (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 audits to obtain
reasonable assurance about whether the financial statements are
free of material misstatement, whether due to error or fraud, and
whether effective internal control over financial reporting was
maintained in all material respects.
Our audits of the
financial statements 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. Our audit of internal control over financial reporting
included obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness
exists, and testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk. Our
audits also included performing such other procedures as we
considered necessary in the circumstances. We believe that our
audits provide a reasonable basis for our opinions.
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
|
|
|
March 15,
2018
|
|
|
|
|
|
We have served as the
Company’s auditor since 2016.
|
|
|
|
|
|
|
|
|
|
|
TELLURIAN
INC. AND SUBSIDIARIES
|
CONSOLIDATED
BALANCE SHEETS
|
(in
thousands, except share and per share amounts)
|
|
|
|
|
|
December
31,
|
|
|
2017
|
|
2016
|
ASSETS
|
|
|
Current assets:
|
|
|
|
|
Cash and cash
equivalents
|
|
$
|
128,273
|
|
|
$
|
21,398
|
|
Accounts
receivable
|
|
583
|
|
|
—
|
|
Accounts receivable due from
related parties
|
|
1,377
|
|
|
1,333
|
|
Prepaid assets and
other
|
|
3,458
|
|
|
2,012
|
|
Total current
assets
|
|
133,691
|
|
|
24,743
|
|
|
|
|
|
|
Property, plant and
equipment, net
|
|
115,856
|
|
|
10,993
|
|
Deferred engineering
costs
|
|
18,000
|
|
|
—
|
|
Other non-current
assets
|
|
9,276
|
|
|
3,342
|
|
Total assets
|
|
$
|
276,823
|
|
|
$
|
39,078
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS’
EQUITY
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
Accounts payable and accrued
liabilities
|
|
$
|
50,563
|
|
|
$
|
24,403
|
|
Accounts payable due to
related parties
|
|
—
|
|
|
323
|
|
Other current
liabilities
|
|
1,735
|
|
|
—
|
|
Total current
liabilities
|
|
52,298
|
|
|
24,726
|
|
|
|
|
|
|
Asset retirement
obligation
|
|
638
|
|
|
—
|
|
Total
liabilities
|
|
52,936
|
|
|
24,726
|
|
|
|
|
|
|
Embedded
derivative
|
|
—
|
|
|
8,753
|
|
|
|
|
|
|
Commitments and contingencies
(Note 7)
|
|
|
|
|
|
|
|
|
|
Stockholders’
equity:
|
|
|
|
|
Series A convertible
preferred stock: par value $0.001 per share;
zero and 5.5 million shares authorized and issued,
respectively
|
|
—
|
|
|
5
|
|
Common stock: par value $0.01
and $0.001 per share, respectively;
400 million shares and 200
million shares authorized, respectively;
222.7 million shares and
109.6 million shares issued, respectively
|
|
2,043
|
|
|
101
|
|
Additional paid-in
capital
|
|
549,958
|
|
|
102,148
|
|
Accumulated
deficit
|
|
(328,114
|
)
|
|
(96,655
|
)
|
Total stockholders’
equity
|
|
223,887
|
|
|
5,599
|
|
Total liabilities and
stockholders’ equity
|
|
$
|
276,823
|
|
|
$
|
39,078
|
|
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,
|
|
|
|
|
2017
|
|
2016
|
|
|
Revenues
|
|
|
|
|
|
|
|
Natural gas
sales
|
|
$
|
503
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
LNG sales
|
|
3,273
|
|
|
—
|
|
|
|
—
|
|
Other LNG
revenue
|
|
1,665
|
|
|
—
|
|
|
|
—
|
|
Related party
|
|
—
|
|
|
—
|
|
|
|
31
|
|
Total revenue
|
|
5,441
|
|
|
—
|
|
|
|
31
|
|
|
|
|
|
|
|
|
|
Operating costs and
expenses
|
|
|
|
|
|
|
|
Cost of sales (exclusive of
items shown separately below)
|
|
7,565
|
|
|
—
|
|
|
|
—
|
|
Development
expenses
|
|
59,498
|
|
|
47,146
|
|
|
|
44
|
|
Depreciation, depletion and
amortization
|
|
479
|
|
|
69
|
|
|
|
8
|
|
General and administrative
expenses
|
|
98,874
|
|
|
46,515
|
|
|
|
617
|
|
Goodwill
impairment
|
|
77,592
|
|
|
—
|
|
|
|
—
|
|
Total operating costs and
expenses
|
|
244,008
|
|
|
93,730
|
|
|
|
669
|
|
|
|
|
|
|
|
|
|
Loss from
operations
|
|
(238,567
|
)
|
|
(93,730
|
)
|
|
|
(638
|
)
|
|
|
|
|
|
|
|
|
Gain (loss) on preferred
stock exchange feature
|
|
2,209
|
|
|
(3,308
|
)
|
|
|
—
|
|
Other income,
net
|
|
5,084
|
|
|
217
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
Loss before income
taxes
|
|
(231,274
|
)
|
|
(96,821
|
)
|
|
|
(638
|
)
|
Income tax benefit
(provision)
|
|
(185
|
)
|
|
166
|
|
|
|
—
|
|
Net loss attributable to
common stockholders
|
|
$
|
(231,459
|
)
|
|
$
|
(96,655
|
)
|
|
|
$
|
(638
|
)
|
|
|
|
|
|
|
|
|
Net loss per common
share:
|
|
|
|
|
|
|
|
Basic and
diluted
|
|
$
|
(1.23
|
)
|
|
$
|
(1.01
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares
outstanding
|
|
|
|
|
|
|
|
Basic and
diluted
|
|
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
|
|
|
|
|
|
|
|
|
Shares
|
|
Par Value
Amount
|
|
Shares
|
|
Cost
|
|
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
|
|
The accompanying
notes are an integral part of these consolidated financial
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TELLURIAN
INC. AND SUBSIDIARIES
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
(in
thousands)
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
|
|
|
|
|
For the
period from January 1, 2016 through April 9, 2016
|
|
|
Year Ended
December 31,
|
|
|
|
|
2017
|
|
2016
|
|
|
Cash flows from operating
activities:
|
|
|
|
|
|
|
|
Net
loss
|
|
$
|
(231,459
|
)
|
|
$
|
(96,655
|
)
|
|
|
$
|
(638
|
)
|
Adjustments to reconcile net
loss to net cash used in operating activities:
|
|
|
|
|
|
|
|
Depreciation, depletion and
amortization
|
|
479
|
|
|
69
|
|
|
|
8
|
|
Goodwill
impairment
|
|
77,592
|
|
|
—
|
|
|
|
—
|
|
Loss on disposal of
assets
|
|
—
|
|
|
185
|
|
|
|
3
|
|
Provision for income tax
benefit
|
|
—
|
|
|
(170
|
)
|
|
|
—
|
|
(Gain) loss on Series A
convertible preferred stock exchange feature
|
|
(2,209
|
)
|
|
3,308
|
|
|
|
—
|
|
Gain on sale of
securities
|
|
(3,481
|
)
|
|
—
|
|
|
|
—
|
|
Share-based
compensation
|
|
23,019
|
|
|
24,495
|
|
|
|
—
|
|
Share-based
payments
|
|
19,397
|
|
|
—
|
|
|
|
—
|
|
Net changes in working
capital (Note 13)
|
|
7,433
|
|
|
18,338
|
|
|
|
516
|
|
Net cash used in operating
activities
|
|
(109,229
|
)
|
|
(50,430
|
)
|
|
|
(111
|
)
|
|
|
|
|
|
|
|
|
Cash flows from investing
activities:
|
|
|
|
|
|
|
|
Cash received in
acquisition
|
|
56
|
|
|
210
|
|
|
|
—
|
|
Acquisition of natural gas
properties
|
|
(90,099
|
)
|
|
—
|
|
|
|
—
|
|
Deferred engineering
costs
|
|
(9,000
|
)
|
|
—
|
|
|
|
—
|
|
Purchase
of property - land
|
|
—
|
|
|
(9,491
|
)
|
|
|
—
|
|
Purchase
of property and equipment
|
|
(1,114
|
)
|
|
(1,225
|
)
|
|
|
(268
|
)
|
Proceeds from sale of
available-for-sale securities
|
|
4,592
|
|
|
—
|
|
|
|
—
|
|
Net cash used in investing
activities
|
|
(95,565
|
)
|
|
(10,506
|
)
|
|
|
(268
|
)
|
|
|
|
|
|
|
|
|
Cash flows from financing
activities:
|
|
|
|
|
|
|
|
Proceeds from the issuance of
common stock
|
|
318,204
|
|
|
59,015
|
|
|
|
—
|
|
Tax payments for net share
settlement of equity awards
|
|
(828
|
)
|
|
—
|
|
|
|
—
|
|
Proceeds from the issuance of
preferred stock
|
|
—
|
|
|
25,000
|
|
|
|
—
|
|
Equity offering
costs
|
|
(5,707
|
)
|
|
(1,681
|
)
|
|
|
—
|
|
Net cash provided by
financing activities
|
|
311,669
|
|
|
82,334
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in
cash and cash equivalents
|
|
106,875
|
|
|
21,398
|
|
|
|
(379
|
)
|
Cash and cash equivalents,
beginning of period
|
|
21,398
|
|
|
—
|
|
|
|
589
|
|
Cash and cash equivalents,
end of period
|
|
$
|
128,273
|
|
|
$
|
21,398
|
|
|
|
$
|
210
|
|
The accompanying
notes are an integral part of these consolidated financial
statements.
TELLURIAN
INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 —
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
Tellurian Inc., a
Delaware corporation based in Houston, Texas (“Tellurian”), plans
to develop, own and operate a global natural gas business and to
deliver natural gas to customers worldwide. Tellurian is
establishing a portfolio of natural gas production, LNG marketing,
and infrastructure including an LNG terminal facility (the
“Driftwood terminal”) and an associated pipeline (the “Driftwood
pipeline”) in southwest Louisiana (the Driftwood terminal and the
Driftwood pipeline collectively, the “Driftwood
Project”).
On February 10,
2017 (the “Merger Date”), Tellurian Investments Inc. (“Tellurian
Investments”) completed a merger (the “Merger”) with a subsidiary
of Magellan Petroleum Corporation (“Magellan”). Magellan changed
its corporate name to Tellurian Inc. shortly after completing the
Merger. The Merger was accounted for as a “reverse acquisition,”
with Tellurian Investments being treated as the accounting
acquirer. As such, the historical consolidated comparative
information as of and for all periods in 2016 in this report
relates to Tellurian Investments and its subsidiaries. Subsequent
to the Merger Date, the information relates to the consolidated
entities of Tellurian Inc., with Magellan reflected as the
accounting acquiree. In connection with the Merger, each issued and
outstanding share of Tellurian Investments common stock was
exchanged for 1.3 shares of Magellan common
stock. All share and per share amounts in the Consolidated
Financial Statements and related notes have been retroactively
adjusted for all periods presented to give effect to this exchange,
including reclassifying an amount equal to the change in par value
of common stock from additional paid-in capital.
On April 9, 2016,
Tellurian Investments acquired Tellurian Services LLC (“Tellurian
Services”), formerly known as Parallax Services LLC (“Parallax
Services”). Under the financial reporting rules of the SEC,
Parallax Services (“Predecessor”) has been deemed to be the
predecessor to Tellurian (“Successor”) for financial reporting
purposes.
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.
While we recently
commenced operations, we are still subject to significant risks and
uncertainties, including failing to secure additional funding to
construct the Driftwood Project.
Basis of
Presentation
Our Consolidated
Financial Statements were prepared in accordance with GAAP. The
Consolidated Financial Statements include the accounts of Tellurian
Inc. and its wholly and majority owned subsidiaries. All
intercompany accounts and transactions have been eliminated in
consolidation.
Segments
Management
allocates resources and assesses financial performance on a
consolidated basis. As such, for the purposes of financial
reporting under GAAP during the years ended December 31, 2017 and
2016, the Company operated as a single operating
segment.
Use of
Estimates
The preparation
of financial statements in conformity with GAAP requires management
to make certain estimates and assumptions that affect the amounts
reported in the Consolidated Financial Statements and the
accompanying notes. Management evaluates its estimates and related
assumptions on a regular basis. Changes in facts and circumstances
or additional information may result in revised estimates, and
actual results may differ from these estimates.
Fair
Value
The Company uses
three levels of the fair value hierarchy of inputs to measure the
fair value of an asset or a liability. Level 1 inputs are quoted
prices in active markets for identical assets or liabilities. Level
2 inputs are inputs other than quoted prices included within Level
1 that are directly or indirectly observable for the asset or
liability. Level 3 inputs are inputs that are not observable in the
market.
Goodwill
Goodwill
resulting from a business combination is not subject to
amortization. The Company tests such goodwill at the reporting unit
level for impairment on an annual basis and between annual tests if
an event occurs or circumstances change that would more likely than
not reduce the fair value of the reporting unit below its carrying
amount.
Revenue
Recognition
TELLURIAN
INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
Revenues
associated with sales of natural gas, condensate, LNG and all other
sources are recorded when title passes to the customer, net of
royalties, discounts and allowances, as applicable. Purchases and
sales of inventory with the same counterparty that are entered into
in contemplation of one another (including buy/sell arrangements)
are combined and recorded on a net basis and reported in “LNG
Sales” on the Consolidated Statements of Operations. Payments
received relating to future revenues are deferred and recognized
when all revenue recognition criteria are met.
Cash
Equivalents
We consider all
highly liquid investments with an original maturity of three months
or less to be cash equivalents.
Concentration
of Cash
We maintain cash
balances at financial institutions, which may at times be in excess
of federally insured levels. We have not incurred losses related to
these balances to date.
Property,
Plant and Equipment
Natural gas
development and production activities are accounted for using the
successful efforts method of accounting. Costs incurred to acquire
a property (whether unproved or proved) are capitalized when
incurred. Lease rentals are expensed as incurred. Natural gas
exploratory costs are expensed as incurred and costs to develop
proved reserves are capitalized. All costs related to production,
general corporate overhead, and similar activities are expensed as
incurred. We deplete our natural gas reserves using the
units-of-production method.
Fixed assets are
recorded at cost. We depreciate our property, plant and equipment,
excluding land, using the straight-line depreciation method over
the estimated useful life of the asset. Upon retirement or other
disposition of property, plant and equipment, the cost and related
accumulated depreciation are removed, and the resulting gains or
losses are recorded in our Statements of Operations. Management
tests property, plant and equipment for impairment whenever events
or changes in circumstances indicate that the carrying amount of
property, plant and equipment might not be
recoverable.
Accounting
for LNG Development Activities
As we have been
in the preliminary stage of developing the Driftwood terminal,
substantially all of the costs to date related to such activities
have been expensed. These costs primarily include professional fees
associated with FEED studies and applying to FERC for authorization
to construct our terminals and other required permitting for the
Driftwood Project.
Costs incurred in
connection with a project to develop the Driftwood terminal shall
generally be treated as development expenses until the project has
reached the notice-to-proceed state (“NTP State”) and the following
criteria (the “NTP Criteria”) have been achieved: (i) regulatory
approval has been received, (ii) financing for the project is
available and (iii) management has committed to commence
construction. In addition to the above, certain costs incurred
prior to achieving the NTP State will be capitalized though the NTP
Criteria have not been met. Costs to be capitalized prior to
achieving the NTP State include land purchase costs, land
improvement costs, costs associated with preparing the facility for
use and any fixed structure construction costs (fence, storage
areas, drainage, etc.). Furthermore, activities directly associated
with detailed engineering and/or facility designs shall be
capitalized.
Share-Based
Compensation
Share-based
payment 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.
Income
Taxes
Income taxes are
accounted for using the asset and liability approach. Under this
approach, deferred tax assets and liabilities are recognized based
on anticipated future tax consequences attributable to
carryforwards and differences between financial statement carrying
amounts of assets and liabilities and their respective tax basis.
Management assesses the realizability of deferred tax assets and
recognizes valuation allowances as appropriate.
Earnings Per
Share
Basic earnings
per share (“EPS”) excludes dilution and is computed by dividing net
income (loss) by the weighted average number of common shares
outstanding during the period. Diluted EPS reflects potential
dilution and is computed by dividing net
TELLURIAN
INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
income (loss) by
the weighted average number of common shares outstanding during the
period increased by the number of additional common shares that
would have been outstanding if the potential common shares had been
issued and were dilutive.
NOTE 2 —
MERGER AND ACQUISITION
The
Merger
As discussed in
Note 1 , Basis of
Presentation and Summary of Significant Accounting Policies
, Tellurian
Investments merged with a subsidiary of Magellan on February 10,
2017. The Merger has been accounted for as a “reverse acquisition,”
with Tellurian Investments being treated as the accounting acquirer
using the acquisition method.
The total
consideration exchanged was as follows (in thousands, except share
and per-share amounts):
|
|
|
|
|
|
|
|
|
|
Number of shares of Magellan
common stock outstanding (1)
|
|
5,985,042
|
|
|
Price per share of Magellan
common stock (2)
|
|
$
|
14.21
|
|
|
Aggregate value of Tellurian
common stock issued
|
|
|
$
|
85,048
|
|
Fair value of stock
options (3)
|
|
|
2,821
|
|
Net purchase consideration to
be allocated
|
|
|
$
|
87,869
|
|
|
|
|
|
|
(1) The number of shares of
Magellan common stock issued and outstanding as of February 9,
2017.
|
(2) The closing price of
Magellan common stock on the NASDAQ on February 9,
2017.
|
(3) The estimated fair value
of Magellan stock options for pre-Merger services
rendered.
|
We utilized
estimated fair values at the Merger Date for the allocation of
consideration to the net tangible and intangible assets acquired
and liabilities assumed. The purchase price allocation to assets
acquired and liabilities assumed in the Merger was as follows (in
thousands):
|
|
|
|
|
|
Fair Value of Assets
Acquired:
|
|
|
Cash
|
|
$
|
56
|
|
Securities
available-for-sale
|
|
1,111
|
|
Other current
assets
|
|
93
|
|
Unproved
properties
|
|
13,000
|
|
Wells in
progress
|
|
332
|
|
Land, buildings and
equipment, net
|
|
67
|
|
Other long-term
assets
|
|
19
|
|
Total assets
acquired
|
|
14,678
|
|
Fair Value of Liabilities
Assumed:
|
|
|
Accounts payable and other
liabilities
|
|
4,393
|
|
Notes payable
|
|
8
|
|
Total liabilities
assumed
|
|
4,401
|
|
Total net assets
acquired
|
|
10,277
|
|
Goodwill as a result of the
Merger
|
|
$
|
77,592
|
|
We valued our
interests acquired in unproved oil and gas properties using a
market approach based on commercial negotiations and bids received
for the interests (see Note 5 , Property,
Plant and Equipment ,
for more
information about the properties). The fair value of other
property, plant and equipment and wells in progress was determined
to be the carrying value of Magellan. Securities available-for-sale
were valued based on quoted market prices. The carrying values of
cash, other current assets, accounts payable and accrued
liabilities and other non-current assets and liabilities
approximated fair value at the Merger Date. The Company has
determined that such fair value measures for the overall allocation
are classified as Level 3 in the fair value hierarchy.
Goodwill
recognized as a result of the Merger totaled approximately
$77.6
million , none of which is deductible for
income tax purposes. Subsequent to the Merger, the Company
determined that there is no evidence that we will recover the value
of this goodwill and an impairment expense of approximately
$77.6
million was recognized during
the year
ended December 31, 2017 .
TELLURIAN
INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
For purposes of
determining the goodwill impairment, we utilized qualitative
factors as well as the fair values determined when allocating
consideration as of the Merger Date.
Parallax
Services Acquisition
On April 9, 2016,
Tellurian Investments acquired Parallax Services, which was renamed
Tellurian Services, with equity consideration valued at
approximately $1 million
. The transaction
was accounted for using the acquisition method. As of
December 31,
2017 ,
goodwill of approximately $1.2 million
, included within
Other non-current assets, net, on our Consolidated Balance Sheets,
was entirely related to the acquisition of Tellurian
Services.
Pro Forma
Results
The following
table provides unaudited pro forma results for the
year ended
December 31, 2017 , and 2016, as if the Merger
occurred and Parallax Services had been acquired as of January 1,
2016 (in thousands, except per-share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31,
|
|
|
2017
|
|
2016
|
Pro forma net
loss
|
|
$
|
(235,201
|
)
|
|
$
|
(100,734
|
)
|
Pro forma net loss per basic
share
|
|
$
|
(1.24
|
)
|
|
$
|
(0.98
|
)
|
Pro forma basic and diluted
weighted average common shares outstanding
|
|
189,246
|
|
|
102,281
|
|
The unaudited pro
forma results include adjustments for the historical net loss of
Magellan and Parallax Services as well as an increase in
compensation expense associated with the addition of three new
directors. The pro forma information is provided for informational
purposes only and is not necessarily indicative of what Tellurian’s
results of operations would have been if the Merger and acquisition
of Parallax Services had occurred on January 1, 2016. Following the
Merger Date, approximately $ 0.8 million
of net loss
related to the acquired activities has been included in our
Consolidated Financial Statements.
NOTE 3 —
DEFERRED ENGINEERING COSTS
Deferred
engineering costs of $18.0 million
at
December 31,
2017 ,
represent detailed engineering services related to the Driftwood
terminal. Such costs will be deferred until construction commences
on the Driftwood terminal, at which time they will be transferred
to construction in progress. The $18.0 million
of deferred
engineering costs includes $9.0 million
which is recorded
in accounts payable.
NOTE 4 —
TRANSACTIONS WITH RE L
ATED
PARTIES
Accounts
Receivable due from Related Parties
Tellurian’s
accounts receivable due from related parties primarily consists of
tax indemnities from employees who received share-based
compensation.
Accounts
Payable due to Related Parties
In December 2017,
Tellurian and Martin Houston, a major shareholder and Vice Chairman
of the Company, agreed to mutually discharge $0.3 million
owed by Tellurian
to entities partially owned by Mr. Houston.
Non-current
Note Receivable due from Related Party
In July 2017,
the $0.3
million non-current note receivable
due from Mr. Houston was repaid in full, and the demand note
evidencing the receivable was canceled.
Other
During the
year ended
December 31, 2017 , the Company incurred
$0.7
million in
legal fees to a law firm for advice associated with a lawsuit that
was settled in April 2017. A member of our board of directors is a
partner at such law firm.
NOTE 5 —
PROPERTY, PLANT AND E
QUIPMENT
Property, plant
and equipment is comprised of fixed assets and oil and natural gas
properties, as shown below (in thousands):
TELLURIAN
INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
|
|
|
|
|
|
|
|
|
|
December
31,
|
|
2017
|
|
2016
|
Land
|
$
|
9,491
|
|
|
$
|
9,491
|
|
Proved oil and natural gas
properties
|
90,869
|
|
|
—
|
|
Unproved oil and natural gas
properties
|
13,000
|
|
|
—
|
|
Wells in
progress
|
345
|
|
|
—
|
|
Corporate and
other
|
2,693
|
|
|
1,571
|
|
Total fixed assets, at
cost
|
116,398
|
|
|
11,062
|
|
Accumulated depreciation and
depletion
|
(542
|
)
|
|
(69
|
)
|
Total property, plant and
equipment, net
|
$
|
115,856
|
|
|
$
|
10,993
|
|
Depreciation and
depletion expense for the years ended December
31, 2017 , and 2016 was approximately
$0.5
million and $0.1 million
,
respectively.
Oil and
Natural Gas Properties
Proved
Properties
Tellurian has
acquired producing and non-producing acreage in northern Louisiana.
For more information about these properties, please see
“Supplemental Disclosures about Natural Gas Producing
Activities.”
Unproved
Properties
In connection
with the Merger, the Company acquired interests in certain unproved
properties in the Weald Basin, United Kingdom and the Bonaparte
Basin, Australia. In the United Kingdom, Tellurian holds
non-operating interests in two licenses which expire in June
and September 2021, respectively. In Australia, Tellurian holds an
operating interest in an exploration permit which expires in May
2019.
NOTE 6 —
ACCOUNTS PAYABLE AND ACCRUED
LIABILITIES
The
components of accounts payable and accrued liabilities consist of
the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
December
31,
|
|
|
2017
|
|
2016
|
Project development
activities
|
|
$
|
14,870
|
|
|
$
|
12,549
|
|
Payroll and
compensation
|
|
25,833
|
|
|
6,311
|
|
Accrued taxes
|
|
2,764
|
|
|
—
|
|
Professional services (e.g.,
legal, audit)
|
|
3,696
|
|
|
2,323
|
|
Contingency loss
|
|
—
|
|
|
2,560
|
|
Other
|
|
3,400
|
|
|
660
|
|
Total accounts payable and
accrued liabilities
|
|
$
|
50,563
|
|
|
$
|
24,403
|
|
NOTE 7 —
COMMITMENTS AND CONT I
NGENCIES
Litigation
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,
n/k/a Tellurian Services) on the other hand (collectively,
“Parallax”). In October 2017, Driftwood Pipeline LLC (“Driftwood
Pipeline”) and Tellurian Services 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 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 September
2018.