FORM 10-K
|
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
|
Delaware
|
|
06-0842255
|
(State or other jurisdiction
of incorporation or organization)
|
|
(I.R.S. Employer Identification No.)
|
|
|
|
1201 Louisiana Street, Suite 3100, Houston, TX
|
|
77002
|
(Address of principal executive offices)
|
|
(Zip Code)
|
(832) 962-4000
|
||
(Registrant’s telephone number, including area code)
|
|
Securities registered pursuant to Section 12(b) of the Act:
|
||
Title of each class
|
|
Name of each exchange on which registered
|
Common stock, $0.01 par value
|
|
NASDAQ Capital Market
|
|
|
|
Securities registered pursuant to Section 12(g) of the Act: None
|
Yes
|
x
|
No
|
¨
|
Yes
|
¨
|
No
|
x
|
Yes
|
x
|
No
|
¨
|
Yes
|
x
|
No
|
¨
|
Large accelerated filer
|
x
|
Accelerated filer
|
¨
|
|
|
|
|
Non-accelerated filer
|
¨
|
Smaller reporting company
|
¨
|
|
|
|
|
|
|
Emerging growth company
|
¨
|
Yes
|
¨
|
No
|
x
|
|
|
|
|
|
|
|
Page
|
|
|
|
Item 1 and 2.
|
Our Business and Properties
|
|
Item 1A.
|
Risk Factors
|
|
Item 1B.
|
Unresolved Staff Comments
|
|
Item 3.
|
Legal Proceedings
|
|
Item 4.
|
Mine Safety Disclosures
|
|
|
|
|
Item 5.
|
Market for the Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities
|
|
Item 6.
|
Selected Financial Data
|
|
Item 7.
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
|
Item 7A.
|
Quantitative and Qualitative Disclosures About Market Risk
|
|
Item 8.
|
Financial Statements and Supplementary Data
|
|
Item 9.
|
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
|
|
Item 9A.
|
Controls and Procedures
|
|
Item 9B.
|
Other Information
|
|
|
|
|
Item 10.
|
Directors, Executive Officers and Corporate Governance
|
|
Item 11.
|
Executive Compensation
|
|
Item 12.
|
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
|
|
Item 13.
|
Certain Relationships and Related Transactions, and Director Independence
|
|
Item 14.
|
Principal Accounting Fees and Services
|
|
|
|
|
Item 15.
|
Exhibits, Financial Statement Schedules
|
|
Item 16.
|
Form 10-K Summary
|
|
Signatures
|
|
•
|
our businesses and prospects and our overall strategy;
|
•
|
planned or estimated capital expenditures;
|
•
|
availability of liquidity and capital resources;
|
•
|
our ability to obtain additional financing as needed and the terms of financing transactions, including at Driftwood Holdings LLC;
|
•
|
revenues and expenses;
|
•
|
progress in developing our projects and the timing of that progress;
|
•
|
future values of the Company’s projects or other interests, operations or rights; and
|
•
|
government regulations, including our ability to obtain, and the timing of, necessary governmental permits and approvals.
|
•
|
the uncertain nature of demand for and price of natural gas and LNG;
|
•
|
risks related to shortages of LNG vessels worldwide;
|
•
|
technological innovation which may render our anticipated competitive advantage obsolete;
|
•
|
risks related to a terrorist or military incident involving an LNG carrier;
|
•
|
changes in legislation and regulations relating to the LNG industry, including environmental laws and regulations that impose significant compliance costs and liabilities;
|
•
|
governmental interventions in the LNG industry, including increases in barriers to international trade;
|
•
|
uncertainties regarding our ability to maintain sufficient liquidity and attract sufficient capital resources to implement our projects;
|
•
|
our limited operating history;
|
•
|
our ability to attract and retain key personnel;
|
•
|
risks related to doing business in, and having counterparties in, foreign countries;
|
•
|
our reliance on the skill and expertise of third-party service providers;
|
•
|
the ability of our vendors to meet their contractual obligations;
|
•
|
risks and uncertainties inherent in management estimates of future operating results and cash flows;
|
•
|
our ability to maintain compliance with our senior secured term loan and other agreements;
|
•
|
changes in competitive factors, including the development or expansion of LNG, pipeline and other projects that are competitive with ours;
|
•
|
development risks, operational hazards and regulatory approvals;
|
•
|
our ability to enter and consummate planned financing and other transactions; and
|
•
|
risks and uncertainties associated with litigation matters.
|
ASC
|
Accounting Standards Codification
|
ASU
|
Accounting Standards Update
|
Bcf
|
Billion cubic feet of natural gas
|
Bcf/d
|
Billion cubic feet per day
|
Bcfe
|
Billion cubic feet of natural gas equivalent
|
Condensate
|
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
|
DD&A
|
Depreciation, depletion, and amortization
|
DOE/FE
|
U.S. Department of Energy, Office of Fossil Energy
|
EPC
|
Engineering, procurement, and construction
|
FASB
|
Financial Accounting Standards Board
|
FEED
|
Front-End Engineering and Design
|
FERC
|
U.S. Federal Energy Regulatory Commission
|
FTA countries
|
Countries with which the U.S. has a free trade agreement providing for national treatment for trade in natural gas
|
GAAP
|
Generally accepted accounting principles in the U.S.
|
LNG
|
Liquefied natural gas
|
LSTK
|
Lump Sum Turnkey
|
Mcf
|
Thousand cubic feet of natural gas
|
MMBtu
|
Million British thermal unit
|
MMcf
|
Million cubic feet of natural gas
|
MMcf/d
|
MMcf per day
|
MMcfe
|
Million of cubic feet gas equivalent volumes using a ratio of 6 Mcf to 1 barrel of liquid.
|
Mtpa
|
Million tonnes per annum
|
Nasdaq
|
Nasdaq Capital Market
|
NGA
|
Natural Gas Act of 1938, as amended
|
Non-FTA countries
|
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
|
Oil
|
Crude oil and condensate
|
PSD
|
Prevention of Significant Deterioration
|
PUD
|
Proved undeveloped reserves
|
SEC
|
U.S. Securities and Exchange Commission
|
Train
|
An industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
|
U.K.
|
United Kingdom
|
U.S.
|
United States
|
USACE
|
U.S. Army Corps of Engineers
|
•
|
rates and charges for natural gas transportation and related services;
|
•
|
the certification and construction of new facilities;
|
•
|
the extension and abandonment of services and facilities;
|
•
|
the maintenance of accounts and records;
|
•
|
the acquisition and disposition of facilities;
|
•
|
the initiation and discontinuation of services; and
|
•
|
various other matters.
|
•
|
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.
|
•
|
increased construction costs;
|
•
|
economic downturns, increases in interest rates or other events that may affect the availability of sufficient financing for LNG projects on commercially reasonable terms;
|
•
|
decreases in the price of natural gas or LNG, which might decrease the expected returns relating to investments in LNG projects;
|
•
|
the inability of project owners or operators to obtain governmental approvals to construct or operate LNG facilities; and
|
•
|
political unrest or local community resistance to the siting of LNG facilities due to safety, environmental or security concerns.
|
•
|
design, engineer and receive critical components and equipment necessary for the Driftwood terminal to operate in accordance with specifications and address any start-up and operational issues that may arise in connection with the commencement of commercial operations;
|
•
|
attract, develop and retain skilled personnel and engage and retain third-party subcontractors, and address any labor issues that may arise;
|
•
|
post required construction bonds and comply with the terms thereof, and maintain their own financial condition, including adequate working capital;
|
•
|
adhere to any warranties the contractors provide in their EPC contracts; and
|
•
|
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.
|
•
|
difficulties or delays in obtaining, or failure to obtain, sufficient equity or debt financing on reasonable terms;
|
•
|
failure to obtain all necessary government and third-party permits, approvals and licenses for the construction and operation of the Driftwood Project or any other proposed LNG facilities;
|
•
|
difficulties in engaging qualified contractors necessary to the construction of the contemplated Driftwood Project or other LNG facilities;
|
•
|
shortages of equipment, material or skilled labor;
|
•
|
natural disasters and catastrophes, such as hurricanes, explosions, fires, floods, industrial accidents and terrorism;
|
•
|
unscheduled delays in the delivery of ordered materials;
|
•
|
work stoppages and labor disputes;
|
•
|
competition with other domestic and international LNG export terminals;
|
•
|
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;
|
•
|
unexpected or unanticipated need for additional improvements; and
|
•
|
adverse general economic conditions.
|
•
|
competitive liquefaction capacity in North America;
|
•
|
insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;
|
•
|
insufficient or oversupply of LNG tanker capacity;
|
•
|
weather conditions;
|
•
|
reduced demand and lower prices for natural gas;
|
•
|
increased natural gas production deliverable by pipelines, which could suppress demand for LNG;
|
•
|
decreased oil and natural gas exploration activities, which may decrease the production of natural gas;
|
•
|
cost improvements that allow competitors to offer LNG regasification services or provide natural gas liquefaction capabilities at reduced prices;
|
•
|
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;
|
•
|
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;
|
•
|
political conditions in natural gas producing regions; and
|
•
|
cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.
|
•
|
increases in worldwide LNG production capacity and availability of LNG for market supply;
|
•
|
increases in demand for LNG but at levels below those required to maintain current price equilibrium with respect to supply;
|
•
|
increases in the cost to supply natural gas feedstock to our liquefaction project;
|
•
|
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;
|
•
|
decreases in the price of non-U.S. LNG, including decreases in price as a result of contracts indexed to lower oil prices;
|
•
|
increases in capacity and utilization of nuclear power and related facilities;
|
•
|
increases in the cost of LNG shipping; and
|
•
|
displacement of LNG by pipeline natural gas or alternative fuels in locations where access to these energy sources is not currently available.
|
•
|
an inadequate number of shipyards constructing LNG vessels and a backlog of orders at these shipyards;
|
•
|
political or economic disturbances in the countries where the vessels are being constructed;
|
•
|
changes in governmental regulations or maritime self-regulatory organizations;
|
•
|
work stoppages or other labor disturbances at the shipyards;
|
•
|
bankruptcies or other financial crises of shipbuilders;
|
•
|
quality or engineering problems;
|
•
|
weather interference or catastrophic events, such as a major earthquake, tsunami, or fire; or
|
•
|
shortages of or delays in the receipt of necessary construction materials.
|
•
|
injury or loss of life;
|
•
|
severe damage to or destruction of property, natural resources or equipment;
|
•
|
pollution or other environmental damage;
|
•
|
facility or equipment malfunctions and equipment failures or accidents;
|
•
|
clean-up responsibilities;
|
•
|
regulatory investigations and administrative, civil and criminal penalties; and
|
•
|
injunctions resulting in limitation or suspension of operations.
|
•
|
conduct of drilling, completion, production and midstream activities;
|
•
|
amounts and types of emissions and discharges;
|
•
|
generation, management, and disposal of hazardous substances and waste materials;
|
•
|
reclamation and abandonment of wells and facility sites; and
|
•
|
remediation of contaminated sites.
|
•
|
currency fluctuations;
|
•
|
war or terrorist attack;
|
•
|
expropriation or nationalization of assets;
|
•
|
renegotiation or nullification of existing contracts;
|
•
|
changing political conditions;
|
•
|
changing laws and policies affecting trade, taxation, and investment;
|
•
|
multiple taxation due to different tax structures;
|
•
|
general hazards associated with the assertion of sovereignty over areas in which operations are conducted; and
|
•
|
the unexpected credit rating downgrade of countries in which Tellurian’s LNG customers are based.
|
|
12/31/2013
|
|
12/31/2014
|
|
12/31/2015
|
|
12/31/2016
|
|
12/31/2017
|
|
12/31/2018
|
|
Tellurian Inc.
|
100
|
|
88
|
|
7
|
|
137
|
|
118
|
|
84
|
|
Russell 2000
|
100
|
|
104
|
|
98
|
|
117
|
|
132
|
|
116
|
|
Peer Group
|
100
|
|
113
|
|
56
|
|
83
|
|
88
|
|
79
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||||||
|
Year Ended December 31,
|
|
|
For the period from January 1, 2016 through April 9, 2016
|
Year Ended December 31,
|
|||||||||||||||
|
2018
|
2017
|
2016
|
|
|
2015
|
2014
|
|||||||||||||
Total revenue
|
$
|
10,286
|
|
$
|
5,441
|
|
$
|
—
|
|
|
|
$
|
31
|
|
$
|
1,686
|
|
$
|
1,460
|
|
Income (loss) from operations
|
(127,720
|
)
|
(238,567
|
)
|
(93,730
|
)
|
|
|
(638
|
)
|
105
|
|
631
|
|
||||||
Net income (loss)
|
(125,745
|
)
|
(231,459
|
)
|
(96,655
|
)
|
|
|
(638
|
)
|
105
|
|
631
|
|
||||||
Net loss per common share - basic and diluted
|
(0.59
|
)
|
(1.23
|
)
|
(1.01
|
)
|
|
|
na*
|
|
na*
|
|
na*
|
|
||||||
|
|
|
|
|
|
|
|
|
||||||||||||
|
Successor
|
|
|
Predecessor
|
||||||||||||||||
|
December 31,
|
|
|
April 9,
|
December 31,
|
|||||||||||||||
|
2018
|
2017
|
2016
|
|
|
2016
|
2015
|
2014
|
||||||||||||
Cash and cash equivalents
|
$
|
133,714
|
|
$
|
128,273
|
|
$
|
21,398
|
|
|
|
$
|
210
|
|
$
|
589
|
|
$
|
258
|
|
Property, plant and equipment, net
|
130,580
|
|
115,856
|
|
10,993
|
|
|
|
480
|
|
148
|
|
111
|
|
||||||
Deferred engineering costs
|
69,000
|
|
18,000
|
|
—
|
|
|
|
—
|
|
—
|
|
—
|
|
||||||
Non-current restricted cash
|
49,875
|
|
—
|
|
—
|
|
|
|
—
|
|
—
|
|
—
|
|
||||||
Total assets
|
408,548
|
|
276,823
|
|
39,078
|
|
|
|
1,108
|
|
1,137
|
|
1,515
|
|
||||||
Long-term borrowings
|
57,048
|
|
—
|
|
—
|
|
|
|
—
|
|
—
|
|
—
|
|
||||||
|
|
|
|
|
|
|
|
|
•
|
Our Business
|
•
|
Overview of Significant Events
|
•
|
Liquidity and Capital Resources
|
•
|
Capital Development Activities
|
•
|
Results of Operations
|
•
|
Off-balance Sheet Arrangements
|
•
|
Commitments and Contingencies
|
•
|
Summary of Critical Accounting Estimates
|
•
|
Recent Accounting Standards
|
|
|
Year Ended December 31,
|
|
|
For the period from January 1, 2016 through April 9, 2016
|
||||||||||||
|
|
|
|
||||||||||||||
|
|
2018
|
|
2017
|
|
2016
|
|
|
|||||||||
Cash used in operating activities
|
|
$
|
(103,752
|
)
|
|
$
|
(109,229
|
)
|
|
$
|
(50,430
|
)
|
|
|
$
|
(111
|
)
|
Cash used in investing activities
|
|
(21,687
|
)
|
|
(95,565
|
)
|
|
(10,506
|
)
|
|
|
(268
|
)
|
||||
Cash provided by financing activities
|
|
180,755
|
|
|
311,669
|
|
|
82,334
|
|
|
|
—
|
|
||||
|
|
|
|
|
|
|
|
|
|
||||||||
Net increase (decrease) in cash, cash equivalents and restricted cash
|
|
55,316
|
|
|
106,875
|
|
|
21,398
|
|
|
|
(379
|
)
|
||||
Cash, cash equivalents and restricted cash, beginning of the period
|
|
128,273
|
|
|
21,398
|
|
|
—
|
|
|
|
589
|
|
||||
Cash, cash equivalents and restricted cash, end of the period
|
|
$
|
183,589
|
|
|
$
|
128,273
|
|
|
$
|
21,398
|
|
|
|
$
|
210
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Net working capital
|
|
$
|
87,664
|
|
|
$
|
81,393
|
|
|
$
|
17
|
|
|
|
$
|
(784
|
)
|
|
Payments Due By Period
|
||||||||||||||||||
|
Total
|
|
2019
|
|
2020-2021
|
|
2022-2023
|
|
Thereafer
|
||||||||||
Senior secured term loan
(1)
|
$
|
60,000
|
|
|
$
|
—
|
|
|
$
|
60,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Operating lease obligations
(2)
|
$
|
25,848
|
|
|
3,126
|
|
|
6,950
|
|
|
7,711
|
|
|
8,061
|
|
||||
Other obligations
(3)
|
$
|
3,727
|
|
|
2,087
|
|
|
1,158
|
|
|
46
|
|
|
436
|
|
||||
Total
|
$
|
89,575
|
|
|
$
|
5,213
|
|
|
$
|
68,108
|
|
|
$
|
7,757
|
|
|
$
|
8,497
|
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
|
|
|
|
|
|
For the
period from January 1, 2016 through April 9, 2016 |
||||||||||
|
|
|
|
|
|
|
|||||||||||
|
|
Year Ended December 31,
|
|
|
|||||||||||||
|
|
2018
|
|
2017
|
|
2016
|
|
|
|||||||||
Total revenue
|
|
$
|
10,286
|
|
|
$
|
5,441
|
|
|
$
|
—
|
|
|
|
$
|
31
|
|
Cost of sales
|
|
6,115
|
|
|
7,565
|
|
|
—
|
|
|
|
—
|
|
||||
Development expenses
|
|
44,034
|
|
|
59,498
|
|
|
47,146
|
|
|
|
44
|
|
||||
Depreciation, depletion and amortization
|
|
1,567
|
|
|
479
|
|
|
69
|
|
|
|
8
|
|
||||
General and administrative expenses
|
|
81,777
|
|
|
98,874
|
|
|
46,515
|
|
|
|
617
|
|
||||
Impairment charge and loss on transfer of assets
|
|
4,513
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Goodwill impairment
|
|
—
|
|
|
77,592
|
|
|
—
|
|
|
|
—
|
|
||||
Loss from operations
|
|
(127,720
|
)
|
|
(238,567
|
)
|
|
(93,730
|
)
|
|
|
(638
|
)
|
||||
Gain (loss) on preferred stock exchange feature
|
|
—
|
|
|
2,209
|
|
|
(3,308
|
)
|
|
|
—
|
|
||||
Interest income, net
|
|
1,574
|
|
|
1,022
|
|
|
—
|
|
|
|
—
|
|
||||
Other income, net
|
|
211
|
|
|
4,062
|
|
|
217
|
|
|
|
—
|
|
||||
Income tax benefit (provision)
|
|
190
|
|
|
(185
|
)
|
|
166
|
|
|
|
—
|
|
||||
Net loss
|
|
$
|
(125,745
|
)
|
|
$
|
(231,459
|
)
|
|
$
|
(96,655
|
)
|
|
|
$
|
(638
|
)
|
•
|
Revenue during the year ended December 31, 2018 increased approximately $4.8 million compared to the same period in 2017, primarily due to the increase in natural gas revenue as a result of a full year of operations and participation in certain wells that became operational in the current period.
|
•
|
The $15.5 million decrease in development expenses is primarily due to the nature of services related to our largest development vendor, Bechtel. The services Bechtel provided during the year ended December 31, 2018, which primarily consisted of detailed engineering services for the Driftwood terminal, are being capitalized, whereas the FEED studies on the Driftwood Project were expensed during the same period in 2017. For more information regarding the detailed engineering services provided by Bechtel, see Note 3,
Deferred Engineering Costs
, of our Notes to Consolidated Financial Statements included in this report.
|
•
|
The $17.1 million decrease in general and administrative expenses is attributable to a decrease in share-based compensation and share-based payments to vendors, partially offset by an increase in compensation expense due to an overall increase in headcount when compared to the same period in 2017.
|
•
|
Approximately $2.7 million and $1.8 million resulting from the impairment of certain non-producing proved properties and loss on the transfer of the Australian exploration permit, respectively, both of which are outlined in Note 5,
Property, Plant and Equipment
, of our Notes to the Consolidated Financial Statements included in this report.
|
•
|
Other income, net for the year ended December 31, 2018 decreased approximately $3.9 million compared to the same period in 2017. The decrease is primarily attributable to an absence of a gain on sale of securities of approximately $3.5 million in 2017.
|
•
|
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
|
•
|
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.
|
•
|
Revenue during the year ended December 31, 2017
increase
d approximately
$5.4 million
compared to the same period in 2016. This increase is primarily due to LNG sales revenue of approximately $3.3 million and LNG sub-charter revenue of approximately $1.7 million.
|
•
|
Approximately
$5.5 million
was recognized due to an exchange feature of the Tellurian Investments Series A convertible preferred stock issued during 2016.
|
•
|
Other income, net for the year ended December 31, 2017
increase
d approximately
$3.8 million
compared to the same period in 2016. The
increase
is primarily attributable to a gain on sale of securities of approximately $3.5 million.
|
•
|
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.
|
|
|
|
|
Page
|
Management’s Report on Internal Control Over Financial Reporting
|
||||
Report of Independent Registered Public Accounting Firm
|
||||
Consolidated Financial Statements:
|
|
|||
|
Consolidated Balance Sheets
|
|||
|
Consolidated Statements of Operations
|
|||
|
Consolidated Statements of Stockholders’ Equity
|
|||
|
Consolidated Statements of Cash Flows
|
|||
|
Notes to the Consolidated Financial Statements
|
|||
Supplementary Information
|
|
|||
|
Supplemental Disclosures About Natural Gas Producing Activities (unaudited)
|
|||
Schedule I
|
|
|||
|
Condensed Financial Information of Registrant Tellurian Inc.
|
/s/ Meg A. Gentle
|
|
/s/ Antoine J. Lafargue
|
|
/s/ Khaled A. Sharafeldin
|
|||
Meg A. Gentle
|
|
Antoine J. Lafargue
|
|
Khaled A. Sharafeldin
|
|||
President and Chief Executive Officer
(as Principal Executive Officer)
|
|
Senior Vice President and Chief Financial Officer
(as Principal Financial Officer)
|
|
Chief Accounting Officer
(as Principal Accounting Officer) |
|||
|
|
||||||
|
|
|
|
|
|
|
|
Houston, Texas
|
|
|
|
|
|
|
|
February 27, 2019
|
|
|
|
|
|
|
|
/s/ DELOITTE & TOUCHE LLP
|
||
|
|
|
Houston, Texas
|
|
|
February 27, 2019
|
|
|
|
|
|
We have served as the Company’s auditor since 2016.
|
/s/ DELOITTE & TOUCHE LLP
|
||
|
|
|
Houston, Texas
|
|
|
February 27, 2019
|
|
|
TELLURIAN INC. AND SUBSIDIARIES
|
||||||||
CONSOLIDATED BALANCE SHEETS
|
||||||||
(in thousands, except share and per share amounts)
|
||||||||
|
|
|
||||||
|
|
December 31,
|
||||||
|
|
2018
|
|
2017
|
||||
ASSETS
|
|
|
||||||
Current assets:
|
|
|
|
|
||||
Cash and cash equivalents
|
|
$
|
133,714
|
|
|
$
|
128,273
|
|
Accounts receivable
|
|
1,498
|
|
|
583
|
|
||
Accounts receivable due from related parties
|
|
1,316
|
|
|
1,377
|
|
||
Prepaids and other
|
|
3,906
|
|
|
3,458
|
|
||
Total current assets
|
|
140,434
|
|
|
133,691
|
|
||
|
|
|
|
|
||||
Property, plant and equipment, net
|
|
130,580
|
|
|
115,856
|
|
||
Deferred engineering costs
|
|
69,000
|
|
|
18,000
|
|
||
Non-current restricted cash
|
|
49,875
|
|
|
—
|
|
||
Other non-current assets
|
|
18,659
|
|
|
9,276
|
|
||
Total assets
|
|
$
|
408,548
|
|
|
$
|
276,823
|
|
|
|
|
|
|
||||
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
||||
Current liabilities:
|
|
|
|
|
||||
Accounts payable
|
|
$
|
11,597
|
|
|
$
|
11,462
|
|
Accrued liabilities
|
|
41,173
|
|
|
39,101
|
|
||
Other current liabilities
|
|
—
|
|
|
1,735
|
|
||
Total current liabilities
|
|
52,770
|
|
|
52,298
|
|
||
|
|
|
|
|
||||
Long-term liabilities:
|
|
|
|
|
||||
Senior secured term loan
|
|
57,048
|
|
|
—
|
|
||
Asset retirement obligation
|
|
796
|
|
|
638
|
|
||
Total long-term liabilities
|
|
57,844
|
|
|
638
|
|
||
|
|
|
|
|
||||
Commitments and contingencies (Note 8)
|
|
|
|
|
||||
|
|
|
|
|
||||
Stockholders’ equity:
|
|
|
|
|
||||
Preferred stock, $0.01 par value, 100,000,000 authorized: 6,123,782 and zero shares outstanding, respectively
|
|
61
|
|
|
—
|
|
||
Common stock, $0.01 par value, 400,000,000 authorized: 240,655,607 and 222,749,220 shares outstanding, respectively
|
|
2,195
|
|
|
2,043
|
|
||
Additional paid-in capital
|
|
749,537
|
|
|
549,958
|
|
||
Accumulated deficit
|
|
(453,859
|
)
|
|
(328,114
|
)
|
||
Total stockholders’ equity
|
|
297,934
|
|
|
223,887
|
|
||
Total liabilities and stockholders’ equity
|
|
$
|
408,548
|
|
|
$
|
276,823
|
|
TELLURIAN INC. AND SUBSIDIARIES
|
|||||||||||||||||
CONSOLIDATED STATEMENTS OF OPERATIONS
|
|||||||||||||||||
(in thousands, except per share amounts)
|
|||||||||||||||||
|
|
|
|
|
|
|
|
|
|
||||||||
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
|
|
|
|
|
|
For the
period from
January 1,
2016 through April 9, 2016
|
||||||||||
|
|
|
|
|
|
|
|||||||||||
|
|
Year Ended December 31,
|
|
|
|||||||||||||
|
|
2018
|
|
2017
|
|
2016
|
|
|
|||||||||
Revenues:
|
|
|
|
|
|
|
|
|
|
||||||||
Natural gas sales
|
|
$
|
4,423
|
|
|
$
|
503
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
LNG sales
|
|
2,689
|
|
|
3,273
|
|
|
—
|
|
|
|
—
|
|
||||
Other LNG revenue
|
|
3,174
|
|
|
1,665
|
|
|
—
|
|
|
|
—
|
|
||||
Related party
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
31
|
|
||||
Total revenue
|
|
10,286
|
|
|
5,441
|
|
|
—
|
|
|
|
31
|
|
||||
|
|
|
|
|
|
|
|
|
|
||||||||
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
||||||||
Cost of sales
|
|
6,115
|
|
|
7,565
|
|
|
—
|
|
|
|
—
|
|
||||
Development expenses
|
|
44,034
|
|
|
59,498
|
|
|
47,146
|
|
|
|
44
|
|
||||
Depreciation, depletion and amortization
|
|
1,567
|
|
|
479
|
|
|
69
|
|
|
|
8
|
|
||||
General and administrative expenses
|
|
81,777
|
|
|
98,874
|
|
|
46,515
|
|
|
|
617
|
|
||||
Impairment charge and loss on transfer of assets
|
|
4,513
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Goodwill impairment
|
|
—
|
|
|
77,592
|
|
|
—
|
|
|
|
—
|
|
||||
Total operating costs and expenses
|
|
138,006
|
|
|
244,008
|
|
|
93,730
|
|
|
|
669
|
|
||||
|
|
|
|
|
|
|
|
|
|
||||||||
Loss from operations
|
|
(127,720
|
)
|
|
(238,567
|
)
|
|
(93,730
|
)
|
|
|
(638
|
)
|
||||
|
|
|
|
|
|
|
|
|
|
||||||||
Gain (loss) on preferred stock exchange feature
|
|
—
|
|
|
2,209
|
|
|
(3,308
|
)
|
|
|
—
|
|
||||
Interest income, net
|
|
1,574
|
|
|
1,022
|
|
|
—
|
|
|
|
—
|
|
||||
Other income, net
|
|
211
|
|
|
4,062
|
|
|
217
|
|
|
|
—
|
|
||||
|
|
|
|
|
|
|
|
|
|
||||||||
Loss before income taxes
|
|
(125,935
|
)
|
|
(231,274
|
)
|
|
(96,821
|
)
|
|
|
(638
|
)
|
||||
Income tax benefit (provision)
|
|
190
|
|
|
(185
|
)
|
|
166
|
|
|
|
—
|
|
||||
Net loss
|
|
$
|
(125,745
|
)
|
|
$
|
(231,459
|
)
|
|
$
|
(96,655
|
)
|
|
|
$
|
(638
|
)
|
|
|
|
|
|
|
|
|
|
|
||||||||
Net loss per common share:
|
|
|
|
|
|
|
|
|
|
||||||||
Basic and diluted
|
|
$
|
(0.59
|
)
|
|
$
|
(1.23
|
)
|
|
$
|
(1.01
|
)
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|
||||||||
Weighted average shares outstanding:
|
|
|
|
|
|
|
|
|
|
||||||||
Basic and diluted
|
|
211,574
|
|
|
188,536
|
|
|
95,795
|
|
|
|
|
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,
|
|
|
|||||||||||||
|
|
2018
|
|
2017
|
|
2016
|
|
|
|||||||||
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
||||||||
Net loss
|
|
$
|
(125,745
|
)
|
|
$
|
(231,459
|
)
|
|
$
|
(96,655
|
)
|
|
|
$
|
(638
|
)
|
Adjustments to reconcile net loss to net cash used in operating activities:
|
|
|
|
|
|
|
|
|
|
||||||||
Depreciation, depletion and amortization
|
|
1,567
|
|
|
479
|
|
|
69
|
|
|
|
8
|
|
||||
Goodwill impairment
|
|
—
|
|
|
77,592
|
|
|
—
|
|
|
|
—
|
|
||||
Loss on disposal of assets
|
|
—
|
|
|
—
|
|
|
185
|
|
|
|
3
|
|
||||
Provision for income tax benefit
|
|
—
|
|
|
—
|
|
|
(170
|
)
|
|
|
—
|
|
||||
Amortization of debt issuance costs
|
|
267
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
(Gain) loss on Series A convertible preferred stock exchange feature
|
|
—
|
|
|
(2,209
|
)
|
|
3,308
|
|
|
|
—
|
|
||||
Gain on sale of securities
|
|
—
|
|
|
(3,481
|
)
|
|
—
|
|
|
|
—
|
|
||||
Share-based compensation
|
|
5,126
|
|
|
23,019
|
|
|
24,495
|
|
|
|
—
|
|
||||
Impairment charge and loss on transfer of assets
|
|
4,513
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Share-based payments
|
|
—
|
|
|
19,397
|
|
|
—
|
|
|
|
—
|
|
||||
Net changes in working capital (Note 16)
|
|
10,520
|
|
|
7,433
|
|
|
18,338
|
|
|
|
516
|
|
||||
Net cash used in operating activities
|
|
(103,752
|
)
|
|
(109,229
|
)
|
|
(50,430
|
)
|
|
|
(111
|
)
|
||||
|
|
|
|
|
|
|
|
|
|
||||||||
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
||||||||
Cash received in acquisition
|
|
—
|
|
|
56
|
|
|
210
|
|
|
|
—
|
|
||||
Acquisition and development of natural gas properties
|
|
(8,356
|
)
|
|
(90,099
|
)
|
|
—
|
|
|
|
—
|
|
||||
Deferred engineering costs
|
|
(10,000
|
)
|
|
(9,000
|
)
|
|
—
|
|
|
|
—
|
|
||||
Proceeds from transfer of asset
|
|
167
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Purchase of property - land
|
|
(3,498
|
)
|
|
—
|
|
|
(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
|
|
(21,687
|
)
|
|
(95,565
|
)
|
|
(10,506
|
)
|
|
|
(268
|
)
|
||||
|
|
|
|
|
|
|
|
|
|
||||||||
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
||||||||
Proceeds from borrowing under term loan
|
|
59,400
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Payments of term loan financing costs
|
|
(2,621
|
)
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Proceeds from the issuance of common stock
|
|
133,800
|
|
|
318,204
|
|
|
59,015
|
|
|
|
—
|
|
||||
Tax payments for net share settlement of equity awards (Note 16)
|
|
(5,734
|
)
|
|
(828
|
)
|
|
—
|
|
|
|
—
|
|
||||
Proceeds from the issuance of preferred stock
|
|
—
|
|
|
—
|
|
|
25,000
|
|
|
|
—
|
|
||||
Equity offering costs
|
|
(4,090
|
)
|
|
(5,707
|
)
|
|
(1,681
|
)
|
|
|
—
|
|
||||
Net cash provided by financing activities
|
|
180,755
|
|
|
311,669
|
|
|
82,334
|
|
|
|
—
|
|
||||
|
|
|
|
|
|
|
|
|
|
||||||||
Net increase (decrease) in cash, cash equivalents and restricted cash
|
|
55,316
|
|
|
106,875
|
|
|
21,398
|
|
|
|
(379
|
)
|
||||
Cash, cash equivalents and restricted cash, beginning of period
|
|
128,273
|
|
|
21,398
|
|
|
—
|
|
|
|
589
|
|
||||
Cash, cash equivalents and restricted cash, end of period
|
|
$
|
183,589
|
|
|
$
|
128,273
|
|
|
$
|
21,398
|
|
|
|
$
|
210
|
|
Supplementary disclosure of cash flow information:
|
|
|
|
|
|
|
|
|
|
||||||||
Interest paid
|
|
$
|
(1,174
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
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.
|
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
|
|
|
|
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
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Land
|
$
|
13,276
|
|
|
$
|
9,491
|
|
Proved properties
|
101,459
|
|
|
90,869
|
|
||
Unproved properties
|
10,204
|
|
|
13,000
|
|
||
Wells in progress
|
4,660
|
|
|
345
|
|
||
Corporate and other
|
2,905
|
|
|
2,693
|
|
||
Total fixed assets, at cost
|
132,504
|
|
|
116,398
|
|
||
Accumulated depreciation and depletion
|
(1,924
|
)
|
|
(542
|
)
|
||
Total property, plant and equipment, net
|
$
|
130,580
|
|
|
$
|
115,856
|
|
|
December 31, 2018
|
|
December 31, 2017
|
||||
Land lease and purchase options
|
$
|
4,115
|
|
|
$
|
2,948
|
|
Permitting costs
|
12,585
|
|
|
4,708
|
|
||
Other
|
1,959
|
|
|
1,620
|
|
||
Total other non-current assets
|
$
|
18,659
|
|
|
$
|
9,276
|
|
|
|
December 31,
|
||||||
|
|
2018
|
|
2017
|
||||
Project development activities
|
|
$
|
8,879
|
|
|
$
|
5,142
|
|
Payroll and compensation
|
|
23,286
|
|
|
25,833
|
|
||
Accrued taxes
|
|
2,507
|
|
|
2,764
|
|
||
Professional services (e.g., legal, audit)
|
|
2,423
|
|
|
2,806
|
|
||
Accrued rent and other
|
|
4,078
|
|
|
2,556
|
|
||
Total accrued liabilities
|
|
$
|
41,173
|
|
|
$
|
39,101
|
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
Thereafter
|
|
Total
|
||||||||||||||
Office leases
|
$
|
3,126
|
|
|
$
|
3,510
|
|
|
$
|
3,440
|
|
|
$
|
3,718
|
|
|
$
|
3,993
|
|
|
$
|
8,061
|
|
|
$
|
25,848
|
|
Land lease and purchase options
|
1,588
|
|
|
634
|
|
|
23
|
|
|
23
|
|
|
23
|
|
|
436
|
|
|
2,727
|
|
|||||||
Other
|
499
|
|
|
499
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,000
|
|
|||||||
|
$
|
5,213
|
|
|
$
|
4,643
|
|
|
$
|
3,465
|
|
|
$
|
3,741
|
|
|
$
|
4,016
|
|
|
$
|
8,497
|
|
|
$
|
29,575
|
|
|
Shares
|
|
Weighted-Average Grant
Date Fair Value |
|||
Unvested at January 1, 2018
|
20,488
|
|
|
$
|
6.95
|
|
Granted
(1)
|
4,311
|
|
|
11.02
|
|
|
Vested
|
(213
|
)
|
|
11.60
|
|
|
Forfeited
|
(202
|
)
|
|
11.73
|
|
|
Unvested at December 31, 2018
|
24,384
|
|
|
$
|
7.59
|
|
|
Stock Options
|
|
Weighted Average
Exercise Price
|
|||
Outstanding at January 1, 2018
|
2,011
|
|
|
$
|
10.32
|
|
Granted
|
—
|
|
|
—
|
|
|
Exercised
|
—
|
|
|
—
|
|
|
Forfeited or Expired
|
(23
|
)
|
|
10.32
|
|
|
Outstanding at December 31, 2018
|
1,988
|
|
|
$
|
10.32
|
|
Exercisable at December 31, 2018
|
665
|
|
|
$
|
10.32
|
|
|
December 31, 2017
|
|
Expected term (in years)
|
6.0
|
|
Expected volatility
|
22.13
|
%
|
Expected dividend yields
|
—
|
%
|
Risk-free rate
|
2.05
|
%
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Current:
|
|
|
|
|
|
||||||
Federal
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
State
|
—
|
|
|
—
|
|
|
(4
|
)
|
|||
Foreign
|
190
|
|
|
(185
|
)
|
|
—
|
|
|||
Total Current
|
190
|
|
|
(185
|
)
|
|
(4
|
)
|
|||
Deferred:
|
|
|
|
|
|
||||||
Federal
|
—
|
|
|
—
|
|
|
170
|
|
|||
State
|
—
|
|
|
—
|
|
|
—
|
|
|||
Foreign
|
—
|
|
|
—
|
|
|
—
|
|
|||
Total Deferred
|
—
|
|
|
—
|
|
|
170
|
|
|||
Total income tax benefit (provision)
|
$
|
190
|
|
|
$
|
(185
|
)
|
|
$
|
166
|
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Domestic
|
$
|
(115,137
|
)
|
|
$
|
(223,991
|
)
|
|
$
|
(95,739
|
)
|
Foreign
|
(10,798
|
)
|
|
(7,283
|
)
|
|
(1,082
|
)
|
|||
Total loss before income taxes
|
$
|
(125,935
|
)
|
|
$
|
(231,274
|
)
|
|
$
|
(96,821
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Income tax benefit (provision) at U.S. statutory rate
|
$
|
26,446
|
|
|
$
|
80,946
|
|
|
$
|
33,887
|
|
Share-based compensation
|
—
|
|
|
—
|
|
|
(5,911
|
)
|
|||
Impairment
|
—
|
|
|
(27,969
|
)
|
|
—
|
|
|||
Change in U.S. tax rate
|
—
|
|
|
(30,562
|
)
|
|
—
|
|
|||
Change in valuation allowance due to change in U.S. tax rate
|
—
|
|
|
30,562
|
|
|
—
|
|
|||
U.S. state tax
|
7,955
|
|
|
—
|
|
|
—
|
|
|||
Change in valuation allowance
|
(32,086
|
)
|
|
(51,030
|
)
|
|
(26,398
|
)
|
|||
Other
|
(2,125
|
)
|
|
(2,132
|
)
|
|
(1,412
|
)
|
|||
Total income tax benefit (provision)
|
$
|
190
|
|
|
$
|
(185
|
)
|
|
$
|
166
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Deferred tax assets:
|
|
|
|
||||
Capitalized engineering costs
|
$
|
6,353
|
|
|
$
|
2,812
|
|
Capitalized start-up costs
|
19,290
|
|
|
17,881
|
|
||
Compensation and benefits
|
3,862
|
|
|
5,465
|
|
||
Net operating loss carryforwards and credits:
|
|
|
|
||||
Federal
|
37,822
|
|
|
19,423
|
|
||
State
|
4,979
|
|
|
522
|
|
||
Foreign
|
2,392
|
|
|
1,694
|
|
||
Other, net
|
8,328
|
|
|
3,541
|
|
||
Deferred tax assets
|
83,026
|
|
|
51,338
|
|
||
Less valuation allowance
|
(83,026
|
)
|
|
(50,942
|
)
|
||
Deferred tax assets, net of valuation allowance
|
—
|
|
|
396
|
|
||
|
|
|
|
||||
Deferred tax liabilities
|
—
|
|
|
(396
|
)
|
||
Net deferred tax assets
|
$
|
—
|
|
|
$
|
—
|
|
Years Ending December 31,
|
Principal Payments
|
|||||
2019
|
$
|
—
|
|
|||
2020
|
—
|
|
||||
2021
|
60,000
|
|
||||
Total
|
$
|
60,000
|
|
|
February 10, 2017
|
|
December 31, 2016
|
||||
Fair value at the beginning of period and initial fair value, respectively
|
$
|
8,753
|
|
|
$
|
5,445
|
|
(Gain) loss on exchange feature
|
(2,209
|
)
|
|
3,308
|
|
||
Fair value at the end of the period and year, respectively
|
$
|
6,544
|
|
|
$
|
8,753
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Net loss
|
|
$
|
(125,745
|
)
|
|
$
|
(231,459
|
)
|
|
$
|
(96,655
|
)
|
Basic weighted average common shares outstanding
|
|
211,574
|
|
|
188,536
|
|
|
95,795
|
|
|||
Loss per share:
|
|
|
|
|
|
|
||||||
Basic and diluted
|
|
$
|
(0.59
|
)
|
|
$
|
(1.23
|
)
|
|
$
|
(1.01
|
)
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
|
|
|
|
|
|
For the period from January 1, 2016 through April 9, 2016
|
||||||||||
|
|
Year Ended December 31,
|
|
|
|||||||||||||
|
|
2018
|
|
2017
|
|
2016
|
|
|
|||||||||
Accounts receivable
|
|
$
|
(958
|
)
|
|
$
|
(442
|
)
|
|
$
|
(39
|
)
|
|
|
$
|
1
|
|
Accounts receivable due from related parties
|
|
62
|
|
|
(60
|
)
|
|
(124
|
)
|
|
|
(32
|
)
|
||||
Prepaids and other current assets
|
|
(431
|
)
|
|
(1,419
|
)
|
|
(1,936
|
)
|
|
|
13
|
|
||||
Note receivable due from related party
|
|
—
|
|
|
251
|
|
|
—
|
|
|
|
—
|
|
||||
Accounts payable and accrued expenses
|
|
23,251
|
|
|
11,338
|
|
|
22,393
|
|
|
|
281
|
|
||||
Accounts payable due to related parties
|
|
—
|
|
|
—
|
|
|
(53
|
)
|
|
|
253
|
|
||||
Other, net
|
|
(11,404
|
)
|
|
(2,235
|
)
|
|
(1,903
|
)
|
|
|
—
|
|
||||
Net changes in working capital
|
|
$
|
10,520
|
|
|
$
|
7,433
|
|
|
$
|
18,338
|
|
|
|
$
|
516
|
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
|
|
|
|
|
|
For the period from January 1, 2016 through April 9, 2016
|
||||||||||
|
|
Year Ended December 31,
|
|
|
|||||||||||||
|
|
2018
|
|
2017
|
|
2016
|
|
|
|||||||||
Net cash paid for income taxes
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4
|
|
|
|
$
|
—
|
|
Property, plant and equipment non-cash accruals
|
|
8,630
|
|
|
83
|
|
|
46
|
|
|
|
75
|
|
||||
Non-cash settlement of withholding taxes associated with the 2017 bonus accrual and vesting of certain awards
|
|
5,733
|
|
|
828
|
|
|
—
|
|
|
|
—
|
|
||||
Non-cash settlement of the 2017 bonus accrual
|
|
15,202
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Asset retirement obligation additions and revisions
|
|
115
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Equity offering cost accrual
|
|
—
|
|
|
65
|
|
|
128
|
|
|
|
—
|
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
|
|
|
|
|
|
For the period from January 1, 2016 through April 9, 2016
|
||||||||||
|
|
Year Ended December 31,
|
|
|
|||||||||||||
|
|
2018
|
|
2017
|
|
2016
|
|
|
|||||||||
Cash and cash equivalents
|
|
$
|
133,714
|
|
|
$
|
128,273
|
|
|
$
|
21,398
|
|
|
|
$
|
210
|
|
Non-current restricted cash
|
|
49,875
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Total cash, cash equivalents and restricted cash in the statement of cash flows
|
|
$
|
183,589
|
|
|
$
|
128,273
|
|
|
$
|
21,398
|
|
|
|
$
|
210
|
|
|
First Quarter
|
|
Second Quarter
|
|
Third Quarter
|
|
Fourth Quarter
|
||||||||
Year Ended December 31, 2018
|
|
|
|
|
|
|
|
||||||||
Total revenue
|
$
|
6,801
|
|
|
$
|
813
|
|
|
$
|
799
|
|
|
$
|
1,872
|
|
Loss from operations
|
(25,392
|
)
|
|
(36,658
|
)
|
|
(34,384
|
)
|
|
(31,287
|
)
|
||||
Net loss
|
(25,184
|
)
|
|
(35,854
|
)
|
|
(33,191
|
)
|
|
(31,516
|
)
|
||||
Net loss per common share - basic and diluted
|
(0.12
|
)
|
|
(0.17
|
)
|
|
(0.15
|
)
|
|
(0.14
|
)
|
||||
Weighted average shares outstanding - basic and diluted
|
204,772
|
|
|
206,531
|
|
|
217,380
|
|
|
217,408
|
|
||||
|
|
|
|
|
|
|
|
||||||||
Year Ended December 31, 2017
|
|
|
|
|
|
|
|
||||||||
Total revenue
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5,441
|
|
Loss from operations
|
(143,721
|
)
|
|
(32,899
|
)
|
|
(26,095
|
)
|
|
(35,852
|
)
|
||||
Net loss
|
(141,349
|
)
|
|
(32,523
|
)
|
|
(22,864
|
)
|
|
(34,723
|
)
|
||||
Net loss per common share - basic and diluted
|
(0.92
|
)
|
|
(0.17
|
)
|
|
(0.12
|
)
|
|
(0.18
|
)
|
||||
Weighted average shares outstanding - basic and diluted
|
154,213
|
|
|
186,102
|
|
|
192,405
|
|
|
194,978
|
|
Standard
|
|
Description
|
|
Date of Adoption
|
|
Effect on our Consolidated Financial Statements or Other Significant Matters
|
ASU 2016-02,
Leases (Topic 842)
|
|
This standard requires a lessee to recognize leases on its balance sheet by recording a liability representing the obligation to make future lease payments and a right-of-use asset representing the right to use the underlying asset for the lease term. A lessee is permitted to make an election not to recognize lease assets and liabilities for leases with a term of 12 months or less. The standard also modifies the definition of a lease and requires expanded disclosures. This standard may be early adopted and must be adopted using a modified retrospective approach with certain available practical expedients, one of which is an option of applying the requirements of the standard either (1) retrospectively to each prior comparative reporting period presented or (2) retrospectively at the beginning of the period of adoption.
|
|
January 1, 2019
|
|
The Company has adopted the standard on January 1, 2019, and will apply it at the beginning of the period of adoption. Therefore, upon adoption, financial information and disclosures will not be updated for comparative reporting periods under the new standard. Additionally, the Company has elected the transition package of practical expedients upon adoption which, among other things, allows an entity to not reassess the historical lease classification. The Company utilized a combination of a bottom-up and top-down approach to identify and analyze its lease portfolio. The analysis included reviewing all forms of leases, performing a completeness assessment over the lease population, assessing the policy elections offered by the standard and evaluating its business processes and internal controls to meet the ASU's accounting, reporting and disclosure requirements. The Company’s adoption of the standard has an impact on the Consolidated Balance Sheet. The Company’s adoption of the standard does not impact the Consolidated Statements of Operations or the Consolidated Statements of Cash Flows. The most significant effect of the new standard on the Consolidated Balance Sheet relates to the recognition of right-of-use assets and lease liabilities for the Company’s real estate portfolio, which the Company expects to be between $15 million and $25 million. The Company will also be providing new disclosures for its leasing activities under the new standard in the first quarter of 2019.
|
|
|
December 31, 2018
|
|
December 31, 2017
|
||||
Proved properties
|
|
$
|
101,459
|
|
|
$
|
90,869
|
|
Unproved properties
|
|
10,204
|
|
|
13,000
|
|
||
Gross capitalized costs
|
|
111,663
|
|
|
103,869
|
|
||
Accumulated DD&A
|
|
(1,335
|
)
|
|
(149
|
)
|
||
Net capitalized costs
|
|
$
|
110,328
|
|
|
$
|
103,720
|
|
|
|
December 31, 2018
|
|
December 31, 2017
|
||||
Property acquisitions:
|
|
|
|
|
||||
Proved
|
|
$
|
13,261
|
|
|
$
|
90,869
|
|
Unproved
|
|
204
|
|
|
13,000
|
|
||
Exploration costs
|
|
—
|
|
|
—
|
|
||
Development
|
|
2,104
|
|
|
949
|
|
||
Costs incurred
|
|
$
|
15,569
|
|
|
$
|
104,818
|
|
|
|
December 31, 2018
|
|
December 31, 2017
|
||||
Natural gas sales
|
|
$
|
4,423
|
|
|
$
|
503
|
|
|
|
|
|
|
||||
Operating costs
|
|
11,251
|
|
|
1,668
|
|
||
Depreciation, depletion and amortization
|
|
1,228
|
|
|
115
|
|
||
Impairment charge
|
|
2,699
|
|
|
—
|
|
||
Total operating costs and expenses
|
|
15,178
|
|
|
1,783
|
|
||
Results of operations
|
|
$
|
(10,755
|
)
|
|
$
|
(1,280
|
)
|
|
|
Gas
(MMcf) |
|
Condensate
(Mbbl) |
|
Gas Equivalent
(MMcfe) |
|||
Proved reserves:
|
|
|
|
|
|
|
|||
December 31, 2016
|
|
—
|
|
|
—
|
|
|
—
|
|
Extensions, discoveries and other additions
|
|
—
|
|
|
—
|
|
|
—
|
|
Revisions of previous estimates
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
|
(190
|
)
|
|
—
|
|
|
(191
|
)
|
Sale of reserves-in-place
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of reserves-in-place
|
|
327,308
|
|
|
10
|
|
|
327,371
|
|
December 31, 2017
|
|
327,118
|
|
|
10
|
|
|
327,180
|
|
Extensions, discoveries and other additions
|
|
22,481
|
|
|
—
|
|
|
22,481
|
|
Revisions of previous estimates
|
|
(84,061
|
)
|
|
(2
|
)
|
|
(84,072
|
)
|
Production
|
|
(1,399
|
)
|
|
(1
|
)
|
|
(1,405
|
)
|
Sale of reserves-in-place
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of reserves-in-place
|
|
715
|
|
|
—
|
|
|
715
|
|
December 31, 2018
|
|
264,854
|
|
|
7
|
|
|
264,899
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|||
December 31, 2016
|
|
—
|
|
|
—
|
|
|
—
|
|
December 31, 2017
|
|
5,720
|
|
|
10
|
|
|
5,782
|
|
December 31, 2018
|
|
17,522
|
|
|
7
|
|
|
17,567
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|||
December 31, 2016
|
|
—
|
|
|
—
|
|
|
—
|
|
December 31, 2017
|
|
321,398
|
|
|
—
|
|
|
321,398
|
|
December 31, 2018
|
|
247,332
|
|
|
—
|
|
|
247,332
|
|
•
|
Acquired
327
Bcfe of reserves in a series of transactions.
|
•
|
Added approximately
22
Bcfe of proved reserves, comprised primarily of
19
Bcfe from additional proved undeveloped locations as a result of a more detailed analysis from an updated development plan and
3
Bcfe from drilling activities.
|
•
|
Had negative revisions of approximately
85
Bcfe, comprised primarily of
59
Bcfe as a result of newly acquired 3D seismic data indicating additional geological faulting risks, which led to a reduction in proved undeveloped locations and some lateral lengths,
14
Bcfe, net, from changes in estimating lateral lengths of proved undeveloped locations as a result of more detailed analysis from an updated development plan, and
12
Bcfe due to loss of leases.
|
•
|
Recorded positive revisions of approximately
1
Bcfe due to an increase in commodity prices.
|
•
|
Acquired approximately
1
Bcfe of proved reserves through minor interest acquisitions.
|
|
|
December 31, 2018
|
|
December 31, 2017
|
||||
Future cash inflows
|
|
$
|
676,454
|
|
|
$
|
777,711
|
|
Future production costs
|
|
(105,341
|
)
|
|
(144,991
|
)
|
||
Future development costs
|
|
(264,239
|
)
|
|
(331,297
|
)
|
||
Future income tax provisions
|
|
(54,564
|
)
|
|
(52,212
|
)
|
||
Future net cash flows
|
|
252,310
|
|
|
249,211
|
|
||
Less effect of a 10% discount factor
|
|
(106,499
|
)
|
|
(161,009
|
)
|
||
Standardized measure of discounted future net cash flows
|
|
$
|
145,811
|
|
|
$
|
88,202
|
|
December 31, 2016
|
|
$
|
—
|
|
Sales and transfers of gas and condensate produced, net of production costs
|
|
(265
|
)
|
|
Net changes in prices and production costs
|
|
—
|
|
|
Extensions, discoveries, additions and improved recovery, net of related costs
|
|
—
|
|
|
Development costs incurred
|
|
—
|
|
|
Revisions of estimated development costs
|
|
—
|
|
|
Revisions of previous quantity estimates
|
|
—
|
|
|
Accretion of discount
|
|
—
|
|
|
Net change in income taxes
|
|
(22,921
|
)
|
|
Purchases of reserves in place
|
|
111,388
|
|
|
Sales of reserves in place
|
|
—
|
|
|
Changes in timing and other
|
|
—
|
|
|
December 31, 2017
|
|
$
|
88,202
|
|
Sales and transfers of gas and condensate produced, net of production costs
|
|
(1,773
|
)
|
|
Net changes in prices and production costs
|
|
27,530
|
|
|
Extensions, discoveries, additions and improved recovery, net of related costs
|
|
13,334
|
|
|
Development costs incurred
|
|
545
|
|
|
Revisions of estimated development costs
|
|
9,663
|
|
|
Revisions of previous quantity estimates
|
|
12,991
|
|
|
Accretion of discount
|
|
11,112
|
|
|
Net change in income taxes
|
|
(9,472
|
)
|
|
Purchases of reserves in place
|
|
844
|
|
|
Sales of reserves in place
|
|
—
|
|
|
Changes in timing and other
|
|
(7,165
|
)
|
|
December 31, 2018
|
|
$
|
145,811
|
|
SCHEDULE I
|
||||||||
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
|
||||||||
TELLURIAN INC.
|
||||||||
PARENT COMPANY BALANCE SHEETS
|
||||||||
(in thousands, except share and per share)
|
||||||||
|
|
|
||||||
|
|
December 31,
|
||||||
|
|
2018
|
|
2017
|
||||
ASSETS
|
|
|
||||||
Cash and cash equivalents
|
|
$
|
—
|
|
|
$
|
—
|
|
Prepaids and other
|
|
72
|
|
|
25
|
|
||
Investments in subsidiaries
|
|
289,802
|
|
|
212,846
|
|
||
Property, plant and equipment, net
|
|
10,000
|
|
|
13,000
|
|
||
Total assets
|
|
$
|
299,874
|
|
|
$
|
225,871
|
|
|
|
|
|
|
||||
LIABILITIES AND EQUITY
|
|
|
|
|
||||
Liabilities:
|
|
|
|
|
||||
Accounts payable
|
|
$
|
114
|
|
|
$
|
148
|
|
Accrued liabilities
|
|
1,826
|
|
|
1,836
|
|
||
Total liabilities
|
|
1,940
|
|
|
1,984
|
|
||
|
|
|
|
|
||||
Equity:
|
|
|
|
|
||||
Preferred stock, $0.01 par value, 100,000,000 authorized: 6,123,782 and zero shares outstanding, respectively
|
|
61
|
|
|
—
|
|
||
Common stock, $0.01 par value, 400,000,000 authorized: 240,655,607 and 222,749,220 shares outstanding, respectively
|
|
2,195
|
|
|
2,043
|
|
||
Additional paid-in capital
|
|
749,537
|
|
|
549,958
|
|
||
Accumulated deficit
|
|
(453,859
|
)
|
|
(328,114
|
)
|
||
Total stockholders’ equity
|
|
297,934
|
|
|
223,887
|
|
||
Total liabilities and stockholders’ equity
|
|
$
|
299,874
|
|
|
$
|
225,871
|
|
SCHEDULE I (Continued)
|
||||||||||||
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
|
||||||||||||
TELLURIAN INC.
|
||||||||||||
PARENT COMPANY STATEMENTS OF OPERATIONS
|
||||||||||||
(in thousands)
|
||||||||||||
|
|
|
||||||||||
|
|
Year Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Total revenues
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
||||||
Operating costs and expenses:
|
|
|
|
|
|
|
||||||
Cost of sales
|
|
93
|
|
|
15
|
|
|
—
|
|
|||
Development expenses
|
|
2,487
|
|
|
320
|
|
|
21
|
|
|||
General and administrative expenses
|
|
4,618
|
|
|
594
|
|
|
25,084
|
|
|||
Goodwill impairment
|
|
—
|
|
|
77,592
|
|
|
—
|
|
|||
Total operating costs and expenses
|
|
7,198
|
|
|
78,521
|
|
|
25,105
|
|
|||
|
|
|
|
|
|
|
||||||
Loss on preferred stock exchange feature
|
|
—
|
|
|
—
|
|
|
3,308
|
|
|||
Interest expense
|
|
2
|
|
|
—
|
|
|
—
|
|
|||
|
|
|
|
|
|
|
||||||
Loss from operations before income taxes and equity in losses of subsidiaries
|
|
(7,200
|
)
|
|
(78,521
|
)
|
|
(28,413
|
)
|
|||
Income tax benefit (provision)
|
|
—
|
|
|
(4
|
)
|
|
170
|
|
|||
Net loss from operations before equity in losses of subsidiaries
|
|
$
|
(7,200
|
)
|
|
$
|
(78,525
|
)
|
|
$
|
(28,243
|
)
|
Equity in losses of subsidiaries, net of tax
|
|
$
|
(118,545
|
)
|
|
$
|
(152,934
|
)
|
|
$
|
(68,412
|
)
|
Net loss
|
|
$
|
(125,745
|
)
|
|
$
|
(231,459
|
)
|
|
$
|
(96,655
|
)
|
SCHEDULE I (Continued)
|
||||||||||||
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
|
||||||||||||
TELLURIAN INC.
|
||||||||||||
PARENT COMPANY STATEMENTS OF CASH FLOWS
|
||||||||||||
(in thousands)
|
||||||||||||
|
|
|
|
|
||||||||
|
|
Year Ended December 31,
|
||||||||||
|
|
2018
|
|
2017
|
|
2016
|
||||||
Net cash used in operating activities
|
|
(123,976
|
)
|
|
(312,553
|
)
|
|
(60,532
|
)
|
|||
|
|
|
|
|
|
|
||||||
Cash flows from investing activities:
|
|
|
|
|
|
|
||||||
Cash received in acquisition
|
|
—
|
|
|
56
|
|
|
210
|
|
|||
Cash used for acquisition
|
|
—
|
|
|
—
|
|
|
(1,190
|
)
|
|||
Net cash received (used) in investing activities
|
|
—
|
|
|
56
|
|
|
(980
|
)
|
|||
|
|
|
|
|
|
|
||||||
Cash flows from financing activities:
|
|
|
|
|
|
|
||||||
Proceeds from the issuance of common stock
|
|
133,800
|
|
|
318,204
|
|
|
59,015
|
|
|||
Tax payments for net share settlement of equity awards
|
|
(5,734
|
)
|
|
—
|
|
|
—
|
|
|||
Proceeds from the issuance of preferred stock
|
|
—
|
|
|
—
|
|
|
25,000
|
|
|||
Equity offering costs
|
|
(4,090
|
)
|
|
(5,707
|
)
|
|
(1,681
|
)
|
|||
Net cash provided by financing activities
|
|
123,976
|
|
|
312,497
|
|
|
82,334
|
|
|||
|
|
|
|
|
|
|
||||||
Net increase (decrease) in cash and cash equivalents
|
|
—
|
|
|
—
|
|
|
20,822
|
|
|||
Cash and cash equivalents, beginning of period
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Cash and cash equivalents, end of period
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
20,822
|
|
|
|
|
|
|
(a) The following financial statements, financial statement schedules and exhibits are filed as part of this report:
|
1.
|
Financial Statements.
Tellurian’s consolidated financial statements are included in Item 8 of Part II of this report. Reference is made to the accompanying Index to Financial Statements.
|
2.
|
Financial Statement Schedules.
Our financial statement schedules filed herewith are set forth in Part II, Item 8 of this report as follows: (1) Tellurian Inc. — Schedule I — Condensed Financial Information of Registrant. All valuation and qualifying accounts schedule were omitted since the subject matter thereof is either not present or is not present in amounts sufficient to require submission of the schedule.
|
3.
|
Exhibits.
The exhibits listed below are filed, furnished or incorporated by reference pursuant to the requirements of Item 601 of Regulation S-K.
|
Exhibit No.
|
|
Description
|
10.5.1
|
|
|
10.6
|
|
|
10.6.1
|
|
|
10.7
|
|
|
10.7.1
|
|
|
10.8
|
|
|
10.8.1*
|
|
|
10.9
|
|
|
10.10†
|
|
|
10.11†
|
|
|
10.12†
|
|
|
10.13†
|
|
|
10.14†
|
|
|
10.15†
|
|
|
10.16†
|
|
|
10.17†
|
|
|
10.17.1†
|
|
|
10.17.2†
|
|
Exhibit No.
|
|
Description
|
10.17.3†
|
|
|
10.17.4†
|
|
|
10.17.5†
|
|
|
10.17.6†
|
|
|
10.17.7†*
|
|
|
10.17.8†
|
|
|
10.18†
|
|
|
10.18.1†
|
|
|
10.18.2†
|
|
|
10.18.3†
|
|
|
10.19†
|
|
|
10.20†*
|
|
|
14.1
|
|
|
21.1*
|
|
|
23.1*
|
|
|
23.2*
|
|
|
31.1*
|
|
|
31.2*
|
|
|
32.1**
|
|
|
32.2**
|
|
|
99.1
|
|
|
99.2*
|
|
|
101.INS*
|
|
XBRL Instance Document
|
101.SCH*
|
|
XBRL Taxonomy Extension Schema Document
|
101.CAL*
|
|
XBRL Taxonomy Extension Calculation Linkbase Document
|
101.DEF*
|
|
XBRL Taxonomy Extension Definition Linkbase Document
|
101.LAB*
|
|
XBRL Taxonomy Extension Labels Linkbase Document
|
101.PRE*
|
|
XBRL Taxonomy Extension Presentation Linkbase Document
|
|
*
|
Filed herewith.
|
**
|
Furnished herewith.
|
†
|
Management contract or compensatory plan or arrangement.
|
††
|
Pursuant to Item 601(b)(2) of Regulation S-K, certain schedules and similar attachments have been omitted. The registrant hereby agrees to furnish supplementally a copy of any omitted schedule or attachment to the Securities and Exchange Commission upon request.
|
|
|
TELLURIAN INC.
|
|
|
|
|
|
Date:
|
February 27, 2019
|
By:
|
/s/ Antoine J. Lafargue
|
|
|
|
Antoine J. Lafargue
|
|
|
|
Senior Vice President and Chief Financial Officer
|
|
|
|
(as Principal Financial Officer)
|
|
|
|
Tellurian Inc.
|
|
|
|
|
Date:
|
February 27, 2019
|
By:
|
/s/ Khaled A. Sharafeldin
|
|
|
|
Khaled A. Sharafeldin
|
|
|
|
Chief Accounting Officer
|
|
|
|
(as Principal Accounting Officer)
|
|
|
|
Tellurian Inc.
|
/s/ Meg A. Gentle
|
Date:
|
February 27, 2019
|
Meg A. Gentle, Director, President and Chief Executive Officer, Tellurian Inc. (as Principal Executive Officer)
|
|
|
|
|
|
/s/ Antoine J. Lafargue
|
Date:
|
February 27, 2019
|
Antoine J. Lafargue, Senior Vice President and Chief Financial Officer, Tellurian Inc. (as Principal Financial Officer)
|
|
|
|
|
|
/s/ Khaled A. Sharafeldin
|
Date:
|
February 27, 2019
|
Khaled A. Sharafeldin, Chief Accounting Officer, Tellurian Inc. (as Principal Accounting Officer)
|
|
|
|
|
|
/s/ Charif Souki
|
Date:
|
February 27, 2019
|
Charif Souki, Director and Chairman, Tellurian Inc.
|
|
|
|
|
|
/s/ Martin J. Houston
|
Date:
|
February 27, 2019
|
Martin J. Houston, Director and Vice Chairman, Tellurian Inc.
|
|
|
|
|
|
/s/ Diana Derycz-Kessler
|
Date:
|
February 27, 2019
|
Diana Derycz-Kessler, Director, Tellurian Inc.
|
|
|
|
|
|
/s/ Dillon J. Ferguson
|
Date:
|
February 27, 2019
|
Dillon J. Ferguson, Director, Tellurian Inc.
|
|
|
|
|
|
/s/ Eric P. Festa
|
Date:
|
February 27, 2019
|
Eric P. Festa, Director, Tellurian Inc.
|
|
|
|
|
|
/s/ Brooke A. Peterson
|
Date:
|
February 27, 2019
|
Brooke A. Peterson, Director, Tellurian Inc.
|
|
|
|
|
|
/s/ Don A. Turkleson
|
Date:
|
February 27, 2019
|
Don A. Turkleson, Director, Tellurian Inc.
|
|
|
Vesting Date
|
Number of Shares
|
September 6, 2018
|
_____________
|
December 6, 2018
|
_____________
|
March 6, 2019
|
_____________
|
June 6, 2019
|
_____________
|
•
|
25% of the Cash Award allocated to such Phase shall vest and become payable on the first anniversary of the NTP Date applicable to such Phase;
|
•
|
25% of the Cash Award allocated to such Phase shall vest and become payable on the second anniversary of the applicable NTP Date;
|
•
|
25% of the Cash Award allocated to such Phase shall vest and become payable on the third anniversary of the applicable NTP Date; and
|
•
|
25% of the Cash Award allocated to such Phase shall vest and become payable on the fourth anniversary of the applicable NTP Date (the “Vesting Schedule”).
|
Subsidiary
|
State or Other Jurisdiction of Incorporation or Organization
|
Ownership
|
Tellurian Inc. owns the following subsidiaries directly:
|
|
|
Tellurian Investments LLC (formerly known as Tellurian Investments Inc.)
|
Delaware
|
100.0%
|
Magellan Petroleum (UK) Investment Holdings Limited
|
United Kingdom
|
100.0%
|
Magellan Petroleum Australia Pty Ltd
|
Queensland, Australia
|
70.0% (1)
|
Tellurian Investments LLC owns the following subsidiaries directly:
|
|
|
Driftwood Holdings LLC
|
Delaware
|
100.0%
|
Tellurian LandCo LLC (formerly known as Parallax LNG LandCo LLC and MBTU LandCo LLC)
|
Delaware
|
100.0%
|
Tellurian LNG LLC (formerly known as Parallax LNG LLC)
|
Delaware
|
100.0%
|
Tellurian Midstream Holdings LLC
|
Delaware
|
100.0%
|
Tellurian Production Holdings LLC
|
Delaware
|
100.0%
|
Tellurian Services LLC (formerly known as Parallax Services LLC)
|
Delaware
|
100.0%
|
Tellurian Supply & Trade LLC
|
Delaware
|
100.0%
|
Tellurian International Holdings Ltd
|
United Kingdom
|
100.0%
|
Tellurian LNG UK Ltd
|
United Kingdom
|
100.0%
|
Tellurian LNG Singapore Pte. Ltd.
|
Singapore
|
100.0%
|
Tellurian International Holdings Ltd owns the following subsidiary directly:
|
|
|
Tellurian Trading UK Ltd
|
United Kingdom
|
100%
|
Driftwood Holdings LLC owns the following subsidiary directly:
|
|
|
Tellurian Management Services LLC (formerly known as Tellurian O&M LLC and Driftwood Operating LLC)
|
Delaware
|
100.0%
|
Tellurian LNG LLC owns the following subsidiaries directly:
|
|
|
Driftwood LNG LLC
|
Delaware
|
100.0%
|
Driftwood LNG Tug Services LLC
|
Delaware
|
100.0%
|
Driftwood Pipeline LLC (formerly known as Driftwood LNG Pipeline LLC)
|
Delaware
|
100.0%
|
Tellurian Midstream Holdings LLC owns the following subsidiary directly:
|
|
|
Tellurian Pipeline LLC
|
Delaware
|
100.0%
|
Tellurian Pipeline LLC owns the following subsidiaries directly:
|
|
|
Haynesville Global Access Pipeline LLC
|
Delaware
|
100.0%
|
Permian Global Access Pipeline LLC
|
Delaware
|
100.0%
|
Tellurian Production Holdings LLC owns the following subsidiaries directly:
|
|
|
Tellurian Operating LLC
|
Delaware
|
100.0%
|
Tellurian Production LLC
|
Delaware
|
100.0%
|
Magellan Petroleum (UK) Investment Holdings Limited owns the following subsidiary directly:
|
|
|
Magellan Petroleum (UK) Limited
|
United Kingdom
|
100.0%
|
Magellan Petroleum Australia Pty Ltd owns the following subsidiaries directly:
|
|
|
Magellan Petroleum (Offshore) Pty Ltd
|
Queensland, Australia
|
100.0%
|
(1)
|
|
Tellurian Inc. directly owns 70% of Magellan Petroleum Pty Ltd (“MPA”), and the remaining 30% of MPA is directly owned by Magellan Petroleum (UK) Limited, a wholly owned subsidiary of Magellan Petroleum (UK) Investment Holdings Limited.
|
/s/ DELOITTE & TOUCHE LLP
|
|
Houston, Texas
|
February 27, 2019
|
NETHERLAND, SEWELL & ASSOCIATES, INC.
|
|
|
|
By:
|
/s/ Danny D. Simmons
|
|
Danny D. Simmons, P.E.
|
|
President and Chief Operating Officer
|
1.
|
I have reviewed this annual report on Form 10-K of Tellurian Inc.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a.
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b.
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
|
c.
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d.
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
a.
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
b.
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
/s/ Meg A. Gentle
|
Meg A. Gentle
|
Chief Executive Officer
|
(as Principal Executive Officer)
|
Tellurian Inc.
|
1.
|
I have reviewed this annual report on Form 10-K of Tellurian Inc.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a.
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b.
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
|
c.
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d.
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
a.
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
b.
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
/s/ Antoine J. Lafargue
|
Antoine J. Lafargue
|
Senior Vice President and Chief Financial Officer
|
(as Principal Financial Officer)
|
Tellurian Inc.
|
1.
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
2.
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
/s/ Meg A. Gentle
|
Meg A. Gentle
|
Chief Executive Officer
|
(as Principal Executive Officer)
|
Tellurian Inc.
|
1.
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
2.
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
/s/ Antoine J. Lafargue
|
Antoine J. Lafargue
|
Senior Vice President and Chief Financial Officer
|
(as Principal Financial Officer)
|
Tellurian Inc.
|
|
|
Net Reserves
|
|
Future Net Revenue (M$)
|
||||||
|
|
Gas
|
|
Oil
|
|
Gas Equivalent
|
|
|
|
Present
Worth |
Category
|
|
(MMCF)
|
|
(MBBL)
|
|
(MMCFE)
|
|
Total
|
|
at 10%
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Producing
|
|
17,007.3
|
|
7.5
|
|
17,052.1
|
|
26,146.8
|
|
23,084.1
|
Proved Developed Non-Producing
|
|
514.8
|
|
0.0
|
|
514.8
|
|
1,096.3
|
|
894.5
|
Proved Undeveloped
|
|
247,332.0
|
|
0.0
|
|
247,332.0
|
|
279,631.7
|
|
154,225.5
|
|
|
|
|
|
|
|
|
|
|
|
Total Proved
|
|
264,854.1
|
|
7.5
|
|
264,898.9
|
|
306,874.8
|
|
178,204.1
|
Sincerely,
|
|
NETHERLAND, SEWELL & ASSOCIATES, INC.
|
|
Texas Registered Engineering Firm F-2699
|
|
/s/ C.H. (Scott) Rees III
|
By:
|
|
|
C.H. (Scott) Rees III, P.E.
|
|
Chairman and Chief Executive Officer
|
|
/s/ Richard B. Talley, Jr.
|
|
|
/s/ Zachary R. Long
|
By:
|
|
|
By:
|
|
|
Richard B. Talley, Jr., P.E. 102425
|
|
|
Zachary R. Long, P.G. 11792
|
|
Senior Vice President
|
|
|
Vice President
|
|
|
|
|
|
Date Signed:
|
January 30, 2019
|
|
Date Signed:
|
January 30, 2019
|
Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.
|
(i)
|
Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
|
(ii)
|
Same environment of deposition;
|
(iii)
|
Similar geological structure; and
|
(iv)
|
Same drive mechanism.
|
(i)
|
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
|
(ii)
|
Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
|
Supplemental definitions from the 2018 Petroleum Resources Management System:
Developed Producing Reserves - Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing Reserves - Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
|
(i)
|
Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
|
(ii)
|
Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
|
(iii)
|
Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
|
(iv)
|
Provide improved recovery systems.
|
(i)
|
Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.
|
(ii)
|
Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
|
(iii)
|
Dry hole contributions and bottom hole contributions.
|
(iv)
|
Costs of drilling and equipping exploratory wells.
|
(v)
|
Costs of drilling exploratory-type stratigraphic test wells.
|
(i)
|
Oil and gas producing activities include:
|
(A)
|
The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;
|
(B)
|
The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
|
(C)
|
The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
|
(1)
|
Lifting the oil and gas to the surface; and
|
(2)
|
Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
|
(D)
|
Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.
|
a.
|
The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
|
b.
|
In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.
|
(ii)
|
Oil and gas producing activities do not include:
|
(A)
|
Transporting, refining, or marketing oil and gas;
|
(B)
|
Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
|
(C)
|
Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
|
(D)
|
Production of geothermal steam.
|
(i)
|
When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
|
(ii)
|
Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
|
(iii)
|
Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
|
(iv)
|
The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
|
(v)
|
Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
|
(vi)
|
Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
|
(i)
|
When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
|
(ii)
|
Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
|
(iii)
|
Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
|
(iv)
|
See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.
|
(i)
|
Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:
|
(A)
|
Costs of labor to operate the wells and related equipment and facilities.
|
(B)
|
Repairs and maintenance.
|
(C)
|
Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
|
(D)
|
Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
|
(E)
|
Severance taxes.
|
(ii)
|
Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used
|
(i)
|
The area of the reservoir considered as proved includes:
|
(A)
|
The area identified by drilling and limited by fluid contacts, if any, and
|
(B)
|
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
|
(ii)
|
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
|
(iii)
|
Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
|
(iv)
|
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
|
(A)
|
Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
|
(B)
|
The project has been approved for development by all necessary parties and entities, including governmental entities.
|
(v)
|
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
|
Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:
|
|
a.
|
Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
|
b.
|
Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).
|
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:
|
|
a.
|
Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.
|
b.
|
Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.
|
c.
|
Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.
|
d.
|
Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.
|
e.
|
Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
|
f.
|
Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.
|
(i)
|
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
|
(ii)
|
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
|
From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):
Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:
|
|
•
|
The company's level of ongoing significant development activities in the area to be developed ( for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);
|
•
|
The company's historical record at completing development of comparable long-term projects;
|
•
|
The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;
|
•
|
The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and
|
•
|
The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).
|
(iii)
|
Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
|