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.
With respect to the information relating to our
working interestownership 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.
ITEM
10. DIRECTORS, EXECUTIVE OFFICERS1 AND
CORPORATE GOVERNANCEThe Company’s certificate of incorporation provides for three classes of directors who are to be elected for terms of three years each and until their successors shall have been elected and shall have been duly qualified. The following sets forth certain information about each of the Company’s eight directors. There are no family relationships among any of Tellurian’s directors or executive officers.
Directors Holdings Office for a Term Expiring at the 2020 Annual Meeting of Stockholders
Name | | Other Positions
Held with the
Company | | Age and Business Experience |
Diana Derycz-Kessler
| | Member of the Audit Committee, Compensation Committee, and Governance and Nominating Committee | | Ms. Derycz-Kessler (age 55) has served as a director of Tellurian since the completion in February 2017 of the merger (the “Merger”) between Tellurian Investments Inc. (now known as Tellurian Investments LLC (“Tellurian Investments”)) and a subsidiary of Magellan Petroleum Corporation (“Magellan”) (now known as Tellurian Inc.), and she served as a director of Tellurian Investments from December 2016 to February 2017. Ms. Derycz-Kessler is an investor with a background in law, business and finance. She has been an active principal of her investment advisory firm Bristol Capital Advisors, LLC since 2000. Her investments have included companies in the energy, biotechnology, technology, education, real estate and consumer products sectors. As part of these investments, she has assumed active operational roles, including a 17-year tenure as Chief Executive Officer of the media arts college of The Los Angeles Film School and manager of commercial property partnerships. In February 2019, Ms. Derycz-Kessler became a founding member and director of PiMac Capital Advisors LLC, a mortgage lending advisory company. Since October 2019, Ms. Derycz-Kessler has been a member of the board of managers of Bristol Luxury Group LLC and Sugarfina Holdings LLC, the parent companies to Sugarfina USA LLC, a luxury candy retailer. Ms. Derycz-Kessler’s early career began as a lawyer in the international oil and gas sector, working at the law firm of Curtis, Mallet-Prevost, Colt & Mosle LLP in New York. Subsequently, she joined Occidental Petroleum Corporation, overseeing legal for its Latin American exploration and production operations. From 2016 to 2018, Ms. Derycz-Kessler was a partner in UNESCO’s TeachHer program, a private–public sector partnership bridging the global gender gap in education. Ms. Derycz-Kessler holds a law degree from Harvard Law School and a master’s degree from Stanford University in Latin American Studies. She obtained her undergraduate “double” degree in History and Latin American Studies from University of California, Los Angeles (UCLA).
Ms. Derycz-Kessler’s qualifications to serve as a director of Tellurian include her knowledge of and experience in the energy industry and her leadership and management experience. |
| | | | |
Dillon J. Ferguson
| | Chairman of the Governance and Nominating Committee | | Mr. Ferguson (age 72) has served as a director of Tellurian since the completion of the Merger in February 2017, and he served as a director of Tellurian Investments from December 2016 to February 2017. Mr. Ferguson is a partner at Pillsbury Winthrop Shaw Pittman LLP in its energy and litigation practices. Mr. Ferguson focuses his practice on oil and gas law, with an emphasis on both transaction and litigation matters. His clients are comprised of companies and individuals who are engaged in oil and gas activities, including exploration, production, processing, transportation, marketing and consumption. Mr. Ferguson has been a partner at Pillsbury Winthrop Shaw Pittman LLP since May 2016. He was a partner at Andrews Kurth LLP from 2001 to May 2016. Mr. Ferguson earned his B.B.A. from The University of Texas at Austin in 1970 and his J.D. from South Texas College of Law in 1973.
Mr. Ferguson’s qualifications to serve as a director of Tellurian include his experience practicing law and counseling energy companies involved in a wide array of transaction and litigation matters. |
4
2. OUR BUSINESS AND PROPERTIESName | | Other Positions
Held with the
Company | | Age and Business Experience |
Meg A. Gentle
| | President and Chief Executive Officer | | Ms. Gentle (age 45) has served as a director and as President and Chief Executive Officer of Tellurian since the completion of the Merger in February 2017 and as President and Chief Executive Officer of Tellurian Investments since August 2016. Previously, at Cheniere Energy, Inc. (“Cheniere”), Ms. Gentle served as Executive Vice President – Marketing (February 2014–August 2016), Senior Vice President – Marketing (June 2013–February 2014), Senior Vice President and Chief Financial Officer (March 2009–June 2013), Senior Vice President – Strategic Planning & Finance (February 2008–March 2009), and other roles in strategic planning (June 2004–February 2008). From 2007 to August 2016, Ms. Gentle was a member of the board of directors of Cheniere Energy Partners GP, LLC, the general partner of Cheniere Energy Partners, L.P. (NYSE American: CQP), an indirect subsidiary of Cheniere. Prior to joining Cheniere, Ms. Gentle spent eight years in energy market development, economic evaluation and long-range planning. She conducted international business development and strategic planning for Anadarko Petroleum Corporation, a publicly traded independent energy company, from January 1998 to May 2004 and energy market analysis for Pace Global Energy Services, an energy management and consulting firm, from August 1996 to December 1998. Ms. Gentle received a B.A. in Economics and International Affairs from James Madison University in May 1996 and an M.B.A. from Rice University in May 2004.
Ms. Gentle’s qualifications to serve as a director of Tellurian include her knowledge of and experience in the LNG industry and her experience and expertise in finance, financial reporting and management. |
Directors Holding Office for a Term Expiring at the 2021 Annual Meeting of Stockholders
Name | | Other Positions
Held with the
Company | | Age and Business Experience |
Martin J. Houston
| | Vice Chairman of the Board | | Mr. Houston (age 62) has served as a director of Tellurian since the completion of the Merger in February 2017, and he served as a director of Tellurian Investments from February 2016 to February 2017. He was also President of Tellurian Investments from February 2016 until August 2016. Immediately prior to Tellurian Investments, Mr. Houston served as Chairman of Parallax Enterprises LLC (“Parallax Enterprises”) starting in December 2014. From February 2014 until December 2014, Mr. Houston was performing preliminary work related to the formation and business of Parallax Enterprises. Having spent more than three decades at BG Group plc, a Financial Times Stock Exchange (FTSE) 10 international integrated oil and gas company, Mr. Houston retired in February 2014 as the BG Group plc’s Chief Operating Officer and an executive director, which positions he held beginning in November 2011 and 2009, respectively. He is a former director of the Society of International Gas Tanker and Terminal Operators (SIGTTO), and from 2008 to 2014 he was the vice president for the Americas of GIIGNL, the International Group of Liquefied Natural Gas Importers. From November 2014 to February 2018, Mr. Houston was the international chairman of the Houston-based investment bank Tudor Pickering Holt. From August 2017 to February 2018, he was a senior advisor to Gresham Advisory Partners Limited, an M&A advisory firm based in Sydney, Australia. From 2014 to 2019, he was a non-executive director of Bupa, an unlisted international healthcare insurer and provider, based in the United Kingdom. Since January 2019, he has been a non-executive of Bupa Arabia, a Saudi-listed healthcare insurer and provider. Since October 2019, Mr. Houston has served as chairman of the board of directors of EnQuest PLC, an independent petroleum production and development company with operations in the U.K. North Sea and Malaysia. Mr. Houston is also a senior advisory partner and chairman of the global energy group of Moelis & Company (a global independent investment bank), sits on the National Petroleum Council of the United States, and is a nonexecutive director of CC Energy Development (a private oil and gas exploration and production company) and a senior advisor to Hakluyt & Company Limited (a strategic information consultancy). Mr. Houston was the first recipient of the CWC LNG Executive of the Year award in 2011 and is a Fellow of the Geological Society of London. In addition, he is on the advisory board of the Center on Global Energy Policy at Columbia University’s School of International Public Affairs (SIPA) in New York and of Radia Inc. Mr. Houston received a bachelor’s degree in Geology from Newcastle University in England in 1979 and a master’s degree in Petroleum Geology from Imperial College in London in 1983.
Mr. Houston’s qualifications to serve as a director of Tellurian include his knowledge of and experience in the LNG industry. In addition to his industry experience, his qualifications include his leadership skills and long-standing senior management experience in the energy industry. |
Name | | Other Positions
Held with the
Company | | Age and Business Experience |
Eric P. Festa
| | | | Mr. Festa (age 50) has served as a director of Tellurian since December 2018. Since October 2017, he has served as Vice President of Asset Management for the Gas division of TOTAL S.A. From August 2015 to September 2017, Mr. Festa served as Managing Director of an exploration and production affiliate of TOTAL S.A. in the Middle East. In addition, he served as Vice President of Upstream M&A of TOTAL S.A. from June 2014 to July 2015 and as Vice President of Upstream Corporate Strategy of TOTAL S.A. from September 2012 to June 2014. Mr. Festa previously served in other roles and capacities with TOTAL S.A. and its affiliated entities, including in business development, project management, gas plant management, and planning and development, and as an economist. Since October 2018, he has served on the board of managers of Cameron LNG Holdings, LLC. Mr. Festa received a MEng degree in energy from French engineering school CentraleSupélec and a master’s degree from the French Petroleum Institute (IFP School) in Paris, and was a visiting scientist in the Energy Lab at the Massachusetts Institute of Technology.
Mr. Festa’s qualifications to serve as a director of Tellurian include his knowledge of and experience in the energy industry. |
Directors Holding Office for a Term Expiring at the 2022 Annual Meeting of Stockholders
Name | | Other Positions
Held with the
Company | | Age and Business Experience |
Brooke A. Peterson
| | Chairman of the Compensation Committee and Member of the Audit Committee and Governance and Nominating Committee | | Mr. Peterson (age 70) has served as a director of Tellurian since the completion of the Merger in February 2017, and he served as a director of Tellurian Investments from July 2016 to February 2017. He has been involved in construction, resort development and real estate for more than 40 years and has been extensively involved in non-profit work since moving to Aspen, Colorado, in 1975. Mr. Peterson is a member of the Colorado Bar and has been licensed to practice law for over 40 years, has served as an arbitrator and mediator since 1985, and has served as a Municipal Court Judge in Aspen since 1981. Mr. Peterson has served as Manager of Ajax Holdings LLC and its affiliated companies since December 2012 and as the Chief Executive Officer of Coldwell Banker Mason Morse since January 2013. Mr. Peterson earned his B.A. degree from Brown University in 1972 and his J.D. degree from the University of Denver College of Law in 1975.
Mr. Peterson’s qualifications to serve as a director of Tellurian include his knowledge of and experience in project development and the construction industry. |
Charif Souki
| | Chairman of the Board | | Mr. Souki (age 67) has served as a director of Tellurian since the completion of the Merger in February 2017, and he served as a director and Chairman of the board of directors of Tellurian Investments from February 2016 to February 2017. Mr. Souki founded Cheniere in 1996 and served as Chairman of the board of directors (2000–2015), Chief Executive Officer (2003–2015), and President (2003–2004 and 2008–2015) until December 2015. Prior to Cheniere, Mr. Souki was an investment banker. Mr. Souki serves on the board of trustees of the American University of Beirut, as a member of the Advisory Board of the Center on Global Energy Policy at Columbia University, and on the International Advisory Board for the Neurological Research Institute (NRI) at Texas Children’s Hospital. Mr. Souki received a B.A. from Colgate University and an M.B.A. from Columbia University.
Mr. Souki is qualified to serve as a director of Tellurian due to his knowledge of and experience in the LNG industry, including his leading the conception, development and construction of the first large-scale LNG export facility in the United States. In addition to his industry experience, his qualifications include his leadership skills, long-standing senior management experience and public company board experience in the LNG industry. |
Don A. Turkleson
| | Chairman of the Audit Committee and Member of the Compensation Committee | | Mr. Turkleson (age 65) has served as a director of Tellurian since March 2017, and he served as Vice President and Chief Financial Officer of Gulf Coast Energy Resources, LLC, a privately held energy exploration and production company, from April 2012 until his retirement in April 2015. He served as Senior Vice President and Chief Financial Officer of Cheniere Energy Partners GP, LLC, the general partner of Cheniere Energy Partners, L.P. (NYSE American: CQP), an indirect subsidiary of Cheniere, from November 2006 to March 2009 and was a member of the board of directors of Cheniere Energy Partners GP, LLC from November 2006 until September 2012. From December 2013 until February 2017, Mr. Turkleson served on the board of directors and audit committee of Cheniere Energy Partners LP Holdings, LLC. Since February 2018, Mr. Turkleson has served on the board of directors and as chairman of the finance and audit committees of ACCEL Energy Canada Limited, a privately held company constructing and operating facilities for the delivery of energy, ultra-clean fuels and specialty products. From November 2013 until July 2015, he served on the board of directors of the general partner of QEP Midstream Partners, L.P., a midstream publicly traded master limited partnership. In addition, he served on the board of directors and as the chairman of the audit committee of Miller Energy Resources, Inc., a publicly traded energy exploration, production and drilling company, from January 2011 to April 2014. Mr. Turkleson is a Certified Public Accountant and received a B.S. in Accounting from Louisiana State University. He is also a Board Governance Fellow with the National Association of Corporate Directors.
Mr. Turkleson’s qualifications to serve as a director of Tellurian include his background and experience in the energy industry and his background as a Certified Public Accountant. |
Voting Agreements
Total Delaware, Inc. (“Total”Tellurian,” “we,” “us,” “our,” or the “Company”), a Delaware corporation, and subsidiary of TOTAL S.A., has the right to designate for election one member of Tellurian’s Board. Mr. Festa is the current Total designee. Total will retain this right for so long as its percentage ownership of Tellurian’s voting stocka Houston-based company that is at least 10%. In January 2017, Tellurian, Tellurian Investments, Total, Charif Souki, the Souki Family 2016 Trust and Martin Houston entered into a voting agreement pursuant to which Mr. Souki, the Souki Family 2016 Trust and Mr. Houston agreed to vote all shares of Tellurian stock that they own in favor of the director nominee designated by Total for so long as Total owns not less than 10% of the outstanding shares of Tellurian common stock (the “2017 Total Voting Agreement”).
In July 2019, in connection with the execution of the Equity Capital Contribution Agreement, dated as of July 10, 2019, between Driftwood Holdings LP, a subsidiary of the Company (“Driftwood Holdings”), and Total, the Company entered into Amendment No. 1 (the “2019 Total Voting Agreement Amendment”) to the 2017 Total Voting Agreement. Pursuant to the 2019 Total Voting Agreement Amendment, (i) each of Brooke Peterson (who, pursuant to an irrevocable special power of attorney executed by the beneficiaries of the Souki Family 2016 Trust, has the exclusive right to vote the shares of Tellurian common stock held by the Souki Family 2016 Trust) and Messrs. Souki and Houston provided a letter to Total confirming his intent, subject to certain conditions and exceptions including their fiduciary duties as directors of the Company, to vote, as a member of the Board in favor of a policy to declare and pay a dividend to the holders of Tellurian common stock of a minimum of 50% of the Company’s available cash and (ii) in the event any of those directors leave the Tellurian board of directors, each of Messrs. Souki and Houston and the Souki Family 2016 Trust would agree to vote their shares of stock of the Company, and the Company would make commercially reasonable efforts, to elect a successor director who is willing to provide a similar letter to Total.
In connection with the execution of the Securities Purchase Agreement, dated as of April 28, 2020, by and between the Company and High Trail Investments SA LLC (the “High Trail SPA”), Tellurian and each of Mr. Souki, Mr. Houston, Meg Gentle and R. Keith Teague, in their capacity as Tellurian stockholders, expect to enter into a voting agreement (each, a “Share Issuance Voting Agreement”) pursuant to which each of Mr. Souki, Mr. Houston, Ms. Gentle and Mr. Teague will agree to vote, at an annual or special meeting of stockholders of the Company, all shares of Tellurian common stock that they hold in favor of proposals to approve (i) the potential issuance of shares of Tellurian common stock upon conversion of a senior unsecured note to be issued pursuant to the High Trail SPA and (ii) an increase in the number of authorized shares of Tellurian common stock.
Executive Officers
As of April 28, 2020, our executive officers were as follows:
Name | | Title | | Age | |
Meg A. Gentle | | President and Chief Executive Officer | | 45 | |
R. Keith Teague | | Executive Vice President and Chief Operating Officer | | 55 | |
L. Kian Granmayeh | | Executive Vice President and Chief Financial Officer | | 41 | |
Daniel A. Belhumeur | | Executive Vice President, General Counsel and Chief Compliance Officer | | 41 | |
Khaled A. Sharafeldin | | Chief Accounting Officer | | 57 | |
See “Item 10, Directors, Executive Officers and Corporate Governance—Directors Holding Office for a Term Expiring at the 2020 Annual Meeting of Stockholders” for biographical information concerning Ms. Gentle.
R. Keith Teague has served as the Executive Vice President and Chief Operating Officer of Tellurian since the completion of the Merger in February 2017, and he served as Executive Vice President and Chief Operating Officer of Tellurian Investments from October 2016 until the completion of the Merger. Previously, at Cheniere, Mr. Teague served as Executive Vice President, Asset Group (February 2014–September 2016), Senior Vice President –Asset Group (April 2008–February 2014), Vice President –Pipeline Operations (May 2006–April 2008), and Director of Facility Planning (February 2004–May 2006). Mr. Teague also served as President of CQH Holdings Company, LLC (formerly known as Cheniere Pipeline Company), a wholly owned subsidiary of Cheniere, from January 2005 until September 2016. From December 2001 until September 2003, Mr. Teague served as the Director of Strategic Planning for the CMS Panhandle Companies. He began his career with Texas Eastern Transmission Corporation, where he managed pipeline operations and facility expansion projects. Mr. Teague received a B.S. in Civil Engineering from Louisiana Tech University and an M.B.A. from Louisiana State University.
L. Kian Granmayeh has served as the Executive Vice President and Chief Financial Officer of Tellurian since March 6, 2020. Mr. Granmayeh began at Tellurian as a consultant to the Chief Financial Officer in January 2019 and was appointed as its Director of Special Projects in July 2019 and as the Company’s Director of Investor Relations in August 2019. Prior to joining Tellurian, he worked at Apache Corporation from May 2014 until February 2018, including as Manager of Investor Relations (July 2016 to February 2018), Manager of Strategic Planning (January 2015 to June 2016) and Manager of Project Execution (May 2014 to December 2014). Prior to that, he was an Associate, and then a Vice President, at Lazard Frères & Co. from 2009 to 2014. He holds a B.A. from Columbia University and an M.B.A. from Rice University.
Daniel A. Belhumeur has served as an Executive Vice President of Tellurian since March 6, 2020, as the Senior Vice President and General Counsel of Tellurian since the completion of the Merger in February 2017 and as Chief Compliance Officer of Tellurian since March 2017, and he served as General Counsel of Tellurian Investments from October 2016 until the Merger. Previously, at Cheniere, Mr. Belhumeur served as Vice President, Tax and General Tax Counsel (January 2011–October 2016), Tax Director (January 2010–December 2010), and Domestic Tax Counsel (2007–2010). Mr. Belhumeur began his career in public accounting after he received his bachelor’s degree and master’s degree in Accounting from Texas A&M University. He then went on to obtain his law degree from the University of Kansas School of Law and his LL.M. from the Georgetown University Law Center.
Khaled A. Sharafeldin has served as the Chief Accounting Officer of Tellurian since the completion of the Merger in February 2017, and he served as Chief Accounting Officer of Tellurian Investments from January 2017 until that time. From April 2012 to January 2017, Mr. Sharafeldin served as Vice President – Internal Audit at Cheniere. Previously, at Pride International, he served as Director – Quality Management (2010–2011) and Director of Internal Audit (2005–2010). In addition, he served as Director of Internal Audit at BJ Services Company (2003–2005), served in several financial management roles at Schlumberger Limited (1996–2003), and was employed by the public accounting firm Price Waterhouse LLP in Houston, Texas (1991–1996). Mr. Sharafeldin received his Bachelor of Commerce from Cairo University in Egypt. He is also a Certified Public Accountant in the State of California.
Corporate Governance
Code of Conduct and Business Ethics
The Company has adopted a Code of Business Conduct and Ethics (the “Code of Conduct”) that summarizes Tellurian’s compliance and ethical standards and the expectations it has for its officers, directors, and employees. Under the Code of Conduct, all directors, officers, and employees must follow ethical business practices in all business relationships, both within and outside of the Company.
The Code of Conduct is available on the Company’s website, http://www.tellurianinc.com, under the heading “Investors—Company and governance—Governance documents.” Tellurian intends to provide disclosure regarding waivers of or amendments to the Code of Conduct by posting such waivers or amendments to the website in the manner provided by applicable law.
Standing Board Committees
Audit Committee
The Audit Committee is comprised of Ms. Derycz-Kessler, Mr. Peterson, and Mr. Turkleson (Chairman). The functions of the Audit Committee are set forth in its written charter, as amended on December 4, 2019 (the “Audit Committee Charter”). The Audit Committee Charter is posted on the Company’s website, http://www.tellurianinc.com, under the heading “Investors—Company and governance—Board committees.” The Board has determined that each member of the committee is independent under applicable Nasdaq and Securities and Exchange Commission (“SEC”) rules and that each of Ms. Derycz-Kessler and Mr. Turkleson qualifies as an “audit committee financial expert” as defined in SEC rules.
Under the Audit Committee Charter, the Audit Committee is responsible for assisting the Board in fulfilling its oversight responsibilities with respect to (i) the Company’s accounting and financial reporting processes and the integrity of the Company’s financial statements; (ii) the effectiveness of the Company’s internal accounting and financial controls, disclosure controls and procedures, and internal control over financial reporting, as well as the performance of the Company’s internal audit function; (iii) the audits of the Company’s financial statements and the appointment, engagement, compensation, termination (if necessary), qualifications, independence, and performance of the Company’s independent registered public accounting firm; and (iv) the Company’s compliance with legal and regulatory requirements and ethics programs. The Audit Committee has the sole authority to select, engage (including approval of the fees and terms of engagement), oversee, and terminate, as appropriate, the Company’s independent registered public accounting firm.
Compensation Committee
The Compensation Committee is comprised of Ms. Derycz-Kessler, Mr. Peterson (Chairman) and Mr. Turkleson. The functions of the Compensation Committee are set forth in its written charter, as amended on December 5, 2018 (the “Compensation Committee Charter”). The Compensation Committee Charter is posted on the Company’s website, http://www.tellurianinc.com, under the heading “Investors—Company and governance—Board committees.”
The Board has determined that each member of the Compensation Committee qualifies as (i) an independent director under applicable Nasdaq rules, (ii) a “non-employee director” for purposes of Rule 16b-3 under the Exchange Act and (iii) to the extent required for awards intended to constitute “qualified performance-based compensation” within the meaning of Section 162(m) of the Internal Revenue Code of 1986, as amended (the “IRS Code”), an “outside director” for purposes of Section 162(m) of the IRS Code.
Under the Compensation Committee Charter, the primary duties and responsibilities of the Compensation Committee are to assist the Board in fulfilling its responsibilities with respect to the Company’s compensation plans, policies, programs, and practices, including (i) determining, and/or recommending to the Board for its determination, the compensation of the Company’s chief executive officer and all other executive officers of the Company; and (ii) reviewing and approving, and/or recommending to the Board for its approval, equity and other incentive compensation plans, policies, and programs for the Company’s directors, officers, employees, or consultants, and overseeing and administering such plans, policies, and programs in accordance with their terms. From time to time, the Compensation Committee consults with the Chairman of the Board regarding executive and director compensation matters and with the Chief Executive Officer and/or Chief Human Resources Officer of the Company regarding executive compensation matters. In addition, the Vice Chairman of the Board regularly serves as a non-voting advisory participant in meetings of the Compensation Committee.
Governance and Nominating Committee
The Governance and Nominating Committee is comprised of Ms. Derycz-Kessler, Mr. Ferguson (Chairman) and Mr. Peterson. The functions of the Governance and Nominating Committee are set forth in its written charter, as amended on December 5, 2018 (the “Governance and Nominating Committee Charter”). The Governance and Nominating Committee Charter is posted on the Company’s website, http://www.tellurianinc.com, under the heading “Investors—Company and governance—Board committees.” The Board has determined that each member of the committee is independent under applicable Nasdaq rules.
Under the Governance and Nominating Committee Charter, the Governance and Nominating Committee is responsible for assisting the Board in fulfilling its oversight responsibilities with respect to (i) identifying individuals qualified to serve as directors; (ii) recommending to the Board candidates for nomination for election to the Board at the annual meeting of stockholders or to fill Board vacancies; and (iii) developing and recommendingplans to the Board a set of corporate governance guidelinesown and reviewing on a regular basis the overall corporate governance of the Company.
ITEM 11. EXECUTIVE COMPENSATION
Compensation discussion and analysis
The following Compensation Discussion and Analysis summarizes our compensation program for our named executive officers for the 2019 fiscal year.
Named Executive Officers
Our named executive officers (“NEOs”) based on position and compensation for the fiscal year ended December 31, 2019 are the following individuals:
Name | | Position |
|
Meg A. Gentle | | President and Chief Executive Officer (“CEO”) |
R. Keith Teague | | Executive Vice President and Chief Operating Officer |
Antoine J. Lafargue | | Senior Vice President of LNG Marketing and former Chief Financial Officer (“former CFO”) (1) |
Daniel A. Belhumeur | | Executive Vice President, General Counsel and Chief Compliance Officer |
Khaled A. Sharafeldin | | Chief Accounting Officer |
| (1) | On March 6, 2020, L. Kian Granmayeh was appointed as the Executive Vice President and Chief Financial Officer of the Company, and Mr. Lafargue joined the Company’s marketing group as Senior Vice President of LNG Marketing. |
2019 Performance Highlights
Under the leadership of our NEOs, we continued our efforts to create value for stockholders by building a low-cost, global natural gas business, profitably delivering natural gas to customers worldwide throughoperate a portfolio of natural gas, production, LNG marketing, and infrastructure assets.
Since our inception as Tellurian Investments in 2016, our efforts have been driven by the goal of constructingassets that includes an LNG terminal facility (the “Driftwood terminal”), an associated pipeline (the “Driftwood pipeline”), other related pipelines, and related pipelines—upstream natural gas assets (collectively referred to as the “Business”). The Driftwood terminal and the Driftwood pipeline are collectively referred to as the “Driftwood Project.” As of December 31, 2022, our upstream natural gas assets consist of 27,689 net acres and interests in 143 producing wells located in the Haynesville Global AccessShale trend of northern Louisiana. Our Business may be developed in phases.
As part of our execution strategy, which includes increasing our asset base, we will consider various commercial arrangements with third parties across the natural gas value chain. We are also pursuing activities such as direct sales of LNG to global counterparties, trading of LNG, the acquisition of additional upstream acreage and drilling of new wells on our existing or newly acquired upstream acreage. We remain focused on the financing and construction of the Driftwood Project and related pipelines while managing our upstream assets.
We manage and report our operations in three reportable segments. The Upstream segment is organized and operates to produce, gather, and deliver natural gas and to acquire and develop natural gas assets. The Midstream segment is organized to develop, construct and operate LNG terminals and pipelines. The Marketing & Trading segment is organized and operates to purchase and sell natural gas produced primarily by the Upstream segment, market the Driftwood terminal’s LNG production capacity and trade LNG.
We continue to evaluate the scope and other aspects of our Business in light of the evolving economic environment, dynamics of the global political landscape, needs of potential counterparties and other factors. How we execute our Business will be based on a variety of factors, including the results of our continuing analysis, changing business conditions and market feedback.
Overview of Significant Events
Limited Notice to Proceed
On March 24, 2022, the Company issued a limited notice to proceed to Bechtel Energy Inc., formerly known as Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”), under our LSTK EPC agreement for Phase 1 of the Driftwood terminal dated as of November 10, 2017 (the “Phase 1 EPC Agreement”). The Company commenced construction of Phase 1 of the Driftwood terminal on April 4, 2022.
Senior Secured Convertible Notes due 2025
On June 3, 2022, we issued and sold $500.0 million aggregate principal amount of 6.00% Senior Secured Convertible Notes due May 1, 2025 (the “Convertible Notes”). Net proceeds from the Convertible Notes were approximately $488.7 million after deducting fees and expenses.
Upstream Asset Acquisition
On August 18, 2022, the Company completed the acquisition of certain natural gas assets in the Haynesville Shale basin. The purchase price of $125.0 million was subject to customary adjustments totaling approximately $8.8 million, for an adjusted purchase price of approximately $133.8 million.
Environmental, Social, Governance Practices
During the year ended December 31, 2021, the Company entered into a pledge with the National Forest Foundation on a five-year plan for reforestation and other forest management projects totaling $25.0 million across the United States. In 2022, the Company supported the planting of more than one million trees on 1,441 acres across the United States and bolstered nursery capacity by one million seedlings.
Upstream Natural Gas Drilling Activities
During the year ended December 31, 2022, we put in production 13 operated Haynesville wells and participated in four non-operated Haynesville wells that were put in production.
Natural Gas Properties
Reserves
Our natural gas assets consist of 27,689 net acres and interests in 143 producing wells located in the Haynesville Shale trend of north Louisiana. For the year ended December 31, 2022, our average net production was approximately 129.7 MMcf/d. All of our proved reserves were associated with those properties as of December 31, 2022. 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, 2022 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 of natural gas for each month from January through December 2022. Prices include consideration of changes in existing prices provided for under contractual arrangements, but not on escalations or reductions based upon future conditions. The price used for the reserve estimates as of December 31, 2022 was $6.36 per MMBtu of natural gas, adjusted for energy content, transportation fees and market differentials.
The following table shows our proved reserves as of December 31, 2022:
| | | | | |
| Natural Gas
(MMcf) |
| Proved reserves (as of December 31, 2022): | |
| Developed | 218,382 | |
| Undeveloped | 226,511 | |
| Total proved reserves | 444,893 | |
As of December 31, 2022, the standardized measure of discounted future net cash flow from our proved reserves (the “standardized measure”) was approximately $1,036.3 million.
During the year ended December 31, 2022, the Company spent approximately $140.0 million on the conversion of our proved undeveloped reserves to proved developed reserves. The Company converted approximately 138 Bcfe of proved undeveloped to proved developed reserves, which represents a conversion rate of approximately 43%.
Refer to Supplemental Disclosures About Natural Gas Producing Activities, starting on page 63, for additional details. Controls Over Reserve Report Preparation, Technical Qualifications and Technologies Used
Our December 31, 2022 reserve report was prepared by NSAI in accordance with guidelines established by the SEC. Reserve definitions comply with the definitions provided by Regulation S‑X of the SEC. NSAI prepared the reserve report based upon a review of property interests being appraised, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, geoscience and engineering data, and other information we provided to them. This information was reviewed by knowledgeable members of our Company for accuracy and completeness prior to submission to NSAI. A letter that identifies the professional qualifications of the individual at NSAI who was responsible for overseeing the preparation of our reserve estimates as of December 31, 2022, has been filed as an addendum to Exhibit 99.1 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 20 years of experience in the oil and natural gas industry, with the majority of that time in reservoir engineering and asset management. She is a graduate of Virginia Polytechnic Institute and State University with dual degrees in Chemical Engineering and French, and a graduate of the University of Houston with a Masters of Business Administration degree. During her career, she has had multiple responsibilities in technical and leadership roles, including reservoir engineering and reserves management, production engineering, planning, and asset management for multiple U.S. onshore and international projects. She is also a licensed Professional Engineer in the State of Texas.
Production
For the years ended December 31, 2022, 2021 and 2020, we produced 47,322 MMcf, 14,302 MMcf and 16,893 MMcf of natural gas at an average sales price of $5.78, $3.52 and $1.74 per Mcf, respectively. Natural gas production and operating costs for the periods ended December 31, 2022, 2021 and 2020 were $0.37, $0.48 and $0.28 per Mcfe, respectively.
Drilling Activity
The information in the table below should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found, or economic value. A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. A productive well is an exploratory, development, or extension well that is not a dry well. Completion refers to installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned. The number of wells drilled refers to the number of wells completed at any time during the fiscal year, regardless of when drilling was initiated. The table below shows the number of net productive and dry development operated and non-operated wells drilled during the past three years.
| | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| Development wells: | | | | | |
| Productive | 13.5 | | | 6.9 | | | — | |
| Dry | — | | | — | | | — | |
| We had no exploratory wells drilled during any of the periods presented. | | | | | | |
Wells
As of December 31, 2022, we owned working interests in 114 gross (45.6 net) productive natural gas wells. As of December 31, 2022, there were 22 gross (9.7 net) in process wells.
Acreage
We have 7,982 gross (7,063 net) developed leasehold acres that are held by production. Additionally, we hold 21,650 gross (20,626 net) undeveloped leasehold acres. Of the total gross and net undeveloped acreage, 16,091 gross (15,681 net) acres are not held by production, of which 1,441 gross and net acres are set to expire in the fourth quarter of 2023 unless production is established within the spacing units covering the acreage prior to the expiration dates or unless such leasehold rights are extended or renewed.
Volume Commitments
For the year ended December 31, 2022, we were not subject to any material volume delivery commitments. The Company is expected to be subject to gas gathering agreements in the near-term with two third-party companies that are constructing gathering systems in the Haynesville Shale. Upon the in-service date of these gathering systems, the Company will have dedicated gathering capacity for a portion of the Upstream segment’s future natural gas production. The contracts will require the Company to make deficiency payments to the extent the Company does not meet the minimum volume commitments per the terms of each contract. The Company expects to fulfill this commitment with existing reserves. The Company will monitor current production, anticipated future production, and future development plans to meet its future commitments.
Gathering, Processing and Transportation
As part of our acquisitions of natural gas properties, we also acquired certain gathering systems that deliver the natural gas we produce into third-party gathering systems. We believe that these systems and other available midstream facilities and services in the Haynesville Shale trend are adequate for our current operations and near-term growth.
Government Regulations
Our operations are and will be subject to extensive federal, state and local statutes, rules, regulations, and laws that include, but are not limited to, the NGA, the Energy Policy Act of 2005 (“EPAct 2005”), the Oil Pollution Act, the National Environmental Policy Act (“NEPA”), the Clean Air Act (the “CAA”), the Clean Water Act (the “CWA”), the Resource Conservation and Recovery Act (“RCRA”), the Pipeline Safety Improvement Act of 2002 (the “PSIA”), and the Coastal Zone Management Act (the “CZMA”), as amended from time to time. These statutes cover areas related to the authorization, construction and operation of LNG facilities, natural gas pipelines 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. These laws are administered and enforced by governmental agencies including but not limited to FERC, the U.S. Environmental Protection Agency (the “EPA”), DOE/FECM, the U.S. Department of Transportation (“DOT”), the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), the Permian Global Access Pipeline (collectively,Louisiana Department of Environmental Quality and the “Pipeline Network”)—Louisiana Department of Natural Resources. Additionally, numerous other governmental and owning upstream gas assets (togetherregulatory permits and
approvals have been and 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 Service, 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 the Driftwood Project, we will be subject to regular reporting requirements to FERC, 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. Criminal and regulatory enforcement agencies such as the U.S. Department of Justice have conducted investigations and have imposed criminal and civil penalties on other companies within our industry.
We have received regulatory permits and approvals in connection with the Driftwood terminal, Driftwood pipeline, and related pipelines, including the following:
| | | | | | | | |
| | |
| Agency | Permit / Consultation | Approval Date (Anticipated) |
| FERC | Section 3 and Section 7 Application - NGA
Related Pipeline - Section
Related Pipeline - Section 7 Application | April 18, 2019 March 2023 |
| DOE | Section 3 Application - NGA | FTA countries: February 28, 2017 (3968); amended December 6, 2018 (3968-A);
amended December 18, 2020 (4641)
Non-FTA countries: May 2, 2019 (4373);
amended December 10, 2020 (4373-A);
amended December 18, 2020 (4641) |
| USACE | Section 404 Section 10 (Rivers and Harbors Act) | May 3, 2019
May 3, 2019 |
Related Pipeline - Section 404 Related Pipeline - Section 10 | January 31, 2023
January 31, 2023 |
| United States Coast Guard | Letter of Intent and Preliminary Water Suitability Assessment | June 21, 2016 |
| Follow-On Water Suitability Assessment and Letter of Recommendation | April 25, 2017 |
| United States Fish and Wildlife Service | Section 7 of Endangered Species Act Consultation Related Pipeline - Section 7 of Endangered Species Act Consultation
| September 19, 2017; February 7, 2019
August 11, 2021; October 27, 2021; April 26, 2022; June 30, 2022 |
| National Oceanic and Atmospheric Administration / National Marine Fisheries Service | Section 7 of the Endangered Species Act Consultation | February 14, 2018 |
Magnuson-Stevens Fishery Management and Conservation Act Essential Fish Habitat Consultation | October 3, 2017 |
Marine Mammal Protection Act Consultation | October 3, 2017 |
| State | | |
| Louisiana Department of Natural Resources- Coastal Management Division | Coastal Use Permit and Coastal Zone Consistency Permit, Joint Permit with USACE | May 21, 2020 (extension) |
| Louisiana Department of Environmental Quality - Air Quality Division | Air Permit for LNG Terminal
Gillis Compressor Station
Related Pipeline - Indian Bayou Compressor Station | June 2, 2021 (extension)
July 6, 2022 (renewal)
March 2023 |
| Louisiana State Historic Preservation Office | Section 106 Consultation
| Concurrence received on June 29, 2016 |
| Concurrence received on November 22, 2016 |
| Concurrence received on April 13, 2017 |
| Concurrence received on March 1, 2019 |
| Related Pipeline - Section 106 Consultation | Concurrence received on July 28, 2021 |
| Concurrence received on November 15, 2021 |
| Concurrence received on March 16, 2022 |
| Concurrence received on July 26, 2022 |
Federal Energy Regulatory Commission
The design, construction and operation of natural gas liquefaction facilities and pipelines, the export of LNG and the Pipeline Network,transportation of natural gas are highly regulated activities. In order to site, construct and operate the “Driftwood Project”)Driftwood Project, we obtained authorizations from FERC under Section 3 and Section 7 of the NGA as well as several other material governmental and regulatory approvals and permits as detailed in the table above. Construction of the Driftwood terminal has commenced. In order to gain regulatory certainty with respect to certain potential commercial transactions, on November 13, 2020, the Company filed a Petition with FERC requesting, among other things, a prospective limited waiver of FERC’s buy/sell
prohibition as well as any other prospective waivers necessary to enable the Company to purchase natural gas from potentially affiliated upstream suppliers that may be resold to a different affiliate under a long-term contract for export as LNG in foreign commerce. On January 19, 2021, FERC issued an order granting a prospective limited waiver of the prohibition on buy/sell arrangements for future proposed transactions in which the Company enters into: (1) an agreement to purchase natural gas from a potentially affiliated supplier; and (2) an agreement to sell LNG to affiliates in foreign commerce.
EPAct 2005 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 EPAct 2005, nothing in the statute 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 to the rates, terms and conditions agreed to by parties for LNG terminalling services, such that LNG terminal owners would not be required to provide optionalityopen-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 interstate natural gas pipelines. Although EPAct 2005 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 terminal operations.
A certificate of public convenience and necessity from FERC is required for the construction and operation of facilities used in interstate natural gas transportation, including pipeline facilities, in addition to other required governmental and regulatory approvals. In this regard, in April 2019, the Company obtained a certificate of public convenience and necessity to construct and operate the Driftwood pipeline. On June 17, 2021, the Company filed an application pursuant to Section 7(c) of the NGA in FERC Docket No. CP21-465-000, which, as amended, requests that FERC grant a certificate of public convenience and necessity and related approvals to construct, own and operate dual 42-inch diameter natural gas pipelines, an approximately 211,200 horsepower compressor station and appurtenant facilities to be located in Beauregard and Calcasieu Parishes, Louisiana, which would provide a maximum seasonal capacity of 5.7 Bcf of natural gas per day. FERC issued the final environmental impact statement for the project on September 15, 2022. The final order on the application is still pending.
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:
•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.
In addition, FERC has the 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.
EPAct 2005 amended 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. EPAct 2005 also gives FERC authority to impose civil penalties for violations of the NGA or Natural Gas Policy Act of more than $1 million per day per violation.
On February 18, 2022, FERC issued two policy statements: (1) an updated policy statement describing how it will determine whether a new interstate natural gas transportation project is required by the public convenience and necessity under section 7 of the NGA; and (2) an interim policy statement explaining how FERC will assess the impacts of natural gas
infrastructure projects on climate change in its review under the National Environmental Policy Act and the NGA. On March 24, 2022, FERC reissued the policy statements as drafts and requested additional comments. FERC is not applying the draft policy statements to new or pending applications until FERC issues the final policy statements. It is not clear when the final policy statements will be issued.
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 Licenses
Under the NGA, exports of natural gas to FTA countries are “deemed to be consistent with the public interest,” and authorization to export LNG to FTA countries shall be granted by the DOE/FECM “without modification or delay.” FTA countries currently capable of importing LNG include but are not limited to 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/FECM “finds that the proposed exportation” “will not be consistent with the public interest.” We have authorization from the DOE/FECM to export LNG in a volume up to the equivalent of 1,415.3 Bcf per year of natural gas to FTA countries for a term of 30 years and to Non-FTA countries for a term through December 31, 2050.
Federal and State Regulation of Pipeline and Hazardous Materials Safety
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.
The Driftwood pipeline and other related 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 mitigative actions.
On December 27, 2020, the Protecting our Infrastructure of Pipelines and Enhancing Safety Act (PIPES Act) of 2020 was signed into law as part of the Consolidated Appropriations Act of 2021. The legislation reauthorizes the PHMSA pipeline safety program through fiscal year 2023 and provides for advances to improve pipeline safety. The legislation includes a directive to PHMSA to update its current regulations for large-scale LNG facilities.
On January 11, 2021, PHMSA published a final rule in the Federal Register amending the Federal Pipeline Safety Regulations to reduce regulatory burdens and offer greater flexibility with respect to the construction, maintenance, and operation of gas transmission, distribution, and gathering pipeline systems, including updates to corrosion control requirements and test requirements for pressure vessels. Mandatory compliance with this rule started on October 1, 2021.
On November 15, 2021, PHMSA published a final rule in the Federal Register revising the Federal Pipeline Safety Regulations to improve the safety of onshore gas gathering pipelines. The rule extends reporting requirements to all gas gathering operators and applies a set of minimum safety requirements to certain gas gathering pipelines with large diameters and high operating pressures. This rule went into effect on May 16, 2022.
On April 8, 2022, PHMSA published a final rule in the Federal Register revising the Federal Pipeline Safety Regulations applicable to most newly constructed and entirely replaced onshore gas transmission, certain gas gathering, and hazardous liquid pipelines with diameters of six inches or greater. In the revised regulations, PHMSA establishes requirements for operators of these lines to install rupture-mitigation valves or alternative equivalent technologies and establishes minimum
performance standards for those valves and requirements for rupture-mitigation valve spacing, maintenance and inspection, and risk analysis, among other actions. The final rule went into effect on October 5, 2022.
On August 24, 2022, as subsequently corrected on October 25, 2022, PHMSA published a final rule in the Federal Register revising the Federal Pipeline Safety Regulations relating to improved safety of onshore gas transmission pipelines. The amendments in this final rule clarify certain integrity management provisions, codify a management of change process, update and bolster gas transmission pipeline corrosion control requirements, require operators to inspect pipelines following extreme weather events, strengthen integrity management assessment requirements, adjust the repair criteria for high-consequence areas, create new repair criteria for non-high consequence areas, and revise or create specific definitions related to the amendments. The rule goes into effect on May 24, 2023.
The Driftwood pipeline and other related pipelines will be subject to regulation by PHMSA, which will involve capital and operating costs for compliance-related equipment and operations. We have no reason to believe that these compliance costs will be material to our financial performance, but the significance of such costs will depend on future events and our ability to achieve and maintain compliance throughout the life of the Driftwood Project or related pipelines.
Natural Gas Pipeline Safety Act of 1968
The State of Louisiana also administers certain 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 terminal and Driftwood pipeline are subject to federal permits, orders, approvals and consultations required by other federal and state agencies, including DOT, the Advisory Council on Historic Preservation, USACE, U.S. Department of Commerce, National Marine Fisheries Service, U.S. Department of the Interior, U.S. Fish and Wildlife Service, the EPA and the U.S. Department of Homeland Security. The necessary permits required for construction have been obtained and will be required to be maintained for the Driftwood terminal and Driftwood pipeline. Similarly, additional permits, orders, approvals and consultations will be required for other related pipelines.
Three significant permits that apply to the Driftwood terminal and Driftwood pipeline are the USACE Section 404 of the CWA/Section 10 of the Rivers and Harbors Act Permit, the CAA Title V Operating Permit and the Prevention of Significant Deterioration Permit, of which the latter two permits are issued by the Louisiana Department of Environmental Quality. Each of the Driftwood terminal and Driftwood pipeline has received its permit from the USACE, including a review and approval by the USACE of the findings and conditions set forth in an Environmental Impact Statement and Record of Decision issued for the Driftwood terminal and Driftwood pipeline pursuant to the requirements of NEPA. The Louisiana Department of Environmental Quality has issued the Prevention of Significant Deterioration permit, which is required to commence construction of the Driftwood terminal, as well as the Title V Operating Permit. These material approvals may be required for other related pipelines.
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. The statutes, regulations and permit requirements imposed under environmental laws are modified frequently, sometimes retroactively. Such changes are difficult to predict or prepare for, and may impose material costs for new permits, capital investment or operational limitations or changes.
The Biden Administration has issued a number of executive orders that direct federal agencies to take actions that may change regulations and guidance applicable to our business.
For example, Executive Order 14008, “Tackling the Climate Crisis at Home and Abroad,” 86 FR 7619 (January 27, 2021), establishes a policy “promoting the flow of capital toward climate-aligned investments and away from high-carbon investments.” It also requires the heads of agencies to identify any fossil fuel subsidies provided by their respective agencies, and to seek to eliminate fossil fuel subsidies from the budget request for fiscal year 2022 and thereafter.
Executive Order 13990, “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis,” 86 FR 7037 (January 20, 2021) directs agencies to review regulations and policies adopted by the Trump Administration and to “confront the climate crisis.” It specifically directs the EPA to consider suspending, revising or rescinding certain regulations, including restrictions on emissions from the oil and gas sector. In addition, Executive Order
13990 establishes a federal inter-agency working group to recommend methods for agencies to incorporate the “social cost of carbon” into their decision-making. In addition, Executive Order 13990 directs the White House Council on Environmental Quality to rescind draft guidance restricting the review of climate change issues in reviews under NEPA and to update regulations to strengthen climate change reviews. In November 2022, the EPA requested public comment on a technical report on the social cost of greenhouse gases and announced that it was also conducting an external peer review of the report, which estimates a substantially higher social carbon cost than past EPA estimates. On February 9, 2023, the peer review panel was selected to review this technical report.
Relatedly, multiple states have challenged the Biden Administration’s interim values for the social cost of greenhouse gases in the federal courts and these challenges remain pending. Regulation and judicial challenges in these areas are evolving and we cannot predict their ultimate impact, but these issues could have an impact on the Company’s operations and financial condition.
NEPA. NEPA and comparable state laws and regulations require that government agencies review the environmental impacts of proposed projects. On January 9, 2023, the CEQ published interim guidance for federal agencies on the consideration of greenhouse gas (“GHG”) emissions and climate change under NEPA and is seeking public comment through March 10, 2023. The impact on us of these and future developments in NEPA regulation and guidance is not determinable at this time, especially with respect to those aspects of our operations and development projects that may require future federal approvals.
Clean Air Act. The CAA and comparable state laws and regulations restrict the emission of air pollutants from many sources and impose various monitoring and reporting requirements, among other requirements. The Driftwood Project and related pipelines include facilities and operations that are subject to the federal CAA and comparable state and local laws, including requirements to obtain pre-construction permits and operating permits. 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.
In November 2021, the EPA published a proposed rule, which it then supplemented with a November 2022 update, that would create significant new requirements and standards designed to reduce air emissions (including methane and volatile organic compounds) from new and existing oil and gas operations, including oil and gas wells, controllers, pumps, storage vessels, and compressor stations, through measures such as leak detection monitoring and repair and the elimination of flaring except under limited circumstances. The impact of these proposed oil and gas regulations on the Driftwood Project and other related pipelines and any related costs and obligations are not determinable at this time.
On January 6, 2023, the EPA issued pre-publication proposed revisions to the primary (health-based) annual PM2.5 standard from its current level of 12.0 µg/m3 to a maximum within the range of 9.0 to 10.0 µg/m3. The EPA will accept public comment on the proposed revisions for 60 days following the publication of the revisions in the Federal Register. The impact of such revisions on the Driftwood Project and related pipelines cannot be predicted at this time.
In addition, under the Biden Administration, the EPA has released guidance documents intended to assist in the evaluation of environmental justice considerations in many aspects of governmental decision making. Among other things, the guidance emphasizes a focus on advancing environmental justice goals in connection with federal permitting and regulatory programs like the Clean Air Act. The impact of this guidance on us is not determinable at this time.
In December 2009, the EPA published its findings that emissions of carbon dioxide, methane, and other 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.
As discussed above, the Biden Administration has issued Executive Orders with respect to certain governmental actions related to climate change, and the EPA has promulgated, and may promulgate additional, regulations for sources of GHG emissions that could affect the oil and gas sector, and Congress or states may enact new GHG legislation, any of which could impose emission limits on the Driftwood Project or related pipelines or require us to implement additional pollution control technologies, pay fees related to GHG emissions or implement mitigation measures. On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (“IRA”).The IRA imposes a fee of up to $1,500 per metric ton of methane emitted above specified thresholds from onshore petroleum and natural gas production facilities, natural gas processing facilities, natural gas transmission and compression facilities, and onshore petroleum and natural gas gathering and boosting facilities, among other facilities. The fees will apply to methane emissions after January 1, 2024. The scope and effects of any new laws or regulations are difficult to predict, and the impact of such laws or regulations on the Driftwood Project or related pipelines cannot be predicted at this time.
Coastal Zone Management Act. Certain aspects of the Driftwood terminal are 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.
Certain facilities that are part of the Driftwood Project obtained permits for construction and operation in coastal areas pursuant to the requirements of the CZMA.
Clean Water Act. The Driftwood Project and related pipelines 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 United States or waters of the state, including discharges of wastewater and storm water runoff and discharges of dredged or fill material into waters of the United States, 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 the states. Additionally, the siting and construction of the Driftwood terminal and Driftwood pipeline will 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. Although the CWA permits required for construction and operation of the Driftwood terminal and Driftwood pipeline have been obtained, other CWA permits may be required in connection with our projects that are under development and our future projects. The approval timeframe may also be longer than expected and could potentially affect project schedules.
In addition, in recent years, certain CWA regulatory programs, including the Section 404 wetlands permitting program, have been the subject of shifting agency interpretations and legal challenges, including in a case, Sackett v. EPA, currently pending before the Supreme Court of the United States. Most recently, on January 18, 2023, the EPA and USACE published a new rule defining jurisdictional waters under the CWA. This new rule is set to become effective March 30, 2023, but has been challenged in judicial proceedings. Further regulatory changes or judicial decisions in this area could affect the Driftwood terminal and Driftwood pipeline or other related pipelines in ways that cannot be predicted at this time.
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 Driftwood Project incorporates appropriate equipment and operational measures to reduce the potential for spills of oil and establish protocols for responding to spills, but oil spills remain an operational risk that could adversely affect our operations and result in additional costs or fines or penalties.
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.
Wastes from oil and gas activities are currently excluded from certain regulatory programs under RCRA. In response to litigation by environmental groups over the EPA’s alleged failure to periodically review existing RCRA regulations, the EPA and certain environmental groups entered into a consent decree pursuant to which the EPA was required to undertake a review of whether changes to the existing regulations were necessary. In April 2019, the EPA issued a report concluding that such revisions were unnecessary. A loss of the exclusion from RCRA coverage for oil and gas-related wastes, including drilling fluids, produced waters and related wastes in the future, could result in a significant increase in our costs to manage and dispose of waste associated with our production operations.
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, 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, or transported 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 were sent. Our operations involve the use or handling of materials that include or 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 the investigation, management and disposal of soils or dredge spoils containing hazardous substances in connection with our operations.
Oil and natural gas exploration and production, and possibly other activities, have been conducted at some 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. Accordingly, we could incur material costs for remediation required under CERCLA or similar state statutes in the future.
Hydraulic Fracturing. Hydraulic fracturing is commonly used to stimulate the production of crude oil and/or natural gas from dense subsurface rock formations. We plan to use hydraulic fracturing extensively in our natural gas development 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.
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 related to the Driftwood Project.
In May 2014, the EPA issued an advance notice of proposed rulemaking under the Toxic Substances Control Act (“TSCA”) pursuant to which it collected extensive information on the chemicals used in hydraulic fracturing fluid, as well as other health-related data, from chemical manufacturers and processors. If the EPA regulates hydraulic fracturing fluid under TSCA in the future, such regulation may increase the cost of our natural gas development operations and the feedstock for the Driftwood terminal.
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. Certain activities of our Business are subject to the pretreatment standards, which means that we are required to use disposal methods that may require additional permits or cost more to implement than disposal at publicly-owned treatment works.
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 in the United States.” 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 the nature of results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms. If the EPA proposes additional regulations of hydraulic fracturing in the future, it could impose additional emission limits and pollution control technology requirements, which could limit our operations and revenues and potentially increase our costs of gas production or acquisition.
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 have been and 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. Although we have conducted studies and engaged in consultations with agencies in order to avoid harming protected species, inadvertent or incidental harm may occur in connection with the construction or operation of our properties, including the Driftwood Project or related pipelines, which could result in fines or penalties. In addition, if threatened or endangered species are found on any part of our properties, including the sites of the Driftwood Project, related pipelines, or pipeline rights of way, then we may be required to implement avoidance or mitigation measures that could limit our operations or impose additional costs.
Regulation of Natural Gas Operations
Our natural gas operations are subject to a number of additional laws, rules and regulations that require, among other things, permits for the drilling of wells, drilling bonds and reports concerning operations. States, parishes and municipalities in which we operate may regulate, among other things:
•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 the voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells and generally prohibit the venting or flaring of natural gas and require that oil and natural gas be produced in a prorated, equitable system. These laws and regulations may limit the amount of oil and natural gas that we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, most states, and some local authorities, impose a production, ad valorem or severance tax with respect to the production and sale of oil and natural gas and minerals in place within their jurisdictions. 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, Trade Control, and Tax Evasion Laws
We are subject to 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 our employees, directors, officers and agents from authorizing, offering, or providing improper payments or anything else of value to government officials or other covered persons to obtain or retain business or gain an improper business advantage. We face the risk that one of our employees or agents will offer, authorize, or provide something of value that could subject us to liability under the FCPA and other anti-corruption laws. In addition, we cannot predict the nature, scope or effect of future regulatory requirements to which our international operations might be subject or the manner in which existing laws might be administered or interpreted.
We are also subject to other laws and regulations governing our international operations, including regulations administered by the U.S. Department of Commerce’s Bureau of Industry and Security, the U.S. Department of Treasury’s Office of Foreign Assets Control, and various non-U.S. government entities, including applicable export control regulations, economic sanctions on countries and persons, customs requirements, currency exchange regulations, and transfer pricing regulations (collectively, “Trade Control laws”).
We are also subject to new U.K. corporate criminal offenses for failure to prevent the facilitation of tax evasion pursuant to the Criminal Finances Act 2017, which imposes criminal liability on a company where it has failed to prevent the criminal facilitation of tax evasion by a person associated with the company.
We have instituted policies, procedures and ongoing training of employees designed to ensure that we and our employees and agents 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, the 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, the Trade Control laws or the Criminal Finances Act 2017 by the U.S. or foreign authorities could have a material adverse impact on our reputation, business, financial condition and results of operations. U.S. or foreign authorities may also seek to hold us liable for successor liability for anti-corruption violations committed by companies we acquire or in which we invest (for example, by way of acquiring equity interests, participating as a joint venture partner, or acquiring assets).
Competition
We are subject to a high degree of competition in all aspects of our business. See “Item 1A — Risk Factors — Risks Relating to Our Business in General — Competition is intense in the energy industry and some of Tellurian’s competitors have greater financial, technological and other resources.”
Production & Transportation. The natural gas and oil business is highly competitive in the exploration for and acquisition of reserves, the acquisition of natural gas and oil leases, equipment and personnel required to develop and produce reserves, and the gathering, transportation and marketing of natural gas and oil. Our competitors include national oil companies, major integrated natural gas and oil companies, other independent natural gas and oil companies, and participants in other industries supplying energy and fuel to industrial, commercial, and individual consumers, such as operators of pipelines and other midstream facilities. Many of our competitors have longer operating histories, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources than we currently possess.
Liquefaction. The Driftwood terminal will compete with liquefaction facilities worldwide to supply low-cost liquefaction to the market. There are a number of liquefaction facilities worldwide that we compete with for customers. Many
of the companies with which we compete have greater name recognition, larger staffs and substantially greater financial, technical and marketing resources than we do.
LNG Marketing. Tellurian competes with a variety of companies in the global LNG market, including (i) integrated energy companies that market LNG from their own liquefaction facilities, (ii) trading houses and aggregators with LNG supply portfolios, and (iii) liquefaction plant operators that market equity volumes. Many of the companies with which we compete have greater name recognition, larger staffs, greater access to the LNG market and substantially greater financial, technical, and marketing resources than we do.
Title to Properties
With respect to our natural gas producing properties, we believe that we hold good and defensible leasehold title to substantially all of our properties in accordance with standards generally accepted in the industry. A preliminary title examination is conducted at the time the properties are acquired. Our natural gas properties are subject to royalty, overriding royalty, and other outstanding interests. We believe that we hold good title to our other properties, subject to customary burdens, liens, or encumbrances that we do not expect to materially interfere with our use of the properties.
Major Customers
We do not have any major customers.
Facilities
Certain subsidiaries of Tellurian have entered into operating leases for office space in Houston, Texas, Washington, D.C. and London, United Kingdom. The tenors of the leases are five, eight and five years for Houston, Washington, D.C. and London, respectively.
Employees and Human Capital
As of December 31, 2022, Tellurian had 171 full-time employees worldwide. None of them are subject to collective bargaining arrangements. The Company’s workforce is primarily located in Houston, Texas, and we have offices in Louisiana, Washington DC, London and Singapore. Many of our employees are originally from or have extensive experience working in countries other than the United States. This reflects our overall strategy of building a natural gas business that is global in scope.
We plan to build, among other things, an LNG liquefaction facility that we believe is one of the largest energy infrastructure projects currently under development in the United States. Given the inherent challenges involved in the construction of a project of this type, in particular by a company that has limited current operations, our human resources strategy focuses on the recruitment and retention of employees who have already established relevant expertise in the industry. The execution of this strategy has resulted in us assembling what we believe to be a premier management team in the global natural gas and LNG industry. A related aspect of our human resources strategy is that the compensation structure for many of our employees is weighted towards incentive compensation that is designed to reward progress toward the development of our business, including in particular the financing and construction of the Driftwood Project.
Jurisdiction and Year of Formation
The Company is a Delaware corporation originally formed in 1967 and formerly known as Magellan Petroleum Corporation.
Available Information
We file annual, quarterly and current reports, proxy statements and other information with the SEC. Our SEC filings are available free of charge from the SEC’s website at www.sec.gov or from our website at www.tellurianinc.com. We also make available free of charge any of our SEC filings by mail. For a mailed copy of a report, please contact Tellurian Inc., Investor Relations, 1201 Louisiana Street, Suite 3100, Houston, Texas 77002.
ITEM 1A. RISK FACTORS
Our business activities and the value of our securities are subject to significant hazards and risks, including those described below. If any of such events should occur, our business, financial condition, liquidity, and/or results of operations could be materially harmed, and holders and purchasers of our securities could lose part or all of their investments. Our risk factors are grouped into the following categories:
•Risks Relating to Financial Matters;
•Risks Relating to Our Common Stock;
•Risks Relating to Our LNG Business;
•Risks Relating to Our Natural Gas and Oil Operating Activities; and
•Risks Relating to Our Business in General.
Risks Relating to Financial Matters
Tellurian will be required to seek additional equity and/or debt financing in the future to complete the Driftwood Project and to grow its other operations, and may not be able to secure such financing on acceptable terms, or at all.
Tellurian will be unable to generate any significant revenue from the Driftwood Project for multiple years, and expects cash flow from its other lines of business to be modest for an extended period as it focuses on the development and growth of these businesses. Tellurian will, therefore, need substantial amounts of additional financing to execute its business plan and to repay its indebtedness when necessary. There can be no assurance that Tellurian will be able to raise sufficient capital on acceptable terms, or at all. Tellurian’s ability to raise financing, and the terms of that financing, will depend to a significant extent on factors outside of its control such as global market conditions.Interest rates rose significantly in 2022 in response to inflationary pressures in the U.S. and world economies, and rising interest rates generally make financing more difficult to obtain as well as more expensive. If adequate financing is not available on satisfactory terms or 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 project finance transactions and sales of equity and debt securities. We do not know whether, and to what extent, potential sources of financing will find the terms we propose acceptable. In addition, potential sources of financing may conclude that the terms of our commercial agreements for the sale of LNG are not attractive enough to justify an investment.
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. Obtaining financing through additional issuances of common stock or other equity securities would impose fewer restrictions on our future operations but would be dilutive to the interests of existing stockholders.
We have a limited operating history and expect to incur losses for a significant period of time.
We have a limited operating history. 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.
Completion of construction of the Driftwood Project will require Tellurian to incur costs and expenses much greater than those it has incurred to date. The Company also expects to devote substantial amounts of capital to the growth and development of its other operations. Tellurian expects that operating losses will increase substantially in 2023 and thereafter, and expects to continue to generate negative operating cash flows for the next several years.
Tellurian’s exposure to the performance and credit risks of its counterparties may adversely affect its operating results, liquidity and access to financing.
Our operations involve our entering into various construction, purchase and sale, hedging, supply and other transactions with numerous third parties. In such arrangements, we will be exposed to the performance and credit risks of our counterparties, including the risk that one or more counterparties fail to perform their obligations under the applicable agreement. Some of these risks may increase during periods of commodity price volatility. In some cases, we will be dependent on a single counterparty or a small group of counterparties, all of whom may be similarly affected by changes in economic and other conditions. These risks include, but are not limited to, risks related to the construction of the Driftwood terminal discussed below in “ — Risks Relating to Our LNG Business — Tellurian will be dependent on third-party contractors for the successful completion of the Driftwood terminal, and these contractors may be unable to complete the Driftwood terminal.” 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 develop our LNG and natural gas marketing and natural gas operating activities, we may enter into commodity hedging arrangements in an effort to reduce our exposure to fluctuations in price and timing risk. Any hedging arrangements entered into would expose us to the risk of financial loss when (i) the counterparty to the hedging contract defaults on its contractual obligations or (ii) there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices received.
Also, commodity derivative arrangements may limit the benefit we would otherwise receive from a favorable change in the relevant commodity price. In addition, regulations issued by the Commodities Futures Trading Commission, the SEC and other federal agencies establishing regulation of the over-the-counter derivatives market could adversely affect our ability to manage our price risks associated with our LNG and natural gas activity and therefore have a negative impact on our operating results and cash flows.
Changes in tax laws or exposure to additional income tax liabilities could have a material impact on our financial condition, results of operations and liquidity.
Factors that could materially affect our future effective tax rates include but are not limited to:
•changes in the regulatory environment;
•changes in accounting and tax standards or practices;
•changes in U.S., state or foreign tax laws;
•changes in the composition of operating income by tax jurisdiction; and
•our operating results before taxes.
We are also subject to examination by the Internal Revenue Service (the “IRS”) and other tax authorities, including state revenue agencies and other foreign governments. While we regularly assess the likelihood of favorable or unfavorable outcomes resulting from examinations by the IRS and other tax authorities to determine the adequacy of our provision for income taxes, there can be no assurance that the actual outcome resulting from these examinations will not materially adversely affect our financial condition and operating results. Additionally, the IRS and several foreign tax authorities have increasingly focused attention on intercompany transfer pricing with respect to sales of products and services and the use of intangibles. Tax authorities could disagree with our cross-jurisdictional transfer pricing or other matters and assess additional taxes. If we do not prevail in any such disagreements, our profitability may be affected.
Tellurian does not expect to generate sufficient cash to pay dividends until the completion of construction of the Driftwood Project.
Tellurian’s directly and indirectly held assets currently consist primarily of natural gas leaseholds and related upstream development assets, cash held for certain development and operating expenses, applications for permits from regulatory agencies relating to the Driftwood Project and certain real property related to that project. Tellurian’s cash flow, and consequently its ability to distribute earnings, is solely dependent upon the cash flow its subsidiaries receive from the Driftwood Project and its other operations. Tellurian’s ability to complete the project, as discussed elsewhere in this section, is dependent upon its and its subsidiaries’ ability to obtain and maintain 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.
We may be unable to fulfill our obligations under our debt agreements.
We have issued senior notes as described in Note 10, Borrowings, of our Notes to Consolidated Financial Statements included in this report. Our ability to generate cash flows from operations or obtain refinancing capital sufficient to pay interest and principal on our indebtedness will depend on our future operating performance and financial condition and the availability of refinancing debt or equity capital, which will be affected by prevailing commodity prices and economic conditions and financial, business and other factors, many of which are beyond our control. Our inability to generate adequate cash flows from operations could adversely affect our ability to execute our overall business plan, and we could be required to sell assets, reduce our capital expenditures or seek refinancing debt or equity capital to satisfy the requirements of the debt agreements. These alternative measures may be unavailable or inadequate, in which case we could be forced into bankruptcy or liquidation, and may themselves adversely affect our overall business strategy. In addition, the indenture governing our convertible notes
contains covenants, including limitations on our ability to incur additional indebtedness and a minimum cash covenant, that could prevent us from pursuing certain business strategies or opportunities.If we are unable to comply with these covenants, amounts due under the notes could be accelerated.Further, the holder of our convertible notes may redeem up to $166 million of those notes at par, plus accrued and unpaid interest, on each of May 1, 2023 and May 1, 2024.The exercise of this redemption right could materially adversely affect our liquidity.
Pandemics or disease outbreaks, such as the COVID-19 pandemic, may adversely affect our efforts to reach a final investment decision with respect to the Driftwood Project.
Pandemics or disease outbreaks such as the COVID-19 pandemic may have a variety of adverse effects on our business, including by depressing commodity prices and the market value of our securities. Prospects for the development and financing of the Driftwood Project are based in part on factors including global economic conditions that have been, and may continue to be, adversely affected by the COVID-19 pandemic.
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, departures of key personnel, and failures to advance the Driftwood Project on the terms or within the time periods anticipated. 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 trading price of our common stock during 2022 was as low as $1.54 per share and as high as $6.54 per share.
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. Such pledges have resulted, and could result in the future, in large amounts of shares of our stock being sold in the market in a short period and corresponding declines in the trading price of the common stock.
In addition, in the future, we may issue shares of our common stock, or securities convertible into our common stock, in connection with acquisitions of assets or businesses or for other purposes. Such issuances may result in dilution to our existing stockholders and could have an adverse effect on the market value of shares of our common stock, depending on market conditions at the time, the terms of the issuance, and if applicable, the value of the business or assets acquired and our success in exploiting the properties or integrating the businesses we acquire.
Risks Relating to Our LNG Business
Various economic and political factors could negatively affect the development, construction and operation of LNG facilities, including the Driftwood terminal, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Commercial development of an LNG facility takes a number of years, requires substantial capital investment and may be delayed by factors such as:
•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 outside of the United States, 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;
•any renegotiation of EPC agreements that may be required in the event of delays in a final investment decision or other failures to meet specified deadlines; and
•political unrest or local community resistance to the siting of LNG facilities due to safety, environmental or security concerns.
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.
Cost estimates for the Driftwood Project and other projects we may pursue are only approximations of the actual costs of construction. 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 could materially increase construction costs, as could supply chain issues affecting long lead-time items. Our estimate of the cost of construction of the Driftwood terminal is based on the prices set forth in our LSTK EPC agreements with Bechtel and those prices are subject to adjustment by change orders, including for consideration of certain increased costs. 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 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 will depend upon it entering into contracts with third-party customers, the terms of those contracts and the performance of those customers under those contracts.
We have entered into a commercial arrangement with a third-party customer for the sale of LNG from Phase I of the Driftwood Project. Our ability to generate revenue from that contract will depend upon, among other factors, LNG prices and our ability to finance and complete the construction of the 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 additional agreements with customers or based on a variety of factors, including the future price outlook, supply and demand of LNG, natural gas liquefaction capacity, and global regasification capacity. If our efforts to market the proposed Driftwood Project and the LNG it will produce are not successful, Tellurian’s business, results of operations, financial condition and prospects may be materially and adversely affected.
We may not be able to purchase, receive or produce sufficient natural gas to satisfy our delivery obligations under any LNG sale and purchase agreements, which could have an adverse effect on us.
Under LNG sale and purchase agreements with our customers, we may be required to make available to them a specified amount of LNG at specified times. However, we may not be able to acquire or produce sufficient quantities of natural gas or LNG to satisfy those obligations, which may provide affected customers with the right to terminate their LNG sale and purchase agreements. Our failure to purchase, receive or produce sufficient quantities of natural gas or LNG in a timely manner could have an adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
The construction and operation of the Driftwood Project and related pipelines remain subject to ongoing compliance obligations and 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. Such approvals and authorizations are often subject to ongoing conditions imposed by regulatory agencies, and additional approval and permit requirements may be imposed. Tellurian and its affiliates will be
required to obtain and maintain governmental approvals and authorizations to implement its proposed business strategy, which includes the construction and operation of the Driftwood Project. Although all the major permits required for construction and operation of the Driftwood terminal and Driftwood pipeline have been obtained, we must still satisfy various conditions of our FERC permits during the construction process. Additionally, numerous permits and approvals will be required in connection with other assets, including our upstream operations and other related pipelines. Certain environmental groups have opposed our efforts to obtain and maintain the permits necessary to grow our operations pursuant to our strategy.
There is no assurance that Tellurian will obtain and maintain these governmental permits, approvals and authorizations, and failure to obtain and maintain any of these permits, approvals or authorizations could have a material adverse effect on its business, results of operations, financial condition and prospects.
Tellurian will be dependent on third-party contractors for the successful completion of the Driftwood terminal, and these contractors may be unable to complete the Driftwood terminal.
The construction of the Driftwood terminal is expected to take several years, will be confined to a limited geographic area and could be subject to delays, cost overruns, labor disputes and other factors that could adversely affect financial performance or impair Tellurian’s ability to execute its proposed business plan. Timely and cost-effective completion of the Driftwood terminal in compliance with agreed-upon specifications will be highly dependent upon the performance of Bechtel and other third-party contractors pursuant to their agreements. However, Tellurian has not yet entered into definitive agreements with all of the contractors, advisors and consultants necessary for the development and construction of the Driftwood terminal. Tellurian may not be able to successfully enter into such construction contracts on terms or at prices that are acceptable to it.
Further, faulty construction that does not conform to Tellurian’s design and quality standards may have an adverse effect on Tellurian’s business, results of operations, financial condition and prospects. For example, improper equipment installation may lead to a shortened life of Tellurian’s equipment, increased operations and maintenance costs or a reduced availability or production capacity of the affected facility. The ability of Tellurian’s third-party contractors to perform successfully under any agreements to be entered into is dependent on a number of factors, including force majeure events and such contractors’ ability to:
•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, 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 that 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.
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. The risk of disagreements with contractors and other construction issues such as increased costs and delays may be exacerbated by inflation, supply chain disruptions and other market conditions. Tellurian may also face difficulties in commissioning a newly constructed facility. Any significant delays in the development of the Driftwood terminal could materially and adversely affect Tellurian’s business, results of operations, financial condition and prospects. The construction of the Driftwood pipeline or related pipelines will be required for the long-term operations of the Driftwood terminal and will be subject to similar risks.
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 and related pipelines 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:
•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 or related pipelines;
•difficulties in engaging qualified contractors necessary for the construction of the contemplated Driftwood Project or related pipelines;
•shortages of equipment, material or skilled labor;
•natural disasters and catastrophes, such as hurricanes, explosions, fires, floods, industrial accidents, pandemics 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.
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 its activities until the proposed Driftwood terminal is constructed and operational (which could cause further delays). Any delay in completion of the Driftwood Project may also cause a delay in the receipt of revenues projected from the Driftwood Project or cause a loss of one or more customers. As a result, any significant construction delay, whatever the cause, could have a material adverse effect on Tellurian’s business, results of operations, financial condition, liquidity and prospects. Similar risks may affect the construction of other facilities and projects we elect to pursue.
Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect Tellurian’s LNG business and the performance of our customers and could lead to the reduced development of LNG projects worldwide.
Tellurian’s plans and expectations regarding its business and the development of domestic LNG facilities and projects are generally based on assumptions about the future price of natural gas and LNG and the conditions of the global natural gas and LNG markets. Natural gas and LNG prices have been, and are likely to remain in the future, volatile and subject to wide fluctuations that are difficult to predict. Such fluctuations may be caused by various factors, including, but not limited to, one or more of the following:
•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;
•changes in demand for natural gas, including as a result of disruptive events such as the Russian invasion of Ukraine and the COVID-19 pandemic;
•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.
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. The profitability of the LNG SPA we have entered into will depend in part on the relationship between the costs we incur in producing or purchasing natural gas and the then-current index prices when sales occur. An adverse change in that relationship, whether resulting from an increase in our costs, a decline in the index prices or both, could make sales under the agreements less profitable or could require us to sell at a loss. Similarly, part of our business involves the trading of LNG cargos from time to time. LNG trading involves risks, including the risk that commodity price changes will result in us selling cargos at a loss. These risks have increased in recent periods as higher commodity prices have resulted in cargos becoming generally more expensive, therefore increasing our exposure to potential losses.
Technological innovation may render Tellurian’s anticipated competitive advantage or its processes obsolete.
Tellurian’s success will depend on its ability to create and maintain a competitive position in the natural gas liquefaction industry. In particular, although Tellurian plans to construct the Driftwood terminal using proven technologies that it believes provide it with certain advantages, Tellurian does not have any exclusive rights to any of the technologies that it will be utilizing. In addition, the technology Tellurian anticipates using in the Driftwood Project may be rendered obsolete or uneconomical by legal or regulatory requirements, technological advances, more efficient and cost-effective processes or entirely different approaches developed by one or more of its competitors or others, which could materially and adversely affect Tellurian’s business, results of operations, financial condition, liquidity and prospects.
Failure of exported LNG to be a competitive source of energy for international markets could adversely affect our customers and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Operations of the Driftwood Project will be dependent upon our ability to deliver LNG supplies from the U.S., which is primarily dependent upon LNG being a competitive source of energy internationally. The success of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be supplied from North America and delivered to international markets at a lower cost than the cost of alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas may be discovered outside the U.S., which could increase the available supply of natural gas outside the U.S. and could result in natural gas in those markets being available at a lower cost than that of LNG exported to those markets.
Factors which may negatively affect potential demand for LNG from our liquefaction projects are diverse and include, among others:
•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 alternative 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.
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:
•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 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.
Any of these factors could have a material adverse effect on Tellurian’s business, results of operations, financial condition, liquidity and prospects.
We will rely on third-party engineers to estimate the future capacity ratings and performance capabilities of the Driftwood terminal, and these estimates may prove to be inaccurate.
We will rely on third parties for the design and engineering services underlying our estimates of the future capacity ratings and performance capabilities of the Driftwood terminal. Any of our LNG facilities, when constructed, may not have the capacity ratings and performance capabilities that we intend or estimate. Failure of any of our facilities to achieve our intended capacity ratings and performance capabilities could prevent us from achieving the commercial start dates under our current or 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 related pipelines will be subject to a number of environmental and safety laws and regulations that impose significant compliance costs, and existing and future environmental, safety and similar laws and regulations could result in increased compliance costs, liabilities or additional operating restrictions.
We are and will be subject to extensive federal, state and local environmental and safety 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. Failure to comply with these regulations and laws could result in the imposition of administrative, civil and criminal sanctions.
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 and have required 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 the operator of the Driftwood Project and other related assets 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 the investigation, cleanup, monitoring, removal, disposal and other remedial actions with respect to hazardous substances on, in or under properties that Tellurian owns or operates, or
released at a site where materials are disposed of from our operations, 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 the results of our operations. 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 and related assets is subject to the inherent risks associated with LNG, pipeline and upstream operations, including explosions, pollution, leakage or release of toxic substances, fires, hurricanes and other adverse weather conditions, leakage of hydrocarbons, and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or result in damage to or destruction of the proposed Driftwood Project, related pipelines, or upstream assets, or damage to persons and property. In addition, operations at the proposed Driftwood Project, related pipelines, upstream assets, 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.
Hurricanes have damaged coastal and inland areas located in the Gulf Coast area, resulting in disruption and damage to certain LNG terminals located in the area. Future storms and related storm activity and collateral effects, or other disasters such as explosions, fires, floods or accidents, could result in damage to, or interruption of operations at, the Driftwood terminal or related infrastructure, as well as delays or cost increases in the construction and the development of the Driftwood terminal or other facilities. Storms, disasters and accidents could also damage or interrupt the activities of vessels that we or third parties operate in connection with our LNG business. Changes in the global climate may have significant physical effects, such as increased frequency and severity of storms, floods and rising sea levels. If any such effects were to occur, they could have an adverse effect on our coastal operations.
Our LNG business will face other types of risks and liabilities as well. For instance, our LNG marketing activities expose us to possible financial losses, including the risk of losses resulting from adverse changes in the index prices upon which contracts for the purchase and sale of LNG cargos are based. Our LNG marketing activities are also subject to various domestic and international regulatory and foreign currency risks.
Tellurian does not, nor does it intend to, maintain insurance against all of these risks and losses, and many risks are not insurable. Tellurian may not be able to maintain desired or required insurance in the future at rates that it considers reasonable. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on Tellurian’s business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Risks Relating to Our Natural Gas and Oil Operating Activities
Acquisitions of natural gas and oil properties are subject to the uncertainties of evaluating reserves and potential liabilities, including environmental uncertainties.
We expect to continue to pursue acquisitions of natural gas and oil properties from time to time. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include reserves, development potential, future commodity prices, operating costs, title issues, and potential environmental and other liabilities. Such assessments are inexact, and their accuracy is inherently uncertain. In connection with our assessments, we perform due diligence that we believe is generally consistent with industry practices.
However, our due diligence activities are not likely to permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well prior to an acquisition, and our ability to evaluate undeveloped acreage is inherently imprecise. Even when we inspect a well, we may not always discover structural, subsurface,
and environmental problems that may exist or arise. In some cases, our review prior to signing a definitive purchase agreement may be even more limited. In addition, we may acquire acreage without any warranty of title except as to claims made by, through or under the transferor.
When we acquire properties, we will generally have potential exposure to liabilities and costs for environmental and other problems existing on the acquired properties, and these liabilities may exceed our estimates. We may not be entitled to contractual indemnification associated with acquired properties. We may acquire interests in properties on an “as is” basis with limited or no remedies for breaches of representations and warranties.
Therefore, we could incur significant unknown liabilities, including environmental liabilities or losses due to title defects, in connection with acquisitions for which we have limited or no contractual remedies or insurance coverage. In addition, the acquisition of undeveloped acreage is subject to many inherent risks, and we may not be able to realize efficiently, or at all, the assumed or expected economic benefits of acreage that we acquire.
In addition, acquiring additional natural gas and oil properties, or businesses that own or operate such properties, when attractive opportunities arise is a significant component of our strategy, and we may not be able to identify attractive acquisition opportunities. If we do identify an appropriate acquisition candidate, we may be unable to negotiate mutually acceptable terms with the seller, finance the acquisition or obtain the necessary regulatory approvals. It may be difficult to agree on the economic terms of a transaction, as a potential seller may be unwilling to accept a price that we believe to be appropriately reflective of prevailing economic conditions. If we are unable to complete suitable acquisitions, it will be more difficult to pursue our overall strategy.
Natural gas and oil prices fluctuate widely, and lower prices for an extended period of time may have a material adverse effect on the profitability of our natural gas or oil operating activities.
The revenues, operating results and profitability of our natural gas or oil operating 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, such as the $81.1 million impairment charge we incurred in 2020. Conversely, any substantial or extended increase in the price of natural gas would adversely affect the competitiveness of LNG as a source of energy (as discussed above in “ — Risks Relating to Our LNG Business — Failure of exported LNG to be a competitive source of energy for international markets could adversely affect our customers and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects”. Part of our strategy involves adjusting the level of our natural gas development activities based on our judgment as to the most cost-effective manner in which to source natural gas for the Driftwood terminal. In some circumstances, making these adjustments may involve costs. For example, a decrease in our activities may result in the expiration of leases or an increase in costs on a per-unit basis.
Historically, the markets for natural gas and oil have been volatile, and they are likely to continue to be volatile. Wide fluctuations in natural gas or oil prices may result from relatively minor changes in the supply of or demand for natural gas or oil, market uncertainty and other factors that are beyond our control. The volatility of the energy markets makes it extremely difficult to predict future natural gas or oil price movements, and we will be unable to fully hedge our exposure to natural gas or oil prices.
Significant capital expenditures will be required to grow our natural gas or oil operating 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 operating activities through cash on hand and financing transactions that may include public or private equity or debt offerings or borrowings under additional debt agreements. 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 operating 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:
•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.
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 either unproductive or productive but do not produce sufficient commercial quantities to cover drilling, completion, 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 rates 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 based in part on costs at the date of the estimate. Any significant variance from these costs could greatly affect our estimates of reserves. At December 31, 2022, approximately 51% 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 reclassify to probable or possible any PUDs that are not developed within this five-year time frame.
Our natural gas operating 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 operating 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:
•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.
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.
Laws or regulations that could impose more stringent permitting, public disclosure and/or well construction requirements on hydraulic fracturing operations are proposed from time to time at the federal, state and local levels. Regulatory bodies and others from time to time 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 assessments, federal and state legislatures and agencies may seek to further regulate or even ban such activities, as some state and local governments have already done. We cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, our business and operations could be subject to delays, increased operating and compliance costs and process prohibitions. Among other things, this could adversely affect the cost to produce natural gas, either by us or by third-party suppliers, and therefore LNG, and this could adversely affect the competitiveness of LNG relative to other sources of energy.
We expect to drill the locations we acquire over a multi-year period, making them susceptible to uncertainties that could materially alter the occurrence or timing of drilling.
Our management team has identified certain well locations on our natural gas properties. Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these factors, we do not know if the well locations we have identified will ever be drilled or if we will be able to produce natural gas from these or any other potential locations.
The unavailability or high cost of drilling rigs, equipment, supplies, personnel and services could adversely affect our ability to execute our development plans within budgeted amounts and on a timely basis.
The demand for qualified and experienced field and technical personnel to conduct our operations can fluctuate significantly, often in correlation with hydrocarbon prices. The price of services and equipment may increase in the future and availability may decrease.
In addition, it is possible that oil prices could increase without a corresponding increase in natural gas prices, which could lead to increased demand and prices for equipment, facilities and personnel without an increase in the price at which we
sell our natural gas to third parties. This could have an adverse effect on the competitiveness of the LNG produced from the Driftwood terminal. 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 rely on third parties to meet our needs for midstream infrastructure and services. Capital constraints and public opposition to projects could limit the construction of new infrastructure by us and third parties. In addition, increased production from us and other operators could lead to capacity constraints. 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, foreign currency exchange rate fluctuations and corruption risk.
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:
•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;
•compliance with laws and regulations of foreign jurisdictions, and with U.S. laws and regulations related to foreign operations;
•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.
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.
Potential legislative and regulatory actions addressing climate change, public views about climate change and the physical effects of climate change could significantly impact us.
In recent years, various federal and state governments and regional organizations have enacted or proposed new legislation and regulations governing or restricting the emission of GHGs, including GHG emissions from oil and natural gas production equipment and facilities. At the federal level, for example, the EPA has issued regulations that require GHG emissions reporting for the Driftwood Project and related operations and proposed new regulations regarding methane emissions from our operations. Additional legislative and/or regulatory proposals targeting the elimination of or restricting
GHG emissions or otherwise addressing climate change could require us to incur additional operating costs or otherwise impact our financial results. 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 additional federal legislation or regulation of GHG emissions, states and other governmental authorities may impose these requirements either directly or indirectly. For example, many states and other governmental authorities have set specific targets for future GHG reductions or created renewable portfolio standards that require the procurement of certain amounts of renewable energy.
Many 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. Such effects 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 laws 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. In addition, many customers are focusing more on sustainability and the environmental impacts of operations of companies. An inability to respond to potential customer demands with respect to these issues could have an impact on our financial results. Furthermore, some governmental or business entities have set voluntary carbon emissions targets or are otherwise subject to regulatory limits on their carbon emissions.Any of these developments could result in less demand for our products and, in turn, affect our financial results.
For additional information on recent regulatory changes relating to climate change, please refer to Item 1, Governmental Regulations.
A major health and safety incident relating to our business model.could be costly in terms of potential liabilities and reputational damage.
Tellurian is 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 our costs and decrease our 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 Executive Chairman, Vice Chairman, Chief Executive Officer 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 dependsof Tellurian’s business relies heavily on key personnel such as its Executive Chairman, Vice Chairman and Chief Executive Officer. Should such persons be unable to perform their duties on behalf of Tellurian, or should Tellurian be unable to retain or attract other members of management, Tellurian’s business, results of operations, financial condition, liquidity and prospects could be materially impacted.
Additionally, we are dependent upon an available labor pool of skilled employees. We will compete with other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct and operate our facilities and to provide our customers with the highest quality service. A shortage of skilled workers or other general inflationary pressures or changes in applicable laws and regulations could make it more difficult for us to attract and retain qualified personnel and could require an increase in the wage and benefits packages that we offer, or increases in the amounts we are obligated to pay our contractors, thereby increasing our operating costs. Any increase in our operating costs could materially and adversely affect our business, financial condition, operating results, liquidity and prospects.
Competition is intense in the energy industry and some of Tellurian’s competitors have greater financial, technological and other resources.
Tellurian plans to operate in various aspects of the natural gas and oil business and will face intense competition in each area. Depending on the area of operations, competition may come from independent, technology-driven companies, large, established companies and others.
For example, many competing companies have secured access to, or are pursuing the 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 terminal. 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
None.
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 NYSE American under the symbol “TELL.” As of February 7, 2023, there were 563,518,417 million shares outstanding held by 793 record holders of Tellurian’s common stock. The Company does not intend to pay cash dividends on its common stock in the foreseeable future.
Recent Sales of Unregistered Securities
None that occurred during the three months ended December 31, 2022.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
None that occurred during the three months ended December 31, 2022.
Stock Performance Graph
The information contained in this Stock Performance Graph section shall not be deemed to be “soliciting material” or “filed” or incorporated by reference in future filings with the SEC, or subject to the liabilities of Section 18 of the Exchange Act, except to the extent that we specifically incorporate it by reference into a document filed under the Securities Act or the Exchange Act. The following graph compares the cumulative total shareholder return, calculated on a dividend reinvested basis, on $100.00 invested at the closing of the market on December 31, 2017, through and including the market close on December 31, 2022, with the cumulative total return for the same time period of the same amount invested in the Russell 2000 index and a peer group index. The peer group was selected based on a review of publicly available information about these companies and our determination that they met one or more of the following criteria: (i) comparable industries, (ii) similar market capitalization and (iii) similar operational characteristics, capital intensity, business and operating risks. Our peer group index consists of the following companies:
| | | | | |
| Peer group |
| APA Corporation (APA) | NextDecade Corporation (NEXT) |
| Cheniere Energy, Inc. (LNG) | NuStar Energy L.P. (NS) |
| Chesapeake Energy Corporation (CHK) | ONEOK, Inc. (OKE) |
| Continental Resources, Inc. (CLR) | Range Resources Corporation (RRC) |
| Enterprise Products Partners L.P. (EPD) | Southwestern Energy Company (SWN) |
| EQT Corporation (EQT) | Targa Resources Corp. (TRGP) |
| Gibson Energy Inc. (GEI) | The Williams Companies, Inc. (WMB) |
| Kinder Morgan, Inc. (KMI) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Year Ended December 31, | |
| | | | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | |
| Tellurian Inc. | | | | | 100 | | 71 | | 75 | | 13 | | 32 | | 17 | |
| Russell 2000 | | | | | 100 | | 88 | | 109 | | 129 | | 146 | | 115 | |
| Peer group | | | | | 100 | | 78 | | 84 | | 60 | | 92 | | 124 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
ITEM 6. [Reserved]
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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:
•Our Business
•Overview of Significant Events
•Liquidity and Capital Resources
•Capital Development Activities
•Results of Operations
•Commitments and Contingencies
•Summary of Critical Accounting Estimates
•Recent Accounting Standards
Our Business
Tellurian Inc. (“Tellurian,” “we,” “us,” “our,” or the “Company”), a Delaware corporation, is a Houston-based company that is developing and plans to operate a portfolio of natural gas, LNG marketing, and infrastructure assets that includes an LNG terminal facility (the “Driftwood terminal”), an associated pipeline (the “Driftwood pipeline”), other related pipelines, and upstream natural gas assets (collectively referred to as the “Business”). The Driftwood terminal and the Driftwood pipeline are collectively referred to as the “Driftwood Project.” As of December 31, 2022, our upstream natural gas assets consist of 27,689 net acres and interests in 143 producing wells located in the Haynesville Shale trend of northern Louisiana. Our Business may be developed in phases.
As part of our execution strategy, which includes increasing our asset base, we will consider various commercial arrangements with third parties across the natural gas value chain. We are also pursuing activities such as direct sales of LNG to global counterparties, trading of LNG, the acquisition of additional upstream acreage and drilling of new wells on our existing or newly acquired upstream acreage. We remain focused on the financing and construction of the Driftwood Project and related pipelines while managing our upstream assets.
We manage and report our operations in three reportable segments. The Upstream segment is organized and operates to produce, gather, and deliver natural gas and to acquire and develop natural gas assets. The Midstream segment is organized to develop, construct and operate LNG terminals and pipelines. The Marketing & Trading segment is organized and operates to purchase and sell natural gas produced primarily by the Upstream segment, market the Driftwood terminal’s LNG production capacity and trade LNG.
We continue to evaluate the scope and other aspects of our Business in light of the evolving economic environment, dynamics of the global political landscape, needs of potential counterparties and other factors. How we execute our Business will be based on a variety of factors, including the results of our continuing analysis, changing business conditions and market feedback.
Overview of Significant Events
Limited Notice to Proceed
On March 24, 2022, the Company issued a limited notice to proceed to Bechtel Energy Inc., formerly known as Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”), under our LSTK EPC agreement for Phase 1 of the Driftwood terminal dated as of November 10, 2017 (the “Phase 1 EPC Agreement”). The Company commenced construction of Phase 1 of the Driftwood terminal on April 4, 2022.
Senior Secured Convertible Notes due 2025
On June 3, 2022, we issued and sold $500.0 million aggregate principal amount of 6.00% Senior Secured Convertible Notes due May 1, 2025 (the “Convertible Notes”). Net proceeds from the Convertible Notes were approximately $488.7 million after deducting fees and expenses.
Upstream Asset Acquisition
On August 18, 2022, the Company completed the acquisition of certain natural gas assets in the Haynesville Shale basin. The purchase price of $125.0 million was subject to customary adjustments totaling approximately $8.8 million, for an adjusted purchase price of approximately $133.8 million.
Environmental, Social, Governance Practices
During the year ended December 31, 2021, the Company entered into a pledge with the National Forest Foundation on a five-year plan for reforestation and other forest management projects totaling $25.0 million across the United States. In 2022, the Company supported the planting of more than one million trees on 1,441 acres across the United States and bolstered nursery capacity by 1 million seedlings.
Upstream Natural Gas Drilling Activities
During the year ended December 31, 2022, we put in production 13 operated Haynesville wells and participated in four non-operated Haynesville wells that were put in production.
Liquidity and Capital Resources
Capital Resources
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We are currently funding our operations, development activities and general working capital needs through our cash on hand and cash generated from our upstream natural gas sales. Our current capital resources consist of approximately $474.2 million of cash and cash equivalents as of December 31, 2022 on a consolidated basis. We currently maintain an at-the-market equity offering program pursuant to which we may sell our common stock from time to time. As of the date of this filing, we have availability to raise aggregate gross sales proceeds of $500.0 million under this at-the-market equity offering program.
As of December 31, 2022, we had total indebtedness of approximately $557.7 million, of which approximately $166.7 million is subject to redemption at the sole discretion of holders of the Convertible Notes on May 1, 2023. The holders of the Convertible Notes may also redeem up to an additional $166.7 million on May 1, 2024. We also had contractual obligations associated with our finance and operating leases totaling $215.8 million, of which $7.7 million is scheduled to be paid within the next twelve months.
The Company has sufficient cash on hand and available liquidity to satisfy its obligations and fund its working capital needs for at least twelve months following the date of issuance of the consolidated financial statements. The Company has the ability to generate additional proceeds from various potential financing transactions. We remain focused on the financing and construction of the Driftwood Project and related pipelines while managing our upstream assets.
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, |
| | 2022 | | 2021 | | |
| Cash used in operating activities | | $ | (22,534) | | | $ | (61,560) | | | |
| Cash used in investing activities | | (565,571) | | | (57,865) | | | |
| Cash provided by financing activities | | 789,299 | | | 344,962 | | | |
| | | | | | |
| Net increase in cash, cash equivalents and restricted cash | | 201,194 | | | 225,537 | | | |
| Cash, cash equivalents and restricted cash, beginning of the period | | 307,274 | | | 81,737 | | | |
| Cash, cash equivalents and restricted cash, end of the period | | $ | 508,468 | | | $ | 307,274 | | | |
| | | | | | |
| Net working capital | | $ | 276,750 | | | $ | 238,920 | | | |
Cash used in operating activities for the year ended December 31, 2022 decreased by approximately $39.0 million compared to the same period in 2021 due primarily to a decrease in our consolidated Net loss of approximately $49.8 million for the year ended December 31, 2022, compared to a Net loss of approximately $114.7 million in 2021. The decrease in our consolidated Net loss was partially offset by an overall increase in disbursements in the normal course of business.
Cash used in investing activities for the year ended December 31, 2022 increased by approximately $507.7 million compared to the same period in 2021. This increase was primarily due to increased spending on natural gas acquisition and development activities of approximately $344.8 million in the current period, as compared to approximately $32.4 million in the prior period. This increase was also due to the funding of Driftwood Project construction activities of approximately $175.8 million and Driftwood Project land purchases and land improvements of approximately $23.5 million in the current period.
See Note 4, Property, plant and equipment, of our Notes to the Consolidated Financial Statements for additional information about our investing activities.
Cash provided by financing activities increased by approximately $444.3 million for the year ended December 31, 2022, as compared to the same period in 2021. This increase was primarily due to higher net proceeds from borrowing transactions of approximately $436.0 million in the current period as compared to the same period of 2021 and the absence of principal repayments of borrowings of approximately $119.7 million which were completed during the year ended December 31, 2021. The increase was partially offset by an overall decrease in net proceeds from equity issuances of $108.1 million in the current period as compared to the prior period.
See Note 10, Borrowings and Note 12, Stockholders’ Equity, of our Notes to the Consolidated Financial Statements for additional information about our financing activities.
Capital Development Activities
The activities we have proposed will require significant amounts of capital and are subject to completion risks and delays. We have received all regulatory approvals for the construction of Phase 1 of the Driftwood terminal and, as a result, our business success will depend to a significant extent upon our ability to obtain the funding necessary to construct
the Driftwood Projectassets on a commercially viable basis
and to finance the costs of
staffing, operating and expanding our
operations, development activitiescompany during that process. In March 2022, we issued a limited notice to proceed to Bechtel under our Phase 1 EPC Agreement and
general working capital needs until our facilities are fully operational and to implement our LNG marketing strategies. In 2019, we entered into an equity capital contribution agreement and an LNG sale and purchase agreement with Total and onecommenced the construction of
its affiliates, respectively (see “Total Transactions” below), and obtained the most significant permits required for construction and operationPhase 1 of the Driftwood terminal
and Driftwood pipeline. See “Components of Pay and 2019 Compensation Decisions—Components of Tellurian’s Compensation Program—Discretionary Annual Bonus” for further information with respect to 2019 performance highlights.Executive Summary of our Compensation Program
Program Focus
| · | Our executive compensation program links our executives’ pay to the achievement of the Company’s current and long-term strategic projects, particularly the successful financing and construction of the Driftwood terminal and related pipelines. |
Pay Elements
| · | Our executive compensation program is currently comprised of three primary pay elements: (i) annual base salary; (ii) a discretionary annual bonus; and (iii) outstanding long-term incentives granted in previous years, consisting of (a) performance-based restricted stock that vests only if we are able to secure FID by our Board to proceed withWe currently estimate the construction of the Driftwood terminal, (b) time-vested stock options, and (c) a long-term cash incentive program (the “Driftwood Incentive Program”). Awards under the Driftwood Incentive Program are earned in four stages based on the delivery of a notice to proceed with designated construction phases of the Driftwood terminal, with the amount earned for a particular phase paying out in equal installments over the first four anniversaries of the delivery of notice to proceed for such phase, generally contingent upon the executive’s continued employment. We also provide standard employee benefits. |
| · | The majority of our NEOs’ compensation is variable and made up of annual bonus awards and outstanding long-term incentives. |
Setting Compensation
| · | Executive compensation decisions generally are made by our Board based on recommendations from our independent Compensation Committee. |
| · | When making compensation recommendations, the Compensation Committee reviews data from its independent compensation consultant (currently Pearl Meyer & Partners, LLC (“Pearl Meyer”)) and receives input from our CEO and other members of our senior management team as well as from the Chairman of the Board. In addition, the Vice Chairman of the Board regularly serves as a non-voting advisory participant in meetings of the Compensation Committee. |
| · | The Compensation Committee also reviews relevant market compensation data, which includes the compensation paid by a peer group of companies in our industry sectors that we compete against for executive talent. We strive to set base salaries at the 50th percentile of market, annual compensation opportunities (i.e., base salary and annual incentives) at the 75th percentile of market, and total compensation opportunities (i.e., base salary, annual incentives and long-term incentives issued or amortized in the relevant year) at up to the 90th percentile of market. |
| · | We view compensation cumulatively over the course of multiple years. Accordingly, we may take into account outstanding compensation opportunities provided in previous years in making decisions for the current year. |
Key 2019 Compensation Actions
| · | We did not make any material changes to the components or structure of our executive compensation program in 2019. |
| · | We adjusted 2019 base salaries for our NEOs for cost of living increases and, in the case of Mr. Lafargue, to better align his base compensation with that of our peer group. |
| · | We increased our CEO’s target and stretch bonus percentages from 100% and 150%, respectively, of her base salary to 150% and 225%, respectively, of her base salary in order to provide her with an annual bonus opportunity that is more competitive with market. We also lowered our former CFO’s target and stretch bonus percentages from 150% and 200%, respectively, of his base salary to 100% and 150%, respectively, of his base salary in order to better align his annual bonus incentive award with that of the remainder of the senior leadership team. |
| · | We did not award discretionary annual bonuses to our NEOs other than Mr. Lafargue for 2019, as we did not achieve FID in 2019. In recognition of Mr. Lafargue’s strong individual efforts throughout 2019 and in order to align his compensation structure with his current non-NEO position as Senior Vice President of LNG Marketing, we awarded Mr. Lafargue a 2019 discretionary bonus that was paid in the form of restricted stock units. The restricted stock units vest in twelve substantially equal monthly installments beginning on June 1, 2020. |
| · | Consistent with our multi-year approach to setting compensation, we did not grant any long-term incentive awards to our NEOs in 2019 as we believe that the long-term incentive awards made to our NEOs in prior years already properly motivate and reward our NEOs’ performance and incentivize the completion of our long-term strategic projects. |
Compensation Best Practices
| · | We seek to incorporate and adhere to compensation best practices in our executive compensation program. Please see the chart under the heading “Our Executive Compensation Philosophy and Practices—Our Executive Compensation Practices” for details. |
Our Executive Compensation Philosophy and Practices
Objectives and Philosophy
The objectives of our executive compensation program are to attract the top executive talent in our competitive, growing industry and to motivate such individuals to execute on the Company’s business strategy and to remain with the Company long-term.
With those objectives in mind, our executive compensation philosophy is as follows:
| · | Our executives’ pay should be linked to the achievement of current and long-term Company strategic projects. Our business strategy is dependent on the successful financing and construction of the Driftwood terminal and Pipeline Network and the acquisition of complementary upstream assets. Accordingly, our NEOs’ compensation is generally tied to the completion of those projects. For example, the outstanding restricted stock awards held by our NEOs generally vest solely upon reaching FID (or anniversaries thereof). The awards under our Driftwood Incentive Program are earned in tranches based on the delivery of a notice to proceed with designated construction phases of the Driftwood terminal. Furthermore, the metrics in our discretionary annual bonus program are weighted toward short-term goals that significantly advance our ability to reach FID, construct the Driftwood terminal, progress the Pipeline Network and acquire upstream assets. |
| · | Compensation should be market competitive. We compete with our peers and other companies in our industry sectors for executive-level talent. We, therefore, benchmark our executive compensation program against a group of publicly traded peers and other companies in our industry sectors using compensation surveys and relevant industry data. Base salaries of our NEOs are targeted at the median, or the 50th percentile, of the relevant benchmarked data (“market”). Annual compensation opportunities (base salary and annual bonus) are targeted at the 75th percentile of market. Total compensation opportunities (base salary, annual bonus and long-term incentives) are targeted at the 90th percentile of market when warranted for exceptional Company performance and individual achievement. In addition, as described below, we have implemented a number of executive compensation best practices. |
| · | Compensation should support the stability of our executive team for the long-term. Our business strategy requires a long-term focus, with the completion of the various phases of the Driftwood terminal and Pipeline Network scheduled to stretch into the early to mid-2020s, and with the full deployment of our capabilities thereafter expected to take several years. We want executives who are similarly focused on the long-term. With the complexity of our business and the extended timelines for completion of our critical projects, the departure of top executive talent and the related loss of institutional knowledge would be harmful to our business. We, therefore, implemented the Driftwood Incentive Program to provide for incentives after FID and designed that program to provide for delayed payouts that are generally contingent upon each executive remaining employed with us for several years following commencement of the various phases of the Driftwood terminal. We also have three-year vesting schedules on our stock option grants. |
| · | Compensation should align the interests of our executives with those of our stockholders. Although we expect that achievement of our business strategy will drive stock price performance, we believe that our executive team should think like and be motivated as owners so that their interests are aligned with those of our stockholders. We have, therefore, structured their long-term incentives so that a portion consists of restricted shares of Tellurian stock (which vest generally upon FID or other milestones), and another portion consists of stock options that have value to the executive only if our stock price increases. We have also included stock performance targets in our CEO’s annual bonus metrics. |
Compensation Mix
Our compensation philosophy is reflected in the proportion of our NEOs’ compensation that is variable as compared to the overall compensation package awarded to our NEOs. The charts below show the targeted fixed and variable components applicable to our NEOs for 2019 as a percentage of their target total direct compensation, as well as the fixed and variable components to the named executive officers of our peers and other companies in our industry sectors as a percentage of their total direct compensation for 2019, based on data provided by Pearl Meyer. These charts are not a substitute for the “Summary Compensation Table,” which includes amounts in addition to target total direct compensation. For 2019, Ms. Gentle’s target compensation was 88% variable and linked to Company performance, consistent with that of chief executive officers of our peers and other companies in our industry sectors, and still below the market median of target total compensation for chief executive officers. For Messrs. Teague, Lafargue and Belhumeur, approximately 85% of their target compensation was variable and linked to Company performance, as compared to approximately 80%, 45%, and 77% of target total compensation being variable and linked to company performance for chief operating officers, chief financial officers and general counsels, respectively, among our peers and other companies in our industry sectors. In addition, for Mr. Sharafeldin, approximately 72% of his target compensation was variable and linked to Company performance, as compared to approximately 56% of target total compensation being variable and linked to company performance for chief accounting officers among our peers and other companies in our industry sectors.
| * | We did not make any new long-term incentive awards in 2019. However, for purposes of determining total compensation opportunities, we amortize awards under the Driftwood Incentive Program over eight years from the date of grant. The portion of such awards amortized in 2019 is, therefore, included in the charts above as our NEOs’ 2019 long-term incentive. |
Our Executive Compensation Practices
Our executive compensation program reflects a number of best pay practices, including the following:
What Tellurian does
| | What Tellurian does not do
|
| | |
·Pay-for-performance compensation structure (a significant portion of NEO pay is variable and tied to individual performance and the achievement of major corporate milestones). | | ·No gross-ups for penalty taxes or interest that may be imposed under the IRS Code. |
·Annual review of market compensation in setting executive compensation. | | ·No guaranteed bonuses. |
·Prohibit hedging transactions involving company stock. | | ·No automatic base salary increases. |
·At-will employment (including our former CFO, whose three-year employment agreement expired on February 10, 2020). | | ·No fixed-term employment agreements (including our former CFO, whose three-year employment agreement expired on February 10, 2020). |
·Retain services of an independent compensation consultant. | | ·No defined benefit retirement plan or supplemental executive retirement plan. |
·No perquisites. | | ·No contractual severance arrangements with NEOs and no executive severance plans or policies. |
·Maintain discretion to pay all or a portion of annual incentives in the form of shares. | | ·No repricing, cancellation or exchange of option awards. |
Administration of Executive Compensation Programs and Methodology
The Role of the Compensation Committee
Our Compensation Committee sets our compensation philosophy and objectives and designs our executive compensation programs to support our strategic business objectives. The Compensation Committee is comprised entirely of independent directors who are appointed by the Board and meets at least annually with the CEO and any other corporate officers that the Compensation Committee deems appropriate. From time to time, the Compensation Committee also consults with the Chairman and Vice Chairman of the Board regarding executive and director compensation matters. The Compensation Committee meets in executive session on an as-needed basis.
The Compensation Committee is responsible for the following:
| · | Reviewing and making recommendations to the Board regarding the compensation of the CEO and all other executive officers of Tellurian. |
| · | Reviewing and making recommendations to the Board, on an annual basis, regarding the corporate goals and objectives relevant to the compensation of the CEO and other executive officers, including annual and long-term performance goals and objectives. |
| · | Considering information and reports with respect to whether our compensation programs encourage unnecessary or excessive risk, and reporting concerns to the Board. |
| · | Designing the equity and other incentive compensation plans, policies and programs for the benefit of Tellurian’s directors, executive officers, officers, employees and consultants and recommending that the Board adopt the same. |
| · | Overseeing and administering equity and other incentive compensation plans, policies and programs in accordance with their terms. |
| · | Reviewing the form and amount of non-employee director compensation at least annually and making recommendations with respect thereto to the Board for its approval. |
| · | Assessing the performance criteria and compensation levels of key executives. |
| · | Reviewing, on a quarterly basis, progress towards the achievement of corporate performance goals and other considerations relevant to the determination of our NEOs’ annual discretionary bonuses and making a final recommendation for the Board’s approval. |
The Role of Management
The Compensation Committee, along with each of the independent directors, is authorized by the Board to obtain information from and work directly with any employee in fulfilling its responsibilities. The Compensation Committee receives from the CEO compensation recommendations and evaluations of the executive group (including with respect to the annual bonus award pool size and individual bonus awards). The CEO meets with the Compensation Committee at least annually as part of the Compensation Committee’s annual discussion and review of the performance criteria and compensation levels of the other key executives. However, the CEO is not, and may not be, present during any voting or deliberations on her compensation.
Management also plays a role in Tellurian’s annual bonus program. Management will review the achievement of corporate goals to date and make a recommendation to the Compensation Committee regarding the annual bonus pool to award employees outside of the executive group and individual bonus awards to employees outside of senior management. The Compensation Committee takes management’s recommendation into account but ultimately has the sole discretion to determine or recommend to the Board for its determination the amount and form (i.e., cash, equity or a mix thereof) of annual bonus awards to the CEO and other executive officers and other employees and service providers outside of senior management.
Our Senior Vice President and Chief Human Resources Officer prepares materials for the CEO and the Compensation Committee for the exercise of their distinct, but interrelated, compensation responsibilities.
The Role of the Independent Compensation Consultant
The Compensation Committee has retained Pearl Meyer as its independent compensation consultant. In 2019, Pearl Meyer provided the Compensation Committee with advice and information regarding current executive compensation practices, including market trends and reviews, and benchmarking of our executive compensation against the market. The Compensation Committee utilizes the benchmarking data provided by Pearl Meyer in making its compensation recommendations to the Board. Representatives of Pearl Meyer are invited to select Compensation Committee meetings to present their benchmarking data and to assist the Compensation Committee with its executive compensation decisions. Pearl Meyer also conducts an annual assessment of issues that may or could be associated with or indicative of excessive compensation-related risk-taking and summarizes its findings for the Compensation Committee’s review. In its compensation-related risk assessments in each of 2017, 2018, and 2019, Pearl Meyer identified no programs or practices that indicated the presence of a material compensation-related risk.
Review of Executive Officer Compensation
Generally
Our review of executive officer compensation encompasses both the structure of our executive compensation program and the targeted amount of compensation. The Compensation Committee considers multiple sources of internal and external data to reach final determinations in order to recommend actions to the Board, including the recommendations of the CEO. Comparative compensation information is one of several analytical tools that we use in setting executive compensation, and the Compensation Committee utilizes its judgment in determining the nature and extent of its use of comparative companies. With the assistance of Pearl Meyer, the Compensation Committee reviews the executive compensation programs in effect at our peer group companies and other companies in our industry sectors. Market and peer group compensation data is one factor among many that the Compensation Committee considers in reviewing executive compensation and is critical in ensuring that Tellurian remains competitive among the companies against which it is competing for talent.
In its analysis and in making decisions, the Compensation Committee may consider factors such as the nature of the officer’s duties and responsibilities as compared to the corresponding position used in the benchmarking data, the experience and value the executive brings to the role, the executive’s performance results, the success demonstrated in meeting strategic and other business objectives, the relationship of compensation earned compared to Company performance, previous compensation awarded to the executive that remains outstanding, and the impact on the internal equity of our pay structure within the Company.
Each year, the Compensation Committee reviews individualized, position-specific compensation benchmarking studies provided by Pearl Meyer, which help the Compensation Committee make recommendations to the Board for the upcoming fiscal year. In the first quarter of each year, the Compensation Committee makes recommendations to the Board regarding base salaries for the upcoming fiscal year and discretionary annual incentive bonus awards for the most recent fiscal year.
The Compensation Committee recommends to the Board, and ultimately the Board sets, goals applicable to the discretionary annual incentive bonuses for the year. The Compensation Committee, together with the CEO, reviews the year-to-date progress on the corporate goal achievement each quarter. Following completion of the year, the Compensation Committee will review the discretionary annual incentive bonus payouts for the NEOs recommended by the CEO and will present them to the Board for approval in the first quarter of that year.
Compensation Peer Group
As noted above, we use peer group companies, along with other companies in our industry sectors, to benchmark our compensation. Our peer group consists of publicly traded companies in (i) the oil and gas storage and transportation sector, (ii) the oil and gas exploration and production sector and (iii) the utilities sector. We have selected companies in each of these sectors as part of our peer group because our business model makes it such that we perform functions performed by or related to companies in each of those sectors. In constructing the peer group, we also considered peers of peers and other peers identified by management as competitors for business or talent, and took into account workforce and business operations footprint in determining whether or not to include companies in the peer group.
With the assistance of Pearl Meyer, our Compensation Committee reviews the composition of the peer group annually so that the included companies remain relevant for comparative purposes. The Compensation Committee, with the assistance of Pearl Meyer, reviewed the peer group in September 2019 and made certain changes to the composition of the peer group to reduce the number of limited partnerships in the peer group, remove companies with the lowest stock price correlation and add two additional LNG companies. The revised peer group will be used for purposes of determining compensation for 2020.
Tellurian’s peer groups for purposes of determining compensation for 2019 and 2020 are listed below:
Sector | Peer | 2019 | 2020 |
| | | |
Oil and Gas Storage and Transportation Companies | | Buckeye Partners, L.P. | ü | |
| Cheniere Energy, Inc. | ü | ü |
| Enable Midstream Partners, LP | ü | |
| Enterprise Products Partners L.P. | ü | ü |
| Gibson Energy Inc. | ü | ü |
| Kinder Morgan, Inc. | | ü |
| Magellan Midstream Partners, L.P. | ü | |
| NextDecade Corporation | | ü |
| NuStar Energy L.P. | ü | ü |
| ONEOK, Inc. | ü | ü |
| Summit Midstream Partners, LP | ü | |
| The Williams Companies, Inc. | ü | ü |
| | | | | |
Oil and Gas Exploration and Production Companies | | Anadarko Petroleum Corporation | ü | ü |
| EQT Corporation | ü | ü |
| Noble Energy, Inc. | ü | ü |
| Range Resources Corporation | ü | ü |
| Southwestern Energy Company | ü | ü |
| WPX Energy, Inc. | ü | ü |
| | | | | |
 Utilities | | The AES Corporation | ü | ü |
| CMS Energy Corporation | ü | |
| Dominion Energy, Inc. | ü | ü |
| NiSource Inc. | ü | |
| PPL Corporation | ü | ü |
| Sempra Energy | ü | ü |
| | | | | |
| | | Total | 22 | 18 |
| | | | | | | |
Risk Oversight
Consistent with the compensation-related risk assessment made by Pearl Meyer, we have determined that any risks arising from our compensation programs and policies are not reasonably likely to have a material adverse effect on the Company. Our compensation programs and policies mitigate risk by combining performance-based, long-term compensation elements with payouts that are highly correlated to the achievement of our strategic business objectives. The combination of performance measures for the annual bonus awards and long-term incentive compensation program encourages executives to maintain both a short and a long-term view with respect to Company performance. We maintain an insider trading policy that prohibits directors, officers and employees of the Company from hedging or engaging in derivative transactions involving shares of Tellurian stock.
Components of Pay and 2019 Compensation Decisions
Components of Tellurian’s Compensation Program
Our executive compensation program consists of the following pay elements:
Compensation Element
| Compensation Type
| Form of Compensation
| Purpose
|
Base salary | Fixed | ·Cash | ·Provide competitive cash compensation based on position and experience |
Annual discretionary bonus awards | Variable | · Annual discretionary bonus paid in cash, common stock, restricted stock units, or a combination thereof | ·Motivate and reward the achievement of annual corporate goals and strategic milestones over the short term
·Payment in stock preserves cash and aligns the long-term interests of employees and stockholders by promoting stock ownership
|
Long-term incentive awards | Variable | ·Performance-based restricted shares and/or restricted stock units
·Stock options
·Performance-based cash awards under the Driftwood Incentive Program
| ·Motivate and reward accomplishment of company milestones and creation of long-term stockholder value
·Align the long-term interests of employees and stockholders
|
Employee benefits | Fixed | ·Health and welfare plans
·Retirement plan
| ·Provide industry-standard employee benefits necessary to attract and retain talent
·Allow executives and other employees to defer compensation on a tax-advantaged basis through our 401(k) plan with Company match
|
Base Salary
Consistent with our executive compensation philosophy, base salaries for the NEOs are targeted at the 50th percentile of market. The Compensation Committee reviews our NEOs’ base salaries annually.
In 2019, we provided each of our NEOs (other than Mr. Lafargue) with a 3% cost of living increase to his or her base salary, which is intended to maintain compensation levels at approximately the median of market (with the exception of Ms. Gentle, who remains positioned at around the 29th percentile of market, and Mr. Sharafeldin, who remains positioned above the 90th percentile of market). Mr. Lafargue’s base salary was increased by 17.7% in order to bring his base salary up to the median of market. The adjustment to Mr. Lafargue’s base salary was also accompanied by a reduction to his target and stretch bonus levels, which are now in line with those of similarly situated members of our senior management team.
Effective as of February 17, 2019, our NEOs’ base salaries were as follows:
| Name | | Prior Base Salary
(through 2/16/19) | | | 2019 Base Salary (eff. 2/17/19) | | | | |
| Meg A. Gentle | | $ | 700,000 | | | $ | 721,000 | | | | 3.0 | % |
| R. Keith Teague | | $ | 500,000 | | | $ | 515,000 | | | | 3.0 | % |
| Antoine J. Lafargue | | $ | 350,000 | | | $ | 412,000 | | | | 17.7 | % |
| Daniel A. Belhumeur | | $ | 400,000 | | | $ | 412,000 | | | | 3.0 | % |
| Khaled A. Sharafeldin | | $ | 350,000 | | | $ | 360,500 | | | | 3.0 | % |
Discretionary Annual Bonus
Our executive officers are eligible to earn a discretionary annual incentive bonus for each fiscal year. Annual bonus awards, if any, are determined in relation to pre-established target and stretch amounts established for each NEO and are based on a holistic review of corporate and individual performance for the year. Although the Compensation Committee and the Board establish corporate goals for each year, there is no bonus formula or weighting of those goals, and actual bonus determinations may take into account a number of other factors, including Company and individual achievements during the year that are not covered by the pre-established goals. The Compensation Committee reviews corporate performance throughout the year (generally on a quarterly basis) and receives input from our CEO and management team before making a final assessment and bonus recommendation to the Board in the first quarter of the year following the year to which such annual bonus relates. Annual bonuses may be paid in cash and/or stock or other equity awards as the Board may determine in its discretion. In the first quarter of each of 2018 and 2019, annual discretionary bonuses for performance with respect to each of 2017 and 2018, respectively, were awarded to our NEOs entirely in the form of shares of Tellurian common stock.
2019 Annual Bonus Targets
For the 2019 annual bonus awards, target and stretch bonus amounts were set by the Compensation Committee as a percentage of each NEO’s base salary. For 2019, we increased Ms. Gentle’s target and stretch bonus percentages from 100% and 150%, respectively, of her base salary to 150% and 225%, respectively, of her base salary in order to provide her with an annual bonus opportunity that is more competitive with market. In addition, we lowered Mr. Lafargue’s target and stretch bonus percentages from 150% and 200%, respectively, of his base salary to 100% and 150%, respectively, of his base salary in order to better align his annual bonus incentive award with that of the remainder of the senior leadership team.
The target annual bonus opportunities for the NEOs for 2019 were as follows:
| NEO | | Target Bonus
(As a Percentage of
Base Salary) | | | Stretch Bonus
(As a Percentage of
Base Salary) | |
| Meg A. Gentle | | | 150 | % | | | 225 | % |
| R. Keith Teague | | | 100 | % | | | 150 | % |
| Antoine J. Lafargue | | | 100 | % | | | 150 | % |
| Daniel A. Belhumeur | | | 100 | % | | | 150 | % |
| Khaled A. Sharafeldin | | | 100 | % | | | 150 | % |
2019 Company Performance Goals
The Company performance goals established by the Compensation Committee and the Board for fiscal year 2019 reflect our overall business strategy of developing a global natural gas business through the development of the Driftwood Project as well as related pipelines to be approximately $25.0 billion, including owners’ costs, transaction costs and contingencies but excluding interest costs incurred during construction and other financing costs. The proposed Driftwood terminal will have a liquefaction capacity of up to approximately 27.6 Mtpa and will be situated on approximately 1,200 acres in Calcasieu Parish, Louisiana. The proposed Driftwood terminal will include up to 20 liquefaction Trains, three full containment LNG storage tanks and three marine berths.
Our strategy involves acquiring additional natural gas properties, including properties in the achievementHaynesville shale basin. We intend to pursue potential acquisitions of such assets, or public or private companies that own such assets. We expect to use stock, cash on hand, or cash raised in financing transactions to complete an acquisition of this type.
We anticipate funding our more immediate liquidity requirements for the construction of the Driftwood terminal, natural gas activities, and general and administrative expenses through the use of cash on hand, proceeds from operations, and proceeds from completed and future issuances of securities by us. Investments in the construction of the Driftwood terminal and natural gas development are and will continue to be significant, but the size of those investments will depend on, among other important milestones.things, commodity prices, Driftwood Project financing developments and other liquidity considerations, and our continuing analysis of strategic risks and opportunities. Consistent with our overall financing strategy, the Company has considered, and in some cases discussed with investors, various potential financing transactions, including issuances of debt, equity and equity-linked securities or similar transactions, to support its capital requirements. The Company will continue to evaluate its cash needs and business outlook, and it may execute one or more transactions of this type in the future.
Results of Operations
The following table summarizes costs and expenses for the periods presented (in thousands):
| | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2022 | | 2021 | | 2020 | | |
| Natural gas sales | | $ | 270,975 | | | $51,499 | | $30,441 | | |
| LNG sales | | 120,951 | | | 19,776 | | | 6,993 | | | |
| Total revenue | | 391,926 | | | 71,275 | | | 37,434 | | | |
| Operating expenses | | 37,886 | | | 11,693 | | | 10,230 | | | |
| LNG cost of sales | | 131,663 | | | 24,745 | | | 6,993 | | | |
| Total cost of sales | | 169,549 | | | 36,438 | | | 17,223 | | | |
| Development expenses | | 68,782 | | | 50,186 | | | 27,492 | | | |
| Depreciation, depletion and amortization | | 44,357 | | | 11,481 | | | 17,228 | | | |
| General and administrative expenses | | 126,386 | | | 85,903 | | | 47,349 | | | |
| Impairment charge and loss on transfer of assets | | — | | | — | | | 81,065 | | | |
| Severance and reorganization charges | | — | | | — | | | 6,359 | | | |
| Related party charges | | 625 | | | — | | | 7,357 | | | |
| Loss from operations | | (17,773) | | | (112,733) | | | (166,639) | | | |
| Interest expense, net | | (13,860) | | | (9,378) | | | (43,445) | | | |
| Gain on extinguishment of debt, net | | — | | | 1,422 | | | — | | | |
| Other (loss) income, net | | (18,177) | | | 5,951 | | | (612) | | | |
| Income tax benefit (provision) | | — | | | — | | | — | | | |
| Net loss | | $ | (49,810) | | | $ | (114,738) | | | $ | (210,696) | | | |
The most significant changes affecting our results of operations for the year ended December 31, 2022 compared to 2021, on a consolidated basis and by segment, are the following:
Upstream
•Increase of approximately $219.5 million in Natural gas sales as a result of higher realized natural gas prices and production volumes attributable to the acquisition of proved natural gas properties and newly drilled and completed wells during 2022.
•Increase of approximately $26.2 million in Operating expenses primarily as a result of higher production volumes attributable to the acquisition of proved natural gas properties and newly drilled and completed wells during 2022.
•Increase of approximately $32.9 million in DD&A is primarily attributable to a higher net book value utilized in the calculation of DD&A due to the acquisition of proved natural gas assets, increased capital expenditures and higher production volumes during the current period.
Marketing & Trading
•Increase of approximately $101.2 million and approximately $106.9 million in LNG sales and LNG cost of sales, respectively, primarily as a result of increased realized sales and purchase prices of an LNG cargo sold during the first quarter of 2022, as compared to the realized price of an LNG cargo sold during the second quarter of 2021.
•Increase of approximately $24.1 million in Other (loss) income, net primarily attributable to approximately $27.2 million of realized losses on the settlement of natural gas financial instruments, which was partially offset by a $10.5 million unrealized gain on natural gas financial instruments due to changes in the fair value of the Company’s derivative instruments during the current period as compared to the same period in 2021. The net loss on natural gas financial instruments in the current period was partially offset by approximately $3.5 million of realized gain on the settlements of LNG financial instruments.
Midstream
•Increase of approximately $18.6 million in Development expenses primarily attributable to a one-time donation of $6.8 million of land and roads for public use in the state of Louisiana, an approximately $3.1 million increase in technical and engineering services associated with the Driftwood Project and pipeline development activities, and
an approximately $8.7 million increase in other development expenses associated with the Driftwood Project and related pipelines.
Consolidated
•Increase of approximately $40.5 million in General and administrative expenses primarily attributable to a $14.6 million increase in professional services, a $9.0 million increase in donations to a university to advance global energy research and an increase of $16.9 million in other expenses in the normal course of business.
•Increase of approximately $4.5 million in Interest expense, net due to increased interest charges as a result of the Company’s increase in borrowing obligations during 2022 as compared to 2021. The increase in Interest expense, net was partially offset by approximately $5.7 million of capitalized interest during 2022. For further information regarding the Company’s outstanding borrowing obligations, see Note 10, Borrowings, of our Notes to the Consolidated Financial Statements.
As a result of the foregoing, our consolidated Net loss was approximately $49.8 million for the year ended December 31, 2022, compared to a Net loss of approximately $114.7 million in 2021.
The most significant changes affecting our results of operations for the year ended December 31, 2021 compared to 2020, on a consolidated basis and by segment, are the following:
Upstream
•Increase of approximately $21.1 million and approximately $1.5 million in Natural gas sales and Operating expenses, respectively, attributable to increased realized natural gas prices, partially offset by decreased production volumes, as compared to 2020.
•Absence of proved natural gas Impairment charges of approximately $81.1 million that were incurred during 2020.
•Decrease of approximately $5.7 million in DD&A expenses due to utilizing a lower net book value in the calculation of DD&A as a result of the Impairment charge that we recognized in the prior year.
Marketing & Trading
•Increase of approximately $12.8 million and approximately $17.8 million in LNG sales and LNG cost of sales, respectively, as a result of increased prices of an LNG cargo sold during the second quarter of 2021, as compared to an LNG cargo sold in the third quarter of 2020.
Midstream
•An increase of approximately $22.7 million in Development expenses primarily attributable to an $18.1 million increase in compensation expenses and a $4.6 million increase in professional services, engineering services and other development expenses associated with the Driftwood Project.
Consolidated
•Absence of Severance and reorganization charges, and Related party charges of approximately $6.4 million and $7.4 million, respectively, that were incurred during 2020.
•Decrease of approximately $34.1 million in Interest expense due to the decline in interest charges as a result of the repayment of our borrowing obligations that were outstanding at the end of 2020. For further information regarding the repayment of our borrowing obligations, see Note 10, Borrowings, of our Notes to the Consolidated Financial Statements.
•Increase of approximately $38.6 million in General and administrative expenses primarily attributable to a $32.2 million increase in compensation expenses and a $6.4 million increase in professional services.
•Increase of approximately $6.6 million in Other income (loss), net primarily attributable to an approximately $8.7 million unrealized gain on natural gas financial instruments due to changes in the fair value of the Company’s derivative instruments during the current period. The increase was partially offset by an approximately $2.5 million realized loss on the settlements of unvested warrants during the current period.
As a result of the foregoing, our consolidated Net loss was approximately $114.7 million for the year ended December 31, 2021, compared to a Net loss of approximately $210.7 million in 2020.
Commitments and Contingencies
The information set forth in Note 11, Commitments and Contingencies, to the accompanying Consolidated Financial Statements included in Part II, Item 8 of this Form 10-K is incorporated herein by reference.
Summary of Critical Accounting Estimates
Our accounting policies are more fully described in Note 2, Summary of Significant Accounting Policies, of our Notes to Consolidated Financial Statements included in this report. As disclosed in Note 2, 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 considered the following to be our most critical accounting estimates that involve significant judgment:
Valuation of Long-Lived Assets
When there are indicators that our proved natural gas properties carrying value may not be recoverable, we compare expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the asset. If the expected undiscounted future cash flows, based on our estimates of (and assumptions regarding) future natural gas prices, operating costs, development expenditures, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally calculated using the income approach in accordance with GAAP. Estimates of undiscounted future cash flows require significant judgment, and the assumptions used in preparing such estimates are inherently uncertain. The impairment review includes cash flows from proved developed and undeveloped reserves, including any development expenditures necessary to achieve that production. Additionally, when probable and possible reserves exist, an appropriate risk-adjusted amount of these reserves may be included in the impairment calculation. In addition, such assumptions and estimates are reasonably likely to change in the future.
Proved reserves are the estimated quantities of natural gas and condensate that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, because we use the units-of-production method to deplete our natural gas properties, the quantity of reserves could significantly impact our DD&A expense. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. Finally, these reserves are the basis for our supplemental natural gas disclosures. See Item 1 and 2 — Our Business and Propertiesfor additional information on our estimate of proved reserves.
Share-Based Compensation
Share-based compensation transactions are measured based on the grant-date estimated fair value. For awards containing only service conditions or performance conditions deemed probable of occurring, the fair value is recognized as expense over the requisite service period using the straight-line method. We recognize compensation cost for awards with performance conditions if and when we conclude that it is probable that the performance condition will be achieved. For awards where the performance or market condition is not considered probable, compensation cost is not recognized until the performance or market condition becomes probable. We reassess the probability of vesting at each reporting period for awards with performance conditions and adjust compensation cost based on our probability assessment. We recognize forfeitures as they occur.
Recent Accounting Standards
We do not believe that any recently issued, but not yet effective, accounting standards, if currently adopted, would have a material effect on our Consolidated Financial Statements or related disclosures.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The primary market risk relating to our financial instruments is the volatility in market prices for our natural gas production. We use financial instruments to reduce cash flow variability due to fluctuations in the prices of natural gas. The market price risk is offset by the gain or loss recognized upon the related sale of the production that is financially protected. Refer to Note 7, Financial Instruments, of the consolidated financial statements included in this Annual Report for additional details about our financial instruments and their fair value. To quantify the sensitivity of the fair value of the Company’s financial instruments to changes in underlying commodity prices, management modeled a 10% increase and decrease in the commodity price for natural gas prices, as follows (in millions):
| | | | | | | | | | | | | | | | | | | | |
| | As of December 31, 2022 | | 10% Increase | | 10% Decrease |
| Natural Gas Financial Instruments | | $ | 10,463 | | | $ | 7,711 | | | $ | 13,446 | |
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
TELLURIAN INC.
| | | | | | | | | | | | | | |
| | | | Page |
Report of Independent Registered Public Accounting Firm (PCAOB Firm ID No. 34) | |
| Consolidated Financial Statements: | |
| Consolidated Balance Sheets | |
| Consolidated Statements of Operations | |
| Consolidated Statements of Stockholders’ Equity | |
| Consolidated Statements of Cash Flows | |
| Notes to Consolidated Financial Statements | |
| Supplementary Information | |
| Supplemental Disclosures About Natural Gas Producing Activities (unaudited) | |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of Tellurian Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Tellurian Inc. and subsidiaries (the "Company") as of December 31, 2022 and 2021, the related consolidated statements of operations, stockholders’ equity and cash flows, for each of the three years in the period ended December 31, 2022, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 2023, expressed an unqualified opinion on the Company’s internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Proved Natural Gas Properties and Depletion – Natural Gas Reserves – Refer to Note 2 and 4 to the financial statements
Critical Audit Matter Description
The Company’s proved natural gas properties are depleted using the units-of-production method based upon natural gas reserves. The development of the Company’s natural gas reserve quantities requires management to make significant estimates and assumptions. The Company engages an independent reservoir engineer, management’s specialist, to estimate natural gas quantities using generally accepted methods, calculation procedures and engineering data. Changes in assumptions or engineering data could have a significant impact on the amount of depletion. Proved natural gas properties, net of accumulated depreciation were $320.6 million as of December 31, 2022, and depletion expense was $43.8 million for the year then ended.
Given the significant judgments made by management and management’s specialist, performing audit procedures to evaluate the Company’s natural gas reserve quantities, including management’s estimates and assumptions related to the five-year development rule, natural gas prices, and capital expenditures requires a high degree of auditor judgment and an increased extent of effort.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to management’s significant judgments and assumptions related to natural gas reserves included the following, among others:
•We tested the effectiveness of controls related to the Company’s estimation of natural gas properties reserve quantities, including controls relating to the natural gas prices.
•We evaluated the reasonableness of management’s five-year development plan by comparing the forecasts to:
◦Historical conversions of proved undeveloped reserves.
◦Compared expected completion date of proved undeveloped reserves in the current year against the completion date the year the reserves were added to the development plan.
•We evaluated the reasonableness of natural gas prices by comparing such amounts to:
◦Third party industry sources.
◦Historical realized natural gas prices.
◦Historical realized natural gas price differentials.
•We evaluated the reasonableness of capital expenditures by comparing to historical wells drilled.
•We evaluated the Company’s estimates around production volumes by evaluating wells’ past production performance to ensure it was appropriately reflected in production forecasts used in generating proved reserves.
•We evaluated the experience, qualifications and objectivity of management’s specialist, an independent reservoir engineering firm, including the methodologies and calculation procedures used to estimate natural gas reserves and performing analytical procedures on the reserve quantities.
| | | | | | | | |
| /s/ DELOITTE & TOUCHE LLP |
| | |
| Houston, Texas |
| February 22, 2023 |
| | |
| 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, |
| | 2022 | | 2021 |
| ASSETS | | | | |
| Current assets: | | | | |
| Cash and cash equivalents | | $ | 474,205 | | | $ | 305,496 | |
| Accounts receivable | | 76,731 | | | 9,270 | |
| | | | |
| Prepaid expenses and other current assets | | 23,355 | | | 12,952 | |
| Total current assets | | 574,291 | | | 327,718 | |
| | | | |
| Property, plant and equipment, net | | 789,076 | | | 150,545 | |
| Deferred engineering costs | | — | | | 110,025 | |
| Other non-current assets | | 63,316 | | | 33,518 | |
| Total assets | | $ | 1,426,683 | | | $ | 621,806 | |
| | | | |
| LIABILITIES AND STOCKHOLDERS’ EQUITY | | | | |
| Current liabilities: | | | | |
| Accounts payable | | $ | 4,805 | | | $ | 2,852 | |
| | | | |
| Accrued and other liabilities | | 129,180 | | | 85,946 | |
| Borrowings | | 163,556 | | | — | |
| Total current liabilities | | 297,541 | | | 88,798 | |
| | | | |
| Long-term liabilities: | | | | |
| Borrowings | | 382,208 | | | 53,687 | |
| Finance lease liabilities | | 49,963 | | | 50,103 | |
| Other non-current liabilities | | 24,428 | | | 10,917 | |
| Total long-term liabilities | | 456,599 | | | 114,707 | |
| | | | |
| Commitments and Contingencies (Note 11) | | | | |
| | | | |
| Stockholders’ equity: | | | | |
| Preferred stock, $0.01 par value, 100,000,000 authorized: 6,123,782 and 6,123,782 shares outstanding, respectively | | 61 | | | 61 | |
| Common stock, $0.01 par value, 800,000,000 and 800,000,000 authorized: 564,567,568 and 500,453,575 shares outstanding, respectively | | 5,456 | | | 4,774 | |
| Additional paid-in capital | | 1,647,896 | | | 1,344,526 | |
| Accumulated deficit | | (980,870) | | | (931,060) | |
| Total stockholders’ equity | | 672,543 | | | 418,301 | |
| Total liabilities and stockholders’ equity | | $ | 1,426,683 | | | $ | 621,806 | |
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) |
| | | | | | |
| | Year Ended December 31, |
| | 2022 | | 2021 | | 2020 |
| Revenues: | | | | | | |
| Natural gas sales | | $ | 270,975 | | | $ | 51,499 | | | $ | 30,441 | |
| LNG sales | | 120,951 | | | 19,776 | | | 6,993 | |
| Total revenue | | 391,926 | | | 71,275 | | | 37,434 | |
| | | | | | |
| Operating costs and expenses: | | | | | | |
| LNG Cost of sales | | 131,663 | | | 24,745 | | | 6,993 | |
| Operating expenses | | 37,886 | | | 11,693 | | | 10,230 | |
| Development expenses | | 68,782 | | | 50,186 | | | 27,492 | |
| Depreciation, depletion and amortization | | 44,357 | | | 11,481 | | | 17,228 | |
| General and administrative expenses | | 126,386 | | | 85,903 | | | 47,349 | |
| Impairment charges | | — | | | — | | | 81,065 | |
| Severance and reorganization charges | | — | | | — | | | 6,359 | |
| Related party charges (Note 8) | | 625 | | | — | | | 7,357 | |
| Total operating costs and expenses | | 409,699 | | | 184,008 | | | 204,073 | |
| | | | | | |
| Loss from operations | | (17,773) | | | (112,733) | | | (166,639) | |
| | | | | | |
| Interest expense, net | | (13,860) | | | (9,378) | | | (43,445) | |
| Gain on extinguishment of debt, net | | — | | | 1,422 | | | — | |
| Other (expense) income, net | | (18,177) | | | 5,951 | | | (612) | |
| | | | | | |
| Loss before income taxes | | (49,810) | | | (114,738) | | | (210,696) | |
| Income tax benefit (provision) | | — | | | — | | | — | |
| Net loss | | $ | (49,810) | | | $ | (114,738) | | | $ | (210,696) | |
| | | | | | |
| Net loss per common share: | | | | | | |
| Basic and diluted | | $ | (0.09) | | | $ | (0.28) | | | $ | (0.79) | |
| | | | | | |
| Weighted average shares outstanding: | | | | | | |
| Basic and diluted | | 526,946 | | | 407,615 | | | 267,615 | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
| | | | | | | | | | | | | | | | | | | | | | | |
| TELLURIAN INC. AND SUBSIDIARIES |
| CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY |
| (in thousands) |
| | | | | | | |
| | | Year Ended December 31, |
| | | 2022 | | 2021 | | 2020 |
| Total shareholders’ equity, beginning balance | | $ | 418,301 | | | $ | 109,090 | | | $ | 166,285 | |
| | | | | | | |
| Preferred stock | | 61 | | | 61 | | | 61 | |
| | | | | | | |
| Common stock: | | | | | | |
| Beginning balance | | 4,774 | | | 3,309 | | | 2,211 | |
| Common stock issuance | | 677 | | | 1,361 | | | 808 | |
Share-based compensation, net(1) | | 3 | | | 43 | | | 55 | |
| Severance and reorganization charges | | — | | | — | | | 22 | |
| Shared-based payments | | 2 | | | 1 | | | — | |
| Settlement of Final Payment Fee (Note 10) | | — | | | — | | | 110 | |
| Borrowings principal repayment (Note 10) | | — | | | — | | | 93 | |
| Warrants exercised | | — | | | 60 | | | 10 | |
| Ending balance | | 5,456 | | | 4,774 | | | 3,309 | |
| | | | | | | |
| Additional paid-in capital: | | | | | | |
| Beginning balance | | 1,344,526 | | | 922,042 | | | 769,639 | |
| Common stock issuance | | 299,063 | | | 406,493 | | | 98,867 | |
Share-based compensation, net(1) | | 3,631 | | | 7,892 | | | 8,589 | |
| Severance and reorganization charges | | — | | | — | | | 2,667 | |
| Share-based payments | | 676 | | | 200 | | | 561 | |
| Settlement of Final Payment Fee (Note 10) | | — | | | — | | | 9,036 | |
| Warrants issued in connection with Borrowings (Note 12) | | — | | | — | | | 17,998 | |
| Borrowings principal repayment (Note 10) | | — | | | — | | | 13,695 | |
| Warrants exercised | | — | | | 8,117 | | | 990 | |
| Debt extinguishment | | — | | | (218) | | | — | |
| Ending balance | | 1,647,896 | | | 1,344,526 | | | 922,042 | |
| | | | | | | |
| Accumulated deficit: | | | | | | |
| Beginning balance | | (931,060) | | | (816,322) | | | (605,626) | |
| Net loss | | (49,810) | | | (114,738) | | | (210,696) | |
| Ending balance | | (980,870) | | | (931,060) | | | (816,322) | |
| | | | | | | |
| Total shareholders’ equity, ending balance | | $ | 672,543 | | | $ | 418,301 | | | $ | 109,090 | |
| | | | | | | |
| | | | | | | |
(1) Includes settlement of 2019 bonuses that were accrued for in 2019. |
The accompanying notes are an integral part of these consolidated financial statements.
| | | | | | | | | | | | | | | | | |
| TELLURIAN INC. AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| (in thousands) |
| | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| Cash flows from operating activities: | | | | | |
| Net loss | $ | (49,810) | | | $ | (114,738) | | | $ | (210,696) | |
| Adjustments to reconcile net loss to net cash used in operating activities: | | | | | |
| Depreciation, depletion and amortization | 44,357 | | | 11,481 | | | 17,228 | |
| Amortization of debt issuance costs, discounts and fees | 2,424 | | | 3,102 | | | 28,741 | |
| Share-based compensation | 3,633 | | | 5,950 | | | 2,699 | |
| Share-based payments | 678 | | | 200 | | | 562 | |
| Severance and reorganization charges | — | | | — | | | 2,689 | |
| Interest elected to be paid-in-kind | — | | | 508 | | | 3,317 | |
| Impairment charge and loss on transfer of assets | — | | | — | | | 81,065 | |
| | | | | |
| Unrealized (gain) loss on financial instruments not designated as hedges | (9,073) | | | (8,693) | | | 2,618 | |
| Net gain on extinguishment of debt | — | | | (1,422) | | | — | |
| Other | 1,210 | | | 1,035 | | | 3,378 | |
| Net changes in working capital (Note 18) | (15,953) | | | 41,017 | | | (1,566) | |
| Net cash used in operating activities | (22,534) | | | (61,560) | | | (69,965) | |
| Cash flows from investing activities: | | | | | |
| Acquisition and development of natural gas properties | (344,800) | | | (32,364) | | | (1,307) | |
| Driftwood Project and other related pipelines construction costs | (175,791) | | | (15,208) | | | — | |
| Land purchases and land improvements | (23,492) | | | (10,293) | | | — | |
| Investment in unconsolidated entities | (6,089) | | | — | | | — | |
| Note receivable | (6,595) | | | | | |
| Capitalized internal use software and other assets | (8,804) | | | — | | | — | |
| Net cash used in investing activities | (565,571) | | | (57,865) | | | (1,307) | |
| Cash flows from financing activities: | | | | | |
| Proceeds from common stock issuances | 309,021 | | | 421,809 | | | 103,664 | |
| Equity issuance costs | (9,281) | | | (13,955) | | | (3,989) | |
| Borrowing proceeds | 501,178 | | | 56,500 | | | 50,000 | |
| Borrowings issuance costs | (11,487) | | | (2,854) | | | (2,612) | |
| Borrowings principal repayments | — | | | (119,725) | | | (60,100) | |
| Proceeds from warrant exercise | — | | | 8,177 | | | 1,000 | |
| Tax payments for net share settlements of equity awards (Note 18) | — | | | (3,064) | | | (1,659) | |
| Finance lease principal payments | (132) | | | (1,926) | | | (1,777) | |
| Net cash provided by financing activities | 789,299 | | | 344,962 | | | 84,527 | |
| | | | | |
| Net increase in cash, cash equivalents and restricted cash | 201,194 | | | 225,537 | | | 13,255 | |
| Cash, cash equivalents and restricted cash, beginning of period | 307,274 | | | 81,737 | | | 68,482 | |
| Cash, cash equivalents and restricted cash, end of period | 508,468 | | | 307,274 | | | 81,737 | |
| Supplementary disclosure of cash flow information: | | | | | |
| Interest paid | $ | 20,647 | | | $ | 4,105 | | | $ | 11,025 | |
The accompanying notes are an integral part of these consolidated financial statements.
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 — ORGANIZATION AND NATURE OF OPERATIONS
Tellurian Inc. (“Tellurian,” “we,” “us,” “our,” or the “Company”), a Delaware corporation, is a Houston-based company that is developing and plans to operate a portfolio of natural gas, LNG marketing, and infrastructure assets that includes an LNG terminal facility (the “Driftwood terminal”), an associated pipeline (the “Driftwood pipeline”), other related pipelines, and upstream natural gas assets (collectively referred to as the “Business”).
The terms “we,” “our,” “us,” “Tellurian” and the “Company” as used in this report refer collectively to Tellurian Inc. and its subsidiaries unless the context suggests otherwise. These terms are used for convenience only and are not intended as a precise description of any separate legal entity associated with Tellurian Inc.
NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
Our Consolidated Financial Statements have been prepared in accordance with GAAP. The Consolidated Financial Statements include the accounts of Tellurian Inc. and its wholly owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation.
Certain reclassifications have been made to conform prior period information to the current presentation. The reclassifications did not have a material effect on our consolidated financial position, results of operations or cash flows.
Liquidity
Our Consolidated Financial Statements have been prepared in accordance with GAAP, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business as well as the Company’s ability to continue as a going concern. As of the date of the Consolidated Financial Statements, we have generated losses and negative cash flows from operations, and have an accumulated deficit. We have not yet established an ongoing source of revenues that is sufficient to cover our future operating costs and obligations as they become due during the twelve months following the issuance of the Consolidated Financial Statements.
The Company has sufficient cash on hand and available liquidity to satisfy its obligations and fund its working capital needs for at least twelve months following the date of issuance of the Consolidated Financial Statements. The Company has the ability to generate additional proceeds from various other potential financing transactions. We remain focused on the financing and construction of the Driftwood Project and implementationrelated pipelines while managing our upstream assets.
Segments
Segment information is prepared on the same basis that our Chief Executive Officer, who is our Chief Operating Decision Maker, uses to manage the segments, evaluate financial results and make key operating decisions. We identified the Upstream, Midstream and Marketing & Trading components as the Company’s operating segments. These operating segments represent the Company’s reportable segments. The remainder of our long-term strategybusiness is presented as “Corporate,” and consists of corporate costs and intersegment eliminations.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the successful coordinationamounts reported in the Consolidated Financial Statements and completionthe 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
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Company uses three levels of multiple objectivesthe fair value hierarchy of inputs to measure the fair value of an asset or a liability. Level 1 inputs are quoted prices in a varietyactive 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.
Revenue Recognition
For the sale of areas, including finance, marketing, natural gas, resource acquisitions, pipeline development, and facility planning and permitting. Accordingly, our fiscal year 2019 Company performance goals were generally project-focused as opposed to financial-metric focused, and incentivizedwe consider the short-term financial, asset, marketing, and gas supply projects that were necessary to implement our business strategy. As discussed below, the Compensation Committee considers reaching FIDdelivery of each unit (MMBtu) to be a significant milestoneseparate performance obligation that is satisfied upon delivery to the designated sales point and therefore is recognized at a point in time. These contracts are either fixed price contracts or contracts with a fixed differential to an index price, both of which are deemed fixed consideration that is allocated to each performance obligation and represents the relative standalone selling price basis.
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Each LNG cargo, in its entirety, is deemed to be a single performance obligation due to each molecule of LNG being distinct and substantially the same and therefore meeting the criteria for Tellurian. It was consideredthe transfer of a keyseries of distinct goods. Accordingly, LNG sales are recognized at a point in time when the LNG has completed discharging to the customer. These are contracts with a fixed differential to an index price, which is deemed fixed consideration that is allocated to each performance goalobligation and represents the relative standalone selling price basis. These LNG sales are recorded on a gross basis and reported in “LNG sales” on the Consolidated Statements of Operations.
Purchases and sales of LNG 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. For such LNG sales, we require payment within 10 days from delivery. We exclude all taxes from the measurement of the transaction price.
Accounts Receivable
The Company’s receivables consist primarily of trade receivables from natural gas sales and joint interest billings due from owners on properties the Company operates. The majority of these receivables have payment terms of 30 days or less. The Company generally has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings for
fiscal year 2019receivables due from joint interest owners. The Company’s historical credit losses have been de minimis and
weighted accordingly.For 2019,are expected to remain so in the Compensation Committeefuture assuming no substantial changes to the business or creditworthiness of the Company’s counterparties.
Cash, Cash Equivalents and Restricted Cash
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. Cash and cash equivalents that are restricted as to withdrawal or use under the terms of certain contractual agreements are recorded in Non-current restricted cash on our Consolidated Balance Sheets. The carrying value of cash, cash equivalents and restricted cash approximates their fair value.
Concentration of Cash
We maintain cash balances and restricted cash 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.
Derivative Instruments
We use derivative instruments to hedge our exposure to cash flow variability from commodity price risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as assets or liabilities, depending on the derivative position and the Board created corporate goalsexpected timing of settlement, unless they satisfy the criteria for and we elect the normal purchases and sales exception.
We have not elected and do not apply hedge accounting for our derivative instruments; therefore, all changes in fair value of the Company’s derivative instruments are recognized within Other income, net, in the Consolidated Statements of Operations. Settlements of derivative instruments are reported as a component of cash flows from operations in the Consolidated Statements of Cash Flows.
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 proved or unproved) are capitalized when incurred. Costs to develop proved reserves are capitalized and our natural gas reserves are depleted 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 Consolidated Statements of Operations.
Management tests property, plant and equipment for impairment whenever there are indicators that the carrying amount of property, plant and equipment might not be recoverable. The carrying values of our proved natural gas properties are reviewed for impairment when events or circumstances indicate that the remaining carrying value may not be recoverable. If there is an indication that the carrying amount of our proved natural gas properties may not be recoverable, we compare the estimated expected undiscounted future cash flows from our natural gas properties to the carrying values of those properties. Proved properties that have carrying amounts in excess of estimated future undiscounted cash flows are written down to fair value.
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Leases
The Company adopted Accounting Standards Update ASU 2016-02, Leases (Topic 842), and subsequent amendments thereto (“ASC 842”) on January 1, 2019 using the optional transition approach to apply the standard at the beginning of the first quarter of 2019 with no retrospective adjustments to prior periods. We elected the transition package of practical expedients to carry-forward prior conclusions related to lease identification and classification for existing leases, combine lease and non-lease components of an arrangement for all classes of our leased assets and omit short-term leases with a term of 12 months or less from recognition on the balance sheet.
The Company determines if an arrangement is a lease at inception. Leases are recognized as either finance or operating leases on our Consolidated Balance Sheets by recording a lease 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. Refer to Note 17 - Leases for operating and finance right-of-use assets and lease liabilities classification within our Consolidated Balance Sheets. In the absence of a readily determinable implicitly interest rate, we discount our expected future lease payments using our incremental borrowing rate. Options to renew a lease are included in the lease term and recognized as part of the right-of-use asset and lease liability, only to the extent they are reasonably certain to be used generallyexercised.
Lease expense for operating lease payments is recognized on a straight-line basis over the lease term. Lease expense for finance leases is recognized as the sum of the amortization of the right-of-use assets on a straight-line basis and the interest on lease liabilities over the lease term.
Accounting for LNG Development Activities
As we have been in the preliminary stage of developing the Driftwood terminal, substantially all the costs related to such activities have been expensed. These costs primarily include professional fees associated with FEED studies and complying with FERC for authorization to construct our terminal and other required permitting for the NEOs,Driftwood Project.
Costs incurred in connection with a project to develop the Driftwood terminal shall generally be treated as welldevelopment expenses until the project has reached the notice-to-proceed state (“NTP State”) and the following criteria (the “NTP Criteria”) have been met: (i) the necessary regulatory permits have been obtained, (ii) financing for the project has been secured and (iii) management has committed to commence construction.
In addition, certain costs incurred prior to achieving the NTP State will be capitalized although 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, direct payroll and payroll benefit-related costs 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. Interest is capitalized in connection with the construction of major facilities. All amounts capitalized are periodically assessed for impairment and may be impaired if indicators are present.
Prior to reaching the NTP State, costs incurred to complete construction activities necessary to proceed under our LSTK EPC agreement with Bechtel are capitalized as construction in progress when the following criteria are met: (i) costs incurred are directly identifiable, (ii) necessary regulatory permits are secured, (iii) funding for the scope of work is available, and (iv) construction activities are creditable under the LSTK EPC agreement.
Prior to reaching the NTP State, costs incurred to complete construction activities necessary to develop the Driftwood pipeline and other related pipelines are capitalized as construction in progress when the following criteria are met: (i) costs incurred are directly identifiable, (ii) necessary regulatory permits are secured, and (iii) funding for the scope of work is available.
Debt
Discounts, fees and expenses incurred with the issuance of debt are amortized over the term of the debt. These amounts are presented as a setreduction of CEO-specificour indebtedness on the accompanying Consolidated Balance Sheets. See Note 10, Borrowings, for additional details about our loans.
Share-Based Compensation
We have awarded share-based compensation in the form of stock, restricted stock, restricted stock units and stock options to employees, directors and outside consultants. Share-based compensation transactions are measured based on the grant-date estimated fair value. For awards containing only service conditions or performance
goals used solely to measureconditions 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
Ms. Gentle.vesting at
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
each reporting period for awards with performance conditions and adjust compensation cost based on our probability assessment. We recognize forfeitures as they occur.
Income Taxes
We account for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, we determine deferred tax assets and liabilities on the basis of the differences between the financial statement and tax basis of assets and liabilities by using enacted tax rates in effect for the year in which the differences are expected to be realized or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.
We recognize deferred tax assets to the extent that we believe that these assets are more likely than not to be realized. In making such a determination, we consider current and historical financial results, expectations for future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. If we determine that we would be able to realize our deferred tax assets in the future in excess of their net recorded amount, we will make an adjustment to the deferred tax asset valuation allowance, which would reduce the provision for income taxes.
Post employment benefits
The Company provides cash and other termination benefits pursuant to ongoing benefit arrangements to its employees in connection with a qualifying termination of their employment. The cost of providing post employment benefits is recognized when the obligation is probable of occurring and can be reasonably estimated.
Net Loss Per Share
Basic net loss per share excludes dilution and is computed by dividing net loss by the weighted average number of common shares outstanding during the period. Diluted net loss per share reflects potential dilution and is computed by dividing net 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 3 — PREPAID EXPENSES AND OTHER CURRENT ASSETS
Prepaid expenses and other current assets consist of the following chart reflects(in thousands):
| | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 |
| Prepaid expenses | $ | 2,174 | | | $ | 605 | |
| Deposits | 172 | | | 2,268 | |
| Restricted cash | 9,375 | | | — | |
| Derivative asset, net - current (Note 7) | 10,463 | | | 8,693 | |
| Other current assets | 1,171 | | | 1,386 | |
| Total prepaid expenses and other current assets | $ | 23,355 | | | $ | 12,952 | |
Deposits
Margin deposits posted with a third-party financial institution related to our financial instrument contracts were approximately $0.1 million and $2.1 million as of December 31, 2022 and December 31, 2021, respectively.
Restricted Cash
Restricted cash as of December 31, 2022 consists of approximately $9.4 million held in escrow under the terms of the purchase and sale agreement for the acquisition of certain natural gas assets in the Haynesville Shale. See Note 4, Property, Plant and Equipment, for further information.
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 4 — PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consist of the following (in thousands):
| | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 |
| Upstream natural gas assets: | | | |
| Proved properties | $ | 412,977 | | | $ | 96,297 | |
| Wells in progress | 55,374 | | | 17,653 | |
| Accumulated DD&A | (92,423) | | | (48,638) | |
| Total upstream natural gas assets, net | 375,928 | | | 65,312 | |
| | | |
| Driftwood Project assets: | | | |
| Land and land improvements | 52,460 | | | 25,222 | |
| Driftwood terminal construction in progress | 292,734 | | | — | |
| Finance lease assets, net of accumulated DD&A | 56,708 | | | 57,883 | |
| Buildings and other assets, net of accumulated DD&A | 340 | | | 371 | |
| Total Driftwood Project assets, net | 402,242 | | | 83,476 | |
| | | |
| Fixed assets and other: | | | |
| Leasehold improvements and other assets | 12,672 | | | 3,104 | |
| Accumulated DD&A | (1,766) | | | (1,347) | |
| Total fixed assets and other, net | 10,906 | | | 1,757 | |
| | | |
| Total property, plant and equipment, net | $ | 789,076 | | | $ | 150,545 | |
Depreciation, depletion and amortization expenses for the years ended December 31, 2022, 2021 and 2020 were approximately $44.4 million, $11.5 million and $17.2 million, respectively.
Driftwood Terminal Construction in Progress
During the year ended December 31, 2021, the Company
performance goals used generallyinitiated certain owner construction activities necessary to proceed under our LSTK EPC agreement with Bechtel Energy Inc., formerly known as Bechtel Oil, Gas and Chemicals, Inc. (“Bechtel”), for
all NEOs for 2019.Annual Corporate Performance Goals |
Description
| | Why we use it
|
Reach FID on Phase 1 of the Driftwood terminal. | | FID is a significant milestone that represents our securing of sufficient financing and completion of the other actions necessary to proceed with the construction of the Driftwood terminal. |
Control spending to +/- 10% of budget. | | Fiscal discipline is essential to our ability to implement our business strategy as we have limited cash resources that need to be deployed to further the Driftwood Project. |
Establish financing for operating business. | | Our ability to conduct our operations and meet our general working capital needs is dependent on our ability to obtain adequate levels of financing. |
Operate owned producing assets (including the sale of gas) safely, efficiently, and profitably. | | Producing natural gas is important to our ability to implement our business strategy, and it is fundamental to our business that we be able to do so on a safe, efficient, and profitable basis. |
Purchase a targeted amount of natural gas resources. | | Achievement of our business objectives requires that we acquire substantial natural gas producing properties at attractive prices. |
Execute Memorandum of Understanding sufficient to FID of Phase 1 of the Driftwood terminal. | | Our ability to reach FID is dependent on our ability to have arrangements in place to sell sufficient volumes of LNG from the Driftwood terminal. |
Execute commercial agreements sufficient to support the financing of Phase 2 of the Driftwood terminal. | | Our ability to finance Phase 2 of the Driftwood terminal is dependent on our ability to have agreements in place to sell sufficient volumes of LNG from the Driftwood terminal. |
Close financing for Phase 2 of the Driftwood terminal. | | Obtaining adequate levels of financing is essential for our ability to complete Phase 2 of the Driftwood terminal. |
Secure binding shipper agreements on the Permian Global Access Pipeline and the Haynesville Global Access Pipeline and begin Federal Energy Regulation Commission (FERC) process on each. | | Securing customers and obtaining regulatory approval of our pipelines is essential to the successful commercialization of those projects. |
Build LNG trading business to a targeted amount of gross profit for fiscal 2018. | | Our long-term business plan includes participation in a variety of natural gas-related lines of business, including LNG trading. |
Execute transition plan for the Driftwood Project on schedule. | | As we structure Driftwood Holdings as a partnership, management is focusing on organizational structure and joint venture capabilities. |
The following chart reflects the Company performance goals used solely in respect of Ms. Gentle:
CEO Performance Goals |
Description | | Why we use it |
Reach FID on Phase 1 of the Driftwood terminal. | | FID is a significant milestone that represents our securing of sufficient financing and completion of the other actions necessary to proceed with the construction of the Driftwood terminal. |
Achieve targeted level of share price appreciation on a one-year basis. | | We believe that our CEO should be compensated in part based on the returns delivered to our stockholders. |
Achieve targeted level of share price appreciation on a three-year basis. | | We believe that our CEO should be compensated in part based on the returns delivered to our stockholders. |
Assessment of 2019 Performance
Upon completion of fiscal year 2019, the Compensation Committee recommended, and the Board approved, that no discretionary annual bonus awards in respect of 2019 be paid to our NEOs other than to Mr. Lafargue, as described below. Although the Company continued to make substantial progress in 2019 and achieved or partially achieved seven of the eleven corporate performance goals established by the Compensation Committee and the Board, the Company did not achieve its key goal of reaching FID on Phase 1 of the Driftwood Project in 2019, which wasterminal. On March 24, 2022, the primary driverCompany issued a limited notice to proceed (“LNTP”) to Bechtel under the Phase 1 EPC Agreement and commenced construction of our NEOs generally not receiving discretionary bonus awards for 2019. Additionally, nonePhase 1 of the CEO-specific goalsDriftwood terminal on April 4, 2022. As the Company commenced construction activities, Deferred engineering costs and Permitting costs of approximately $110.0 million and $13.4 million, respectively, were achieved for 2019.
2019 Annual Bonus Awards
Based ontransferred to construction in progress as of March 31, 2022. During the foregoing assessment of 2019 Company and individual performance, the Board, on the Compensation Committee’s recommendation, did not make any 2019 discretionary annual bonus awards to our NEOs, other than to Mr. Lafargue. On March 9, 2020, following Mr. Lafargue’s transition into his new role, we awarded Mr. Lafargue a 2019 discretionary annual bonus of $250,000 paid in the form of 206,611 restricted stock units as an annual performance bonus for the fiscal year ended December 31, 2019.2022, we also capitalized approximately $169.3 million of directly identifiable project costs as construction in progress, inclusive of approximately $5.7 million in capitalized interest.
Asset Acquisition
On August 18, 2022, the Company completed the acquisition of certain natural gas assets in the Haynesville Shale basin (the “Asset Acquisition”). The purchase price of $125.0 million was subject to customary adjustments totaling approximately $8.8 million, for an adjusted purchase price of approximately $133.8 million. The sellers may receive an additional cash payment of $7.5 million if the average NYMEX Henry Hub gas price for the contract delivery months beginning with August 2022 through March 2023 exceeds a specific threshold per MMBtu (the “Contingent Consideration”). See Note 7, Financial Instruments, for further information.
Proved Properties
During the year ended December 31, 2022, we put in production 13 operated Haynesville wells and participated in four non-operated Haynesville wells that were put in production.
NOTE 5 — DEFERRED ENGINEERING COSTS
Deferred engineering costs related to the planned construction of the Driftwood terminal were transferred to construction in progress upon issuing the LNTP to Bechtel in March 2022. See Note 4, Property, Plant and Equipment, for further information.
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 6 — OTHER NON-CURRENT ASSETS
Other non-current assets consist of the following (in thousands):
| | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 |
| Land lease and purchase options | $ | 300 | | | $ | 6,368 | |
| Permitting costs | 916 | | | 13,408 | |
| Right of use asset — operating leases | 13,303 | | | 10,166 | |
| Restricted cash | 24,888 | | | 1,778 | |
| Investment in unconsolidated entities | 6,089 | | | — | |
| Note receivable | 6,595 | | | |
| Driftwood pipeline materials and rights of way | 9,136 | | | — | |
| Other | 2,089 | | | 1,798 | |
| Total other non-current assets | $ | 63,316 | | | $ | 33,518 | |
Land Lease and Purchase Options
During the first quarter of 2022, we exercised the final land purchase options related to the Driftwood terminal. Land purchase options held by the Company as of December 31, 2022 are related to the Driftwood pipeline.
Permitting Costs
Permitting costs primarily represent the purchase of wetland credits in connection with our permit application to the USACE in 2017, which was supplemented in 2018. The permit was issued on May 3, 2019 (the “Permit”). These wetland credits were transferred to construction in progress upon issuing the limited notice to proceed to Bechtel in March 2022. See Note 4, Property, Plant and Equipment, for further information. The purchase of these wetland credits was a condition of the Permit in accordance with the Clean Water Act and the Rivers and Harbors Act, which requires us to mitigate the potential impact to Louisiana wetlands that might be caused by the construction of the Driftwood Project.
Restricted Cash
Restricted cash as of December 31, 2022 and December 31, 2021, represents the cash collateralization of letters of credit associated with finance leases.
Investment in Unconsolidated Entities
On February 24, 2022, the Company purchased 1.5 million ordinary shares of an unaffiliated entity that provides renewable energy services. The total cost of this investment was approximately $6.1 million. This investment does not provide the Company with a controlling financial interest in or significant influence over the operating or financial decisions of the unaffiliated entity. The Company’s investment was recorded at cost.
Note Receivable
The Company issued an amended and restated $6.6 million promissory note due June 14, 2024 (the “Promissory Note”) to an unaffiliated entity (the “Borrower”) engaged in the development of infrastructure projects in the energy industry. The Promissory Note is collateralized by a secondary interest in the Borrower’s rights to certain land lease agreements. The Promissory Note bears interest at a rate of 6.00%, which will be capitalized into the outstanding principal balance annually.
NOTE 7 — FINANCIAL INSTRUMENTS
Natural Gas Financial Instruments
The primary purpose of our commodity risk management activities is to hedge our exposure to cash flow variability from commodity price risk due to fluctuations in commodity prices. The Company uses natural gas financial futures and option contracts to economically hedge the commodity price risks associated with a portion of our expected natural gas production. The Company’s open positions as of December 31, 2022 had notional volumes of approximately 9.8 Bcf, with maturities extending through October 2023.
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
LNG Financial Futures
During the year ended December 31, 2021, we entered into LNG financial futures contracts to reduce our exposure to commodity price fluctuations and to achieve more predictable cash flows relative to two LNG cargos that we were committed to purchase from and sell to unrelated third-party LNG merchants in the normal course of business in January and April 2022. As of December 31, 2022, there were no open LNG financial instrument positions.
Contingent Consideration
The purchase price for the Asset Acquisition includes Contingent Consideration which was determined to be an embedded derivative and is recorded at fair value in the Consolidated Balance Sheets. Refer to Note 4, Property, Plant and Equipment, for additional information. As of the date of the acquisition, the fair value of the Contingent Consideration was approximately $3.9 million, which was recorded as part of the basis in proved natural gas properties with a corresponding embedded derivative liability. Changes in the fair value of the Contingent Consideration are recognized in the period they occur and included within Other expense, net on the Consolidated Statements of Operations.
The following table summarizes the effect of the Company’s financial instruments which are included within Other expense, net on the Consolidated Statements of Operations (in thousands):
| | | | | | | | | | | | | | |
| | Year ended December 31, 2022 | | Year ended December 31, 2021 |
| Natural gas financial instruments: | | | | |
| Realized loss | | $ | 27,179 | | | $ | 826 | |
| Unrealized gain | | 10,463 | | | — | |
| LNG financial futures contracts: | | | | |
| Realized gain | | 3,532 | | | 1,010 | |
| Unrealized (loss) gain | | (5,161) | | | 8,693 | |
| Contingent Consideration: | | | | |
| Unrealized gain | | 3,770 | | | — | |
The following table presents the classification of the Company’s financial derivative assets and liabilities that are required to be measured at fair value on a recurring basis on the Company’s Consolidated Balance Sheets (in thousands):
| | | | | | | | | | | | | | |
| | Year ended December 31, 2022 | | Year ended December 31, 2021 |
| Current Assets: | | | | |
| Natural Gas Financial Instruments | | $ | 10,463 | | | $ | — | |
| LNG Financial Futures | | — | | | 8,693 | |
| | | | |
| | | | |
| Current liabilities: | | | | |
| Contingent Consideration | | 118 | | | — | |
The Company’s natural gas and LNG financial instruments are valued using quoted prices in active exchange markets as of the balance sheet date and are classified as Level 1 within the fair value hierarchy.
The fair value of the Contingent Consideration was determined using Monte Carlo simulations including inputs such as quoted future natural gas price curves, natural gas price volatility, and discount rates. These inputs are substantially observable in active markets throughout the full term of the Contingent Consideration arrangement and are therefore designated as Level 2 within the valuation hierarchy.
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 8 — RELATED PARTY TRANSACTIONS
Accounts Payable due to Related Parties
In conjunction with the dismissal of prior litigation (the “Litigation”), we agreed to reimburse the Vice Chairman of the Company’s Board of Directors, Martin Houston, for reasonable attorneys’ fees and expenses he incurred during the Litigation. During the year ended December 31, 2020, we paid approximately $5.1 million to third parties to settle outstanding amounts incurred by Mr. Lafargue’s 2019 discretionary annual bonus was madeHouston for reasonable attorneys’ fees and expenses. During the years ended December 31, 2021 and 2020, we also paid Mr. Houston approximately $0.9 million and $1.4 million, respectively, for other expenses he incurred in recognitionconnection with the Litigation. As of his efforts throughout 2019December 31, 2022 and in order to align his compensation structure with his current non-NEO position as Senior Vice President of LNG Marketing. Each restricted stock unit granted2021, all amounts owed to Mr. Lafargue representsHouston were fully settled.
Related Party Contractor Service Fees and Expenses
The Company entered into a contingentone-year independent contractor agreement, effective January 1, 2022, with Mr. Houston. Pursuant to the terms and conditions of this agreement, the Company paid Mr. Houston a monthly fee of $50.0 thousand plus approved expenses. In December 2022, the Company amended the independent contractor agreement to expire on the earlier of (i) termination of Mr. Houston and (ii) December 31, 2023, and to increase the monthly fee to $55.0 thousand plus approved expenses. For the year ended December 31, 2022, the Company paid Mr. Houston approximately $0.6 million, for contractor service fees and expenses. As of December 31, 2022, there were no balances due to Mr. Houston.
NOTE 9 — ACCRUED AND OTHER LIABILITIES
Accrued and other liabilities consist of the following (in thousands):
| | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 |
| Upstream accrued liabilities | $ | 71,977 | | | $ | 26,421 | |
| Payroll and compensation | 37,329 | | | 50,243 | |
| Accrued taxes | 730 | | | 991 | |
| Driftwood Project and related pipelines development activities | 4,423 | | | 435 | |
| Lease liabilities | 2,875 | | | 2,279 | |
| | | |
| Accrued interest | 5,793 | | | 660 | |
| Other | 6,053 | | | 4,917 | |
| Total accrued and other liabilities | $ | 129,180 | | | $ | 85,946 | |
NOTE 10 — BORROWINGS
The Company’s borrowings consist of the following (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | |
| | | December 31, 2022 |
| | | Principal repayment obligation | | Unamortized DFC | | Carrying value |
| Senior Secured Convertible Notes, current | | $ | 166,666 | | | $ | (3,110) | | | $ | 163,556 | |
| Senior Secured Convertible Notes, non-current | | 333,334 | | | (6,219) | | | 327,115 | |
| Senior Notes due 2028 | | 57,678 | | | (2,585) | | | 55,093 | |
| Total borrowings | | $ | 557,678 | | | $ | (11,914) | | | $ | 545,764 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | December 31, 2021 |
| | | Principal repayment obligation | | Unamortized DFC | | Carrying value |
| Senior Notes due 2028 | | $ | 56,500 | | | $ | (2,813) | | | $ | 53,687 | |
| | | | | | |
| | | | | | |
| | | | | | |
| Total borrowings | | $ | 56,500 | | | $ | (2,813) | | | $ | 53,687 | |
| | | | | | | |
| | | |
| | | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | | |
| | | | | | | |
|
Amortization of the Company’s DFC is a component of Interest expense, net in the Company’s Consolidated Statements of Operations. The Company amortized approximately $2.4 million, $3.1 million, and $28.7 million during the years ended December 31, 2022, 2021, and 2020, respectively.
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Senior Secured Convertible Notes due 2025
On June 3, 2022, we issued and sold $500.0 million aggregate principal amount of 6.00% Senior Secured Convertible Notes due May 1, 2025 (the “Convertible Notes” or the “Notes”). Net proceeds from the Convertible Notes were approximately $488.7 million after deducting fees and expenses. The Convertible Notes have quarterly interest payments due on February 1, May 1, August 1, and November 1 of each year and on the maturity date. Debt issuance costs of approximately $11.5 million were capitalized and are being amortized over the full term of the Notes using the effective interest rate method.
The holders of the Convertible Notes have the right to receive on or within thirty days after vesting oneconvert the Notes into shares of our common stock at an initial conversion rate of 174.703 shares per $1,000 principal amount of Notes (equivalent to a conversion price of approximately $5.724 per share of Telluriancommon stock) (the “Conversion Price”), subject to adjustment in certain circumstances. Holders of the Convertible Notes may force the Company to redeem the Notes for cash upon (i) a fundamental change or (ii) an event of default.
The Company will force the holders of the Convertible Notes to convert all of the Notes if the trading price of our common stock
cash of equal value, or a combination of both, and the restricted stock units vest in twelve substantially equal monthly installments beginning on June 1, 2020.Long-Term Incentive Awards
Long-Term Incentive Compensation
Our long-term incentive compensation program consists primarilycloses above 200% of the vehicles set forthConversion Price for 20 consecutive trading days and certain other conditions are satisfied. The Company may provide written notice to each holder of the Notes calling all of such holder’s Notes for a cash purchase price equal to 120% of the principal amount being redeemed, plus accrued and unpaid interest (the “Optional Redemption”), and each holder will have the right to accept or reject such Optional Redemption.
On each of May 1, 2023 and May 1, 2024, the holders of the Convertible Notes may redeem up to $166.7 million of the initial principal amount of the Notes at par, plus accrued and unpaid interest (the “Redemption Amount”). The Company classified the potential Redemption Amount in respect of May 1, 2023 as a current borrowing on the Consolidated Balance Sheet as of December 31, 2022.
Our borrowing obligations under the Convertible Notes are collateralized by a first priority lien on the Company’s equity interests in Tellurian Production Holdings LLC (“Tellurian Production Holdings”), a wholly owned subsidiary of Tellurian Inc. Tellurian Production Holdings owns all of the Company’s upstream natural gas assets described in Note 4, Property, Plant and Equipment. Upon the Company’s compliance with its obligations in respect of an Optional Redemption (regardless of whether holders accept or reject the redemption), the lien on the equity interests in Tellurian Production Holdings will be automatically released. The Notes contain a minimum cash balance requirement of $100.0 million and non-financial covenants. As of December 31, 2022, we remained in compliance with the minimum cash balance requirement and all other covenants under the Notes.
As of December 31, 2022, the estimated fair value of the Convertible Notes was approximately $446.1 million. The Level 3 fair value was estimated based on inputs that are observable in the chart below,market or that could be derived from, or corroborated with, observable market data, including our stock price and inputs that are not observable in the market.
Senior Notes due 2028
On November 10, 2021, we sold in a registered public offering $50.0 million aggregate principal amount of 8.25% Senior Notes due November 30, 2028 (the “Senior Notes”). Net proceeds from the Senior Notes were approximately $47.5 million after deducting fees. The underwriter was granted an option to purchase up to an additional $7.5 million of the Senior Notes within 30 days. On December 7, 2021, the underwriter exercised the option and purchased an additional $6.5 million of the Senior Notes resulting in net proceeds of approximately $6.2 million after deducting fees. The Senior Notes have quarterly interest payments due on January 31, April 30, July 31, and October 31 of each year and on the maturity date. As of December 31, 2022, the Company was in compliance with all covenants under the indenture governing the Senior Notes. The Senior Notes are listed and trade on the NYSE American under the symbol “TELZ,” and are classified as Level 1 within the fair value hierarchy. As of December 31, 2022, the closing market price was $17.45 per Senior Note.
At-the-Market Debt Offering Program
On December 17, 2021, we entered into an at-the-market debt offering program under which were granted to our NEOs prior to 2019. Wethe Company may offer and sell, from time to time granton the NYSE American, up to an aggregate principal amount of $200.0 million of additional awardsSenior Notes. During the year ended December 31, 2022, we sold approximately $1.2 million aggregate principal amount of additional Senior Notes for total proceeds of approximately $1.1 million after fees and commissions under our at-the-market debt offering program. On December 30, 2022, the Company terminated the at-the-market debt offering program.
2020 Senior Unsecured Note
On April 29, 2020, we issued a zero coupon $56.0 million senior unsecured note (the “2020 Unsecured Note”) to an unrelated third party. The 2020 Unsecured Note was repaid in installments with the final contractually required payment made on March 31, 2021.
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2019 Term Loan
On May 23, 2019, Driftwood Holdings LP (“Driftwood Holdings”), a wholly owned subsidiary of the sameCompany, entered into a senior secured term loan agreement (the “2019 Term Loan”) to borrow an aggregate principal amount of $60.0 million. On July 16, 2019, the principal amount was increased by an additional $15.0 million. Upon maturity or early repayment of the 2019 Term Loan, Driftwood Holdings was obligated to pay to the lender a different typefee equal to executives20% of the principal amount borrowed less financing costs and cash interest paid (the “Final Payment Fee”). We issued to the lender a warrant to purchase approximately 1.5 million shares of our common stock at $10.00 per share (the “Original Warrant”). On March 3, 2020, the Original Warrant was replaced with a new warrant (the “Replacement Warrant”) which provided the lender with the right to purchase 9.0 million shares of our common stock at $1.00 per share.
On March 12, 2021 (the “Extinguishment Date”), we finalized a voluntary repayment of the remaining outstanding principal balance of the 2019 Term Loan. The extinguishment of the 2019 Term Loan resulted in an approximately $2.1 million gain, which was recognized within Gain on extinguishment of debt, net, on our Consolidated Statements of Operations for the year ended December 31, 2021. As a result of repaying the outstanding balance prior to its contractual maturity, an approximately $4.4 million in unamortized debt issuance costs and discount were written off and included in the computation of the gain from the extinguishment of the 2019 Term Loan for the year ended December 31, 2021.
The holder of the 2019 Term Loan held approximately 3.5 million unvested warrants that had a fair value of approximately $6.3 million as of the Extinguishment Date. Due to the extinguishment of the 2019 Term Loan, all the unvested warrants were contractually terminated, and their respective fair value was included in the computation of the gain on extinguishment of the 2019 Term Loan.
2018 Term Loan
On September 28, 2018, Tellurian Production Holdings LLC, a wholly owned subsidiary of Tellurian Inc., entered into a three-year senior secured term loan credit agreement (the “2018 Term Loan”) in an aggregate principal amount of $60.0 million.
On April 23, 2021, we voluntarily repaid the remaining outstanding principal balance of the 2018 Term Loan. As a result of the voluntary repayment, we recognized an approximately $0.7 million loss, which was recognized within Gain on extinguishment of debt, net, on our Consolidated Statements of Operations for the year ended December 31, 2021.
NOTE 11 — COMMITMENTS AND CONTINGENCIES
Trade Finance Credit Line
On July 19, 2021, we entered into an uncommitted trade finance credit line for up to $30.0 million that is intended to finance the purchase of LNG cargos for ultimate resale in the normal course of business. On December 7, 2021, the uncommitted trade finance credit line was amended and increased to $150.0 million. As of the period ended December 31, 2022, no amounts were drawn under this credit line.
NOTE 12 — STOCKHOLDERS’ EQUITY
At-the-Market Equity Offering Programs
We maintained multiple at-the-market equity offering programs pursuant to which we sold shares of our common stock from time to time on the NYSE American. For the year ended December 31, 2022, we issued 67.7 million shares of our common stock under our at-the-market equity offering programs for net proceeds of approximately $299.7 million. The Company has not sold any given year basedcommon stock under the at-the-market equity offering programs since April 2022.
On December 30, 2022, the Company terminated the Company’s then-existing at-the-market equity offering programs. On December 30, 2022, the Company entered into a new at-the-market equity offering program pursuant to which the Company may sell shares of its common stock from time to time on exceptional performancethe NYSE American for aggregate sales proceeds of up to $500.0 million. As of December 31, 2022, we had availability under the at-the-market program to raise aggregate gross sales proceeds of up to $500.0 million.
Common Stock Issuances
On August 6, 2021, we sold 35.0 million shares of our common stock in an underwritten public offering at a price of $3.00 per share. Net proceeds from this offering, after deducting fees and expenses, were approximately $100.8 million. The underwriters were granted an option to purchase up to an additional 5.3 million shares of common stock within 30 days. On August 31, 2021, the underwriters exercised this option, which generated net proceeds, after deducting fees, of approximately $15.1 million.
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Common Stock Purchase Warrants
2020 Unsecured Note
In conjunction with the issuance of the 2020 Unsecured Note, we issued a warrant providing the lender with the right to purchase up to 20.0 million shares of our common stock at $1.542 per share (the “2020 Warrant”). The 2020 Warrant, which vested immediately, will expire in October 2025. The 2020 Warrant was valued using a Black-Scholes option pricing model that resulted in a relative fair value of approximately $16.1 million on the Issuance Date and is not subject to subsequent remeasurement. The 2020 Warrant has been classified as equity and is recognized within Additional paid-in capital on our Consolidated Balance Sheets. The 2020 Warrant has been excluded from the computation of diluted loss per share because including it in the computation would have been antidilutive for the periods presented.
2019 Term Loan
During the first quarter of 2021, the lender of the 2019 Term Loan exercised warrants to purchase approximately 6.0 million shares of our common stock for total proceeds of approximately $8.2 million. As discussed in Note 10, Borrowings, the 2019 Term Loan has been repaid in full and the lender no longer holds any warrants.
Preferred Stock
In March 2018, we entered into a preferred stock purchase agreement with BDC Oil and Gas Holdings, LLC (“Bechtel Holdings”), a Delaware limited liability company and an affiliate of Bechtel Oil, Gas and Chemicals, Inc., a Delaware corporation, pursuant to which we sold to Bechtel Holdings approximately 6.1 million shares of our Series C convertible preferred stock (the “Preferred Stock”).
The holders of the Preferred Stock do not have dividend rights but do have a liquidation preference over holders of our common stock. The holders of the Preferred Stock may convert all or other factors that the Compensation Committee deems relevant. We consider long-term incentivesany portion of their shares into shares of our common stock on a cumulative basis,one-for-one basis. At any time after “Substantial Completion” of “Project 1,” each as defined in and accordingly view grants made in prior yearspursuant to the LSTK EPC Agreement for the Driftwood LNG Phase 1 Liquefaction Facility, dated as a vital partof November 10, 2017, or at any time after March 21, 2028, we have the right to cause all of the Preferred Stock to be converted into shares of our ongoing long-termcommon stock on a one-for-one basis. The Preferred Stock has been excluded from the computation of diluted loss per share because including it in the computation would have been antidilutive for the periods presented.
NOTE 13 — 2020 SEVERANCE AND REORGANIZATION
During the first quarter of 2020, we implemented a cost reduction and reorganization plan due to the sharp decline in oil and natural gas prices as well as the negative economic effects of the COVID-19 pandemic. We satisfied all amounts owed to former employees and incurred approximately $6.4 million of severance and reorganization charges during the year ended December 31, 2020.
Employee Retention Plan
In July 2020, the Company’s Board of Directors approved an employee retention incentive
structureplan (the “Employee Retention Plan”) aggregating $12.0 million. The Employee Retention Plan was designed to vest in four equal installments upon the attainment of a ten-day average closing price of the Company’s common stock above $2.25, $3.25, $4.25 and
an important consideration regarding$5.25 (the “Stock Performance Targets”). During the
amount, if any,year ended December 31, 2021, three of the four installments vested and
typewe recognized approximately $7.9 million in retention charges within General and administrative expenses and Development expenses in our Consolidated Statements of
additional grants to be made in any future year. | | FID Restricted Stock
 | | Stock Options
 | | Driftwood Incentive
Program Awards
 |
Description | | A significant grant of shares of restricted stock, the vesting of which is contingent upon FID. | | An award of time-vesting non-qualified stock options designed to allow the recipients to participate in the upside of the Company. | | A cash award under the Driftwood Incentive Program designed to reward employees, including our NEOs, for commencement of work on each of the four phases of the Driftwood terminal (each, a “Phase”). Each award provides a fixed dollar amount for each Phase. After satisfaction of the relevant milestone, the amount is paid over time, contingent upon continued employment, creating a meaningful long-term retention incentive. |
Why it is consistent with our compensation philosophy | | Creates alignment with stockholders and links pay to achievement of a significant corporate project. | | Creates alignment with our stockholders and encourages long-term retention of executives. | | Links pay to achievement of a significant corporate project and encourages long-term retention of executives. |
When issued | | Each of our NEOs received an initial grant prior to the Merger in connection with their offer letter with Tellurian Investments, except for Mr. Lafargue, who received his initial grant upon the Merger. Additional awards may be issued upon the achievement of strategic milestones (e.g., Mr. Teague’s additional 2018 award). | | October 2017 | | April 2018 |
Vesting terms | | Generally, vests in full upon FID. Mr. Teague’s additional 2018 award vests in equal one-third increments upon FID and the two anniversaries thereof. | | Vests in three equal annual installments on the first three anniversaries of the date of grant, subject to continued employment through each vesting date. | | Vests in increments, with 25% of the award allocable to any Phase vesting on each of the first four anniversaries of the date on which a notice to proceed or similar action or authorization is issued and delivered by Driftwood LNG LLC under an EPC contract with Bechtel to commence work on the applicable Phase of the Driftwood terminal (each, an “NTP Date”). |
Settlement | | Upon vesting, shares of common stock are no longer subject to forfeiture or transfer restrictions. | | Exercisable into shares of common stock. | | Upon vesting, payable in cash within 30 days of the applicable vesting date. |
Termination of services; change of control | | Treatment of the awards in connection with a termination of services and upon a “change of control” is described under the heading “Potential Payments upon Termination or Change of Control” below. | | Treatment of the awards in connection with a termination of services and upon a “change of control” is described under the heading “Potential Payments upon Termination or Change of Control” below. | | Treatment of the awards in connection with a termination of services and upon a “change of control” is described under the heading “Potential Payments upon Termination or Change of Control” below. |
Other terms | | Dividends, if any, would be accrued and paid solely when and if the related restricted stock vests. | | All unexercised options expire upon the tenth anniversary of the grant date. | | Each award expires on the 10-year anniversary of the grant date (the “Expiration Date”). If the NTP Date for any Phase does not occur by the Expiration Date, entitlement to the award allocated to such Phase will be forfeited without any right to compensation. |
2019 Long-Term Incentive Compensation Actions
WeOperations, of which $3.6 million was paid during 2022. The plan expired on March 31, 2022, and the fourth installment did not make any long-term incentive compensation awards to our NEOs in 2019. After consideringvest, as the existing long-term incentives provided to our NEOs, the Compensation Committeefinal Stock Performance Target was not attained.
NOTE 14 — SHARE-BASED COMPENSATION
We have granted restricted stock and
our Board determined that our NEOs were already appropriately incentivized to achieve the Company’s current and long-term strategic projects.Outstanding Long-Term Incentive Awards
A full listing of the FID restricted stock units (collectively, “Restricted Stock”), as well as unrestricted stock and stock options, held by our NEOs is set forth in the section below entitled “Outstanding Equity Awards at December 31, 2019.” In addition, each of our executives has the ability to earn the following cash incentive awardsemployees, directors and outside consultants under the Driftwood Incentive Program in respect of each Phase of the Driftwood terminal:
| NEO | | Phase 1 | | Phase 2 | | | | Phase 3 | | | Phase 4 | | | Total
Driftwood
Incentive
Program
Award | |
| Meg A. Gentle | | $ | 14,000,000 | | | $ | 7,000,000 | | | $ | 7,000,000 | | | $ | 7,000,000 | | | $ | 35,000,000 | |
| R. Keith Teague | | $ | 8,000,000 | | | $ | 4,000,000 | | | $ | 4,000,000 | | | $ | 4,000,000 | | | $ | 20,000,000 | |
| Antoine J. Lafargue | | $ | 6,000,000 | | | $ | 3,000,000 | | | $ | 3,000,000 | | | $ | 3,000,000 | | | $ | 15,000,000 | |
| Daniel A. Belhumeur | | $ | 6,000,000 | | | $ | 3,000,000 | | | $ | 3,000,000 | | | $ | 3,000,000 | | | $ | 15,000,000 | |
| Khaled A. Sharafeldin | | $ | 1,800,000 | | | $ | 900,000 | | | $ | 900,000 | | | $ | 900,000 | | | $ | 4,500,000 | |
Benefits
Retirement and Other Benefits
Our NEOs are eligible to participate in Tellurian’s defined contribution 401(k) plan, the Tellurian Services LLC 401(k) Retirement Plan (the “401(k) Plan”), on the same basis as all other employees. Tellurian matches 100% of the first 6% of a participant’s compensation that is contributed by an eligible participant to the 401(k) Plan, subject to the applicable limits imposed by the IRS Code. In addition to the 401(k) Plan, our NEOs are eligible to participate in all of our employee benefit plans, such as medical, dental, vision, group life, short and long-term disability, and supplemental life and accidental death and dismemberment insurance, in each case on the same basis as other employees (and subject to applicable law). NEOs are also eligible for vacation and other paid holidays that are generally available to Tellurian’s employees. We do not offer a defined benefit pension plan or a nonqualified deferred compensation plan to any of our employees or NEOs.
Employment, Severance and Change of Control Arrangements
During 2019, NEOs other than Mr. Lafargue were employed on an at-will basis, which means that Tellurian or the NEO can terminate the employment relationship at any time. During 2019, we did not maintain any severance or change of control plan or policy for the benefit of our NEOs other than Mr. Lafargue and our NEOs are not entitled to any cash severance benefits upon termination of employment for any reason. Mr. Lafargue previously entered into an employment agreement with Tellurian for a fixed term of three years that provided for severance benefits in the event of certain termination events, as described in greater detail under the heading “Potential Payments upon Termination or Change of Control”; however, the term of the employment agreement expired on February 10, 2020, and we did not renew the agreement.
Our NEOs are eligible for accelerated and/or continued vesting of their long-term incentive awards upon the occurrence of a change of control of Tellurian and/or certain termination events, as explained in greater detail under the heading “Potential Payments upon Termination or Change of Control.” In addition, on April 9, 2020, we entered into a letter agreement with Mr. Lafargue (the “Lafargue Letter Agreement”) in connection with his assumption of the position of Senior Vice President of LNG Marketing that provides that for purposes of any of Mr. Lafargue’s then-outstanding awards under our equity-based and other long-term performance incentive plans and programs, termination of employment for any reason will be treated as a termination of Mr. Lafargue’s employment without “cause,” entitling him to certain additional vesting benefits under the terms of such outstanding awards. The vesting benefits under the Lafargue Letter Agreement are subject to Mr. Lafargue’s compliance with certain restrictive covenants and his execution of a general release of claims in favor of the Company. The Lafargue Letter Agreement also makes certain adjustments to Mr. Lafargue’s compensation in connection with his new position.
Tax Considerations
In designing our compensation programs, we take into account the tax, accounting and disclosure rules associated with various forms of compensation, although the design of our programs is focused primarily on attracting and retaining the top talent in our industry and incentivizing those individuals to execute on the Company’s business strategy and to increase stockholder value.
For tax years beginning on or after January 1, 2018, the Tax Cuts and Jobs Act of 2017 generally eliminated the exception to the non-deductibility of compensation in excess of $1 million per year paid to certain executive officers of the Company (“covered employees”) under Section 162(m) of the IRS Code for certain qualified performance-based compensation, and expanded the scope of “covered employees” whose compensation may be subject to this deduction limit to include the Company’s chief financial officer and former covered employees of the Company for tax years beginning after December 31, 2016. We intend to design programs that recognize a range of performance criteria important to our success, even though compensation paid under such programs may not be deductible.
Under Section 280G and Section 4999 of the IRS Code, compensation that is granted, accelerated or enhanced upon the occurrence of a change in control may give rise, in whole or in part, to “excess parachute payments” and, to such extent, will be non-deductible by the Company and will be subject to a 20% excise tax payable by the executive. Our compensation arrangements do not provide for gross-ups for this excise tax.
Section 409A of the IRS Code requires that nonqualified deferred compensation be deferred and paid under plans or arrangements that satisfy the requirements of the statute with respect to the timing of deferral elections, the timing of payments and certain other matters. Failure to satisfy these requirements can expose our employees and other service providers to accelerated income tax liabilities and penalty taxes and interest on their vested compensation under such plans. We design our compensation programs with the intent that they comply with or be exempt from Section 409A of the IRS Code, although there is no guarantee that any particular element of compensation will, in fact, be so compliant or exempt. Our compensation arrangements do not provide for gross-ups for any penalty taxes or interest that may be imposed under Section 409A of the IRS Code.
Summary Compensation Table
The following table shows the compensation paid or accrued to the NEOs for the fiscal years ended December 31, 2019, December 31, 2018 and December 31, 2017.
Name and
Principal Position | | Year | | | Salary (1) | | | Bonus (2) | | | Stock Awards | | | Option Awards | | | All Other
Compen-
sation (3) | | | Total | |
| Meg A. Gentle, President and Chief | | | 2019 | | | $ | 701,615 | | | $ | — | | | $ | — | | | $ | — | | | $ | 26,134 | | | $ | 727,749 | |
| Executive Officer | | | 2018 | | | $ | 691,667 | | | $ | 549,999 | | | $ | — | | | $ | — | | | $ | 23,084 | | | $ | 1,264,750 | |
| | | | 2017 | | | $ | 534,231 | | | $ | 717,652 | | | $ | 260,305 | | | $ | 550,620 | | | $ | 12,724 | | | $ | 2,075,532 | |
| R. Keith Teague, Executive Vice | | | 2019 | | | $ | 501,154 | | | $ | — | | | $ | — | | | $ | — | | | $ | 25,900 | | | $ | 527,054 | |
| President and Chief Operating | | | 2018 | | | $ | 491,667 | | | $ | 500,000 | | | $ | 5,825,000 | | | $ | — | | | $ | 23,084 | | | $ | 6,839,751 | |
| Officer | | | 2017 | | | $ | 356,154 | | | $ | 717,652 | | | $ | 65,076 | | | $ | 307,800 | | | $ | 19,924 | | | $ | 1,466,606 | |
| Antoine J. Lafargue, Senior Vice | | | 2019 | | | $ | 394,385 | | | $ | 250,000 | | | $ | — | | | $ | — | | | $ | 22,239 | | | $ | 666,624 | |
| President of LNG Marketing and | | | 2018 | | | $ | 350,000 | | | $ | 524,994 | | | $ | — | | | $ | — | | | $ | 23,383 | | | $ | 898,377 | |
| former Chief Financial Officer | | | 2017 | | | $ | 344,930 | | | $ | 1,547,371 | | | $ | 11,224,000 | | | $ | 256,500 | | | $ | 227,164 | | | $ | 13,599,965 | |
| Daniel A. Belhumeur, Executive Vice | | | 2019 | | | $ | 400,923 | | | $ | — | | | $ | — | | | $ | — | | | $ | 22,067 | | | $ | 422,990 | |
| President, General Counsel and Chief | | | 2018 | | | $ | 391,667 | | | $ | 400,000 | | | $ | — | | | $ | — | | | $ | 20,428 | | | $ | 812,095 | |
| Compliance Officer | | | 2017 | | | $ | 267,115 | | | $ | 598,041 | | | $ | 74,844 | | | $ | 273,600 | | | $ | 17,560 | | | $ | 1,231,160 | |
| Khaled A. Sharafeldin, Chief | | | 2019 | | | $ | 350,808 | | | $ | — | | | $ | — | | | $ | — | | | $ | 21,974 | | | $ | 372,782 | |
| Accounting Officer | | | 2018 | | | $ | 344,583 | | | $ | 400,000 | | | $ | — | | | $ | — | | | $ | 2,795 | | | $ | 747,378 | |
| (1) | Effective as of February 17, 2019, each of our NEOs (other than Mr. Lafargue) received a 3% cost of living increase to his or her base salary. On December 4, 2019, the Board, upon the recommendation of the Compensation Committee, approved a base salary increase effective as of January 5, 2020 for Mr. Sharafeldin from $350,000 to $400,000. |
| (2) | On March 9, 2020 Mr. Lafargue received an annual discretionary bonus award for performance in 2019 that was paid in the form of restricted stock units, vesting in twelve substantially equal monthly installments beginning on June 1, 2020 and payable in shares of Tellurian common stock, cash of equal value, or a combination of both. The amount of Mr. Lafargue’s bonus for 2019, expressed in dollars as approved by the Board, is reported as “Bonus” for 2019. The number of restricted stock units issued to Mr. Lafargue on March 9, 2020 in respect of his discretionary bonus was determined by dividing the dollar amount of the bonus by $1.21, the closing price of Tellurian common stock on March 6, 2020. Because the grant of restricted stock units to Mr. Lafargue in respect of his 2019 annual bonus was not made during the fiscal year ended December 31, 2019, the grant is not reflected in the “Grants of Plan Based Awards” table for 2019. |
| (3) | The amounts entitled “All Other Compensation” for 2019 are detailed in the following table: |
| Name | | Premiums for Life
and Disability
Insurance Plans (1) | | | Company
Contributions to
401(k) Plans (2) | | | Total | |
| Meg A. Gentle | | $ | 9,334 | | | $ | 16,800 | | | $ | 26,134 | |
| R. Keith Teague | | $ | 9,100 | | | $ | 16,800 | | | $ | 25,900 | |
| Antoine J. Lafargue | | $ | 5,439 | | | $ | 16,800 | | | $ | 22,239 | |
| Daniel A. Belhumeur | | $ | 5,267 | | | $ | 16,800 | | | $ | 22,067 | |
| Khaled A. Sharafeldin | | $ | 5,335 | | | $ | 16,639 | | | $ | 21,974 | |
| (1) | Comprised of premiums for life and disability insurance. |
| (2) | Comprised of the value of the Company match in connection with the Company’s 401(k) defined contribution plan. |
Grants of Plan-Based Awards
The following table summarizes grants of awards to the NEOs during the fiscal year ended December 31, 2019 and possible future payouts pursuant to those awards.
| Name | | Grant date | | | Estimated future payouts
under non-equity incentive
plan awards
Target ($) | | | All other stock
awards: Number
of shares of
stock or
units (#) | | | Exercise or base
price of option
awards ($/Sh) | | | Grant date fair
value of stock and
option awards ($) | |
| Meg A. Gentle | | | 2/26/2019 | (2) | | | | | | | 59,945 | | | | | | | $ | 549,999 | |
| R. Keith Teague | | | 2/26/2019 | (2) | | | | | | | 49,950 | | | | | | | $ | 500,000 | |
| Antoine J. Lafargue (1) | | | 2/26/2019 | (2) | | | | | | | 52,447 | | | | | | | $ | 524,994 | |
| Daniel A. Belhumeur | | | 2/26/2019 | (2) | | | | | | | 39,960 | | | | | | | $ | 400,000 | |
| Khaled A. Sharafeldin | | | 2/26/2019 | (2) | | | | | | | 39,960 | | | | | | | $ | 400,000 | |
| (1) | This Grants of Plan-Based Awards table does not include the grant of restricted stock units to Mr. Lafargue in March 2020 as an annual discretionary bonus with respect to performance for 2019, as such grant was not made during the fiscal year ended December 31, 2019. However, this bonus is discussed under the heading “Components of Pay and 2019 Compensation Decisions—Discretionary Annual Bonus—2019 Annual Bonus Awards.” |
| (2) | Represents shares of fully vested Tellurian common stock awarded to our NEOs on February 26, 2019 (with a grant date value equal to $10.01 per share) as a discretionary bonus with respect to performance in the fiscal year ended December 31, 2018. Amounts reported represent the aggregate grant date fair value of the common stock awards calculated in accordance with FASB ASC Topic 718. The grant date values have been determined based on assumptions and methodologies discussed in Notes 1 and 13 of the Notes to the Consolidated Financial Statements included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2019. |
Outstanding Equity Awards at December 31, 2019
The following table summarizes information regarding unexercised options, stock that has not vested and equity incentive plan awards outstanding as of December 31, 2019 for each of the NEOs.
| | | Option Awards (1) | | | Stock Awards (2) | |
| | | | | | | | | Equity | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | incentive | | | | | | | | | | | | | | | Equity | | | Equity | |
| | | | | | | | | plan | | | | | | | | | | | | | | | incentive | | | incentive plan | |
| | | | | | | | | awards: | | | | | | | | | | | | | | | plan awards: | | | awards: | |
| | | Number of | | | Number of | | | Number of | | | | | | | | | Number | | | Market | | | Number of | | | Market or | |
| | | securities | | | securities | | | securities | | | | | | | | | of shares | | | value of | | | unearned | | | payout value | |
| | | underlying | | | underlying | | | underlying | | | | | | | | | or units | | | shares or | | | shares, units | | | of unearned | |
| | | un- | | | un- | | | un- | | | | | | | | | of stock | | | units of | | | or other | | | shares, units | |
| | | exercised | | | exercised | | | exercised | | | Option | | | | | | that have | | | stock that | | | rights that | | | or other rights | |
| | | options | | | options | | | unearned | | | exercise | | | Option | | | not | | | have not | | | have not | | | that have not | |
| | | (#) | | | Un- | | | options | | | price | | | expiration | | | vested | | | vested | | | vested | | | vested | |
| | | exercisable | | | exercisable | | | (#) | | | ($) | | | date | | | (#) | | | ($) | | | (#) (3) | | | ($)(4) | |
| Meg A. Gentle | | | 107,333 | | | | 53,667 | | | | — | | | $ | 10.32 | | | | 10/16/2027 | | | | — | | | | — | | | | 3,250,000 | | | | 23,660,000 | |
| R. Keith Teague | | | 60,000 | | | | 30,000 | | | | — | | | $ | 10.32 | | | | 10/16/2027 | | | | — | | | | — | | | | 3,750,000 | | | | 27,300,000 | |
| Antoine J. Lafargue | | | 50,000 | | | | 25,000 | | | | — | | | $ | 10.32 | | | | 10/16/2027 | | | | — | | | | — | | | | 650,000 | | | | 4,732,000 | |
| Daniel A. Belhumeur | | | 53,333 | | | | 26,667 | | | | — | | | $ | 10.32 | | | | 10/16/2027 | | | | — | | | | — | | | | 1,170,000 | | | | 8,517,600 | |
| Khaled A. Sharafeldin | | | 38,666 | | | | 19,334 | | | | — | | | $ | 10.32 | | | | 10/16/2027 | | | | — | | | | — | | | | 526,500 | | | | 3,832,920 | |
(1) | The final installment of the options will vest on October 16, 2020. If an NEO incurs a termination of service due to his or her death or “disability,” any unvested options will vest in full as of the date of termination (subject to compliance with certain obligations in the case of a termination due to “disability”) and remain exercisable for 12 months following termination. If an NEO is terminated without “cause,” he or she will vest in a pro-rata portion of his or her award based on the number of days worked in the total vesting period (subject to compliance with certain obligations), which will remain exercisable for 90 days following termination. If there is a “change of control” (or if any NEO is terminated without “cause” within one year following a “change of control”), the option award will vest in full as of the date of the “change of control” and remain exercisable until its expiration date. |
| (2) | This Outstanding Equity Awards table does not include the grant of restricted stock units to Mr. Lafargue in March 2020 as an annual discretionary bonus with respect to performance for 2019, as such grant was not made during the fiscal year ended December 31, 2019. However, this bonus is discussed under the heading “Components of Pay and 2019 Compensation Decisions—Discretionary Annual Bonus—2019 Annual Bonus Awards.” |
| (3) | This column represents awards of restricted shares of Tellurian common stock. All such restricted share FID awards will vest in full upon FID, except for 500,000 restricted shares granted to Mr. Teague, which vest as follows: (i) 166,666 of such restricted shares will vest upon FID, and (ii) 166,667 of such restricted shares will vest each on the first and second anniversaries of FID. |
| (4) | Market or payout value based on the $7.28 closing price of Tellurian common stock on the Nasdaq on December 31, 2019. |
Option Exercises and Stock Vested
The following table sets forth the aggregate dollar value realized by the NEOs upon the exercise of stock options and the vesting of stock awards during the fiscal year ended December 31, 2019.
| | | Stock awards | |
| Name | | Number of shares acquired on
vesting (#) | | | Value realized on
vesting ($) | |
| Meg A. Gentle | | | 54,945 | (1) | | $ | 549,999 | |
| R. Keith Teague | | | 49,950 | (1) | | $ | 500,000 | |
| Antoine J. Lafargue | | | 52,447 | (1) | | $ | 524,994 | |
| Daniel A. Belhumeur | | | 39,960 | (1) | | $ | 400,000 | |
| Khaled A. Sharafeldin | | | 39,960 | (1) | | $ | 400,000 | |
| (1) | Represents shares of fully vested Tellurian common stock awarded to our NEOs on February 26, 2019 (with a grant date value equal to $10.01 per share) as a discretionary bonus with respect to performance in the fiscal year ended December 31, 2018. |
Potential Payments upon Termination or Change of Control
Summary of Termination and Change of Control Benefits
As described above, we did not provide severance benefits for any of our executive officers other than Mr. Lafargue in 2019, although certain of our long-term incentive awards contain specialized vesting provisions applicable in the event of a termination of employment or a “change of control.” The following chart sets forth the effect of (i) various types of terminations and (ii) a “change of control” on Mr. Lafargue’s severance benefits pursuant to the employment agreement that expired on February 10, 2020 (and not renewed), as well as under our long-term cash and equity incentive awards. Following the expiration of Mr. Lafargue’s employment agreement, we do not have any contractual agreements or understandings with any of our named executive officers that provide for cash severance benefits. Please note that the following chart does not reflect the Lafargue Letter Agreement, as described in “Employment, Severance and Change of Control Arrangements” above.
Disability | | Death | | Termination without Cause | | Change of Control |
Mr. Lafargue Employment Agreement |
Continued payments of the then-current base salary through February 10, 2020, subject to execution of a general release of claims in favor of Tellurian. | | Continued payments of the then-current base salary through February 10, 2020, subject to execution of a general release of claims in favor of Tellurian. | | Continued payments of the then-current base salary through February 10, 2020, subject to execution of a general release of claims in favor of Tellurian. | | No single-trigger severance. |
Driftwood Incentive Program |
Full vesting of any portion of any Driftwood Incentive Program award allocated to any Phase for which the applicable NTP Date has occurred as of the date of such termination or within one year thereafter.
Any portion of a Driftwood Incentive Program award that does not vest in accordance with these terms will be forfeited on the first anniversary of the date of termination of service. | | Upon death before the occurrence of the NTP Date of a particular Phase, any portion of the Driftwood Incentive Program award allocated to such Phase will remain outstanding and eligible to become fully vested, subject to the occurrence of the applicable NTP Date before the Expiration Date.
Upon death on or after the occurrence of the NTP Date for a particular Phase, any unvested portion of an award allocated to such Phase will vest in full as of the date of such termination of service. | | Upon a “termination without cause” (which would include for each of our NEOs certain terminations by the NEO) before the NTP Date for a particular Phase, any unvested portion of a Driftwood Incentive Program award allocated to such Phase will remain outstanding and eligible to vest in accordance with the regular vesting schedule (subject to the occurrence of the NTP Date on or before the Expiration Date).
Upon a “termination without cause” on or after the NTP Date for a particular Phase, any unvested portion of an award allocated to such Phase will remain outstanding and eligible to vest in accordance with the regular vesting schedule.
Continued vesting is subject to (i) compliance of the NEO with any restrictive covenants to which it is subject, and (ii) the NEO’s execution of a release of claims. | | Upon the occurrence of a “change of control,” any unvested portion of any Driftwood Incentive Program award granted to our NEOs (other than Mr. Sharafeldin) will fully vest as of the date of the “change of control” if either (i) the applicable NEO has not experienced a termination of service prior to the “change of control” or (ii) subject to a release of claims and compliance with restrictive covenants, there has been a “termination without cause” within six months prior to the date of the “change of control.”
Mr. Sharafeldin’s Driftwood Incentive Program award will only vest in connection with a “change of control” if Mr. Sharafeldin incurs a “termination without cause” during the 12-month period following a “change of control,” subject to his continued compliance with restrictive covenants and a release of claims. |
Disability | | Death | | Termination without Cause | | Change of Control |
Teague FID Award |
Full vesting upon the date of such termination (subject to continued compliance with confidentiality obligations and restrictive covenants). | | Full vesting upon the date of such termination. | | Upon termination without “cause” before the FID date, any unvested portion of the award remains outstanding for five years following the date of termination, subject to his continued compliance with all confidentiality obligations and restrictive covenants and execution of a general release of claims.
Upon termination without “cause” on or after the FID date, any unvested portion of the award remains outstanding and vests in accordance with the regular vesting schedule, subject to his continued compliance with all confidentiality obligations and restrictive covenants and execution of a general release of claims. | | Full vesting upon the date of a “change of control.” |
Stock Option Awards |
Full vesting upon the date of such termination (subject to continued compliance with confidentiality obligations and restrictive covenants). | | Full vesting upon the date of such termination. | | Upon termination without “cause,” vest in a pro-rata portion of stock option award based on the number of days worked in the total vesting period (subject to continued compliance with all confidentiality obligations and restrictive covenants and execution of a general release of claims). | | Full vesting upon the date of a “change of control.” |
FID Restricted Stock Awards (Amended and Restated Tellurian Investments 2016 Omnibus Incentive Plan) |
Any unvested shares of restricted stock remain outstanding and continue to be subject to vesting upon the occurrence of FID, and subject to Compensation Committee discretion to accelerate vesting following termination. | | Any unvested shares of restricted stock remain outstanding and continue to be subject to vesting upon the occurrence of FID, subject to Compensation Committee discretion to accelerate vesting following termination. | | Any unvested shares of restricted stock remain outstanding and continue to be subject to vesting upon the occurrence of FID, subject to Compensation Committee discretion to accelerate vesting following termination. | | Upon the occurrence of a “change of control,” the Board or the Compensation Committee has the discretion to accelerate the vesting of all or any portion of the restricted stock award, cancel and cash out the restricted stock award, or issue substitute awards or otherwise assume and replace outstanding restricted stock awards. |
Lafargue FID Restricted Stock Award |
Any unvested shares of restricted stock remain outstanding and continue to be subject to vesting upon the occurrence of FID, subject to Compensation Committee discretion to accelerate vesting following termination. | | Any unvested shares of restricted stock remain outstanding and continue to be subject to vesting upon the occurrence of FID, subject to Compensation Committee discretion to accelerate vesting following termination. | | Any unvested shares of restricted stock remain outstanding and continue to be subject to vesting upon the occurrence of FID, subject to Compensation Committee discretion to accelerate vesting following termination. | | Full vesting upon the date of a “change of control.” |
Estimated Termination and Change of Control Benefits
The following table quantifies the dollar value of benefits that would have been received by the NEOs in the event of a “change of control” and/or had they experienced a termination of employment under various circumstances as of December 31, 2019 under the terms of their incentive and equity awards in effect on such date and, in the case of Mr. Lafargue, his employment agreement in effect on such date. The following table does not include the grant of restricted stock units to Mr. Lafargue in March 2020 as an annual discretionary bonus with respect to performance for 2019, as such grant was not made during the fiscal year ended December 31, 2019.
| Name | | Outstanding
Unvested
Options (1) | | | Outstanding
Driftwood
Construction
Incentive
Program (2) | | | Outstanding
Restricted
Stock /
RSUs (3) | | | Severance
Benefits (4) | | | Total | |
| Meg A. Gentle | | | | | | | | | | | | | | | | | | | | |
| Retirement | | | — | | | | — | | | | — | | | | — | | | | — | |
| Death, Disability | | | — | | | | — | | | $ | 23,660,000 | | | | — | | | $ | 23,660,000 | |
| Termination without Cause | | | — | | | | — | | | $ | 23,660,000 | | | | — | | | $ | 23,660,000 | |
| Termination for Good Reason | | | — | | | | — | | | | — | | | | — | | | | — | |
| Change of Control without Termination | | | — | | | $ | 35,000,000 | | | $ | 23,660,000 | | | | — | | | $ | 58,660,000 | |
| Termination in connection with a Change of Control | | | — | | | $ | 35,000,000 | | | $ | 23,660,000 | | | | — | | | $ | 58,660,000 | |
| R. Keith Teague | | | | | | | | | | | | | | | | | | | | |
| Retirement | | | — | | | | — | | | | — | | | | — | | | | — | |
| Death, Disability | | | — | | | | — | | | $ | 27,300,000 | | | | — | | | $ | 27,300,000 | |
| Termination without Cause | | | — | | | | — | | | $ | 27,300,000 | | | | — | | | $ | 27,300,000 | |
| Termination for Good Reason | | | — | | | | — | | | | — | | | | — | | | | — | |
| Change of Control without Termination | | | — | | | $ | 20,000,000 | | | $ | 27,300,000 | | | | — | | | $ | 47,300,000 | |
| Termination in connection with a Change of Control | | | — | | | $ | 20,000,000 | | | $ | 27,300,000 | | | | — | | | $ | 47,300,000 | |
| Antoine J. Lafargue (5) (6) | | | | | �� | | | | | | | | | | | | | | | |
| Retirement | | | — | | | | — | | | | — | | | | — | | | | — | |
| Death, Disability | | | — | | | | — | | | $ | 4,732,000 | | | $ | 45,603 | | | $ | 4,777,603 | |
| Termination without Cause | | | — | | | | — | | | $ | 4,732,000 | | | $ | 45,603 | | | $ | 4,777,603 | |
| Termination for Good Reason | | | — | | | | — | | | | — | | | | — | | | | — | |
| Change of Control without Termination | | | — | | | $ | 15,000,000 | | | $ | 4,732,000 | | | | — | | | $ | 19,732,000 | |
| Termination in connection with a Change of Control | | | — | | | $ | 15,000,000 | | | $ | 4,732,000 | | | $ | 45,603 | | | $ | 19,777,603 | |
| Daniel A. Belhumeur | | | | | | | | | | | | | | | | | | | | |
| Retirement | | | — | | | | — | | | | — | | | | — | | | | — | |
| Death, Disability | | | — | | | | — | | | $ | 8,517,600 | | | | — | | | $ | 8,517,600 | |
| Termination without Cause | | | — | | | | — | | | $ | 8,517,600 | | | | — | | | $ | 8,517,600 | |
| Termination for Good Reason | | | — | | | | — | | | | — | | | | — | | | | — | |
| Change of Control without Termination | | | — | | | $ | 15,000,000 | | | $ | 8,517,600 | | | | — | | | $ | 23,517,600 | |
| Termination in connection with a Change of Control | | | — | | | $ | 15,000,000 | | | $ | 8,517,600 | | | | — | | | $ | 23,517,600 | |
| Khaled A. Sharafeldin | | | | | | | | | | | | | | | | | | | | |
| Retirement | | | — | | | | — | | | | — | | | | — | | | | — | |
| Death, Disability | | | — | | | | — | | | $ | 3,832,920 | | | | — | | | $ | 3,832,920 | |
| Termination without Cause | | | — | | | | — | | | $ | 3,832,920 | | | | — | | | $ | 3,832,920 | |
| Termination for Good Reason | | | — | | | | — | | | | — | | | | — | | | | — | |
| Change of Control without Termination | | | — | | | | — | | | $ | 3,832,920 | | | | — | | | $ | 3,832,920 | |
| Termination in connection with a Change of Control | | | — | | | $ | 4,500,000 | | | $ | 3,832,920 | | | | — | | | $ | 8,332,920 | |
| (1) | All outstanding and unvested options held by our NEOs had an exercise price greater than the closing price of Tellurian common stock as of December 31, 2019 and the NEOs would, therefore, not be entitled to any payments with respect to their outstanding options upon the occurrence of a “change of control” or upon termination of employment for any reason as of December 31, 2019. |
| (2) | In the event of a “change of control,” the Driftwood Incentive Program awards granted to Ms. Gentle and Messrs. Teague, Lafargue and Belhumeur would fully vest and become payable, and the Driftwood Incentive Program awards granted to Mr. Sharafeldin would fully vest and become payable upon certain terminations of employment on or within 12 months following the “change of control.” No NTP Dates have occurred as of December 31, 2019 and, therefore, none of the NEOs have been entitled to any payments under their Driftwood Incentive Program awards solely upon a termination for any reason on December 31, 2019. However, in the event that an NTP Date were to occur following certain terminations of employment, the NEOs would be eligible to earn payments with respect to the applicable Phase under their Driftwood Incentive Program awards. If all of the NTP Dates had occurred as of December 31, 2019, our NEOs would have received the full amount of their Driftwood Incentive Program awards (the value of which is reflected in the above table for a “Termination in connection with a Change of Control”) upon a termination of their employment due to death or “disability.” Our NEOs would also have received full payment of their Driftwood Incentive Program awards (with the same value) if all of the NTP Dates had occurred as of December 31, 2019 upon a “termination without cause” (which, for all of our NEOs except Mr. Sharafeldin, would include a termination by the NEO for good reason under certain circumstances), but the amounts would become vested and payable over time on the regularly scheduled vesting dates. For more information regarding the treatment of the Driftwood Incentive Program awards upon the occurrence of a “change of control” or upon a termination of employment, see the chart above under the heading “Potential Payments upon Termination or Change of Control—Summary of Termination and Change of Control Benefits.” |
| (3) | Amounts are based on the value of all unvested shares of restricted stock and all unvested restricted stock units on December 31, 2019 and are calculated using the $7.28 closing price of Tellurian common stock on the Nasdaq on December 31, 2019. Contractual provisions vary among the different restricted stock grants and often provide that awards will remain outstanding and vest only if FID occurs; immediate accelerated vesting is generally permissive and not mandatory under most scenarios. The amounts set forth in the table, therefore, represent the maximum value of potential accelerated vesting as of December 31, 2019 and should not be viewed as indicative of the actual vesting that would occur in most scenarios. See “Summary of Termination and Change of Control Benefits” for additional details. |
| (4) | Pursuant to his employment agreement as in effect on December 31, 2019, if Mr. Lafargue’s employment is terminated without “cause” or as a result of his death, he (or his estate, as applicable) is entitled to continued payment of his then-current base salary for the remainder of the three-year term of his employment agreement ending on February 10, 2020, subject to his execution of a general release of claims in favor of the Company. The amount disclosed is based on Mr. Lafargue’s annual salary as in effect on December 31, 2019. Mr. Lafargue’s employment agreement expired on February 10, 2020, and we have not renewed the agreement. Mr. Lafargue is, therefore, not entitled to any cash severance payments upon any termination occurring after February 10, 2020. |
| (5) | The table does not take into account the Lafargue Letter Agreement, which generally provides that if Mr. Lafargue’s employment is terminated for any reason, any of Mr. Lafargue’s outstanding awards as of April 9, 2020 under our equity-based and other long-term incentive performance compensation plans and programs will be treated as though Mr. Lafargue incurred a termination without “cause” under the terms of each such award, as described in “Employment, Severance and Change of Control Arrangements” above. |
Non-Employee Director Compensation
Our non-employee director compensation program is intended to attract and retain highly qualified individuals to serve on our Board and provide leadership on strategic initiatives that are critical to growing our business and increasing stockholder value. For the fiscal year ended December 31, 2019, each of our non-employee directors received restricted stock awards under the Amended and Restated Tellurian Inc. 2016 Omnibus Incentive Compensation Plan, as amended (the “Tellurian“2016 Plan”), and the Amended and Restated Tellurian Investments Inc. 2016 Omnibus Incentive Plan (the “Legacy Plan”) with an intended value. The maximum number of $200,000. The restrictedshares of Tellurian common stock vests in substantially equal quarterly installments over a one-year period followingauthorized for issuance under the 2016 Plan is 40 million shares of common stock, and no further awards can be made under the Legacy Plan.
For the years ended December 31, 2022, 2021 and 2020, Tellurian recognized approximately $3.6 million, $6.0 million and $2.7 million, respectively, of share-based compensation expense related to all share-based awards. As of December 31, 2022, unrecognized compensation expense, based on the grant date subject to the director’s continued service. Unvestedfair value, for all share-based awards totaled approximately $179.7 million.
Restricted Stock
As of December 31, 2022, we had approximately 27.4 million shares of restricted stock become fully vestedprimarily performance-based Restricted Stock outstanding, of which approximately 15.7 million shares will vest entirely based upon terminationan affirmative FID by the Company’s
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Board of
service due to death or disability, or without cause or uponDirectors, as defined in the
occurrenceaward agreements, and approximately 11.0 million shares will vest in one-third increments at FID and the first and second anniversaries of
a changeFID. The remaining shares of
control.primarily performance-based Restricted Stock, totaling approximately 0.7 million shares, will vest based on other criteria. As of December 31, 2022, no expense had been recognized in connection with performance-based Restricted Stock.
The Board believes that compensating directors with restricted stock awards is appropriateapproximately 27.4 million shares of primarily performance-based and time-based Restricted Stock have been excluded from the computation of diluted loss per share because it directly links our directors’ interests to thoseincluding them in the computation would have been antidilutive for the periods presented.
Summary of our
stockholders and also enables our directors to obtain meaningful ownership of our stock through their service on the Board. The Compensation Committee, which is responsible for recommending non-employee director compensation to the Board, reviews the competitiveness of our non-employee director compensation program on an annual basis. In connection with its reviews, the Compensation Committee considered peer company director compensation data compiled by Pearl Meyer. Following its reviews, the Compensation Committee determined that it was appropriate to continue to compensate non-employee directors using only restricted stock awards.Ms. Gentle does not receive any additional compensation for her service as a member of our Board.
2019 Director Compensation Table
The table below summarizes the compensation paid to each director who was not an employee of the CompanyRestricted Stock transactions for the year ended December 31, 2019.
| Name | | Stock Awards (1) | | | All Other
Compensation (2) | | | Total | |
| Charif Souki | | $ | 192,206 | | | $ | 3,507 | | | $ | 195,713 | |
| Martin J. Houston | | $ | 192,206 | | | $ | 3,215 | | | $ | 195,421 | |
| Dillon J. Ferguson | | $ | 192,206 | | | $ | — | | | $ | 192,206 | |
| Diana Derycz-Kessler | | $ | 192,206 | | | $ | — | | | $ | 192,206 | |
| Brooke A. Peterson | | $ | 192,206 | | | $ | — | | | $ | 192,206 | |
| Don A. Turkleson | | $ | 192,206 | | | $ | — | | | $ | 192,206 | |
| Eric P. Festa (3) | | $ | — | | | $ | — | | | $ | — | |
| (1) | The amounts in this column represent the grant date fair value of 25,125 shares of restricted stock granted to each non-employee director on June 5, 2019 as compensation for their service on the Board. The grant date fair value is calculated in accordance with FASB ASC 718 by multiplying the number of shares of restricted stock issued on June 5, 2019 by the $7.65 closing price of Tellurian common stock on that date, and is, therefore, slightly different than the intended $200,000 value of each grant as described in the narrative above. The assumptions used in determining the grant date fair values of these awards are set forth in Notes 1 and 13 to our Consolidated Financial Statements included in our Annual Report on Form 10-K2022 (shares and units in thousands): | | | | | | | | | | | | | Shares | | Weighted-Average Grant
Date Fair Value | | Unvested at January 1, 2022 | 30,804 | | | $ | 6.43 | | Granted (1) | 1,420 | | | 4.46 | | | Vested | (399) | | | 4.34 | | | Forfeited | (4,399) | | | 5.36 | | | Unvested at December 31, 2022 | 27,426 | | | $ | 6.52 | |
(1) The weighted-average per share grant date fair values of Restricted Stock granted during the years ended December 31, 2021 and 2020 were $2.90 and $1.17, respectively. The total grant date fair value of restricted stock vested during the years ended December 31, 2022, 2021 and 2020 was approximately $1.7 million, $7.4 million and $11.7 million, respectively. Stock Options Participants in the 2016 Plan have been granted non-qualified options to purchase shares of common stock. Stock options are granted at a price not less than the market price of the common stock on the date of grant. Summary of our stock option transactions for the fiscal year ended December 31, 2019 filed with the SEC. |
The number of shares of unvested restricted stock held as of December 31, 2019 by each non-employee director for fiscal 2019 is detailed in the following table:
Name | | Unvested Shares of
Restricted Stock | |
Charif Souki | | | 12,563 | |
Martin J. Houston | | | 12,563 | |
Dillon J. Ferguson | | | 12,563 | |
Diana Derycz-Kessler | | | 12,563 | |
Brooke A. Peterson | | | 12,563 | |
Don A. Turkleson | | | 12,563 | |
Eric P. Festa | | | — | |
| (2) | All other compensation is comprised of club memberships for Mr. Souki and Mr. Houston. |
| (3) | Mr. Festa received no compensation from us for his service during 2019. Mr. Festa is the current Total designee on the Board pursuant to the 2017 Total Voting Agreement. |
Pay Ratio Disclosure
The following disclosure provides the median of the annual total compensation of all of Tellurian’s employees (excluding our CEO), the annual total compensation of our CEO and the resulting ratio of the annual total compensation of our CEO to the median of the annual total compensation of all of Tellurian’s employees (excluding our CEO) for the fiscal year ended December 31, 2019:
| | | CEO Compensation | | | Median Employee Compensation | |
 | | $ | 727,749 | | | $ | 232,278 | |
| | $ | — | | | $ | — | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Ratio of CEO pay to pay of median employee | | | | | | | | |
As of December 31, 2019, our total population consisted of 176 employees (including our CEO). Our CEO2022 (stock options in thousands):
| | | | | | | | | | | |
| Stock Options | | Weighted Average
Exercise Price |
| Outstanding at January 1, 2022 | 11,079 | | | $ | 5.07 | |
| Granted | — | | | — | |
| Exercised | — | | | — | |
| Forfeited or expired | (110) | | | 10.32 | |
| Outstanding at December 31, 2022 | 10,970 | | | 5.01 | |
| Exercisable at December 31, 2022 | 7,637 | | | $ | 4.80 | |
| | | |
The stock options that were granted to
median employee pay ratio is a
reasonable estimate calculated in accordance with Item 402(u) of Regulation S-K. We believe that there has been no change in our employee population or employee compensation arrangements in the fiscal year 2019 that would significantly impact our pay ratio disclosure and we have, therefore, used the same median employee for purposes of determining our pay ratio for the fiscal year 2019 as was used for the fiscal year 2018. To identify the median compensated employee in the fiscal year 2018, we used the aggregation of base salary or total wages (including overtime compensation) and target annual incentive bonus (expressed as a percentage of salary or annualized total wages (including overtime compensation)). We used target annual incentive bonus rather than actual bonus payments to identify the median employee due to the large number of employees hired throughout 2018, as use of target bonus provides a normalized, consistent and more accurate representation of the pay distribution of our workforce when considering such individuals. We also annualized base salary and wages for those individuals not employed for a full year in 2018, where SEC rules permitted, for purposes of identifying our median employee, in recognition of the significant number of new hires who were employed and compensated for only part of 2018. We excluded four non-U.S. employees, consisting of three employees in Singapore and one employee in Hungary, who accounted for all of the employees in those countries and less than 5% of our total employee population from our analysis. For purposes of calculating our pay ratio, compensation of the CEO and our median employee was determined by including employer retirement contributions and the value of certain insurance premiums.
Equity Compensation Plan Information
The following table provides information about our equity compensation plans as of December 31, 2019.
| Plan category | | Number of securities to
be issued upon exercise
of outstanding options,
warrants and rights (a) | | | Weighted-average
exercise price of
outstanding options,
warrants and rights (b) | | | Number of securities
remaining available for
future issuance under
equity compensation
plans (excluding
securities reflected in
column (a)) (c) |
| Equity compensation plans approved by security holders: | | | | | | | | | | | | |
| Amended and Restated Tellurian Inc. 2016 Omnibus Incentive Compensation Plan | | | 1,901,363 | | | $ | 10.32 | | | | 23,409,211 | (1) |
| Magellan Petroleum Corporation 2012 Omnibus Incentive Compensation Plan | | | 49,998 | | | $ | 14.40 | | | | — | |
| Magellan Petroleum Corporation 1998 Stock Incentive Plan | | | 87,500 | | | $ | 17.92 | | | | — | |
| Equity compensation plans not approved by security holders | | | — | | | $ | — | | | | — | |
| Total | | | 2,038,861 | | | $ | 10.75 | | | | 23,409,211 | |
| (1) | In determining the number of securities remaining available for future issuance under the Tellurian 2016 Plan, shares subject to awards of options or stock appreciation rights are counted as 0.4 shares for every share granted, and shares subject to other types of awards are counted as one share for every share granted. The 23,409,211 figure noted in the table above assumes that all future issuances under the Tellurian 2016 Plan are in the form of awards other than options or stock appreciation rights. If all future issuances under the Tellurian 2016 Plan were in the form of awards of options or stock appreciation rights, then there would be 58,523,027 securities remaining available for future issuance under the Tellurian 2016 Plan. |
Compensation Committee Interlocks and Insider Participation
No member of the Compensation Committee was,Company’s executive management team during the fiscal year ended December 31, 2019, an officer or employee2020 vest and become exercisable upon the achievement of the Company, and no such member has ever servedboth triggers as an officer offollows (stock options in thousands):
| | | | | | | | | | | | | | |
Service Trigger (1) | | Stock Price Trigger (2) | | Amount |
December 15, 2021 (3) | | $3.50 | | 3,333 |
December 15, 2022 (4) | | $4.50 | | 3,333 |
| December 15, 2023 | | $5.50 | | 3,334 |
| | | | 10,000 |
| | | | |
(1) Satisfied through continued employment or other service to the Company through the designated date. |
(2) Satisfied upon the Company’s common stock price closing at a price per share at or equal to the designated closing price for any ten consecutive trading days. |
(3) Vested during the year ended December 31, 2021. |
(4) Vested during the year ended December 31, 2022. |
The stock options granted during the Company. During the fiscal year ended December 31, 2019, none2020, expire on the fifth anniversary of the date of its grant.
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The fair value of each stock option awarded in 2020 was estimated using a Monte Carlo simulation and, due to the service trigger, is being recognized as compensation expense ratably over the vesting term. Valuation assumptions used to value stock options granted during the year ended December 31, 2020 were as follows:
| | | | | |
| Expected volatility | 113.6 | % |
| Expected dividend yields | — | % |
| Risk-free rate | 0.4 | % |
Due to our limited history, the expected volatility is based on a blend of our executive officers served as a directorhistorical annualized volatility and the implied volatility utilizing options quoted or membertraded. The expected dividend yield is based on historical yields on the date of grant. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of the grant.
There were no stock options exercised during any of the years ended December 31, 2022, 2021, and 2020. Further, the approximately 11.0 million stock options outstanding have been excluded from the computation of diluted loss per share because including them in the computation would have been antidilutive for the periods presented.
NOTE 15 — INCENTIVE COMPENSATION PROGRAM
On November 18, 2021, the Company’s Board of Directors approved the adoption of the Tellurian Incentive Compensation Program (the “Incentive Compensation Program” or “ICP”). The ICP allows the Company to award short-term and long-term performance and service-based incentive compensation
committee (or other committee serving an equivalent function)to full-time employees of
any other entity whose executive officers served on our Compensation Committee or the
Board.Compensation Committee Report
The Compensation Committee has reviewedCompany. ICP awards may be earned with respect to each calendar year and discussed the Compensation Discussion and Analysis with management and,are determined based on such review and discussions, has recommended to the Board that the Compensation Discussion and Analysis be included in this annual report.
Respectfully submittedguidelines established by the Compensation Committee of the Board of Directors,
Brooke A. Peterson (Chairman)
Diana Derycz-Kessler
Don A. Turkleson
as administrator of the ICP.
Short-term incentive awards
Short-term incentive (“STI”) awards are payable annually in cash at the discretion of the Company’s Board of Directors. Compensation expense for STI awards is recognized over the performance period when it is probable that the performance condition will be achieved. For the years ended December 31, 2022 and December 31, 2021, we recognized approximately $15.7 million and $26.2 million, respectively, in compensation expenses for STI awards.
Long-term incentive awards
Long-term incentive (“LTI”) awards under the ICP were granted in January 2022 in the form of “tracking units,” at the discretion of the Company’s Board of Directors (the “2021 LTI Award”). Each such tracking unit has a value equal to one share of Tellurian common stock and entitles the grantee to receive, upon vesting, a cash payment equal to the closing price of our common stock on the trading day prior to the vesting date. These tracking units will vest in three equal tranches at grant date, and the first and second anniversaries of the grant date. Non-vested tracking unit awards as of December 31, 2022, and awards granted during the period were as follows:
| | | | | | | | | | | |
| Number of Tracking Units (in thousands) | | Price per Tracking Unit |
| Balance at January 1, 2022 | — | | | — | |
| Granted | 19,332 | | | $ | 3.09 | |
| Vested | (6,444) | | | 3.38 | |
| Forfeited | (169) | | | 3.40 | |
| Unvested balance at December 31, 2022 | 12,719 | | | $ | 1.68 | |
We recognize compensation expense for awards with graded vesting schedules over the requisite service periods for each separately vesting portion of the award as if each award was in substance multiple awards. Compensation expense for the first tranche of the 2021 LTI Award that vested at the grant date was recognized over the performance period when it was probable that the performance condition was achieved. Compensation expense for the second and third tranches of the 2021 LTI Award is recognized on a straight-line basis over the requisite service periods. Compensation expense for unvested tracking units is subsequently adjusted each reporting period to reflect the estimated payout levels based on changes in the Company’s stock price and actual forfeitures. For the year ended December 31, 2021, we recognized approximately $19.9 million in compensation expenses for LTI awards that have been earned over the 2021 performance period.
As of December 31, 2022, no tracking units for LTI awards had been granted under the ICP for the December 31, 2022 fiscal period. For the year ended December 31, 2022, we recognized approximately $10.3 million in compensation expenses for LTI awards that have been earned over the 2022 performance period.
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 16 — INCOME TAXES
Income tax benefit (provision) included in our reported net loss consisted of the following (in thousands):
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| Current: | | | | | |
| Federal | $ | — | | | $ | — | | | $ | — | |
| State | — | | | — | | | — | |
| Foreign | — | | | — | | | — | |
| Total Current | — | | | — | | | — | |
| Deferred: | | | | | |
| Federal | — | | | — | | | — | |
| State | — | | | — | | | — | |
| Foreign | — | | | — | | | — | |
| Total Deferred | — | | | — | | | — | |
| Total income tax benefit (provision) | $ | — | | | $ | — | | | $ | — | |
The sources of loss from operations before income taxes were as follows (in thousands): | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| Domestic | $ | (36,591) | | | $ | (111,114) | | | $ | (202,831) | |
| Foreign | (13,219) | | | (3,624) | | | (7,865) | |
| Total loss before income taxes | $ | (49,810) | | | $ | (114,738) | | | $ | (210,696) | |
The reconciliation of the federal statutory income tax rate to our effective income tax rate is as follows:
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| Income tax benefit (provision) at U.S. statutory rate | $ | 10,460 | | | $ | 24,095 | | | $ | 44,246 | |
| Share-based compensation | (126) | | | 1,352 | | | — | |
| Executive compensation | (3,688) | | | (203) | | | — | |
| Change in U.S. state tax rate | (1,313) | | | — | | | — | |
| Change in foreign tax rate | 1,816 | | | — | | | — | |
| U.S. state tax | 792 | | | 4,333 | | | 8,563 | |
| Change in valuation allowance | (8,871) | | | (29,648) | | | (49,802) | |
| R&D Credit | 748 | | | 524 | | | 524 | |
| Foreign rate differential | 516 | | | (74) | | | (168) | |
| Other | (334) | | | (379) | | | (3,363) | |
| Total income tax benefit (provision) | $ | — | | | $ | — | | | $ | — | |
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Significant components of our deferred tax assets and liabilities are as follows (in thousands):
| | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 |
| Deferred tax assets: | | | |
| Capitalized costs | $ | 85,875 | | | $ | 75,315 | |
| Compensation and benefits | 8,860 | | | 12,403 | |
| Lease liability | 16,086 | | | 15,514 | |
| Disallowed interest expense carryforward | 3,510 | | | — | |
| Net operating loss carryforwards and credits: | | | |
| Federal | 99,922 | | | 80,246 | |
| State | 16,142 | | | 13,406 | |
| Foreign | 11,023 | | | 5,687 | |
| Other, net | 7,080 | | | 2,993 | |
| Deferred tax assets | 248,498 | | | 205,564 | |
| Less valuation allowance | (211,157) | | | (201,366) | |
| Deferred tax assets, net of valuation allowance | 37,341 | | | 4,198 | |
| | | |
| Deferred tax liabilities | | | |
| Property and equipment | (37,341) | | | (4,198) | |
| Net deferred tax assets | $ | — | | | $ | — | |
As of December 31, 2022, we had federal, state and international net operating loss (“NOL”) carryforwards of approximately $453.6 million, $303.9 million and $45.6 million, respectively. Approximately $495.9 million of these NOLs have an indefinite carryforward period. All other NOLs will expire between 2036 and 2040.
Due to our historical losses and other available evidence related to our ability to generate taxable income, we have established a valuation allowance to fully offset our federal, state and international deferred tax assets as of December 31, 2022 and 2021. We will continue to evaluate the realizability of our deferred tax assets in the future. The increase in the valuation allowance was approximately $9.8 million for the year ended December 31, 2022.
In addition, we experienced a Section 382 ownership change in April 2017. An analysis of the annual limitation on the utilization of our NOLs was performed in accordance with IRC Section 382. It was determined that IRC Section 382 will not materially limit the use of our NOLs over the carryover period. We will continue to monitor trading activity in our shares which could cause an additional ownership change. If the Company experiences a Section 382 ownership change, it could further affect our ability to utilize our existing NOL carryforwards.
As of December 31, 2022, the Company determined that it has no uncertain tax positions, interest or penalties as defined within ASC 740-10. The Company does not have unrecognized tax benefits. The Company does not believe that it is reasonably possible that the total unrecognized benefits will significantly increase within the next 12 months.
We are subject to tax in the U.S. and various state and foreign jurisdictions. Federal and state tax returns filed with each jurisdiction remain open to examination under the normal three-year statute of limitations.
Pursuant to ASC 740-30-25-17, the Company recognizes deferred tax liabilities associated with outside basis differences on investments in foreign subsidiaries unless the difference is considered essentially permanent in duration. As of December 31, 2022, the Company has not recorded any deferred taxes on unremitted earnings as the Company has no undistributed earnings and profits. If circumstances change in the foreseeable future and it becomes apparent that some or all of the undistributed earnings and profits will not be reinvested indefinitely, or will be remitted in the foreseeable future, a deferred tax liability will be recorded for some or all of the outside basis difference.
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 17 — LEASES
Our land leases are classified as finance leases and include one or more options to extend the lease term for up to 40 years, as well as to terminate the lease within five years, at our sole discretion. We are reasonably certain that those options will be exercised, and that our termination rights will not be exercised, and we have, therefore, included those assumptions within our right of use assets and corresponding lease liabilities. Our office space leases are classified as operating leases and include one or more options to extend the lease term up to 10 years, at our sole discretion. As we are not reasonably certain that those options will be exercised, none are recognized as part of our right of use assets and lease liabilities. As none of our leases provide an implicit rate, we have determined our own discount rate.
The following table shows the classification and location of our right-of-use assets and lease liabilities on our Consolidated Balance Sheets (in thousands):
| | | | | | | | | | | | | | |
| | December 31, |
| Leases | Consolidated Balance Sheets Classification | 2022 | | 2021 |
| Right of use asset | | | | |
| Operating | Other Non-Current Assets | $ | 13,303 | | | $ | 10,166 | |
| Finance | Property, plant and equipment, net | 56,708 | | | 57,883 | |
| Total Leased Assets | | $ | 70,011 | | | $ | 68,049 | |
| Liabilities | | | | |
| Current | | | | |
| Operating | Accrued and other liabilities | $ | 2,734 | | | $ | 2,147 | |
| Finance | Accrued and other liabilities | 140 | | | 132 | |
| Non-Current | | | | |
| Operating | Other non-current liabilities | 12,148 | | | 9,563 | |
| Finance | Finance lease liabilities | 49,963 | | | 50,103 | |
| Total leased liabilities | | $ | 64,985 | | | $ | 61,945 | |
Lease costs recognized in our Consolidated Statements of Operations is summarized as follows (in thousands):
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| Lease Costs | 2022 | | 2021 | | 2020 |
| Operating lease cost | $ | 3,149 | | | $ | 2,519 | | | $ | 2,741 | |
| Finance lease cost | | | | | |
| Amortization of lease assets | 1,174 | | | 788 | | | 367 | |
| Interest on lease liabilities | 3,978 | | | 2,904 | | | 1,694 | |
| Finance lease cost | $ | 5,152 | | | $ | 3,692 | | | $ | 2,061 | |
| Total lease cost | $ | 8,301 | | | $ | 6,211 | | | $ | 4,802 | |
Other information about lease amounts recognized in our Consolidated Financial Statements is as follows:
| | | | | | | | | | | |
| December 31, |
| Lease term and discount rate | 2022 | | 2021 |
| Weighted average remaining lease term (years) | | | |
| Operating lease | 4.5 | | 4.7 |
| Finance lease | 48.4 | | 49.4 |
| Weighted average discount rate | | | |
| Operating lease | 6.2 | % | | 8.0 | % |
| Finance lease | 9.4 | % | | 9.4 | % |
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following shows other quantitative information for our operating and finance leases (in thousands):
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| . | 2022 | | 2021 | | 2020 |
| Cash paid for amounts included in the measurement of lease liabilities: | | | | | |
| Operating cash flows from operating leases | $ | 3,423 | | | $ | 2,953 | | | $ | 2,847 | |
| Operating cash flows from finance leases | $ | 3,674 | | | $ | 1,813 | | | $ | 1,056 | |
| Financing cash flows from finance leases | $ | 132 | | | $ | 1,926 | | | $ | 1,777 | |
The table below presents an analysis of the maturity of our lease liability on an undiscounted basis and reconciles those amounts to the present value of the lease liability as of December 31, 2022 (in thousands):
| | | | | | | | | | | |
| Operating | | Finance |
| 2023 | $ | 3,581 | | | $ | 4,111 | |
| 2024 | 3,848 | | | 4,111 | |
| 2025 | 3,891 | | | 4,111 | |
| 2026 | 3,913 | | | 4,111 | |
| 2027 | 1,665 | | | 4,111 | |
| After 2027 | 275 | | | 178,111 | |
| Total lease payments | $ | 17,173 | | | $ | 198,666 | |
| Less: discount | 2,291 | | | 148,563 | |
| Present value of lease liability | $ | 14,882 | | | $ | 50,103 | |
NOTE 18 — SUPPLEMENTAL CASH FLOW INFORMATION
The following table provides information regarding the net changes in working capital (in thousands):
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| Accounts receivable | $ | (67,462) | | | $ | (4,770) | | | $ | 506 | |
| Prepaid expenses and other current assets | 5,801 | | | (2,536) | | | 6,915 | |
| Accounts payable | 1,953 | | | (5,514) | | | (1,069) | |
| Accounts payable due to related parties | — | | | (910) | | | 910 |
| Accrued liabilities | 44,548 | | | 55,884 | | | (6,842) | |
| Other, net | (793) | | | (1,137) | | | (1,986) | |
| Net changes in working capital | $ | (15,953) | | | $ | 41,017 | | | $ | (1,566) | |
The following table provides supplemental disclosure of cash flow information (in thousands):
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| Non-cash accruals of property, plant and equipment and other non-current assets | $ | 13,323 | | | $ | 56,305 | | | $ | 8,370 | |
| Non-cash settlement of Final Payment Fee | — | | | — | | | 8,539 | |
| | | | | |
| | | | | |
| Non-cash settlement of withholding taxes associated with the 2019 bonus paid and vesting of certain awards | — | | | 3,064 | | | 1,659 | |
| Non-cash settlement of the 2019 bonus paid | — | | | 5,430 | | | 7,602 | |
| Asset retirement obligation additions and revisions | 1,533 | | | 76 | | | — | |
For the year ended December 31, 2020, the statement of cash flows reflects approximately $78.5 million and $2.1 million in non-cash movements related to the 2019 Term Loan and the Replacement Warrant, respectively.
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the Condensed Consolidated Balance Sheets that sum to the total of such amounts shown in the Condensed Consolidated Statements of Cash Flows (in thousands):
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2022 | | 2021 | | 2020 |
| Cash and cash equivalents | | $ | 474,205 | | | $ | 305,496 | | | $ | 78,297 | |
| Current restricted cash | | 9,375 | | | — | | | — | |
| Non-current restricted cash | | 24,888 | | | 1,778 | | | 3,440 | |
| Total cash, cash equivalents and restricted cash in the statement of cash flows | | $ | 508,468 | | | $ | 307,274 | | | $ | 81,737 | |
NOTE 19 — DISCLOSURE ABOUT SEGMENTS AND RELATED INFORMATION
During the quarter ended June 30, 2022, the Company commenced construction of the Driftwood terminal under the Phase 1 EPC Agreement with Bechtel. The Company also continued to increase its natural gas presence in the Haynesville Shale basin in northern Louisiana through the acquisition of mineral rights and natural gas drilling and marketing activities. The Company’s Chief Operating Decision Maker (“CODM”) determined to place additional emphasis on operating cash flows generated by our upstream and natural gas marketing business activities. Consequently, we identified the Upstream, Midstream and Marketing & Trading components as the Company’s operating segments. The Company’s prior period information was retrospectively revised to reflect this change in reportable segments.
These functions have been defined as the operating segments of the Company because (1) they are engaged in business activities from which revenues are recognized and expenses are incurred, (2) their operating results are regularly reviewed by the Company’s CODM to make decisions about resources to be allocated to the segment and to assess its performance, and (3) they are segments for which discrete financial information is available.
Factors used to identify these operating segments are based on the nature of the business activities that are undertaken by each component. The Upstream segment is organized and operates to produce, gather and deliver natural gas and to acquire and develop natural gas assets. The Midstream segment is organized to develop, construct and operate LNG terminals and pipelines. The Marketing & Trading segment is organized and operates to purchase and sell natural gas produced primarily by the Upstream segment, market the Driftwood terminal’s LNG production capacity and trade LNG. These operating segments represent the Company’s reportable segments. The remainder of our business is presented as “Corporate,” and consists of corporate costs and intersegment eliminations. The Company’s CODM does not currently assess segment performance or allocate resources based on a measure of total assets. Accordingly, a total asset measure has not been provided for segment disclosure.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year ended December 31, 2022 | | Upstream | | Midstream | | Marketing & Trading | | Corporate | | Consolidated | |
Revenues from external customers (1) | | $ | 15,993 | | | $ | — | | | $ | 375,933 | | | $ | — | | | $ | 391,926 | | |
Intersegment revenues (purchases) (2) (3) | | 254,984 | | | (1,760) | | | (241,229) | | | (11,995) | | | — | | |
Segment operating income (loss) (4) | | 130,663 | | | (80,626) | | | (31,192) | | | (36,618) | | | (17,773) | | |
| Interest expense, net | | — | | | (1,751) | | | (454) | | | (11,655) | | | (13,860) | | |
| Gain on extinguishment of debt, net | | — | | | — | | | — | | | — | | | — | | |
| Other income (loss), net | | 3,770 | | | — | | | (22,912) | | | 964 | | | (18,177) | | |
| Consolidated loss before tax | | | | | | | | | | $ | (49,810) | | |
TELLURIAN INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year ended December 31, 2021 | | Upstream | | Midstream | | Marketing & Trading | | Corporate | | Consolidated |
Revenues from external customers (1) | | $ | 2,317 | | | $ | — | | | $ | 68,958 | | | $ | — | | | $ | 71,275 | |
Intersegment revenues (purchases) (2) (3) | | 49,182 | | | — | | | (44,755) | | | (4,427) | | | — | |
Segment operating loss (4) | | (5,651) | | | (42,040) | | | (22,889) | | | (42,153) | | | (112,733) | |
| Interest expense, net | | (1,642) | | | (4,722) | | | — | | | (3,014) | | | (9,378) | |
| Gain on extinguishment of debt, net | | (665) | | | 2,087 | | | — | | | — | | | 1,422 | |
| Other (loss) income , net | | (1,284) | | | (2,494) | | | 9,460 | | | 269 | | | 5,951 | |
| Consolidated loss before tax | | | | | | | | | | $ | (114,738) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year ended December 31, 2020 | | Upstream | | Midstream | | Marketing & Trading | | Corporate | | Consolidated | |
Revenues from external customers (1) | | $ | 2,358 | | | $ | — | | | $ | 35,076 | | | $ | — | | | $ | 37,434 | | |
Intersegment revenues (purchases) (2) | | 28,083 | | | — | | | (28,083) | | | — | | | — | | |
Segment operating loss (4) | | (100,788) | | | (15,027) | | | (13,886) | | | (36,938) | | | (166,639) | | |
| Interest expense, net | | (6,215) | | | (14,424) | | | — | | | (22,806) | | | (43,445) | | |
| Other income (loss), net | | 2,452 | | | 195 | | | (408) | | | (2,851) | | | (612) | | |
| Consolidated loss before tax | | | | | | | | | | $ | (210,696) | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(1) The Marketing & Trading segment markets to third party-purchasers most of the Company's natural gas production from the Upstream segment. | |
(2) The Marketing & Trading segment purchases most of the Company’s natural gas production from the Upstream segment. Intersegment revenues are eliminated at consolidation. | |
(3) Intersegment revenues related to the Marketing & Trading segment are a result of cost allocations to the Corporate component using a cost plus transfer pricing methodology. Intersegment revenues are eliminated at consolidation. | |
(4) Operating profit (loss) is defined as operating revenues less operating costs and allocated corporate costs. | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, | | | |
| Capital expenditures | | 2022 | | 2021 | | 2020 | | | | | |
| Upstream | | $ | 347,240 | | | $ | 32,364 | | | $ | 1,307 | | | | | | |
| Midstream | | 199,283 | | | 25,501 | | | — | | | | | | |
| Marketing & Trading | | 675 | | | — | | | — | | | | | | |
| Total capital expenditures for reportable segments | | 547,198 | | | 57,865 | | | 1,307 | | | | | | |
| Corporate capital expenditures | | 5,690 | | | — | | | — | | | | | | |
| Consolidated capital expenditures | | $ | 552,888 | | | $ | 57,865 | | | $ | 1,307 | | | | | | |
NOTE 20 — SUBSEQUENT EVENTS
In February 2023, the Company was assigned the rights and obligations of an unrelated third party in certain land lease agreements. Total consideration paid was approximately $24.6 million, of which approximately $6.6 million was paid in 2022. The Company is currently unable to estimate the impact of the land lease agreements on the Company’s consolidated financial statements.
TELLURIAN INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
SUPPLEMENTAL DISCLOSURES ABOUT NATURAL GAS PRODUCING ACTIVITIES
In accordance with FASB and SEC disclosure requirements for natural gas producing activities, this section provides supplemental information on Tellurian’s natural gas producing activities in six separate tables. Tables I through III provide historical cost information pertaining to costs incurred in exploration, property acquisitions and development; capitalized costs; and results of operations. Tables IV through VI present information on the Company’s estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves and changes in estimated discounted future net cash flows.
Table I — Capitalized Costs Related to Natural Gas Producing Activities
Capitalized costs related to Tellurian’s natural gas producing activities are summarized as follows (in thousands):
| | | | | | | | | | | | | | | | | |
| December 31, |
| 2022 | | 2021 | | 2020 |
| Proved properties | $ | 468,351 | | | $ | 113,950 | | | $ | 62,718 | |
| Unproved properties | — | | | — | | | — | |
| Gross capitalized costs | 468,351 | | | 113,950 | | | 62,718 | |
| Accumulated DD&A | (92,423) | | | (48,637) | | | (37,639) | |
| Net capitalized costs | $ | 375,928 | | | $ | 65,313 | | | $ | 25,079 | |
Table II — Costs Incurred in Property Acquisitions,Exploration and Development
Costs incurred in natural gas property acquisition (inclusive of producing well costs), exploration and development activities are summarized as follows (in thousands):
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| Property acquisitions: | | | | | |
| Proved | $ | 135,974 | | | $ | 3,409 | | | $ | 1,307 | |
| Unproved | — | | | — | | | — | |
| Exploration costs | — | | | — | | | — | |
| Development costs | 210,546 | | | 28,955 | | | — | |
| Costs incurred | $ | 346,520 | | | $ | 32,364 | | | $ | 1,307 | |
Table III — Results of Operations for Natural Gas Producing Activities
The following table includes revenues and expenses directly associated with our natural gas and condensate producing activities. It does not include any interest costs or indirect general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our natural gas operations. Tellurian’s results of operations from natural gas and condensate producing activities for the periods presented are as follows (in thousands):
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| Natural gas sales | $ | 270,977 | | | $ | 51,499 | | | $ | 30,441 | |
| Operating costs | 53,963 | | | 20,576 | | | 15,814 | |
| Depreciation, depletion and amortization | 43,966 | | | 10,998 | | | 16,703 | |
| Impairment charge | — | | | — | | | 81,065 | |
| Total operating costs and expenses | 97,929 | | | 31,574 | | | 113,582 | |
| Results of operations | $ | 173,048 | | | $ | 19,925 | | | $ | (83,141) | |
TELLURIAN INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Table IV — Natural Gas Reserve Quantity Information
Our estimated proved reserves are located in Louisiana. We caution that there are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. Accordingly, these estimates are expected to change as further information becomes available. Material revisions of reserve estimates may occur in the future, development and production of the natural gas and condensate reserves may not occur in the periods assumed, and actual prices realized and actual costs incurred may vary significantly from those used in these estimates.
The estimates of our proved reserves as of December 31, 2022, 2021 and 2020 have been prepared by Netherland, Sewell & Associates, Inc., independent petroleum consultants.
| | | | | | | | | | | | | | | | | |
| Gas
(MMcf) | | Condensate
(Mbbl) | | Gas Equivalent
(MMcfe) |
| Proved reserves: | | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| December 31, 2019 | 268,538 | | | — | | | 268,538 | |
| Extensions, discoveries and other additions | — | | | — | | | — | |
| Revisions of previous estimates | (152,132) | | | — | | | (152,132) | |
| Production | (16,898) | | | — | | | (16,898) | |
| Sale of reserves-in-place | — | | | — | | | — | |
| Purchases of reserves-in-place | — | | | — | | | — | |
| December 31, 2020 | 99,508 | | | — | | | 99,508 | |
| Extensions, discoveries and other additions | 202,897 | | | — | | | 202,897 | |
| Revisions of previous estimates | 35,237 | | | — | | | 35,237 | |
| Production | (14,306) | | | — | | | (14,306) | |
| Sale of reserves-in-place | — | | | — | | | — | |
| Purchases of reserves-in-place | — | | | — | | | — | |
| December 31, 2021 | 323,336 | | | — | | | 323,336 | |
| Extensions, discoveries and other additions | 113,047 | | | — | | | 113,047 | |
| Revisions of previous estimates | (52,185) | | | — | | | (52,185) | |
| Production | (47,322) | | | — | | | (47,322) | |
| Sale of reserves-in-place | — | | | — | | | — | |
| Purchases of reserves-in-place | 108,017 | | | — | | | 108,017 | |
| December 31, 2022 | 444,893 | | | — | | | 444,893 | |
| Proved developed reserves: | | | | | |
| | | | | |
| December 31, 2020 | 26,593 | | | — | | | 26,593 | |
| December 31, 2021 | 73,927 | | | — | | | 73,927 | |
| December 31, 2022 | 218,382 | | | — | | | 218,382 | |
| Proved undeveloped reserves: | | | | | |
| | | | | |
| December 31, 2020 | 72,915 | | | — | | | 72,915 | |
| December 31, 2021 | 249,409 | | | — | | | 249,409 | |
| December 31, 2022 | 226,511 | | | — | | | 226,511 | |
2021 to 2022 Overall Reserve Changes
•The Company added 113 Bcfe of proved reserves comprised of 89 Bcfe from additional proved undeveloped locations and 24 Bcfe of proved developed reserves from drilling activities.
•The Company had total negative revisions of approximately 52 Bcfe, comprised primarily of a 38 Bcfe negative revision from removing proved undeveloped locations that now fall outside of the SEC mandated five-year development window, a 25 Bcfe negative revision from changes in lateral lengths and ownership, a 3 Bcfe negative revision from increased operational costs, partially offset by an 8 Bcfe positive revision from improved well performance, and a 6 Bcfe positive revision due to an increase in commodity prices. The removal of the proved
TELLURIAN INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
undeveloped locations that fell outside of the five-year development window resulted from a re-prioritization of activity due to (i) our asset acquisition and (ii) unanticipated third party development activity that caused an existing well to be shut in and unable to return to production and thereby required us to alter our drilling schedule to preserve the affected leases.
•During the year ending December 31, 2022, we acquired approximately 108 Bcfe primarily related to the acquisition of natural gas assets.
2021 to 2022 PUD Changes
•The Company added approximately 89 Bcfe from additional proved undeveloped locations.
•The Company had total negative revisions of approximately 44 Bcfe, comprised of a 38 Bcfe negative revision from removing proved undeveloped locations that now fall outside of the SEC mandated five-year development window, a 13 Bcfe negative revision from changes in lateral lengths and ownership, partially offset by a 5 Bcfe positive revision from improved well performance, and a 2 Bcfe positive revision due to an increase in commodity prices.
•During the year ending December 31, 2022, we acquired approximately 71 Bcfe of proved undeveloped reserves primarily related to the acquisition of natural gas assets.
•The Company converted approximately 138 Bcfe from proved undeveloped reserves to proved developed reserves.
2020 to 2021 Overall Reserve Changes
•Added 203 Bcfe of proved reserves comprised of 152 Bcfe from additional proved undeveloped locations and 51 Bcfe of proved developed reserves from drilling activities.
•Had total positive revisions of approximately 35 Bcfe, comprised primarily of a 9 Bcfe positive revision due to an increase in commodity prices, a 15 Bcfe positive revision from changes in ownership and an 11 Bcfe positive revision from improved well performance.
2020 to 2021 PUD Changes
•Added approximately 152 Bcfe from additional proved undeveloped locations.
•Had total positive revisions of approximately 25 Bcfe, comprised of a 3 Bcfe positive revision due to an increase in commodity prices, a 16 Bcfe positive revision from changes in ownership and a 6 Bcfe positive revision from improved well performance.
2019 to 2020 Overall Reserve Changes
•Had total negative revisions of approximately 152 Bcfe, comprised primarily of a 149 Bcfe negative revision due to the downturn in commodity prices and a 17 Bcfe negative revision from the loss of leases. These downward revisions were offset by a 14 Bcfe positive revision due to improved well performance.
2019 to 2020 PUD Changes
•Had total negative revisions of approximately 165 Bcfe, comprised of a 148 Bcfe negative revision due to the downturn in commodity prices and a 17 Bcfe negative revision from lease expirations.
TELLURIAN INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Table V — Standardized Measure of Discounted Future Net Cash Flows Related to Proved Natural Gas Reserves
ASC 932 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. Tellurian has followed these guidelines, which are briefly discussed below.
Future cash inflows and future production and development costs as of December 31, 2022, 2021 and 2020 were determined by applying the average of the first-day-of-the-month prices for the 12 months of the year and year-end costs to the estimated quantities of natural gas and condensate to be produced. Actual future prices and costs may be materially higher or lower than the prices and costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on the continuation of the economic conditions applied for that year. Estimated future income taxes are computed using current statutory income tax rates, including consideration of the current tax basis of the properties and related carryforwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.
The assumptions used to compute the standardized measure are those prescribed by the FASB and do not necessarily reflect our expectations of actual revenue to be derived from those reserves or their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.
The following summary sets forth our future net cash flows relating to proved natural gas and condensate reserves based on the standardized measure (in thousands):
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2022 | | 2021 | | 2020 |
| Future cash inflows | $ | 2,441,930 | | | $ | 945,651 | | | $ | 132,563 | |
| Future production costs | (341,925) | | | (133,909) | | | (34,624) | |
| Future development costs | (360,107) | | | (211,836) | | | (71,557) | |
| Future income tax provisions | (257,908) | | | (54,401) | | | — | |
| Future net cash flows | 1,481,990 | | | 545,505 | | | 26,382 | |
| Less effect of a 10% discount factor | (445,686) | | | (181,302) | | | (19,497) | |
| Standardized measure of discounted future net cash flows | $ | 1,036,304 | | | $ | 364,203 | | | $ | 6,885 | |
TELLURIAN INC.
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Table VI — Changes in Standardized Measure of Discounted Future Net Cash Flows Related to Proved Natural Gas Reserves
The following sets forth the changes in the standardized measure of discounted future net cash flows (in thousands):
| | | | | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| December 31, 2019 | $ | 53,171 | | |
| Sales and transfers of gas and condensate produced, net of production costs | (20,211) | | |
| Net changes in prices and production costs | (58,136) | | |
| Extensions, discoveries, additions and improved recovery, net of related costs | — | | |
| Development costs incurred | — | | |
| Revisions of estimated development costs | — | | |
| Revisions of previous quantity estimates | 26,133 | | |
| Accretion of discount | 5,725 | | |
| Net change in income taxes | 4,077 | | |
| Purchases of reserves in place | — | | |
| Sales of reserves in place | — | | |
| Changes in timing and other | (3,874) | | |
| December 31, 2020 | $ | 6,885 | | |
| Sales and transfers of gas and condensate produced, net of production costs | (39,806) | | |
| Net changes in prices and production costs | 110,850 | | |
| Extensions, discoveries, additions and improved recovery, net of related costs | 255,246 | | |
| Development costs incurred | — | | |
| Revisions of estimated development costs | 10,643 | | |
| Revisions of previous quantity estimates | 35,012 | | |
| Accretion of discount | 688 | | |
| Net change in income taxes | (27,455) | | |
| Purchases of reserves in place | — | | |
| Sales of reserves in place | — | | |
| Changes in timing and other | 12,140 | | |
| December 31, 2021 | $ | 364,203 | | |
| Sales and transfers of gas and condensate produced, net of production costs | (236,374) | | |
| Net changes in prices and production costs | 503,099 | | |
| Extensions, discoveries, additions and improved recovery, net of related costs | 255,970 | | |
| Development costs incurred | 154,931 | | |
| Revisions of estimated development costs | (105,352) | | |
| Revisions of previous quantity estimates | (143,398) | | |
| Accretion of discount | 36,420 | | |
| Net change in income taxes | (127,154) | | |
| Purchases of reserves in place | 262,050 | | |
| Sales of reserves in place | — | | |
| Changes in timing and other | 71,909 | | |
| December 31, 2022 | $ | 1,036,304 | | |
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Octávio Simões, the Company’s Chief Executive Officer and President, in his capacity as principal executive officer, and Kian Granmayeh, the Company’s Chief Financial Officer, in his capacity as principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2022, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Company’s disclosure controls and procedures were effective, providing effective means to ensure that the information we are required to disclose under applicable laws and regulations is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure. We periodically review the design and effectiveness of our disclosure controls, including compliance with various laws and regulations that apply to our operations both inside and outside the U.S. We make modifications to improve the design and effectiveness of our disclosure controls and may take other corrective action if our reviews identify deficiencies or weaknesses in our controls.
Management’s Annual Report on Internal Control Over Financial Reporting
Management, including the Company’s Chief Executive Officer, Chief Financial Officer, and Chief Accounting Officer, is responsible for establishing and maintaining adequate internal control over the Company’s financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Tellurian Inc.’s internal control over financial reporting was effective as of December 31, 2022. The effectiveness of our internal control over financial reporting as of December 31, 2022 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report below.
Changes in Internal Control over Financial Reporting
There was no change in our internal control over financial reporting during the quarter ended December 31, 2022, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of Tellurian Inc.
Opinions on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Tellurian Inc. and subsidiaries (the "Company") as of December 31, 2022, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control – Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2022, of the Company and our report dated February 22, 2023, expressed an unqualified opinion on those financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
| | | | | | | | |
| /s/ DELOITTE & TOUCHE LLP |
| | |
| Houston, Texas |
| February 22, 2023 |
ITEM 9B. OTHER INFORMATION
Not applicable
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this Item is incorporated by reference from Tellurian’s Definitive Proxy Statement with respect to its 2023 Annual Meeting of Stockholders to be filed not later than May 1, 2023.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference from Tellurian’s Definitive Proxy Statement with respect to its 2023 Annual Meeting of Stockholders to be filed not later than May 1, 2023.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTER
Directors
The information required by this Item with respect to security ownership of certain beneficial owners and
Executive OfficersThe following table sets forth the numbermanagement is incorporated by reference from Tellurian’s Definitive Proxy Statement with respect to its 2023 Annual Meeting of shares of Tellurian common stock owned beneficially by each director and named executive officer of the Company as of April 24, 2020 (unless another date is specified by footnote below), and by all current directors and executive officers of Tellurian as a group:
| | Amount and Nature of Beneficial Ownership * | |
| Name of Individual or Group (a) | | Shares | | | Percent of Class (b) | |
| Charif Souki, Chairman | | | 28,533,853 | (c) | | | 11.1 | % |
| Martin J. Houston, Vice Chairman | | | 20,144,018 | (d) | | | 7.8 | % |
| Meg A. Gentle, President and Chief Executive Officer | | | 11,941,004 | (e) | | | 4.6 | % |
| R. Keith Teague, Executive Vice President and Chief Operating Officer | | | 6,496,287 | (f) | | | 2.5 | % |
| Diana Derycz-Kessler, Director | | | 2,230,268 | (g) | | | ** | |
| Daniel A. Belhumeur, Executive Vice President, General Counsel and Chief Compliance Officer | | | 1,295,574 | (h) | | | ** | |
| Khaled A. Sharafeldin, Chief Accounting Officer | | | 672,360 | (i) | | | ** | |
| Brooke A. Peterson, Director | | | 618,604 | | | | ** | |
| Dillon J. Ferguson, Director | | | 239,718 | | | | ** | |
| Don A. Turkleson, Director | | | 197,349 | | | | ** | |
| L. Kian Granmayeh, Executive Vice President and Chief Financial Officer | | | 0 | | | | ** | |
| Eric P. Festa, Director | | | 0 | | | | ** | |
| Current Directors and Executive Officers as a Group (a total of 12 persons) | | | 72,369,035 | | | | 28.0 | % |
| * | Unless otherwise indicated, each person listed has the sole power to vote and dispose of the shares listed. Pursuant to Rule 13d-3 under the Exchange Act, beneficial ownership includes shares as to which the individual or entity has or shares voting power or investment power, and any shares that the individual or entity has the right to acquire within 60 days of April 24, 2020, including through the exercise of any option, warrant, or right. For each individual or entity that holds options, warrants or rights to acquire shares, the shares of Tellurian common stock underlying those securities are treated as owned by that holder and as outstanding shares when that holder’s percentage ownership of Tellurian common stock is calculated. That Tellurian common stock is not treated as outstanding when the percentage ownership of any other holder is calculated. |
| ** | The percent of class owned is less than 1%. |
| (a) | Except as otherwise indicated below, the address and telephone number of each of these persons is c/o Tellurian Inc., 1201 Louisiana Street, Suite 3100, Houston, Texas 77002 and (832) 962-4000, respectively. |
| (b) | Based on a total of 257,835,259 shares of Tellurian common stock outstanding as of April 24, 2020. |
| (c) | In January 2017, Mr. Souki entered into the 2017 Total Voting Agreement. In July 2019, in connection with the execution of the Contribution Agreement, Mr. Souki entered into the 2019 Total Voting Agreement Amendment. As part of a collateral package to secure a loan for certain real estate investments, Mr. Souki has pledged 25,000,000 shares of Tellurian common stock. In connection with the execution of the High Trail SPA, Mr. Souki expects to enter into a Share Issuance Voting Agreement. |
| (d) | Includes (i) 650,000 shares of Tellurian common stock held by T.B.D. MH Family Trust LLC, of which Mr. Houston is the sole member and has sole voting and dispositive power and (ii) 1,300,000 shares of Tellurian common stock owned by Mr. Houston’s wife for which Mr. Houston has shared voting and dispositive power. In January 2017, Mr. Houston entered into the 2017 Total Voting Agreement. In July 2019, in connection with the execution of the Contribution Agreement, Mr. Houston entered into the 2019 Total Voting Agreement Amendment. In connection with the execution of the High Trail SPA, Mr. Houston expects to enter into a Share Issuance Voting Agreement. |
| (e) | Includes (i) 3,250,000 shares of restricted common stock that vest upon FID and (ii) 107,333 shares subject to options exercisable within 60 days of April 24, 2020. In connection with the execution of the High Trail SPA, Ms. Gentle expects to enter into a Share Issuance Voting Agreement. |
| (f) | Includes (i) 1,301,300 shares held in a grantor retained annuity trust (“GRAT”), of which Mr. Teague is the trustee and sole annuitant, and his spouse and children are the beneficiaries; (ii) 1,301,300 shares held in a GRAT, of which Mr. Teague is the trustee, his spouse is the sole annuitant, and his spouse and children are the beneficiaries; (iii) 3,416,666 shares of restricted common stock that vest upon FID; (iv) 166,667 shares of restricted common stock that vest upon each of the one-year and two-year anniversaries of FID; and (v) 60,000 shares subject to options exercisable within 60 days of April 24, 2020. In connection with the execution of the High Trail SPA, Mr. Teague expects to enter into a Share Issuance Voting Agreement. |
| (g) | Includes (i) 2,150,000 shares of Tellurian common stock held by Bristol Investment Fund, Ltd., a Cayman Islands company (“BIF”) that is affiliated with Ms. Derycz-Kessler and her spouse; (ii) 524 shares held by her son in a custodial account of which her spouse is the custodian; and (iii) 89 shares held by her spouse and stepdaughter as joint tenants. The spouse of Ms. Derycz-Kessler has sole voting and dispositive power over the shares of Tellurian common stock held by each of BIF and her son. The spouse of Ms. Derycz-Kessler has shared voting and dispositive power over the shares held by her spouse and stepdaughter. |
| (h) | Includes (i) 1,170,000 shares of restricted common stock that vest upon FID and (ii) 53,333 shares subject to options exercisable within 60 days of April 24, 2020. |
| (i) | Includes (i) 526,500 shares of restricted common stock that vest upon FID and (ii) 38,666 shares subject to options exercisable within 60 days of April 24, 2020. |
Holders of More Than 5% of Tellurian Common Stock
The following table sets forth information (as of the date indicated) as to all persons or groups known to TellurianStockholders to be beneficial owners of morefiled not later than 5% of issued and outstanding shares of Tellurian common stock as of April 24, 2020.
| Name and Address of Beneficial Holder | | Shares Beneficially Owned | | | Percent of Class (a) | |
TOTAL S.A., 2, place Jean Miller, La Défense 6, 92400 Courbevoie, France
Total Delaware, Inc., 1201 Louisiana Street, Suite 1800, Houston, Texas 77002 | | 45,999,999 | (b) | | 17.8 | % |
Charif Souki
1201 Louisiana, Suite 3100
Houston, Texas 77002 | | 28,533,853 | (c) | | 11.1 | % |
Martin J. Houston
1201 Louisiana, Suite 3100
Houston, Texas 77002 | | 20,144,018 | (d) | | 7.8 | % |
Nineteen77 Capital Solutions A LP
c/o Maples Fiduciary Services (Delaware) Inc.
4001 Kennett Pike, Suite 302
Wilmington, Delaware 19807 | | 14,019,298 | (e) | | 5.4 | % |
| (a) | Based on a total of 257,835,259 shares of Tellurian common stock outstanding as of April 24, 2020. |
| (b) | This information is based on a Schedule 13D/A filed on July 12, 2019 by TOTAL S.A. and Total Delaware, Inc., each of which has shared voting and dispositive power over the shares listed. |
| (c) | In January 2017, Mr. Souki entered into the 2017 Total Voting Agreement. In July 2019, in connection with the execution of the Contribution Agreement, Mr. Souki entered into the 2019 Total Voting Agreement Amendment. As part of a collateral package to secure a loan for certain real estate investments, Mr. Souki has pledged 25,000,000 shares of Tellurian common stock. In connection with the execution of the High Trail SPA, Mr. Souki expects to enter into a Share Issuance Voting Agreement. |
| (d) | Includes (i) 650,000 shares of Tellurian common stock held by T.B.D. MH Family Trust LLC, of which Mr. Houston is the sole member and has sole voting and dispositive power and (ii) 1,300,000 shares of Tellurian common stock owned by Mr. Houston’s wife for which Mr. Houston has shared voting and dispositive power. In January 2017, Mr. Houston entered into the 2017 Total Voting Agreement. In July 2019, in connection with the execution of the Contribution Agreement, Mr. Houston entered into the 2019 Total Voting Agreement Amendment. In connection with the execution of the High Trail SPA, Mr. Houston expects to enter into a Share Issuance Voting Agreement. |
| (e) | Includes 3,000,000 shares of Tellurian common stock that are issuable and exercisable within 60 days of April 24, 2020 pursuant to a common stock purchase warrant, dated as of March 23, 2020, held by Nineteen77 Capital Solutions A LP, or NCS. UBS O’Connor LLC, or O’Connor, is the investment manager of NCS and has sole voting and investment power with respect to the shares. Each entity named in this footnote expressly disclaims any such beneficial ownership, except to the extent of its individual pecuniary interests therein. |
Total, Mr. Souki, and Mr. Houston collectively own 94,677,870 shares, or approximately 36.7% of the outstanding shares, of Tellurian common stock. The amounts reflected in the above table do not include shares Total may be deemed to beneficially own as a result of the 2017 Total Voting Agreement or the 2019 Total Voting Agreement Amendment. See “Item 10, Directors, Executive Officers and Corporate Governance—Voting Agreements” for a description of the 2017 Total Voting Agreement and the 2019 Total Voting Agreement Amendment.
May 1, 2023.
Holders of More Than 5% of Tellurian Preferred Stock
The following table sets forth information (as of the date indicated) as to all persons or groups known to Tellurian to be beneficial owners of more than 5% of issued and outstanding shares of Preferred Stock as of April 24, 2020.
| Name and Address of Beneficial Holder | | Shares Beneficially
Owned | | | Percent of
Class (a) | |
BDC Oil and Gas Holdings, LLC
12011 Sunset Hills Road
Reston, Virginia 20190 | | | 6,123,782 | (b) | | | 100.0 | % |
| (a) | Based on a total of 6,123,782 shares of Preferred Stock outstanding as of April 24, 2020. |
| (b) | On March 21, 2018, Tellurian entered into a preferred stock purchase agreement with BDC Oil and Gas Holdings, LLC (“Bechtel Holdings”), a Delaware limited liability company and an affiliate of Bechtel, pursuant to which Bechtel Holdings purchased, and Tellurian sold and issued to Bechtel Holdings, 6,123,782 shares of Preferred Stock. In exchange for the Preferred Stock, Bechtel agreed to discharge $50 million in liabilities associated with detailed engineering services for the Driftwood Project. |
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The
Company recognizes that transactions in which the Company participates and any of the Company’s directors, executive officers or substantial security holders have a direct or indirect material interest can present potential or actual conflicts of interest. The Audit Committee Charter requires the Audit Committee to review and approve any related party transaction for which disclosure would beinformation required
pursuant toby this Item
404 of Regulation S-K.Set forth below is a description of all transactions between the Company and such related persons since January 1, 2019 that are required to be disclosed under Item 404 of Regulation S-K.
Certain Relationships and Related Party Transactions
Cheniere 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 (in this section, collectively, “Cheniere”), and Parallax Enterprises and certain of its affiliates (not including Parallax Services LLC, now known as Tellurian Services LLC (“Tellurian Services”)) on the other hand (collectively, “Parallax”). In October 2017, Driftwood Pipeline LLC and Tellurian Services were also namedincorporated by Cheniere as third-party defendants in the lawsuit. In April 2019, Charif Souki was also named by Cheniere as a third-party defendant in the lawsuit. Cheniere alleged that it entered into a note and a pledge agreement with Parallax. Cheniere claimed, among other things, that the third-party defendants tortiously interfered with the note and pledge agreement and aided in the fraudulent transfer of Parallax assets.
In December 2019, Cheniere dropped its claims against all the individuals named as third-party defendants in the lawsuit when it was first filed in July 2017 other than Mr. Houston. On January 30, 2020, Cheniere withdrew all claims it had asserted against the Company’s subsidiaries and directors, and all such claims were dismissed with prejudice.
In January 2020, a special committee of independent directors of the Company approved, and in March 2020 the Board approved (with Mr. Houston abstainingreference from the vote), the payment of reasonable attorneys’ fees and expenses guaranteed by Mr. Houston in connection with the lawsuit, as determined in the sole discretion of the Company and subject to certain conditions. As of April 28, 2020, the Company has paid $305,290 to Mr. Houston.
Tarek Souki Employment Agreement
Each employee in the Company’s London office, including Tarek Souki, an Executive Vice President of Tellurian and the President of Tellurian Trading UK Ltd, a wholly owned subsidiary of the Company, has an employment agreement with the Company or one of its subsidiaries. Tarek Souki is the son of Charif Souki. Mr. Souki’s employment agreement (the “T. Souki Employment Agreement”), dated as of August 5, 2016, as amended on February 8, 2017, with Tellurian LNG UK Ltd, then a wholly owned subsidiary of Tellurian Investments (“Tellurian UK”), provides for an annual base salary and an annual target bonus of 100% of Mr. Souki’s base salary, with a stretch target bonus of 150% of his base salary. The annual bonus is purely discretionary on the part of Tellurian UK and is based on the achievement of various performance milestones of Tellurian UK and Mr. Souki, among other things. The T. Souki Employment Agreement is terminable by either party upon six months’ written notice and by Tellurian UK for “Cause” (as defined in the T. Souki Employment Agreement). The T. Souki Employment Agreement does not have a fixed term and is continuously subject to termination under the terms of the agreement.
On February 26, 2019, the Board, upon the recommendation of the Compensation Committee, approved, (i) effective as of February 17, 2019, a fiscal 2019 base salary increase of £8,518 (from £284,000 to £292,518) for Mr. Souki and (ii) a grant under the Tellurian 2016 Plan of 39,960 vested shares of Tellurian common stock to Mr. Souki in connection with an annual performance bonus for the fiscal year ended December 31, 2018.
On March 6, 2020, the Board, upon the recommendation of the Compensation Committee, approved a grant to Mr. Souki under the Tellurian 2016 Plan of 206,611 restricted stock units in connection with an annual performance bonus for the fiscal year ended December 31, 2019, whereby (i) each restricted stock unit represents a contingent right to receive on or within thirty days after vesting one share of Tellurian common stock, cash of equal value, or a combination of both, and (ii) the restricted stock units vest in substantially equal monthly installments beginning on June 1, 2020.
Total Transactions
On April 3, 2019, the Company entered into a Common Stock Purchase Agreement (the “Tellurian CSPA”) with Total pursuant to which Total agreed to purchase, and the Company agreed to issue and sell in a private placement to Total, 19,872,814 shares of Tellurian common stock in exchange for a cash purchase price of $10.064 per share (the “Per Share Purchase Price”), which would result in aggregate gross proceeds to the Company of approximately $200 million (the “Private Placement”). The closing of the Private Placement is subject to the satisfaction of certain closing conditions, including (i) Tellurian’s affirmative final investment decisionDefinitive Proxy Statement with respect to the Driftwood LNG Project – Phase I (as such term is defined in the Tellurian CSPA) (the “Phase I Driftwood LNG Project”); (ii) Tellurian acquiring a 7.2% interest in Driftwood Holdings, the entity that will hold the Phase I Driftwood LNG Project, for $1.0 billion (the “Company Subsidiary Investment”); and (iii) certain other customary closing conditions.
Under the termsits 2023 Annual Meeting of the Tellurian CSPA, Tellurian granted certain anti-dilution rightsStockholders to Total that will entitle Total to purchase additional shares of Tellurian common stock under certain circumstances if all or a portion of the Company Subsidiary Investment is financed with securities convertible into Tellurian common stock (“Phase I Convertible Securities”). This anti-dilution right will entitle Total to buy additional shares of Tellurian common stock following any conversion of Phase I Convertible Securities to the extent necessary for Total to maintain an ownership percentage of 20% with respect to the outstanding shares of Tellurian common stock, as calculated in the manner provided in the Tellurian CSPA. The purchase price for such shares will be equal to the lower of (i) the Per Share Purchase Price and (ii) the price per share of Tellurian common stock at which the applicable Phase I Convertible Securities were converted. The maximum number of shares of Tellurian common stock issuable under this anti-dilution right will be 25,000,000 shares. In addition, pursuant to the Tellurian CSPA, Tellurian agreed to provide certain registration rights to Total with respect to shares of Tellurian common stock that Total currently owns and shares it will receive in the transactions contemplated by the Tellurian CSPA.
On July 10, 2019, Driftwood Holdings entered into an Equity Capital Contribution Agreement (the “Contribution Agreement”) with Total, whereby Total agreed to make a $500 million capital commitment to Driftwood Holdings in exchange for Class A limited partnership interests in Driftwood Holdings. The closing of the transactions contemplated by the Contribution Agreement is subject to the satisfaction of certain closing conditions, including FID with respect to “Phase 1” of the Driftwood Project. See “Item 10, Directors, Executive Officers and Corporate Governance—Voting Agreements” for a description of the related 2019 Total Voting Agreement Amendment.
Subject to the terms and conditions of the Contribution Agreement, upon the occurrence of FID with respect to Phasefiled not later than May 1, of the Driftwood Project, Total Gas & Power North America, Inc., an affiliate of Total (“Total Gas & Power”), and Driftwood LNG, will enter into a sale and purchase agreement pursuant to which Total Gas & Power will have the right to purchase from Driftwood LNG approximately 1.0 mtpa of LNG from the Driftwood terminal.
Also on July 10, 2019, Tellurian Trading UK Ltd, a subsidiary of the Company (“Tellurian Trading”), and Total Gas & Power entered into a sale and purchase agreement pursuant to which Total Gas & Power has the right to purchase from Tellurian Trading approximately 1.5 mtpa of LNG on a free on board basis at prices based on the Japan Korea Marker index price, subject to the terms and conditions of the agreement.
Currently, Total beneficially owns approximately 18% of the outstanding shares of common stock of the Company and Eric Festa, a director of the Company, is the Vice President of Asset Management of the Gas Division of TOTAL S.A.
2023.
Legal Fees to Pillsbury Winthrop Shaw Pittman LLP
During the fiscal year ended December 31, 2019, the Company and its subsidiaries incurred approximately $0.4 million in fees to Pillsbury Winthrop Shaw Pittman LLP for legal advice in connection with various corporate matters. Dillon J. Ferguson, a director of the Company, is a partner of Pillsbury Winthrop Shaw Pittman LLP.
Amendment of Credit Agreement
Nineteen77 Capital Solutions A LP (“Nineteen77”) is the beneficial owner of approximately 5.4% of our common stock. On April 28, 2020, a wholly owned subsidiary of ours entered into an amendment to a credit agreement with the lender, an affiliate of which is Nineteen77. Pursuant to the amendment, among other things, we issued 9,348,706 shares of our common stock, and a warrant to purchase an additional 4,674,353 shares of common stock, to Nineteen 77. The terms of the amendment are further described in our Current Report on Form 8-K filed on April 28, 2020.
Director Independence
Tellurian common stock is listed on the Nasdaq under the trading symbol “TELL.” Nasdaq listing rules require that a majority of the Company’s directors be “independent directors,” as defined by Nasdaq corporate governance standards. Generally, a director does not qualify as an independent director if the director has, or in the past three years has had, certain material relationships or affiliations with the Company, its external or internal auditors, or is an employee of the Company.
The Board is currently comprised of eight directors: Charif Souki, Martin Houston, Meg Gentle, Diana Derycz-Kessler, Dillon Ferguson, Eric Festa, Brooke Peterson, and Don Turkleson. The Board has determined that each of Ms. Derycz-Kessler and Messrs. Ferguson, Festa, Peterson, and Turkleson are “independent” for purposes of the Nasdaq listing standards. The Board has determined that Ms. Gentle, Mr. Souki and Mr. Houston are not independent in view of their current or prior executive roles with the Company or its subsidiaries. In assessing the independence of Mr. Ferguson, the Board considered his role as a partner at Pillsbury Winthrop Shaw Pittman LLP, a law firm that represents Tellurian Investments, Tellurian and Mr. Souki on various matters from time to time. In assessing the independence of Mr. Festa, the Board considered his role as an officer of TOTAL S.A. or one of its affiliates since September 2012 and his current role as the Vice President of Asset Management of the Gas Division of TOTAL S.A., which beneficially owns approximately 18% of the outstanding shares of common stock of the Company. In assessing the independence of Mr. Peterson, the Board considered his role as the Chief Executive Officer of a company, Ajax Holdings LLC, which is owned 50% indirectly by Mr. Souki and 50% by the Souki Family 2016 Trust.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Principal Accountants’ Fees and Services
Deloitte & Touche LLP (“Deloitte”) served as the principal accountant for the audit
