Corporate Presentation April 2018

Transcription

1 Corporate Presentation April 2018

2 Disclaimer and forward-looking statements This presentation includes forward-looking statements within the meaning of Private Securities Litigation Reform Act of All statements other than statements of historical fact contained in this presentation, including statements regarding the future results of operations and financial position of NextDecade Corporation ( NextDecade or the Company ), its strategy and plans, and its expectations for future operations, are forward-looking statements. The words anticipate, contemplate, estimate, expect, project, plan, intend, believe, may, might, will, should, can have, likely, continue, design and other words and terms of similar expressions, are intended to identify forward-looking statements. The Company has based these forward-looking statements largely on its current expectations and projections about future events and trends that it believes may affect its financial condition, results of operations, strategy, short-term and long-term business operations and objectives and financial needs. Actual results could differ from those expressed in its forward-looking statements. The Company s future financial position and results of operations, as well as any forward-looking statements are subject to change and inherent risks and uncertainties, including those described in the section entitled Risk Factors in its Annual Report on Form 10-K as well as other filings the Company has made and will make with the Securities and Exchange Commission (the SEC ) which, after their filing, can be found on the Company s website, You should consider the Company s forward-looking statements in light of a number of factors that may cause actual results to vary from its forward-looking statements, including, but not limited to: the Company s ability to maintain the listing of its securities on a securities exchange or quotation medium; changes adversely affecting the business in which the Company is engaged; management of growth; general economic conditions; the Company s development of liquefied natural gas ( LNG ) liquefaction and export projects; the Company s ability to secure additional debt and equity financing in the future to complete the terminal at the Port of Brownsville in southern Texas (the Terminal ) and an associated 137-mile pipeline to supply gas to the Terminal (the Pipeline, and together with the Terminal, the Project ); the accuracy of estimated costs for the Project; the governmental approval of construction and operation of the Project; the successful completion of the Project by third-party contractors; the Company s ability to generate cash; the development risks, operational hazards, regulatory approvals applicable to the Terminal s and the Pipeline s construction and operations activities; the Company s anticipated competitive advantage; the global demand for and price of natural gas (versus the price of imported LNG); the availability of LNG vessels worldwide; legislation and regulations relating to the LNG industry; negotiations for the Terminal site lease and right-of-way options for the Pipeline route; compliance with environmental laws and regulations; or the result of future financing efforts. The forward-looking statements contained in this presentation are made as of the date of this presentation and you should not rely on forward-looking statements as predictions of future events. In addition, neither the Company nor any other person assumes responsibility for the accuracy and completeness of any of these forward-looking statements. Except as required by applicable law, the Company does not undertake any obligation to publicly correct or update any forward-looking statements. All forward-looking statements attributable to the Company are expressly qualified in their entirety by these cautionary statements as well as others made in this presentation, the Company s most recent Annual Report on Form 10-K, and in its other filings and public communications. You should evaluate all forward-looking statements made by the Company in the context of these risks and uncertainties. 1

3 About us NextDecade is a liquefied natural gas development company focused on LNG export projects and associated pipelines in Texas (USA)

4 Experienced leadership team Matt Schatzman President & Chief Executive Officer BG Group: EVP, Global Energy Marketing & Shipping Dynegy, Inc.: President & CEO, Energy Convergence René van Vliet Chief Operating Officer Royal Dutch Shell: VP, Global LNG, Gas & Power Shell International: Project Manager Ben Atkins Chief Financial Officer GE Capital & GE Financial Services: Senior Vice President United States Navy: Lieutenant, Submarine Officer Krysta De Lima General Counsel Bechtel: Senior Counsel, Oil, Gas & Chemicals BG Group: Chief of Staff & VP, Legal, Trinidad Asset Eric Garcia Chief Accounting Officer KPMG: Managing Director, Audit KPMG: Senior Manager, Audit Alfonso Puga SVP, LNG Marketing Europe & South America PetroChina: Global Head of LNG Trading Union Fenosa Gas: Manager, Gas Procurement & Trading Shaun Davison SVP, Development & Regulatory Affairs Excelerate Energy: Director, Business Development Teekay Shipping: Director, LNG Terminals James MacTaggart SVP, LNG Marketing Asia Shell: General Manager, New Gas & LNG Markets Asia Shell: Lead Negotiator, LNG Supply Patrick Hughes VP, Corporate Strategy & Investor Relations Height Securities: Partner, Investment Banking & Advisory FBR & Co.: Senior Associate, Energy & Natural Resources Kevin Hyatt VP, Gas Supply & Transportation Energy Transfer Partners: VP, Business Development Transwestern: VP, Commercial & Business Development Raquel Couri VP, Human Resources & Administration BG Group: Head of Human Resources, GEMS BG Group: Head of Human Resources, Latin America Chris Migura Deputy General Counsel Occidental Petroleum: Assistant General Counsel BG Group: Chief Counsel, Global LNG 3

5 World class partners 4

6 mtpa Significant LNG demand growth by 2025 Global demand has grown by nearly 19% since 2015; we expect growth to continue at an 8% CAGR to 2025 We anticipate global LNG demand will exceed available supply by 150 mtpa by 2025 (30+ new trains) Investment in new liquefaction capacity must be made to alleviate the projected supply gap We expect two-thirds of the supply shortfall will be supplied by North America, with the majority coming from new capacity built on the Gulf Coast of the United States % Global LNG Demand Growth Since North America, Esp. U.S. Gulf Coast Ex-North America 2/3 1/ e.g. Mozambique, Qatar, PNG Expansion, etc E Supply Sources: Wood Mackenzie, GIIGNL (Historical Figures); NextDecade Estimates using data from Wood Mackenzie, GIIGNL, International Gas Union (Projections) 5

7 Historical natural gas pricing (2000 present) Significant U.S.-Asia spreads drove U.S. first wave LNG contracts After several years of collapsed spreads ( ), Asian and European prices are strengthening (2018) Spreads are showing signs of moderate widening, supporting interest in second wave U.S. LNG projects $18 $16 Notes United States Europe Japan $14 $12 > U.S.: Henry Hub Spot Price > Europe: Average import border price, incl. U.K. post-march 2010 > Japan: Average import price (JLC, Japan LNG Cocktail) $10 $8 $6 $4 $2 $ Source: The World Bank, Development Prospects Group, Global Economic Monitoring 6

8 Rio Grande LNG Location & Site Brownsville, Texas, USA 984-acre site Optimally located in the Port of Brownsville PERMIAN ANADARKO BARNETT EAGLE FORD FAYETTEVILLE HAYNESVILLE GULF of MEXICO Capacity 27 mtpa (6 x 4.5 mtpa trains) Storage 4 x 180,000m 3 full containment LNG tanks Marine Facilities Deepwater port access with supporting marine infrastructure Two marine jetties, berth pocket, turning basin Feed Gas Permian Basin and Eagle Ford Shale Low Cost Lower Risk Optimal Location EPC Cost (Est.) 3- or 6-Train: $490/ton ($450 target) 2-Train: $535/ton ($500 target) Artist rendering 7

9 Project progress Regulatory DOE Application: December 2015 FERC Application: May 2016 Next Up: Notice of Schedule and Draft Environmental Impact Statement (EIS) Final EIS expected in 2H 2018 Approval to construct and operate expected in early 2019 EPC Lump Sum Turnkey (LSTK) EPC contract expected in 2Q 2018 Updated FEED completed reaffirming market-leading EPC cost estimates Commercial Opened offices in Singapore and Beijing to serve customers throughout Asia Added key LNG marketing personnel in certain of the largest and fastest growing markets Expanded U.S. gas supply and transportation expertise FID to occur by 1H 2019 to meet 2023 commercial deliveries 8

10 Market-leading EPC costs and lower risk Technology Proven: Air Products C3MR liquefaction, GE rotating equipment, ABB automation system Reliable: Large-scale, fit-for-purpose design minimizes cost and execution risk Design Basis: Peru LNG (400+ cargoes since 2010) Enhanced: Updated FEED incorporates identified cost reduction and value improvement initiatives CB&I Experience: Multiple projects with similar technology and lessons learned Continuity: Same firm for FEED and EPC reduces hand-off uncertainty Process: Open-Book Estimate (OBE) fosters collaboration and cost transparency Scalable Initial: 2 trains at market-leading EPC costs of $535/ton ($500 target) (Est.) Optimal: 3 or 6 trains at $490/ton ($450 target) (Est.) 9

11 Per Train EPC Cost Estimates $/ton EPC costs per phase $600 Bottom line, there is a clear cost benefit from a step down in common infrastructure needs NextDecade has a clear advantage in coming to the market with a competitive rate -- Bank of America Merrill Lynch April 17, 2018 [Rio Grande LNG] offers the lowest EPC cost structure [and provides] cost effectiveness even before scaling to full development and flexibility to be scalable with market demand -- Wells Fargo Securities April 17, 2018 Analyst Corner* $500 $400 $300 Trains 1 & 2 Train 3 Trains 4 & 5 Train 6 $535 Average EPC Cost ($/ton) $490 $508 $490 Storage Tanks 1 & 2 Storage Tanks 3 & 4 Common Infrastructure Jetty 1 Jetty 2 Rio Bravo Pipeline 1 Rio Bravo Pipeline 2 Note: EPC costs are estimates, and do not include owner s engineer, contingency, pipeline, or financing costs. All figures are subject to finalization in NextDecade s EPC contract. No efficiency gains reflected in Trains 4-6. * Analyst quotes are excerpts from research reports. In each case, they were included in coverage initiation reports dated April 17,

12 EPC Cost Estimates $/ton Relative EPC costs: U.S. second wave Rio Grande LNG s 3- and 6-train development cost estimates ($490/ton EPC) are expected to be lower than any other second wave U.S. LNG project s full-scale development costs Likewise, Rio Grande LNG s first phase (2-train) development cost estimates ($535/ton EPC) are expected to be lower than other projects first phase costs $900 $850 $800 Second Wave Projects Rio Grande LNG $750 $700 $650 $600 $550 $500 $450 $400 Rio Grande Rio Grande T1- Magnolia* Driftwood * Golden Pass ^ Driftwood T1- Jordan Cove ^ (Full) * T2 (Phase I) * (Full) T8 (Phase I) * mtpa mtpa Note: NextDecade, LNG Limited, and Tellurian publicly disclose EPC cost estimates. The Golden Pass and Jordan Cove cost estimates are derived from Wood Mackenzie. We assume Wood Mackenzie plant capex data include EPC and non-epc costs. These are reduced by 15% (non-epc estimate) in the above chart to standardize EPC cost comparison across projects. Specifically, Wood Mackenzie cites plant capex as $687/ton and $981/ton for Golden Pass and Jordan Cove, respectively. Adjusted to account for non-epc costs, these are reduced to $597/ton and $853/ton in the above chart. Sources: Wood Mackenzie (^), Company Filings (*), Wells Fargo Securities EPC costs only. Does not include owner s engineer, contingency, pipeline, or financing costs. 11

13 South Texas: Avoiding Calcasieu congestion Low congestion in the Brownsville Ship Channel to benefit Rio Grande LNG Severe congestion on Louisiana s Calcasieu Ship Channel poses risk to multiple projects Texas Brownsville Ship Channel Louisiana Calcasieu Ship Channel LNG Facility Industrial Terminal ~ 7 miles LNG Facility Industrial Terminal ~ 22 miles Distance to: TEXAS RGLNG: 7 Miles LOUISIANA Inland LNG Facilities: 22 Miles Current Traffic: 470 ships p.a. 1,400 ships p.a. Anticipated 2023 Traffic: ~ 600 ships p.a. ~ 2,200 ships p.a. Winter Season Channel Closures (Peak LNG Export): Median 2023 Wait Time: Wind: 3-5% Visibility: 2% Est. limited due to low traffic Wind: 10-16% Visibility: 10-14% 12.4 hours Sources: American Press: August, 6, 2017; Ausenco: Port of Lake Charles, Calcasieu Ship Channel Traffic Study (January 6, 2015); Port of Brownsville reporting and estimates 12

14 Remaining Wellhead Gas (Tcfe) Remaining Wellhead EUR (Bboe) Permian Basin: Superior resource and economics Permian Basin L48 Remaining Resource by Play and Breakeven (PV-10 20:1 HH:WTI) OIL & GAS L48 Remaining Resource by Play and HH Breakeven (PV-10) at $60 WTI GAS The Permian Basin offers the deepest inventory of economic resource in the United States In the past months, the Permian Basin has garnered significant attention and capital Permian Basin economics are driven by the production of oil not by natural gas Texas and New Mexico prohibit long-term flaring of natural gas, so Permian producers must find a market for associated gas to enable oil production The Basin is estimated to hold nearly 500 Tcf or more than 50 years of natural gas at breakevens below $0* This represents a major opportunity for LNG buyers transacting with second wave U.S. LNG projects in Texas Source: RS Energy Group (RSEG) * Assumes Permian natural gas production grows to 25 Bcf/d 13

15 $/acre Horizontal Rigs Permian Basin: Rig counts, capex flow, M&A The Permian Basin has more rigs today than at peak activity levels of 2014 and $100/bbl WTI Operators are allocating more capital to the Permian Basin relative to any other U.S. region The Delaware and the Midland command the highest valuations per acre Delaware-Hz Rigs Midland-Hz Rigs Permian % of Lower 48 Hz Rigs 60% 50% 40% 30% 20% 10% Permian % of Lower 48 Hz Rigs 0 0% Based on terms of Concho Resources acquisition of RSP Permian, as disclosed on March 28, , Acreage Acquisition Cost 50,000 25,000 0 Sources: RS Energy Group (RSEG), Company Disclosures 14

16 Accessing the Permian: Waha to Agua Dulce The Permian Basin is located in West Texas and southeastern New Mexico Rio Grande LNG benefits from its proximity to abundant associated gas in the Permian Basin Pipeline expansion projects from Permian Basin/Waha to Agua Dulce: Kinder Morgan, DCP, Targa: 1.9 Bcf/day Gulf Coast Express (FID December 2017) NAmerico: 1.5 Bcf/day Pecos Trail (Proposed) Other major sponsors likely seeking anchor customers with proposed capacities from Bcf/d Waha Texas Louisiana Permian Gas Takeaway Paths Katy Henry Hub WAHA Carthage Agua Dulce Sources: BTU Analytics, Company Filings 15

17 Discount to Henry Hub $ / MMBtu Bcf/d More gas, more pipelines: The market is East Limited takeaway exists to transport Permian Basin gas to market Mexico does not solve the problem Moving supply East to Agua Dulce or Katy comprise the least expensive and most viable options As many as seven additional pipelines may be needed over the next 10 years to transport gas to the Texas Gulf Coast Existing Capacity Gulf Coast Express New Pipelines East Flow New Pipelines East Gulf Coast Express Existing Capacity Flow $0.00 ($0.50) ($1.00) ($1.50) ($2.00) ($2.50) Waha Basis NYMEX U.S. LNG Second Wave BRG Discount to Henry Hub Sources: New York Mercantile Exchange (NYMEX), Berkeley Research Group (BRG) 16

18 Rio Bravo Pipeline Compressor Station 1 Scope & Distance Twin 42-inch pipelines Three 180,000-hp compressor stations 137 miles from Agua Dulce to Rio Grande LNG terminal Capacity 2 x 2.25 Bcf/d (4.5 Bcf/d total) Compressor Station 2 Scalable Development pace of RGLNG determines pipeline capital expenditures Each pipeline supports three trains at RGLNG Interconnection Eight existing pipelines (6.7 Bcf/d) Expect over 10 Bcf/d of interconnect capacity including planned Waha- AD pipelines Compressor Station 3 Supply Area Agua Dulce poised to attract significant natural gas volumes, including from the Permian Basin Regulatory FERC filings for Rio Bravo Pipeline made in conjunction with those for Rio Grande LNG project 17

19 Projected economics $MM 1 2 Trains 3 Trains 6 Trains Toll Scenario* (Estimates) Liquefaction Fees 2 $ 1,175 $ 1,822 $ 3,878 Marketing Volumes Pipeline Total Revenues 1,548 2,381 4,997 Terminal O&M and CapEx Pipeline Total Expenses Run-Rate EBITDA $ 1,285 $ 2,047 $ 4,352 Notes & Assumptions 1. Estimated run-rate economics (consolidated) presented without inflation for future trains. All amounts in 2023 dollars. EBITDA for FOB contracts not expected to be substantially different given gas procurement and transportation costs to be offset by variable revenue component. 2. Term take-or-pay fees for 4.5 mtpa/train. Trains 1 & 2 average $2.50/MMBtu. Trains 3 & 4 average $2.75/MMBtu. Trains 5 & 6 average $3.00/MMBtu. 3. Higher throughput to be achieved through potential asset optimization prior to substantial completion. 1.0 mtpa per train, average $2.50/MMBtu. 4. Excludes economics related to fuel gas and variable power. Note: EBITDA is a non-gaap measurement defined as net earnings before interest expense, taxes, depreciation and amortization. For purposes of this presentation, maintenance capex is expensed. The Company views EBITDA primarily as a liquidity measure and, as such, believes that the GAAP financial measure most directly comparable to it is cash flows provided by operating activities. Because EBITDA is not a measure of financial performance calculated in accordance with GAAP, it should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. Furthermore, because the Company has not forecasted net income or cash flows from operating activities, the Company is unable to reconcile differences between EBITDA and cash flows provided by operating activities. The estimated values set forth herein assume that the Company will achieve its financial projections in all material respects. Such financial projections reflect the Company s best currently available estimates and reflect its good faith judgments. Events and conditions subsequent to this date as well as other factors could have a substantial effect upon the estimated values. The Company gives no assurance that the estimated values will prove to be correct and does not undertake any duty to update them. Please refer to the slide titled Disclaimer and Forward Looking Statements. * Projected economics are presented assuming a tolling scenario for reference purposes. NextDecade expects to sell a significant portion of its LNG free-on-board (FOB). 18

20 Conclusion We have an experienced leadership team 150 mtpa of new LNG capacity must be constructed by 2025 Rio Grande LNG expects to have market-leading costs and lower execution risk than other second wave U.S. LNG projects Rio Bravo Pipeline is designed to afford access to abundant associated gas from the Permian Basin and Eagle Ford Shale NextDecade expects to generate significant value for its customers and shareholders 19

21 Low Cost Lower Risk Optimal Location Experienced Leadership Contact Patrick Hughes Corporate Strategy & Investor Relations T: + 1 (832) E: phughes@next-decade.com NextDecade Corporation 3 Waterway Square Place, Suite 400 The Woodlands, Texas USA