Editor's note: This article originally appeared in the December 2019 issue of E&P as part of an LNG Special Report. Subscribe to the magazine here.

The International Energy Agency reported in its World Energy Outlook 2017, “A new gas order is emerging, with U.S. LNG helping to accelerate a shift toward a more flexible, liquid global market.”

U.S. LNG exporters are certainly turning world markets topsy-turvy. Since Cheniere began commercial operations at its Corpus Christi Train 1 in 2016, the U.S. has overtaken Malaysia as the third largest exporting country in terms of capacity. U.S. LNG producers expect to compete with Qatar and Australia to be the largest exporter.

“The U.S. has truly been a game changer for the industry. We think that U.S. LNG competition has resulted in a more dynamic, more competitive and more resilient trade system, which is good for everyone,” said Andrew Walker, vice president of LNG strategy and communications for Cheniere Energy, at the 2019 Gastech Conference in September in Houston. “It is making LNG more abundant, more affordable and more secure for buyers.”

Cheniere now has 20 long-term customers. He noted that when looking at these customers, there are different types, including national oil companies, international oil companies (IOCs), trading houses and utilities as well as different geographies. “We’ve produced more than 800 cargoes from our facilities as of Sept. 19,” he said.

Most companies are generally in agreement on LNG trade. In Shell’s LNG Outlook 2019, which was released in February 2019, the company said LNG trading reached 313 MMmt in 2018. The company expects LNG demand to reach 384 MMmt in 2020.

China became the world’s largest gas importer with LNG imports doubling in two years. LNG exports grew by 27 MMmt with half of the growth coming from Australia. About 21 MMmt of new final investment decisions (FIDs) were sanctioned in 2018, according to the outlook.

“Encouragingly for the long-term health of the global LNG market, the average length of contracts doubled from around six years in 2017 to about 13 years in 2018. There were more than 1,400 spot cargoes in 2018,” according to Shell. 

In 2019 about 35 MMmt of new LNG supply are expected. “A rebound in new long-term contracting in 2018 could revive investment in liquefaction projects. There is a potential for a supply shortage in the mid-2020s unless more LNG production project commitments are made soon,” according to the company.

In three short years, the industry has gone through a major transformation when it comes to contracts, indexation, pricing, gas supply, markets and players. More change is on its way.

LNG and gas markets
“Global gas demand will peak in 2033, then slowly decline to 2050 with some variation in supply sources. Conventional onshore gas production will peak in 2033 with offshore gas production peaking in 2040,” according to DNV GL’s Energy Transition Outlook 2019.

“Unconventional onshore gas is forecast to continue rising slowly to [2050],” said Hans Kristian Danielsen, DNV GL marketing and sales director, oil and gas, during a Sept. 17, 2019, presentation. “We see gas continuing to grow. It will actually surpass oil as the world’s primary energy source in 2026 and continue to grow into 2033.”

Demand for LNG will follow a similar trend. The company’s model shows that 298 MMmt of LNG were traded in 2018. For 2019 it predicts total trading of 320 MMmt. In 2050 the model predicts a little less than 1,200 MMmt. 

The predictions point to a rosy future for U.S. LNG. There are now 42 LNG importing markets. A record for new sanctioned capacity is expected for the 2019-2020 period. “That’s over 100 million metric tons of new capacity looking at FID in 2019 alone and quite a few of those have already reached final investment decision,” said Elizabeth “Betsy” Spomer, board adviser for Gas Strategies.

But there are some potential difficulties as with all complex negotiations. The new capacity “is going to have huge implications going forward as this market probably stays unbalanced to the buyers’ benefit,” she said.

“One of the things that has allowed this to happen is a breakdown in the development of supply through the emergence of portfolio players—the big IOCs that take equity positions in these projects and then use their balance sheets to support sales and purchase agreements with or without designated markets. It will be interesting to see how this imbalance plays through the next several years,” Spomer continued.

“Gas Strategies projects the market is going to stay on into the late 2020s based on what’s been achieved to date. You have a 250 million metric ton variance between supply and demand in 2035. That’s massive,” she said.

When Spomer went to Gastech, she questioned, “Where are the deals? Why haven’t we seen a whole slew of deals announced? Where are all pending FIDs? I think uncertainty and current low prices have been a drag on all these things.”

Gas liquefaction by region
North America is forecast to have the highest growth in natural gas liquefaction capacity through 2050. (Source: DNV GL)
The LNG regasification import capacity by region through 2050 shows the Indian Subcontinent with the highest growth. (Source: DNV GL)

Second LNG wave faces tougher market
At Gastech, Blackstone Energy Partners CEO David Foley said the developers of the next wave of U.S. LNG projects will face “tougher” market conditions for bringing new plants online.

“In terms of liquefaction capacity that gets FID from the U.S., the hit rate will be a lot higher on projects either sponsored by major oil companies or expansions of existing facilities. I think the hit rate will be pretty low if you don’t have a customer that is willing to do a long-term offtake and its investment grade,” he said.

Permits might get tougher after the election in November 2020, and pipeline construction might get a little tougher. “The hit rate will be a lot higher on projects that are either sponsored by major oil companies because they can contract themselves or are expansions at existing facilities. You might have one or two new startups that might make it,” he said.

Blackstone committed $2 billion in equity to Cheniere seven years ago for liquefaction at Sabine Pass. “Cheniere has done a fantastic job in terms of bringing those facilities on time and on budget—actually a little bit ahead of schedule—and delivering reliable service to the customers. The whole idea of the Henry Hub based prices has really taken off globally,” he said.

Getting sensible contracts with shippers was a challenge then as now. “Getting long-term contracts from investment-grade companies that could stand behind the contract and provide a good sensible basis for project financing wasn’t easy then, but it seems to be even harder in the current market. LNG is in something of a glut right now, which makes it harder to sign up a long-term contract,” Foley said.

LNG market is changing
One of the major changes in the LNG industry has to do with increased competitiveness, according to DNV GL’s Danielsen. “On the demand side, people are really looking for more flexible contracts. Many potential buyers don’t have the consumption or outlook to agree to 20-year, 1 million metric tons per year contracts,” he said. 

In 2019 there is a changing landscape in the LNG portfolio.

“We’re moving away from the old model with one operator controlling the full value chain—export, transport and import, like Shell, Petronas, etc.,” Danielsen continued. “New players like Gunvor, Trafigura, Vitol and Glencore are now buying up LNG and breaking it up, or they gather portfolios of LNG. Of course, as traders, they will try to buy LNG when the price is low, providing more floor in the LNG price and hopefully more predictability for large exporters. In fact, these companies traded up to 7 million metric tons of LNG. That is not insignificant.”

Internationally on the supply side, there is a lot of activity in Australia. “Our forecast suggests that Australia’s competitiveness will lead to more LNG trains,” he said.

“Qatar is also starting to build more trains, which should bring capacity to 110 million metric tons. Russia is also high on the radar with Arctic LNG 2 and Yamal coming onstream,” he added.

Where is the gas going? China increased its imports by 38% from 2017 to 2018 to 56 MMmt.

“At the end of June 2019, China had imported 28 million metric tons, which would lead to a 17% increase from 2018,” Danielsen said. “What’s different about our forecast this year compared to previous years is that we see a massive increase in demand from India.”

The market is definitely moving more toward flexible contracts. “Our forecast shows that North American LNG has become even more competitive,” Danielsen said.

Jan Hagen Anderson, DNV GL business development manager of Maritime Americas, talked about the LNG shipping fleet. “Today the fleet of LNG carriers is about 545 to 550 vessels. We expect that to double by 2030 and more than triple by 2050,” he said.

The International Maritime Organization (IMO) has some very ambitious goals to reduce greenhouse-gas emissions by 50% and transportation CO2 by 70% by 2050. LNG would be a large part of this push.

For LNG as a marine fuel, Anderson said between 40% and 80% of all shipping will be fueled by LNG by 2050.

Cheniere embraces competition
Competition is helping the LNG marketplace. Buyers have more options to supply and manage their markets and more ability to choose the supply that suits them best, noted Cheniere’s Walker.

“We embrace competition. We think that U.S. LNG competition has resulted in a more dynamic, more competitive and more resilient trade system, which is good for everyone. It is making LNG more abundant, more affordable and more secure for buyers,” he said.

The background to the whole U.S. story is U.S. resources.

“We have tripled the resource base over the past decade. The Potential Gas Committee released their assessment for 2018 for future gas supply at 38 Tcf,” he said. “That also has been developed at reduced prices. Average gas price was over $8.50 per million British thermal units [MMBtu] in 2005. Today year-to-date the price is $2.66/MMBtu.”

Most markets and trades tend to evolve toward increasing competition. “LNG is doing that. We are in a very different business in the U.S. with that latent supply than we would be without it,” he said.

“Price diversification is something we offer in the U.S. that allows people to move away from the secondary indexation against oil. Destination flexibility has really changed the industry and is creating liquidity and a sustainable low-cost supply over the long run,” Walker continued. “If you can’t end up with a project that is equal to or lower than U.S. Henry Hub plus shipping, you probably don’t have a project because people know there is a large availability of resource that may be monetized.” 

The U.S. has increased industry diversification because the U.S. does not export as a national player. “It allows project-on-project competition unlike many exporters. We’re really seeing increased competition inter-project, increased commercial competition, increased technology and cost innovation. It is going to drive liquidity,” he said.

Spot and short-term trade in 2018 was about 32% of the market.

“The U.S. is driving competition in the marketplace but more importantly driving liquidity. You can appreciate the impact this is having in the marketplace,” he added. “In 2013 buyers tendered for nine cargoes. That has grown hugely since 2013. Trading house activity has grown hugely over the last five years. For Japan/Korea Marker [JKM] swaps, you can see almost nothing in 2016. That is growing quite rapidly today. We counted to date [that] about 25% of the total market share were JKM swaps. There were 161 cargoes equivalent in July 2019.”

Cheniere signed 15-year gas supply deals with EOG Resources, in which some of the gas is tied to Asian spot LNG prices. The deals indicate that upstream U.S. gas producers have an increased willingness to take on LNG price risk.

Unique business model
Petronet LNG Ltd. INDIA signed a memorandum of understanding (MOU) with Tellurian Inc. wherein Petronet and its affiliates intend to negotiate the purchase of up to 5 MMmt/year of LNG from Driftwood LNG, as stated in a Sept. 21 press release. The two companies are expected to finalize the transaction agreements by March 31, 2020. The total investment in Driftwood would be $2.5 billion.

That is part of the basically 8 MMmt/year that Tellurian has sold out of the 12 MMmt/year of LNG the company would like to sell before beginning construction of Phase 1 of the 26.6-MMmt/year project total. Tellurian has 2 MMmt/year for its own account, and Total has 1 MMmt/year, said Joi Lecznar, senior vice president of public affairs and communication at Tellurian.

“We’re looking to sell to anybody that wants to buy low-cost LNG. What we’re finding is that the potential edgewater partners that we’re talking to are quite frankly all over the world. It is really remarkable,” she said. “Another thing that differentiates us is that we have a lot of optionality in our gas supply. We can really get it from everywhere. We are just looking at the lowest cost we can procure in the market in either the Permian or the Haynesville or anywhere. We do have some upstream operations so we can produce it ourselves.”

These agreements are part of Tellurian’s business model, explained Renee Pirrong, director of research at Tellurian. “I would really consider them to be partners. As a partner in Driftwood LNG for $500 million, you purchase an equity stake of about 1 million metric tons per year of LNG in the LNG plant, upstream resource and the pipeline network that we are building. Altogether that is about $30 billion worth of infrastructure,” she said. 

Using that approach, Driftwood “will be the largest privately funded project in the U.S. once we go forward. What that enables you to do as a partner is lift your LNG at cost. You’re able to take advantage of lower cost throughout the entire value chain,” she said.

Tellurian also has a marketing team based out of London.

“As a partner in the facility, Tellurian will have our portfolio from Driftwood through our own equity stake. Our marketing team will sell those volumes on a variety of different terms and contracts,” Pirrong said. “Keep in mind that the market always underestimates demand. This year demand will be growing at about 13.3% year on year. There is a huge amount of latency of demand around the world that will be triggered by the low, LNG-price environment that we’re seeing today. We expect that demand to grow faster than most would anticipate.”

She explained, “I would characterize our entire business model as special. It really eliminates the need for long-term contracts, which we think is pretty creative and pretty important. As the market continues to commoditize, you need to incentivize new LNG projects to go forward, even as customers are more reluctant to commit to long-term contracts at prices that might not reflect the underlying supply and demand fundamentals of the LNG market.”

A partner in Driftwood LNG can purchase an equity stake for $500 million of about 1 MMmt/year of LNG in the LNG plant, upstream resource and the pipeline network that will be built. (Source: Tellurian)
A partner in Driftwood LNG can purchase an equity stake for $500 million of about 1 MMmt/year of LNG in the LNG plant, upstream resource and the pipeline network that will be built. (Source: Tellurian)

Targeting 45 MMmt/year
The goal of Sempra LNG is to be the premiere North American LNG company.

“The measure of ‘premiere’ for us is reaching 45 million metric tons per year,” said Justin Bird, president at Sempra LNG. “Our focus is really on building the infrastructure in North America so that we can export clean-burning U.S. natural gas to other countries around the world as they make a clean-energy transition.”

The company’s plan to reach that goal includes the first three trains at Cameron LNG, Phase 1 at Energía Costa Azul (ECA) in Mexico, the first two trains at Port Arthur LNG, Phase 2 at Cameron LNG and Phase 2 at ECA.

The first step in the plan began with commercial operations with Train 1 at Cameron LNG in August 2019. The second train is scheduled to start production in the first quarter of 2020 with the third train coming online in the second quarter of 2020. That will be the first 12 MMmt/year, Bird explained.

Sempra has much of its capacity under contract, MOU or heads of agreement (HOA). “Cameron Phase 1 is fully contracted to Mitsui, Mitsubishi and Total. Total has signed an MOU to take up to 9 million metric tons per year of capacity of both Cameron Phase 2 and ECA LNG, which would be an expansion. It is likely the customers would be the same as Phase 1,” he said.

“Moving west to Port Arthur, we have publicly announced that there is a 2 million metric ton per year SPA [sales and purchase agreement] with the Polish Oil & Gas Co. and a 5 million metric tons per year HOA with Saudi Services, a subsidiary of Saudi Aramco. For the remaining volumes, we’re in active discussions with many parties,” Bird continued. “For ECA Phase 1, the customers are Mitsui, Total and Tokyo Gas. Total also signed an MOU for up to one-third of the capacity of Phase 2.”

Sempra has learned quite a few lessons between the development of Cameron LNG as a regasification facility and its redevelopment into a liquefaction plant. “We got regas so wrong, as did many others, but it became pretty attractive for liquefaction. I would say being able to take underperforming assets and turning them into wonderful projects is a great experience. That really worked well,” he said.

On the development front, he said, “Generally, we continue to see the strong value of partnerships where interests are aligned. We’ve seen a lot of value in being able to forge strong relationships early through development, construction and operation.”

He added, “Selecting the right partners and customers is also important. We like to build strategic relationships.”

Bird pointed out that Sempra was a little different from some of the other smaller LNG developers. “We’re a holding company with the largest U.S. customer base. We serve about 10% of the U.S. population in terms of power or energy needs,” he said.

Sempra has taken advantage of both Cameron LNG and ECA being brownfield projects. “Cameron Phase 1 was a regas asset that was being underutilized. What it allowed us to do is take a lot of that infrastructure and use it to see significant savings versus a newbuild. Some of the common facilities are in place. Right now the parties are figuring out what is the optimal design for the Phase 2 expansion to make it very cost competitive,” Bird said.

Port Arthur is a greenfield project. “What’s really different there is that you have a site that is expandable up to eight trains. We have some parties that want a significant equity holding. Port Arthur is a project where they can have equity,” he added.

“Saudi Services is interested in Port Arthur for three reasons: Sempra can build it economically, there is a large site capable of significant expansion, and they can have a significant equity holding,” he continued.

Although Cameron LNG is a tolling facility, both Port Arthur and ECA will be based on sales and purchase agreement models. That means Sempra will be responsible for gas supply to the plants. “At ECA, we will basically use existing U.S. infrastructure probably with adding a compressor or other minor upgrade. The pipelines in Mexico are operated by our affiliate IEnova,” Bird said.

For ECA Phase 2, Sempra would build a new pipeline from the Permian Basin to ECA, which would be located in either Mexico or the U.S.

“For Port Arthur, we see the Gulf Coast as a draw. We’re comfortable that the Permian revolution is what is underpinning a lot of the U.S. LNG. There are vast amounts of natural gas looking for foreign markets because it is associated gas. The options are to flare or stop oil production. Through our infrastructure, we can help that gas find a home around the world,” he said.

Midscale, small-scale trains next energy wave
With record numbers of FIDs in 2019 and a bullish forecast for 2020, the prognosis is generally good for midscale liquefaction.

“The preferred model, certainly for North American liquefaction and export, is midscale where total plant capacity is achieved through multiple modules rather than a single large train. Midscale developers are specifying lower costs per metric ton of LNG produced and shorter project timescales versus traditional baseload,” said Paul Shields, director of marketing for Chart Industries.

Chart Industries
Midscale plant solutions are challenging the paradigm that large baseload facilities provide the best economies of scale. (Source: Chart Industries)

At the opposite end of the LNG chain, small-scale import terminals, like the Klaipeda floating storage and regasification unit in Lithuania, are proving the economic and technological viability of small-scale LNG storage and distribution.

Standardization and modularization are crucial in reducing cost and timescale, and small-scale terminals also provide operational flexibility. This creates an attractive business model for terminal operators and owners to quickly address the growing demand for LNG as a fuel for transportation and energy and take advantage of new supply, particularly North American shale.

Principle end-uses for LNG are power generation and vehicle fueling. The LNG Virtual Pipeline is already a well-established model for bringing natural gas power to regions off the grid, including remote locations and islands to displace diesel, propane, butane and oil.

“Using cryogenic ISO containers to transport LNG means it can be delivered from source to site efficiently and safely via different modes, for instance road and sea. A full-for-empty swap system provides greater cost efficiencies,” Shields said.

Integrated systems, comprising storage, vaporization and delivery, bring natural gas power to off-grid locations through the LNG virtual pipeline. Chart has experience with both large projects, such as powering generator sets at mines, through to enabling small/medium enterprises to switch to natural gas from other liquid fuels.

Satellite integrated systems also are used for distributed energy with small-scale, gas-fired power stations. Based on Chart’s experience, a nameplate capacity of about 50 MW typically requires an LNG satellite plant with 100,000 gal of LNG storage that feeds multiple reciprocating engine generator sets. Such systems are also in place as backup power for peakshaving and curtailment.

In the marine sector, IMO 2020 regulations mean that sulphur content in marine fuels has to be reduced from 3.5% to 0.5% and to 0.1% in emission controlled areas. LNG achieves this. Consequently, there has been a large increase in the number of LNG-fueled vessels on the water, under construction and ones classed as marine ready.

It also means that greater investment is needed in the bunkering infrastructure, and there are a number of new facilities in operation or being built, both land-based (e.g., Eagle LNG in Jacksonville, Fla.) and bunkering vessels.

In Europe there are a number of companies investing in developing the refueling infrastructure for LNG trucks. Main drivers promoting LNG over diesel are environmental and, in particular, the elimination of particulates.

Florida East Coast Railway has been operating natural-gas-fueled locomotives for some time. In another positive move for LNG, the U.S. administration is allowing it to be transported by rail.

Read the rest of E&P's special report on LNG here