Seeking an Edge in Liquefaction [NGW Magazine]
The predicted over-supply has not materialised: LNG has found a home at higher prices than were expected a few years ago, as nobody foresaw Chinese demand growth in particular.
For LNG Canada, the Anglo-Dutch major’s decision to commit to the LNG project had been delayed from 2016 until early October 2018. This allowed Shell to call it the right project at the right place at the right time when it did announce final investment decision.
In this case, deep pockets were needed as the payback time is long and the up-front sums huge.
Therefore the final investment decision (FID) was not preceded by announcements of heads of agreements for LNG offtake, as the companies involved are hoping their output, priced at $1,000/metric ton/year, will be competitive in Asia with other LNG. Not least as the cost of transport is relatively low: LNG can get to Asian markets year-round in 10 days or less and there is no need to use the busy Panama Canal. All the partners have the money to fund it, with the prospect perhaps of shifting the financing later.
Another project that will be able to rely on its owners for financing is Golden Pass, planned originally as an LNG import terminal, as was the case with Cheniere’s Sabine Pass just across the water in Louisiana. Much of the infrastructure is already in place.Seeking an edge in liquefaction14
Its owners are the US major ExxonMobil and Qatar Petroleum, both having the financial and technological clout to pull it off without the need of external financing. The former’s head of gas and power marketing, Peter Clarke, told NGW on the sidelines of the Gastech conference in Barcelona mid-September that the final investment decision would be taken later this year.
“Golden Pass could potentially export 10–15mn metric tons/year of US gas as LNG with Qatar Petroleum in the Ocean LNG joint venture. We are excited about that. The gas to supply it would be bought on the market,” he said. This would be instead of using equity gas from its upstream subsidiary, XTO.
The US market is hugely liquid and it is not always sensible to move physical volumes around – gas is traded at a number of hubs, he said. “We will take our final investment decision before the end of 2018.
“We are very disciplined about investment, we want to confirm that we have a technology advantage, we know that to compete we need a very low cost of supply. We will not commit until we are sure. But it is advantaged. We already have a lot of steel in the ground: Golden Pass is a brownfield development.”
ExxonMobil is bullish on Chinese gas demand growth, although the trade war with the US is less encouraging for project developers there at the moment. Clarke, speaking before its announcement on tariffs, said that China “has taken clear policy decisions to remove coal from its power mix; it has very large cities in coastal provinces and LNG demand is rising very fast, accounting for almost a third of global LNG demand growth out to 2040.”
But even if tariffs remain in place for some years, there is scope elsewhere. Gas is critically important for reducing carbon emissions and brings other environmental benefits such as lower particulate emissions, he said.
“We see the market is undergoing a profound transition, thanks to the global LNG market development. Volatility has replaced the long-prized stability, from ExxonMobil’s perspective. We like the way this new world is playing out as our integrated position in each of the key markets helps us to put together packages to meet our customers’ needs. Long term supply flexibility leads to long-term partnerships that are mutually beneficial,” he said.
Unlike his peers at the European majors Shell and Total, Clarke said ExxonMobil is not jumping into retail, or into power. “Regarding the power market, we continue to assess the entire value chain to see where we should participate, how, and in what kind of partnerships, depending on what geography we are considering. We participate where we have an advantage and can provide a technical or environmental solution that makes sense for us and other stakeholders,” he said. 15
“We have 5.5 GW of installed capacity but the focus has been on cogeneration in our refineries: steam raising and power at the same time. And some of our generated power spills over into the national grid and we are trading power across multiple countries in Europe.
“In Vietnam we are progressing a gas to power project; in Guyana, there is a massive oil field and we are considering building a combined-cycle gas turbine. How we dispose of the gas there is important: we have to ensure the development of local communities, and we are looking at how to do that.”
ExxonMobil is also happy to produce gas for others to market as LNG, as witnessed by the deal whereby it will sell stranded gas to the Alaska Gasline Development Company. “That was a very important precedent agreement. It is a state-led project and could help commercialise the very large North Slope gas reserves and provide the state with gas. We have been working on that for some time,” he said – although again, with China as an offtaker, that project now is looking a little less rosy.
But most other Gulf of Mexico projects are relying on third parties to provide financing through liquefaction capacity deals: for these, where competition is intense, each needs to have an ‘edge’.
One has already been successful: Venture Global has sold out capacity at its 10mn mt/ yr Calcasieu Pass LNG project and is going to take FID ‘soon’. It is now moving on to selling capacity at its second, to be twice the size, at Plaquemines.
Most of the buyers have been European firms, although with free on board sales contracts the LNG may go further afield as the buyer decides. And their “extremely high” credit rating, and the very low cost, makes the project attractive for ‘plain vanilla’ project financing, co-founder Michael Sabel told a breakfast briefing at the Oil & Money conference in London October 9.
As a private company, it is not giving anything away in terms of the price; as evidence, it directs enquiries instead to the sales agreements it has signed, of 20-year durations. That shows that customers think that the Henry Hub price, now averaging $3/mn Btu annually for a decade, and the liquefaction cost, will be attractive over the project lifetime.
Its costs are low, as it is building a lot of small trains offsite for installation. This is the opposite to other plants, which use economies of scale to lower costs.
It will use 18 trains to produce the 10mn mt/yr at Calcasieu Pass, which is near major pipelines. The company has signed up Baker Hughes a GE company to design the project, which will all be built more cheaply in a controlled environment with its own power supply. Without the need for remote labour on conventional ‘stick-building’ projects, the project is de-risked, he said.
And again, there is no shortage of markets for the output, as technology improves downstream, shortening construction and pay-back. Low-cost gas is the best way of raising living standards and replacing coal, he said. “There are dozens of companies offering power plants and floating regasification. This is a great opportunity for inexpensive gas: the power side has been commoditised for many years. There is a well-educated investor class used to energy infrastructure and with more money than projects to invest in.”
This same investor class might also be interested in Venture Global’s ideas to make these small-scale liquefaction plants mobile so that they can be brought to stranded onshore gas fields and set to work there.
On the question of trade wars, he said that the key point is that demand exists: as long as China switches to gas, that needs LNG production capacity; and as long as that lasts, there will be demand for LNG. “It’s not just about China,” he said.
RIO GRANDE: NEXTDECADE
NextDecade’s Rio Grande project is in southern Texas: Brownsville is an uncongested deepwater port, which now receives one large vessel daily, the head of corporate strategy and investor relations Patrick Hughes told NGW at Gastech mid-September. This is much quieter than Calcasieu parish, the putative home to Tellurian’s Driftwood, Cameron LNG in Hackberry, and Venture Global’s Calcasieu and Plaquemines and other projects. Also it has access to skilled labour and it is close to the Permian and Eagle Ford shale basins, which are primarily oil plays.
These rival the Saudi’s and the Qatari’s reserves, with 250bn barrels, so oil is the focus, with more than half of it accessible at breakevens below $40/barrel, he said. The Eagle Ford adds more than 20bn barrels of oil equivalent. The gas will of course be sold, not given away; but it is an abundant resource and the economics of production are about the oil.
As producers have to market the gas to produce the oil, they will need a low tariff. The cheapest and most efficient routes are the planned pipeline transport from Waha to the Agua Dulce and Katy markets. On top of the existing 6.7bn ft3/day of pipeline capacity, four new ones are planned, totaling 6.6bn ft3/day, to service the Permian production.
These include Kinder Morgan’s $1.75bn Gulf Coast Express pipeline, designed to transport up to 1.98bn ft3/d from the Permian Basin to the Agua Dulce, Texas area. Fully subscribed under long-term, binding transportation agreements, work on that has started and expected to be in service in October 2019.
Shippers that have committed to the project include: DCP Midstream, Targa, Apache Pioneer Natural Resources Company and ExxonMobil subsidiary XTO Energy.
Unlike the projects in Calcasieu, these pipelines go nowhere near the populated regions of far east Texas and so the gas pressure does not need to vary and the pipeline walls can be thinner. This makes it cheaper than the pipelines to the projects alluded to earlier which will need higher tariffs. And NextDecade expects the Waha discount to Henry Hub to continue for some time. Projects on the Calcasieu Ship Channel are, therefore, more likely to source gas from the US northeast and other basins, said Hughes.
The Rio Grande project is to liquefy 4.5bn ft3/day from six trains each of 4.5mn mt/yr. NextDecade expects to have long term LNG offtake contracts to support at least two trains by the end of the second quarter of next year. Three trains will comprise the first phase.
“We take the view, shared by many, that long-term contracts are needed to build capacity, with investment-grade counterparties. NextDecade expects FID in Q3 2019; first gas 2023; bidding for the EPC are Bechtel; Fluor; and McDermott and a partner in a JV. McDermott had been bidding alone but asked to postpone the June 30 deadline as it had to consider the situation following the closure of the CB&I takeover.
NextDecade had to ensure that the contractor met both the technical and the financial capacity for Rio Grande and McDermott decided it needed a partner to satisfy these conditions, unlike Fluor and Bechtel. The decision to start the process again was a deliberate decision on both sides. The EPC will use the same technology as the front-end engineering and design.
Like Tellurian’s Martin Houston, NextDecade has a former senior BG executive at the top: Matt Schatzmann.
Tellurian’s equity-for-LNG plan has been covered extensively elsewhere, but it too is expecting to take FID in the first half of next year, telling NGW that it expected to have sold out the capacity of at least three and possibly five trains each of 5.5mn mt/yr by the end of 2018, in principle. “It’s great to be in a sellers’ market,” co-founder Charif Souki said.
MAGNOLIA LNG – LNGL
Australian LNGL is another company aiming to sell liquefaction capacity to finance its $6bn project: so far it has found $1.5bn of equity so the rest of the money to build the 8mn mt/yr Magnolia LNG plant will come from borrowing of about three times as much, including owners’ costs and finance.
Among the company’s selling points is its elevated position: built on the spoil from excavating the Lake Charles LNG import terminal across the way, the plant is 30 feet above sea level and some way inland. This puts it out of reach of the damage that hurricanes can do, unlike plants downstream and on lower ground, CFO John Baguley told NGW on the sidelines of the Oil & Money conference.
The Federal Energy Regulatory Commission will not allow plants to be built without protection against waves, he said; but it adds to the cost of construction. On top of that, if a hurricane washes the roads away, the recovery work afterwards could take some time.
Another selling point is its size. “Our plant is smaller than others,” he said, explaining why it chose the site. “We use compact technology, with 115 acres for 8mn mt/yr. No other project is that compact.” Without giving details, he said a tenth off the size of each train meant a tenth off the cost of the plant.
The plant is fully consented and the company can start work whenever it likes; it has already bought two compressors and two coldboxes for the first two trains, and has signed KBR and Korean SK E&C to do the EPC work. “We can still make FID by the end of this year,” he said, “but it could slip into early next year.”
It has an offtake agreement for 2mn mt/yr to supply a floating storage and regasification unit at Port Meridian in Lancashire, UK; but this has been extended several times and LNGL does not consider itself bound by it. “We are still marketing all the 8mn mt/yr,” he said.
As with Venture Global, the plan is to build small scale trains, although bigger: four in all, each of 2mn mt/yr. And as with other projects, it is sitting on top of a 42-inch gas line with some seven other pipes bringing gas across the country, and next to a shipping canal and not far from a power substation, roads, fresh water and docking facilities, none of which need to be laid on or built.
LNGL is also backing the Bear Head LNG project in eastern Canada, but that project is about three years after Magnolia, and there is still a 1,100 mile shortage of pipelines from the Dawn hub to Nova Scotia. •