Workable strategies for new US LNG projects

This note discusses the predicaments of US LNG projects as a result of new price and supply developments. Also, the attempts to help US LNG sales by political avenues are with few exceptions likely to be unproductive and ongoing trade conflicts add a strong sense of geopolitical risk among prospective buyers to sourcing LNG from the US. The cost and complexity of LNG projects is such that project developers must now compete for strong mid-stream LNG players to back them, or otherwise struggle. In the longer term, project cost, time and complexity must be reduced to allow a more market-responsive and merchant project development.

The Trump administration has through the ongoing trade conflicts created uncertainties and barriers for buyers to enter into long-term LNG contracts to back the construction of new US LNG projects. At the same time, an increase in LNG exports is seen as a major foreign policy tool to help secure US interests abroad. However, the bluntly stated goal to secure “US dominance” of international trade in crude oil and LNG has irked OPEC and large LNG producers alike, but also worries buyers.

In fact, the US Department of Energy require that contracts for the sale of LNG include destination provisions that “LNG may be exported to any country … which trade is not prohibited by U.S. law or policy.” The list of countries and products prohibited for export and import is maintained by the OFAC of the Department of the Treasury. The presidential authority to unilaterally impose limitations on imports and exports is most clearly stated with regard to the protection of US national security. Congress has effectively chosen not to challenge the president on his commercial extension of what constitutes a threat to national security.

Much like Donald Trump announced an overnight increase in import taxes on Chinese products to the US from 10% to 25%, the US can conceivably tax or halt LNG exports to any country with a similar Twitter message from the president. Increased trade between independent commercial parties has traditionally been seen as a key indirect tool to build international cooperation and dependency to minimize international conflicts and reduce risk of war. The problem for the market and commercial players arises when trade is usurped for political purposes. This is the threat faced by sellers and buyers of LNG presently; a threat that can possibly become acute. Buyers effectively face “sovereign” risk.

US LNG project developers on their side have secured permitting and NEPA process improvements that substantially lower cost and shorten pre-FID time. Earlier requirements to also document substantial progress on long-term sales contracts have also been relaxed. While Jordan Cove LNG was stopped two years ago for i.a. lack of sales progress, the Driftwood LNG project this spring received both its final EIS and export permit without being fully contracted. However, the current situation is that it is largely the market and geopolitics that limit progress of US LNG projects. This is seen by the lack of progress of train 6 at Sabine Pass. Additionally, permitting process relaxation has brought projects earlier to a market that may not need them now.

The US now imposes pressure on Europe not to accept the construction and commissioning of the Nordstream-2 pipeline as this would increase the dependency on Russian gas and undermine gas transit income for the Ukraine. In the US view, the solution is for Europe instead to buy US LNG. This situation has a parallel in the political processes in the early 1980s when Europe bought large quantities of Russian gas, but energy markets are now dramatically different. European gas companies then were statutory monopolies, often under direct government control. Strangely, recent statements and white-papers, from May 2019, suggest that key US policy makers and Washington players have a image of Europe that is 15 years old, before the radical changes that took place after the second EU gas and electricity directives passed in year 2002. Equally, there is little understanding of the force behind Russian gas projects.

It is therefore useful to look back, to see the depth of the changes. In addition to the complete Europe-wide unbundling of the industry, there has been a strong and continuous focus on transmission system integration, starting with EU’s “Christophersen list” in the 1990s. The triple objectives were security of supply, lower end-user costs and the competitiveness of European industry. The dramatic curtailment of Russian gas deliveries to Europe during February 2009, because of cold weather and a commercial conflict with the Ukraine, sparked an additional round of Europe-wide system integration initiatives. Through new reverse flow capabilities, both Slovakia and the Ukraine have sourced gas from west. These system integration measures will largely be complete in 2019, with the important side effect of reducing the number of price areas and balancing zones.

Prospective US LNG project developers therefore face a situation where the classic national European gas buyers have been transformed, or are no longer there. Without the old-style national linkage these companies are much less positioned for and able to take significant sovereign risk. They will also have to carefully balance the commercial exposure that they face. National or EU support can come in the form of grants and financing assistance for the construction of terminals and infrastructure, in combination with an open season contracting phase and possible reservation of capacity for short-term open access. The US has similar funding mechanisms for selected export projects. Guarantees for actual LNG contracting would typically not be possible as it would skew the competitive playing field.

This largely leaves three financing and sales strategies for US LNG projects targeting Europe. They differ in their degree of merchant exposure but are all very challenging to realize:

• A semi-merchant model based on shorter-term contracts, limiting buyer exposure, but lowering the bankability of the project. The effect is that more risked equity is needed. Cheniere has been able to increase its merchant exposure as more trains have entered production, but a fully merchant model is extremely challenging. The development of such a model will require a very competitive, low-cost plant along with secured shipping capacity and capacity at liquid receiving terminals.
• Equity participation or substantial contracting with a large global LNG upstream/midstream player that naturally assumes sovereign risk in its business model. Such companies include Shell, Total and BP, but projects have to fit their strategies and have high quality. Some larger diversified Asian companies may increasingly be willing to assume sovereign risks also. In the current environment, however, Chinese companies are unlikely to wish to increase exposure to the US unless part of a new trade arrangement. While the participating company will normally also have an LNG fleet at its disposal, onward sales will typically be on a portfolio basis to traders, importers or end-users with terminal access.
• The modernized legacy model with a large national buyer and/or trader integrating vertically into LNG production and possibly beyond, to the wellhead. These players seek to extend their current footprint to sourcing as part of a competitive strategy and create a balanced portfolio. While Engie sold its upstream assets to Total in 2018, some key traders (e.g. Vitol) and European mid/downstream companies are making upstream moves to reinforce their core business. These companies effectively seek to create an integrated supply chain with varying degrees of flexible trading.

Several US LNG projects have taken to heart that global marketing and sales from Houston is difficult. Permanent representatives now work in Europe and Asia. While this helps profile projects closer to buyers’ own markets and top management, the competition between projects has become far more intense. It is now also much more difficult for smaller or new LNG buyers to fully understand the differences between upstream gas sourcing, liquefaction technological choices and the often severe operational and sales constraints from annual delivery programs and operational logistics. While access to US shale-based gas prices was a major lure up to 2015, lower world natural gas prices and lower costs now also complicate the commercial proposition of US LNG.

In addition to sovereign risk, in the spring of 2019 exposed a new low fully marginal LNG price level that also drove natural gas market prices generally down in both Europe and Asia. The structural and seasonal surplus of LNG sold to competitive markets resulted in a marginal “Henry Hub plus” price. The gross price difference between TTF and HH as of early May 2019 was 2 USD/MMBtu, of which variable liquefaction, shipping, port, regas, system entry and admin cost absorb at about 1.50 USD/MMBtu. For LNG developers and long-term buyers this new marginal price gives a loss of more than 2 USD/MMBtu to what is required to finance the plant. Such a large differential between the supply cost and the market price can create big tensions in long-term contracts that cannot be resolved by price-review clauses.

The US seller’s perspective is naturally a Henry Hub base, while the buyer sees daily prices in the end-user market. For Europe that typically means TTF or NBP, and JKM in North-East Asia. Today, these prices are linked dynamically via arbitrage. The number of days that market prices are at a level sufficient to pay back the substantial LNG project investments are currently less than 180. Several factors suggest that both gas price variability and price bands have expanded to new levels that will remain.

The difficulty of fully quantifying this new price framework further complicates LNG project development and marketing. While the profitability of US shale gas export in the form of LNG US seems unquestionable a few year ago, the new price levels have created a more classic conflict between buyer and seller perspectives. For buyers LNG contracts must be indexed to delivered gas prices in the market of the final buyer. Some new US LNG projects have already started to accept JKM, TTF and crude oil indexation in sales HOAs, but it is difficult to see these projects move until the market get comfort that LNG netback prices on average will be above Henry Hub prices.

As a result, new US LNG projects must accept conditions of the market of the ultimate buyer and time project development according to supply-demand balances. Political pressure by the US to stop competing projects and promote US LNG is unlikely to be welcome. Instead, project downscaling, cost reduction and very rapid development will be the key success factors for the next wave of US LNG project. These are the same factors that have been behind the success of US shale gas supply. With the realization of these conditions, US LNG projects can compete effectively even on a merchant basis. If not, and in the medium-term, the likely best way for US LNG projecs is to associate themselves with oil and gas companies that have a strong mid-stream LNG presence.