LNG Projects Have Stalled. A New Business Model Could Help
Liquefied natural gas (LNG) developers and natural gas producers have depended on third parties to create demand for their product. In recent years, LNG market prices have dropped in response to a surge in supplies and roughly two million tons of LNG contracts are set to expire in the next 10 years. Promising new LNG projects cannot be financed and have stalled.
Developers need to do more to encourage end users – including industrial users and electric generation facilities – to switch from diesel and other liquid fuels to LNG. A new business model could help. We propose a broad collaborative, including natural gas producers, pipeline companies, Engineering, Procurement and Construction (EPC) companies, equipment manufacturers and end users to accelerate market growth.
The International Energy Agency predicts that global oil use will decline as it is replaced by natural gas and renewables. The collaboration we are proposing could accelerate the switch.
A Little Background
Early LNG developments in the 1970s were driven by oil companies that had the misfortune to discover natural gas distant from gas markets. The discovery would have been stranded but for the advent of integrated LNG developments to liquefy, transport and regasify the gas for use in power plants and local distribution. Although LNG was more expensive than oil, utilities in Japan and Europe were prepared to sign long term, take-or-pay contracts because of natural gas’ low emissions and enhanced energy security through the interdependence of buyer and seller and diversification from oil.
U.S. utilities signed similar deals with Sonatrach, the Algerian national oil company, but reneged when domestic production and pipeline companies were deregulated from 1978 through 1985 and advances in 3D seismic technologies opened the Gulf of Mexico shelf as a prolific hydrocarbons resource. A natural gas oversupply “bubble” caused prices to decline below the contractual costs of LNG, and a long arbitration process resulted in settlement agreements. Regasification plants were built, but essentially no LNG was delivered until the bubble deflated after 2000.
Meanwhile, successful lobbying encouraged new domestic natural gas demand, notably through cogeneration facilities that provided steam to industrial customers and sold surplus electricity into the grid at “avoided cost” that would have been incurred from a new power generator.
It is time to shake the dust off that playbook.
Recent LNG Contracting Evolution
Those early LNG sales contracts were all point-to-point, stressing the interdependence of buyer and seller. Cracks in the global contracting regime began to emerge in 1995 with Atlantic LNG’s waiver of destination restrictions. From its web site: “Atlantic was often described as “The Trinidad Model”, which referred to the unique partnership between four energy majors and the Government of Trinidad and Tobago to form an LNG company. The model was unique too in its objective to target two dedicated primary markets at that time: the US East Coast and Spain, capitalizing on Trinidad and Tobago’s geographic proximity to these markets and therefore competitive delivery costs.” To further that goal, Atlantic successfully lowered the construction cost of its liquefaction plant below previous international LNG projects.
Fifteen years later, the majors led by ExxonMobil doubled the size of single liquefaction trains and the size of the LNG carriers as they invested in massive Qatargas LNG projects commissioned in 1998 through 2011. LNG supplies surged, and the global contracting regime could have come under extreme pressure (Figure 1).
However, on March 11, 2011, a massive earthquake offshore Japan caused a tsunami which killed thousands and inundated the Fukushima Diichi nuclear power plant. Failure of back-up systems resulted in a meltdown and release of radiation. Most nuclear power plants in Japan were shut down in reaction and fossil fuel power generation plants had to fill the supply gap; demand for LNG escalated and fortunately major new Qatar LNG plants were able to supply it.
A robust spot market soon emerged to provide incremental LNG supply to Japan beyond that assured under previously executed long term contracts. LNG prices rose to support new LNG plants in Australia to address growing Asian demand.
At the same time global LNG suppliers were realizing premium prices for their spot sales, U.S. natural gas prices were under tremendous downward pressure in the face of the oversupply of unconventional gas. The coupling of these premium LNG prices and the glut of U.S. gas combined to provide the economic incentive for the U.S. to evolve from LNG importer to exporter, adding to LNG capacity being built in Australia and Papua New Guinea (Figure 1).
Cheniere was first and pioneered a new tolling contracting model to support financing its Sabine Pass natural gas liquefaction complex. Under this model, buyers would acquire U.S. natural gas at spot market prices and make long term take-or-pay commitments to liquefy their gas in Cheniere’s facilities. Buyers took the risk that the delivered cost of LNG would be lower than it would be under a traditional oil-indexed contracting regime.
Table 1: Traditional and New LNG Contracting Models
|Natural Gas Supply||Integrated with field production||Purchased at market prices|
|Liquefaction Cost||Passed through by seller to buyer||Long term tolling fee charged to buyer|
|Transportation||Dedicated tanker fleet||Buyer’s responsibility|
|Marketing/ Pricing||Point-to-point long term S-Curve||Cost Recovery|
|Price risk||Passed to end user||Buyer’s responsibility|
Today we have two competing contracting models (Table 1): the traditional model still used for integrated LNG projects from reservoir through end user, with prices indexed to oil prices, coexisting with the new tolling model seen in the wave of U.S. liquefaction projects. This should provide arbitrage opportunities for global LNG traders, while LNG project developers will see enhanced spot liquidity as they optimize not only the rights they retained to process uncontracted volumes from the new projects but also those volumes from contracts which are soon to expire.
The problem with spot markets for a capital-intensive commodity such as LNG is that variable operating costs are low, especially for the traditional integrated field to liquefaction facilities. It costs very little to produce incremental volumes at the field especially if condensate is a co-product. Any price above these costs will contribute positively to cash flow and the economic incentive will favor running the liquefaction complex at full utilization. The consequence was illustrated by the collapse of spot Japanese LNG prices in advance of crude oil in 2014 (Figure 2).
The market rebalanced in 2016 and 2017, but contracts were shorter term and covered lower volume, with prices influenced by local alternatives and less creditworthy buyers than in the past (Figure 3). New importing countries Egypt, Pakistan, Jordan, Jamaica and Colombia were added in 2016, showing newly price-elastic demand segments benefiting from pre-existing infrastructure but contributing to lower overall credit risk. Buyers have become more sophisticated and are putting together portfolios of contract supplies with different tenors and pricing but will soon need new downstream infrastructure to accommodate higher export volumes.
Figure 3: Deteriorating Contract Quality in 2016-17
Australian supplies continue to expand, the U.S. is emerging as a major LNG supplier and Qatar has promised to increase its LNG production 30% by 2020. Natural gas discoveries in the Levant Basin have the potential to supply Egypt, Jordan and Israel, displacing LNG imports in the next few years.
China and India both suffer from appalling air quality and benefit from switching from coal to natural gas in power generation. However, coal extraction is a major employer in both countries, and there are political risks in switching too fast. China and India will want to negotiate low prices based on coal economics; in the medium term the industry must find innovative ways to expand global LNG demand by providing end users with incentives to encourage a switch from oil to LNG.
Absent long-term contracts with high credit counterparties, it has become almost impossible for an independent LNG developer to finance the huge capital investment required for a new project, and major oil companies are demonstrating capital discipline. Domestic natural gas producers will struggle to find markets and prices will remain depressed as associated gas production increases. Project developers are trying different business models but fail to engage with end-users, hoping that low LNG prices alone will stimulate demand. A more detailed discussion of new business models is found in the full paper. Will insert link here Opening a new market segment has the potential to smooth the typical bust and boom commodity price cycle.
With a plentiful supply, barriers to continued growth in demand and reluctance by traditional buyers to commit to long-term contracts required to finance needed infrastructure, new projects will be stranded. We propose a new model (Figure 4) that may be difficult to negotiate but would spread the risk among entities which in aggregate should have sufficient credit to support project finance.
Figure 4: Schematic of Hypothetical Collaboration Relationships
In our view, natural gas producers are the primary medium-term beneficiaries of expanding the global LNG market by encouraging fuel switching from diesel to natural gas. By securing new markets on long-term contracts, producers will eliminate the need to sell at sometimes distressed spot prices and will strengthen the overall market by increasing global demand. End users should also reap strong benefits of improved air quality, lower carbon emissions and lower costs.
- Natural gas producers should be prepared to commit a proportion of their production to long-term reserve-backed contracts with emerging LNG markets at prices related to the oil products that are being substituted.
- End users and their stakeholders should benefit from lower costs and improved air quality by switching from diesel fuel to regasified LNG.
- Providers of equipment needed for the switch from oil to LNG should be prepared to lease the equipment and provide ongoing maintenance at fair prices, rather than trying to sell the units at prices that the end user would find difficult to finance.
- A shipping agreement for small used LNG tankers should be negotiable at favorable rates.
- A liquefaction agreement could be negotiated with “ceiling and floor” features that allows the developer low returns on investment when netback prices to the producer are below Henry Hub spot rates but delivers superior returns when netback prices are above spot prices.
- The “fixed price” construction agreement with the EPC contractor could also provide upside when netback prices are favorable.
- By repeating the same model to various end users in various countries, country risk can be reduced.
This arrangement should spur expanded LNG demand from end users who might not otherwise switch from oil and aggregate credit strength to allow project financing and FID (Final Investment Decision) of the fuel switching and liquefaction construction projects.
The primary economic driver is the current and expected future gap between oil and natural gas prices. Google has recently compiled a database of power plants, listing nearly 3,000 globally (other than China) that rely primarily on oil as fuel.
The natural targets for switching to LNG may be in South and Central America (Figure 5) where there are close to 100 oil-fired power plants greater than 80 MW in capacity. The IEA estimates worldwide oil use for power generation in 2016 at 275 million tons of oil equivalent (over 5 million barrels per day) so the potential market is large.
Perhaps over time, LNG penetration may happen organically, but it is important to recognize the high inertia for change. The schematic we propose will be difficult to negotiate, but the alternative absent a catalyst to overcome inertia is a bust period of low LNG capacity growth as good project ideas are stranded, coupled with depressed U.S. natural gas prices. LNG supplies will then fail to meet demand growth ultimately leading to a commodity boom with higher LNG (but not domestic natural gas) prices leading to stifled global LNG demand growth and frustrating low cost domestic natural gas producers.
It’s an appropriate time to look for innovative ways to accelerate creditworthy LNG demand growth in the medium term. Our hope is that this article will stimulate some productive conversations.
Source: University of Houston Energy