Those following the international business press will know that both Russia and the United States, amongst other countries in the world (such as Canada, Australia and Qatar) each have a number of proposed liquefied natural gas (LNG) projects in the works. However, even though LNG is by no means a phenomenon limited to the US or Russia, the Ukrainian crisis and media coverage regarding the possibility of Europe’s diversification of gas supply towards LNG has put particular geopolitical focus on a perceived “LNG race” between the US and Russia.
Incidentally, each of the US and Russia has a single existing LNG liquefaction plant – in Russia it is Sakhalin II (owned by a consortium of Gazprom, Shell, Mitsui and Mitsubishi) and in the United States it is Kenai in Alaska, owned by ConocoPhillips. The fortunes of each of these projects have been quite different, however – Sakhalin II has been an active LNG exporter since its launch in 2009, but Kenai, although it was the world’s largest LNG liquefaction facility when it was completed in 1967, eventually was shut down for being small and uncompetitive.
At the moment, there are at least 13 LNG export facilities proposed in the United States and six (not including expansion trains) proposed in Russia.
Since there are certain differences between Russia and the United States in both the basic legal framework for allowing LNG exports, as well as the prevailing project concepts, investment case, risk profile and pricing, it seems timely to provide a brief note (necessarily leaving out some potentially important details) describing these differences.
Leaving aside for the moment the myriad permits, licences and other governmental permits required in both Russia and the United States for the construction and operation of an LNG export facility, in each of the two countries an LNG project must have permission from the government to export LNG.
In December 2013, Russian legislative amendments came into effect pursuant to which the Ministry of Energy is empowered to issue licences to export LNG. These amendments were long-debated – in part because their effect is to allow LNG exports to be made by companies other than Gazprom, which enjoys a legal monopoly over exports of pipeline gas from Russia. Now, state-controlled companies operating on the Russian continental shelf, as well as non-state-controlled companies operating onshore whose production licences provide for the right to produce and export LNG, may receive LNG export licences from the Ministry of Energy. It is important to note that in both cases the LNG export licence is linked to the source of the gas.
In the United States, LNG export facilities require a permit from the Department of Energy. Such permit can be issued for exports to countries with which the US has a free-trade agreement, or can be broader, allowing exports to countries without a free-trade agreement with the US. Two key differences from the Russian approach are (1) there is no category of companies or gas deposits that give rise to a right to export LNG and (2) following on the first difference, the Department of Energy is understood to have broad administrative discretion as to whether or not to issue a permit.
Although the US and Russian approaches are not dissimilar and both countries are the world’s largest natural gas powers (Russia being first in proven reserves and the United States being first in production volumes), the policy drivers behind each country’s approach are understood to be quite different. Russia’s national energy strategy is focussed on maximising export revenues and on ensuring security of and control over reserves and production, but with the exception of Gazprom’s monopoly over pipeline gas exports, hydrocarbon producers are more-or-less freely permitted and encouraged to export oil (and now, LNG). The United States, on the other hand, retains policies focussed on ensuring security of domestic supply – although exploration, ownership of reserves and production of hydrocarbons in the US are liberalised and—to a much greater extent than in Russia and most other major hydrocarbon-producing countries—divided amongst a very large number of small, medium and large outfits, there is a blanket prohibition on exports of crude oil and gas from the US without government permission, which is costly and time-consuming to obtain, and the process for issuing US export permits is discretionary and without set criteria to be met.
With some oversimplification, there are three possible types of LNG projects:
- Integrated. The project company (PC) owns both the source of the gas (gas reserves and wells) and the LNG liquefaction facility, and sells LNG to its customers.
- Merchant. The PC buys gas in the market, liquefies it in its LNG liquefaction plant, and sells LNG to its customers.
- Tolling. The PC provides and sells LNG liquefaction services to its customers, who are responsible for sourcing and supplying their own gas to the LNG liquefaction facility.
Given the structure of the Russian permitting process and certain geographic and infrastructure issues that space does not allow, Russian projects fall under the Integrated type. American projects, on the other hand, fall under the Tolling type. We will leave to one side the rarer Merchant type.
The Integrated project type, generally speaking, is more attractive to sponsors (equity investors) that are in the business of producing and selling hydrocarbons and that have a market value based on their ownership of hydrocarbon resources and exposure to related risks – in other words, publicly traded, vertically integrated oil & gas companies. This is because, through their shareholding in the PC, the sponsors can “book” (record on their balance sheets) the value of the reserves attached to the project. Although a sponsor can, and often does, contract to offtake some of the LNG production itself, all things being equal the sponsor would typically prefer for the PC to sell the LNG at the highest potential price.
The Tolling project type, on the other hand, is generally more attractive to sponsors that need to secure a stable source of LNG for consumption purposes (e.g., power generating companies) and the projects are typically set up as “capacity sharing” arrangements where the sponsors’ shareholdings in the PC correspond to the proportion of the LNG plant’s throughput capacity each sponsor is required / entitled to use.
Project Perimeter and Risk Profile
As mentioned above, the Integrated and Tolling project models tend to appeal to different types of equity investors. However, every LNG on the “drawing board” in both Russia and the US also requires debt financing from third-party banks (typically at the ratio of 70:30 debt to equity), which take a close look at what is actually included in the project perimeter (meaning, roughly, the assets and commercial risks allocated to the PC) and the other risks of various levels of likelihood that could come to bear during the period while the project debt is being repaid – typically 15-20 years. Although the main instrument for managing risk in both an Integrated and a Tolling project is the same—long-term offtake contracts with a satisfactory price formula for the LNG (Integrated) or liquefaction services (Tolling)—the other factors can be quite different.
An Integrated project is generally bigger and more expensive to build than a Tolling project, even if they are located in equivalent geographical areas. However, an Integrated project (particularly in Russia) would be more likely than a Tolling project to be located in a more extreme and undeveloped environment since the LNG plant needs to be built in close proximity to the gas field. The greater expense involved in bringing an Integrated project online is because the Integrated project includes the cost of exploring, delineating, developing infrastructure for, and producing the gas that will be used to make the LNG. The sale price of the LNG needs to be sufficient to cover all those costs, plus operating costs, plus debt service, plus shareholder return. On the upside, however, typically the production from the field attached to an Integrated LNG project will be contractually dedicated to the LNG plant, so if sufficient proved reserves are delineated, the cost of production can be estimated with a high degree of accuracy (and with constantly improving technology, the tendency is typically for the volume of recoverable reserves to go up over time, while the cost of production goes down). So long as the production costs over time are expected to be in line with gas production costs elsewhere in the world, the sponsors and creditors of an Integrated project can be confident that their LNG will be competitive in the market.
A Tolling project doesn’t rely on supplies from a particular gas deposit. Typically a Tolling LNG project is located in an area where there is plentiful existing gas distribution infrastructure and easy access to the open sea. For this reason, 7 of the 13 LNG plants for which US export permits are being sought are concentrated on the coast of the Gulf of Mexico in Texas and Louisiana. Since the “thing” being sold by the LNG plant is liquefaction services / capacity and not LNG itself, and the price of the tolling services doesn’t need to cover the cost of gas exploration and production, the sponsors and lenders can have even more confidence than in an Integrated project that the cash stream from the long-term contracts will cover capital costs, operating costs, debt service and return on investment. However, as described in a bit more detail below, there is a somewhat greater risk, particularly in the United States, that the overall price to the customer of LNG produced from a Tolling project will become uncompetitive, thus putting a lot of pressure to breach the long-term offtake contracts and/or resulting in the LNG plant sitting idle once the long-term contracts have expired.
It’s common knowledge by now that the United States has some of the lowest natural gas prices in the world. Those following the gas markets a bit closer also are well aware that Gazprom (and by extension Russia) have been adamant about retaining oil price-linked pricing for Russian gas exports. According to media reports and market rumours, in negotiating LNG offtake contracts for planned Russian LNG projects the Russian approach of oil-linked pricing has met some resistance from Asian customers in particular, who have floated the idea of using pricing based on the US Henry Hub spot market.
Briefly about the rationale for oil-linked natural gas pricing. Conventional (not shale) hydrocarbon reservoirs typically contain some mix of oil and gas, amongst other things, which means that natural gas is a normal byproduct of oil production, regardless of whether the gas is marketable (this is why, in the absence of a local gas market, gas is often flared at the oil well as a waste product). Therefore, the production costs of oil and gas are tightly linked. Also, since there isn’t a world market for gas the way there is for oil (i.e., nothing exists like the “quoted crudes” Urals Blend, Brent or WTI), gas prices are subject to localised market pressures (demand, transportation / transit costs, monopoly suppliers, etc.) and are not very transparent. An oil-linked price actually takes away some of the arbitrariness in gas pricing by recognising that gas has a certain energy value that could be replaced by oil-derived fuels like fuel oil in certain major applications, such as electricity generation.
In the US, decades of increasing gas production from shale deposits without a proportional increase in the production of oil have disrupted the link between oil and gas production costs. Also, the US gas transportation network is built out to a sufficient extent, and the number of suppliers and consumers is so great, that a quite transparent market has developed where the Henry Hub spot price (named for a gas pipeline node in Louisiana) is quoted on merchantile exchanges and serves as a reference point for futures contracts and wellhead prices throughout the USA.
In an Integrated project, if an oil-linked price formula is applied the initial long-term contracts used to secure project financing are likely to have a floor and possibly a ceiling. The floor is intended to ensure that the capital and operating costs and debt payments are always covered, and the ceiling is intended to ensure that in terms of energy value, LNG stays competitive with alternatives like fuel oil.
In a Tolling project, the customer has the responsibility of buying and supplying gas to the LNG plant, and has considerable leeway in deciding how to do this – long-term contracts with particular suppliers, futures contracts, spot market purchases or a combination of these. The price is therefore whatever the customer and its suppliers negotiate and thus is subject to the vagaries of the US market.
As you’ve probably already gathered, even though LNG buyers are eager to get exposure to US gas pricing, it’s quite possible that, over time, oil-linked gas prices will drop significantly lower than Henry Hub-based prices. Given that the prevailing gas pricing model in North America is unique in the world (for now at least) and is de-linked from oil production and oil prices, if circumstances conspire to make Henry Hub prices higher than the oil-linked prices found elsewhere in the world, the Tolling LNG model that will be used for most US LNG projects could result in US LNG being uncompetitive in the global market.
In closing, I will note that some market observers predict (and many LNG consumers hope) that as LNG capacities come online all over the world, and especially when long-term LNG offtake contracts begin to expire, LNG will begin to trade in a transparent global market all its own. Others point out that since LNG competes directly with pipeline gas and some major gas importing markets, such as China and Europe, will have access to both, localised market pressures will continue to be an important factor in LNG pricing.