EU Green Deal
A key theme coming out of the side events taking place at COP25 is that private sector involvement is critical in the transition to net zero emissions by 2050.
This article first appeared in the January 2018 issue of LNG Industry magazine.
“Richard Howley, partner, and Penny Cygan-Jones, senior knowledge lawyer, of global law firm Norton Rose Fulbright, discuss with their colleagues what lies ahead for the LNG industry in 2018”.
At the start of a new year, thoughts naturally turn to what lies ahead for the industry in 2018. The end of 2017 has seen improved oil prices (around $61 boe at the time of writing) which has helped to boost gas prices, and this is viewed in some quarters as a reason for optimism. For those of us in Europe, 2017 has seen little investment in large scale LNG projects; instead, the focus has been on small scale initiatives, or the retrofitting of existing import terminals to offer more services – bunkering (which is now available at the port of Zeebrugge), break bulk and truck refuelling to name but three. In addition, the ready availability of Russian pipeline gas and the rise of renewables (due to both clean air initiatives and price competitiveness), coupled with the trend towards shorter term sale and purchase agreements, mean that funders are unwilling to commit the vast capital sums required for new large-scale infrastructure. Efforts by the European gas industry to tout gas-to-power solutions as the answer to curbing greenhouse gas emissions (required under the Paris Agreement and recently reaffirmed – leaving America aside for the moment – in Bonn at the COP23 meeting) or to promote gas as a replacement to coal, which is being phased out in a number of countries, have been less than impressive. However, if we turn our attention to the rest of the world, there are some interesting developments to note and the future of LNG in some regions – notably Africa and Asia – looks promising.
The construction boom comes to an end, now it’s time to operate
Australia has eight operating LNG projects and two under construction. Together, the two new projects, Icthys and Prelude, along with the recently operational Wheatstone project, will add around 21 million tonnes to Australia’s LNG export capacity which according to the Department of Industry, Innovation and Science’ latest report, are forecast to reach 74 million tonnes in 2018-19. However, as the construction phase comes to an end, it is expected that some projects will continue to be impacted by post-construction dispute resolution processes for some years.
While no further LNG projects are on the horizon in Australia, Papua New Guinea is backing a new greenfield project (Papua LNG ) led by Total, in addition to an expansion of the existing Exxon Mobil PNG LNG project.
Political intervention in the market
The Australian domestic gas security mechanism, put in place by the federal government earlier this year, allows the minister to impose restrictions on LNG export on a year to year basis by declaring a shortfall year. Despite a gas shortfall forecast for 2018, declaration of a shortfall year has been averted this year by the three largest gas producers agreeing to supply domestic gas.
The government’s cautious approach to LNG export restrictions can be linked to Australia negotiating the Regional Comprehensive Economic Partnership with ASEAN and Japan, China, South Korea, India and New Zealand. Placing export restrictions on projects that sell LNG to Japanese, Korean and Chinese buyers would not align with Australia’s international trade and investment strategy.
If the government were to trigger export restrictions, the chances of successfully pursuing legal remedies against the Australian government would not be high, at least in the current LNG market awash with spot cargoes available to substitute the east coast sourced LNG.
Will Australia, the world’s second largest LNG exporter that is forecast to overtake Qatar in the next decade, become an LNG importer?
To address a tightening of gas supplies on the east coast, AGL Energy has proposed a floating regas terminal in Victoria to bring LNG cargoes from Western Australia or Singapore. Whilst there are suggestions that the cost of bringing liquid cargoes to the east coast is cheaper than the cost of piping gas from Queensland to Victoria, whether AGL’s project will go ahead remains to be seen. Cabotage issues are among the many concerns for AGL to address.
Both established LNG market participants and new entrants have looked to open up new markets, for instance by developing LNG-to-power projects. The most obvious examples of this are in Indonesia, Bangladesh, Pakistan and Myanmar. Countries that have declining indigenous gas supplies are best suited for LNG imports because gas transportation infrastructure is already in place.
Markets which have traditionally lacked the credit rating to be LNG buyers, or more credit worthy buyers within those markets, are looking at the commodity again as a potential feedstock for power projects and other higher-value gas consuming projects, such as petrochemicals. In some markets, notably India, Pakistan and Myanmar, the buyers of LNG are prepared to pay a premium over regulated prices for indigenous pipeline gas in order to ensure reliable gas supplies.
Established markets for LNG are outperforming expectations, particularly in China, India and Korea. In many cases this is due to a phasing out of coal from the energy mix due to concerns about air pollution, and the relatively competitive prices on offer for spot cargoes of LNG.
the development of Asian-centric pricing indices, leading to a race for market acceptance as the pricing hub between Tokyo, Singapore and Shanghai;
a push-back on destination clauses by the Japan Fair Trade Commission. Whilst the market has for the most part moved away from the types of destination restrictions that the JFTC has indicated are “highly likely” to be violations of Japanese Antimonopoly Act, this development is indicative of buyers’ markets taking a more robust position;
the development of new uses of LNG, and new business models, such as break bulk and bunkering. Whilst Europe is probably leading the way with regard to the development of LNG bunkering there is huge interest in Asia, particularly in China, and the archipelagic nature of the region lends itself to bulk break solutions; and
generally a push for more LNG to be purchased on terms of less than 25 years. This is becoming more and more of a requirement for Asian buyers. The danger is that this becomes an impediment to the next wave of LNG liquefaction projects which struggle to find financing because the offtake agreements are too short.
To summarise, the Asian outlook for the next few years is an increase in the number of projects in the region using LNG, a big increase in the trading of LNG as a commodity and the development of new pricing indices to support that trading, and a degree of uncertainty about how the next generation of liquefaction projects will be financed.
In 2016 and 2017, trains 1 - 3 of the Sabine Pass liquefaction project came on line, marking the first time that natural gas has been liquefied and exported from the lower 48 states. Dominion’s Cove Point LNG project is in the process of commissioning its first train, and the Corpus Christi LNG and Cameron LNG projects are all in advanced construction phases and expected to come on-line next year. Collectively, these projects are expected to add 29.2 mmpta of liquefaction to the global production output. In total, nearly 58mmtpa of new US liquefaction capacity is under construction, according to the International Gas Union, equivalent to 17% of total existing global capacity, and according to Petroleum Economist, the US is expected to account for about half of all LNG export capacity growth over the next five years.
At the same time, the debate surrounding the appropriate regulatory regime for approving LNG exports, especially authorisation of exports to non-Free Trade Agreement countries, continues unabated. Advocates for maintaining or tightening the current regulatory regime, mostly manufacturing groups and politicians from states with large natural gas consumption, argue that increasing LNG exports to non-FTA countries drives up the price for natural gas domestically, harming manufacturers not only by increasing their commodity costs but by rewarding countries without trade agreements who subsidize their manufacturers and impose import tariffs on U.S. manufacturers. These advocates also point to the recent regulatory action in Australia (see above). Those in favour of a more free market approach and loosening restrictions argue that, even with a significant increase in LNG export authorizations, such exports will still constitute a small percentage of total U.S. natural gas production, and that the modest impact on domestic natural gas prices would be outweighed by the overall benefit to U.S. both financially and in terms of it having an enhanced role in the global energy market.]
Meanwhile, the hectic pace of liquefaction development in the U.S. has slowed somewhat, not so much because of the regulatory framework debate, as much as because of supply/demand and competitive pressures in the global LNG industry. Significant liquefaction capacity has recently come online in Australia; Qatar has decided to lift its self-imposed moratorium and resume aggressive development of its existing and planned liquefaction capacity from the North Field; and large natural gas discoveries offshore East Africa and elsewhere in the continent are driving LNG liquefaction plans in Mozambique and Tanzania, as well as West Africa and Egypt. With several other U.S. liquefaction projects now holding both FERC and DOE approval for their projects, the large amount of additional capacity that has come online and is currently under construction or in the planning phase has led to concerns of a potential LNG supply glut.
Timing of the perceived supply glut could not be worse from a seller's perspective. In a low oil price environment, converging and declining LNG spot cargo prices across Europe, Asia and North and South America (in many instances to a price below full capital cost recovery for new liquefaction projects) have become the norm, slowing demand even further and giving buyers the upper hand in negotiations for long-term supply contracts that are necessary for the next wave of US liquefaction projects in order to secure long-term financeable off-take agreements.
Rebounding demand for natural gas in Europe and India and demand growth in China may provide new opportunities for traditional long-term off-take agreements with creditworthy large-scale utilities. Nevertheless, as noted above, there will likely be pressure for more favourable pricing and other terms (eliminating destination restrictions, etc.), a trend that has already started with the recent move by larger, more traditional purchasers of LNG (think JURA) entering into cooperative agreements for joint procurement of LNG. Market seers suggest that it is unlikely that traditional off-takers will be able to absorb all of the liquefaction capacity in the pipeline.
To take advantage of new markets, with smaller or less frequent buyers of LNG, the next wave of US liquefaction projects will need to develop more flexible and creative pricing structures, possibly take account of regional pricing indices, and be prepared to offer shorter term agreements or a combination of short-, medium- and long-term LNG sales agreements. Sponsors of these new liquefaction projects will need to educate and convince their financiers to provide financing on the basis of such off-take agreements, rather than the traditional long-term agreements with large, credit-worthy utility off-takers.
Interestingly, the surge in development, financing, construction and deployment of FSRUs and the increased focus on small- and mid-scale LNG facilities may be the solution to soaking up the excess supply, and allow more sellers to find outlets for their LNG production.]
Since 2010, large discoveries of offshore gas have underpinned numerous proposals for LNG projects in Mozambique and Tanzania, and earlier this year, President Jacob Zuma of South Africa, also the incoming Chairperson of the Southern African Development Community (SADC), stated that the discovery and use of natural gas should form the backbone of the regional economic integration among the SADC member countries. However, although East Africa has potential to become a major LNG supplier, a lack of infrastructure, political will, and fiscal and legal regulation means development of LNG projects to date has been slow, and whether this will shows signs of improvement in 2018 is hard to tell.
However, Mozambique is leading the way with progress to market. Anadarko is developing Mozambique's first onshore LNG plant consisting of two initial LNG trains with a total capacity of 12 mmtpa, and in June of this year, it finalised agreements with the government – known as the marine concessions – granting it the right to design, construct and operate marine facilities for Mozambique LNG in the north of the country. This represented a key milestone in the project, and subject to agreeing long terms SPAs and reaching FID next year, the first LNG produced in Mozambique should reach the market in 2020.
Looking west, West Africa has emerged as an important region for the deployment of small-scale floating LNG. In light of the global trend towards more flexible supply options, this could place West Africa on solid footing for a greater role in the LNG market over the coming years, particularly when coupled with the floating liquefaction projects in Cameroon (where the LNG FPSO “HILLI EPISEYO” is already en route to Cameroon) and Equatorial Guinea (Fortuna FLNG). The Greater Tortue FLNG project has also made good progress in a short amount of time, and as the first cross border LNG project (straddling the maritime boarder between Mauritania and Senegal), it’s development and operation will be closely watched by the industry.
The South Africa LNG-to-power independent procurement program
Following the ministerial determinations in August 2015 and March 2016, which decreed that an additional 3726MW of new gas-fired electrical generation capacity should be procured for the national grid, an information memorandum was published by the South African Department of Energy in October 2016 setting out the principles for a gas-to-power IPP, envisaged to run off LNG. The Coega Industrial Development Zone, adjacent to the deepwater port of Ngqura in the Eastern Cape Province, and the Port of Richards Bay in KwaZulu-Natal Province, have been identified as having sufficient existing infrastructure to support the first phase of the IPP programme. It is expected that 1000 MW will be allocated to Coega and 2000 MW to Richards Bay some time next year, and separate procurement processes will follow for projects at each site. These were expected to commence a year ago but have been delayed until publication of the Integrated Resource Plan (IRP). The IRP, which establishes a policy framework for resource consumption in South Africa, is available in draft form and is expected to be finalised early 2018. Progress is likely to be slow, however, whilst regulatory uncertainty remains. A number of key policy documents (such as the Gas Utilisation Master Plan (GUMP) and the Integrated Energy Plan) have yet to be published and harmonised with existing legislation, and IPP players will be unwilling to enter the South African market before the roadmap for development of the gas economy in South Africa is complete.
Competing energy resources
The lower-than-forecast economic growth, and the success of energy programmes such as the South African Renewable Energy IPP Programme, has resulted in a stable supply of energy within South Africa. It has been argued that further power production capacity should therefore not be a priority for policy makers, although should South Africa return to a stable economic growth path, electricity generation capacity will once again become a significant roadblock to development.
In addition to these background considerations, there is a political drive to promote the development of a nuclear energy industry within the country from some factions within the ruling African National Congress party. This forms part of a broader internal party power struggle, the most recent manifestation of which being the replacement of the Minister of Energy on 17 October 2017. It is possible that these events have caused the reconsideration of framework documents such as the GUMP and IRP. The ANC is due to elect is next presidential nominee and party president in December, and the start of 2018 could therefore bear witness to significant changes for both the country’s energy policy generally, and development of the LNG industry in South Africa.
To conclude, whilst 2017 has clearly not been a game changing year for the LNG industry (except perhaps in respect of the deployment of the first two LNG FPSOs in Australia and Malaysia), there is cause for optimism notwithstanding the high cost of project development and the lower oil price.
Dylan McKimmie is a partner and Tatiana Gotvig is a senior associate in Norton Rose Fulbright’s Australian oil and gas practice.
Ben Smith is a partner in Norton Rose Fulbright’s Asia practice, based in the Singapore office.
Noam Ayali is a partner and Ginger Collier is a senior associate in Norton Rose Fulbright’s USA practice.
Lizel Oberholzer is a partner and Jarrett Whitehead is a candidate attorney in Norton Rose Fulbright’s Cape Town office.
A key theme coming out of the side events taking place at COP25 is that private sector involvement is critical in the transition to net zero emissions by 2050.
Welcome to the thirteenth edition of Global asset management quarterly.