Energy and Climate Change CommitteeWritten evidence submitted by Dr. Thierry Bros, Senior Analyst, European Gas and LNG, Société Générale (ISG 02)
Executive Summary
Shale gas production has transformed the US gas industry in recent years, boosting both production rates and booked reserves. The country was changed from a growing importer to a possible exporter, while US gas prices have dropped to 2 $/MBtu, against 9 $/MBtu in Europe. The UK is facing not only a severe drop in gas production (-8.1% CAGR in 2001–2011) but also a record drop in gas proven reserves (-15.6% CAGR in 2001–2011). As shale gas reserves are only estimates and need to be validated by effective drilling at each field, the only way to check the real potential in the UK for shale gas is to allow fracking. But this new production process needs to be tightly regulated, with a systematic program for the disclosure of chemicals used in unconventional gas production. Tight environmental standards mean that this business will not be as profitable as conventional gas production in major resource-holder countries… but the risks (financial, security, etc.) are much lower in Europe than in other gas producing countries. European shale gas production could also be the only answer to the ill functioning EU gas market where four foreign National Oil Companies control c.50% of the supply. After the US shale gas revolution, companies are now investing to allow the US to become a major LNG exporter. If this happens, the US could be the cheapest gas market until the end of the decade; other markets will be linked via the cost of arbitrage (liquefaction, transport and regasification). If a single, global gas market is to be achieved then all countries need to follow the US route by producing shale gas, something that seems improbable before 2020e.
The UK is Facing a Major Drop in Gas Proven Reserves and Production
2001–2011 CAGR OF GAS PROVEN RESERVES IN SELECTED COUNTRIES
Turkmenistan huge growth comes from an area that wasn’t explored much under the Soviet regime and that should hold the second biggest gas reservoir on a worldwide level. Albeit from a very low level, China gas reserves have been rising by 8.4% CAGR in 2001–2011. This high growth (coming from conventional and unconventional gas and from fields along the East-West new pipeline that can now be produced) is laying a solid foundation for the further expansion of China gas production. US growth, more than twice the worldwide average, comes from the unconventional gas resources that are now been deemed recoverable thanks to innovative technologies. This high growth has allowed the US to overtake Saudi Arabia as the fourth reserve holder on a worldwide basis. Australia growth is recent (2008) and comes from the huge capex private companies are dedicating to new LNG projects. The EU (and particularly the UK with -15.6% CAGR) saw its gas proven reserves reduced over 2001–2011 as it was producing more gas than it was finding reserves. The world record decline in terms of gas proven reserves is held by the UK even worse than Argentina, where the government decided earlier this year to nationalize the local oil company (YPF). Not a positive start!
For the top four reserve holders (Russia, Qatar, Iran and Turkmenistan), the R/P ratio is over 73 years. Then comes the US (number five) where the R/P is “only” 13 years. This is because, in the US, private companies are geared at monetising resources rapidly; hence, the timing between booking and production is faster than anywhere else. This doesn’t mean that in 14 years the US won’t have any more gas reserves because, by then, some resources should have been booked into reserves thanks to companies’ capex programs. For the EU, the ratio R/P is 12 years but, if the EU continues to fail to replace its gas production (and to ban unconventional gas at large), this could mean that in 13 years’ time, EU domestic production could be insignificant. And, for the UK, the R/P ratio has reached a record low of 4.5 years.
2001–2011 CAGR OF GAS PRODUCTION IN SELECTED COUNTRIES
On the production level, the UK is again, for 2001–2011, the worst in class with—8.1% pa vs worldwide growth of 2.8% pa… It is therefore time to review the situation as the clock is ticking…
Shale Gas Recoverable Resources are Just Estimates That Need to be Checked by Drilling
On March 2012, the Chinese Ministry of Land and Resources announced that according to its survey, China’s onshore exploitable shale gas reserves are 25 tcm. Although the Chinese figure is lower than the US Department of Energy (DoE) number, it confirms that China has the largest shale gas reserves in the world.
SHALE GAS RECOVERABLE RESOURCES ARE JUST ESTIMATES
According to the US DoE (April 2011), Poland has the largest estimated recoverable shale gas reserves in Europe. But Poland’s recoverable shale gas reserves could be lower than estimated by the US DoE (5.2 tcm) as, in March 2012, the Polish Geological Institute (PGI) estimated the shale gas resources to be between 346 bcm and 1.9 tcm. Both numbers are still estimates and more drilling is required to have a better view. So, when we restate US DoE data to take account of new Polish data, we end up with France having the largest estimated recoverable shale gas reserves in Europe.
POLAND OR FRANCE, FIRST IN EUROPE?
As shale reserves are just estimates that need to be checked at each field level by drilling, EU countries will need to allow fracking if we want to stop this massive decline in proven reserves and production. Some unconventional production was tried in the UK but stopped due to tremors. Problems were raised in the UK over potential links to earthquake activity, as well as the chemicals included in fracking fluids. But offshore fracking technologies could mitigate the rate of decline of conventional fields in the UK. Even if onshore unconventional production is unlikely, companies could use fracking techniques for offshore fields. This could perhaps help stop the decline of the European gas proven reserves that we have witnessed since 1999.
In Europe, shale gas could supply a useful diversification to boost energy security. With shale gas development in its early stages in Europe, the resource has the potential to play a marginal role in helping meet Europe’s energy requirements this decade. The aim is to protect the environment while capturing the economic benefit. European shale gas production could also be the only answer to the ill functioning EU gas market where 4 foreign National Oil Companies (Gazprom from Russia, Statoil from Norway, QP from Qatar and Sonatrach from Algeria) control c.50% of supply. Unfortunately the EU is pushing for a single energy market but not for domestic shale gas production...
Like any human activity, shale needs a “social license” to operate and the industry should be aware that its least successful player, in the eyes of the general public, defines the industry as a whole. The way the industry operates in the first countries to allow fracking will have a major impact for further shale (oil &) gas production throughout Europe. A tightly regulated production process, with a systematic program for the disclosure of chemicals used in unconventional gas production, could help this industry to expand in Europe. The move to reveal the make-up of fluids used in hydraulic fracturing of shale gas reserves (a similar initiative as the US fracfocus website (fracfocus.org)) could be developed to head off criticism of the new gas production method, which is attracting growing attention in European countries. A comprehensive disclosure program would allow citizens and communities to assess this technology. Only this could lead to open discussion about environmental protection and risk management, and the potential benefits of shale development in Europe. Any environmental issue would have a dramatic effect on shale production throughout Europe. The industry must understand that tighter environmental standards (and potential reduction in oil-linked prices) will mean that this business will not be as profitable as conventional gas production in major resource-holder countries, but the risks (financial, security, etc.) are much lower in Europe than in other gas producing countries.
It took 30 years of Research & Development in the US to unlock the shale gas resources. As understanding of unconventional resources improves, Europe could find a way to extract shale in a greener way (less water and air pollution) perhaps by the end of this decade. And even if costs turn out to be higher than in the US, technology improvement could help to reduce these.
Continued Growth in Production Should Enable the US to Become a LNG Exporter
Recent developments in the US and Canada could lead to North America becoming a major LNG exporter. For a liquefaction facility to be built in the US, a wide range of authorizations are needed:
An important one is granted by the DoE to allow exports as any state has permanent sovereignty over its natural resources. An application for export authorisation has to be filed by companies that want to build and operate an LNG export terminal. The DoE can grant authorization either to countries with which the US has a free trade agreement (FTA countries are Australia, Bahrain, Canada, Chile, Costa Rica, Dominican Republic, El Salvador, Guatemala, Honduras, Israel, Jordan, Mexico, Morocco, Nicaragua, Oman, Peru, Singapore and South Korea. Colombia and Panama should join the FTA countries once all legislation is passed) or to all countries with which trade is not prohibited by US law.
Another one is granted by the US Federal Energy Regulatory Commission (FERC) to site, construct and operate facilities for the liquefaction and export of domestically produced natural gas. This process takes more than a year and costs tens of millions of dollars.
In less than four months, Cheniere, that was the first company to be granted a DoE authorization to export US LNG to FTA and non-FTA countries, managed to sell all its LNG (16 mtpa) under a US spot- linked (Henry Hub) formula (LNG delivered Free On Board: 115% HH + fixed fee). The 115% HH covers the gas sourcing (100% at the hub), the cost of fuel gas needed for the process (10%) and additional transportation cost to the liquefaction terminal (5%). The fixed fee is for the remuneration of the liquefaction plant that will therefore operate as a tolling plant. As Cheniere took a Final Investment Decision in July 2012 on Sabine Pass Phase 1 ($5.6 billion), US LNG should arrive as early as 2016e.
In April 2012, Cameron LNG signed commercial development agreements with Mitsubishi and Mitsui to develop and construct a liquefaction export facility in Louisiana. The commercial development agreements bind the parties to fund all development expenses, as well as to negotiate 20-year tolling agreements. Each tolling agreement would be for 4 mtpa (5.4 bcm/y). In May 2012, GDF SUEZ signed with Cameron LNG an agreement to negotiate a 20-year liquefaction contract for 4 mtpa (5.4 bcm/y). The completed liquefaction facility is expected to be comprised of three liquefaction trains with a total export capability of 12 mtpa (16.2 bcm/y). Cameron LNG expects to receive the required permits from the DoE and the FERC and enter into a turnkey contract in 2013 for engineering and construction services for the project. In July 2012, Freeport LNG announced that it had executed 20-year liquefaction tolling agreements with Osaka Gas and Chubu Electric for the first liquefaction train (4.4 mtpa). Freeport LNG is also in exclusive negotiations with respect to the second and third liquefaction trains. Freeport LNG expects to receive all regulatory approvals by mid-2013, and to begin construction in Q3 2013. This shows that major downstream market players (especially Japanese companies) are increasingly willing to access US LNG directly.
Several projects with a total capacity of 113 mtpa have filed applications with the US DoE seeking authorization to export LNG. If all these projects were approved and built, the US would become the number one LNG producer, far ahead of current number one (with 77 mtpa or 104 bcm/y) Qatar!
Federal law gives the US DoE the authority to revisit liquefied natural gas export applications it has approved. We believe this is unlikely as:
Cheniere’s Henry Hub linked formula will not make the US gas market oil-indexed dependent.
A claw-back would have to mitigate a very serious threat where gas would not be available even for US citizens, and in this case HH would have gone up so much that exports would be uneconomical anyway!
The US is already a net gas pipe exporter to Mexico (14.1 bcm in 2011).
Thanks to unconventional gas, Australia is set to become the next growth area for LNG from 2015e. Australia’s current 20 mtpa (27 bcm/y) capacity is set to grow, as 57 mtpa (77 bcm/y) capacity is already in construction and another 28 mtpa (38 bcm/y) could materialize before 2020e. This adds up to 107 mtpa (144 bcm/y) and could make Australia the number one LNG producer in 2020e. Future Australian LNG has already been sold mainly on an oil-indexation basis in Asia. So this extra gas shouldn’t have an impact on future pricing.
QATAR VS AUSTRALIA: LNG CAPACITY
As Qatar, the lowest cost producer, was not prepared to compromise on a strategy of seeking prices close to crude oil parity, the highest cost producer, Australia, was able to stay in the competition and achieve prices that make economic sense for the investment in its new projects. But recent developments in the US and Canada could lead to North America becoming a major LNG exporter. US LNG should be much cheaper to build as: 1/the upstream, transportation and LNG infrastructure (jetty, tanks) are already there; 2/cost of labour is cheaper than in Australia. Finally, competition for water supplies (agriculture, industry and humans) is a major issue in Australia, as water management from unconventional production is an ongoing and expensive operation.
DISCLOSED CAPEX OF LNG PROJECTS
Given their high capex requirements, Australian producers can only offer oil-linked LNG contracts, whereas Cheniere (and perhaps other US projects) are selling (and could sell) LNG under a Henry Hub linked formula. We therefore believe that US LNG supply could grow quickly over 2016–2020e.
In May 2012, BG announced a 36% rise in its Queensland Curtis LNG project since the Final Investment Decision (October 2010). This announcement could be followed by other Australian projects increases. And Ichthys could be the last greenfield LNG project sanctioned in Australia because, with rampant cost inflation and faced with an increasingly price-sensitive customer base, these large-scale, expensive projects simply look cumbersome and out-dated in the context of intensifying global competition. As a result, Australian projects are being priced out of the market. This, coupled with delays, is eroding returns from the country’s already marginal developments. In the last two years, Qatar’s pricing policy has meant that the highest cost producer, Australia, has been able to undercut the lowest cost producer, Qatar. The emergence of the US and Canada as potentially major LNG exporters will create a new environment in which Australia will find it more difficult to compete.
Thanks to the shale gas revolution, the US has become a low cost energy producer on a global basis. The US could mitigate Russia power on the international gas scene by delaying its entrance on the Chinese market as China could view the US LNG as cheaper and safer than pipe gas from Russia or LNG from the Middle East.
Also, as greenfield projects in Australia are going to be delayed or derailed by the cheaper US LNG export projects, it is possible that, in 2020e, Qatar would still be the number 1 LNG producer worldwide, followed by Australia and North America.
QATAR, AUSTRALIA OR NORTH AMERICA: WHO COULD BE FIRST LNG PRODUCER IN 2020E?
2020E LNG PRODUCTION: 3 FIRST PRODUCERS
IN THE FUTURE, MARKETS COULD BE LINKED VIA THE COST OF LNG ARBITRAGE
By directly sourcing US LNG priced under an HH formula, Asian customers are cutting out the middle man, the LNG aggregator. And, if the US becomes a major LNG producer as we believe, then this change in business model could start to reduce oil-indexation in Asia, as we are seeing in Europe.
The US could be the cheapest gas market by the end of the decade; other markets will be linked via the cost of arbitrage (liquefaction, transport and regasification).
OVERVIEW OF GAS PRICES IN 2020E (WITH ESTIMATED SPREADS IN $/MBTU)
To supply growing markets, the major resource holder, Russia, is now in direct competition with the major gas producer, the US. China has the potential not only to select the winner but also to decide the pricing principle for all Asian buyers in 2020e. As China is a new and growing gas importer and has a lower price tolerance than historical Asian buyers (Japan and South Korea), it is highly possible that, contrary to what basic geography would suggest, China selects waterborne US LNG vs close Russian pipe gas, to achieve lower import prices.
The Singapore LNG terminal should start operations in 2013. The main role of the terminal is to supply the Singapore market, but the functionality of the terminal to operate as a trading hub has been built into the design and the commercial arrangements. Singapore will help balance supply and demand in Asia by allowing arbitrages of LNG cargoes.
Until the shale gas revolution, net importers were bound to become more and more energy dependent. The shale gas revolution changed this dependency paradigm forever and is offering an alternative. The US has chosen to reduce its dependency on foreign (oil &) gas. China will use this new technology to mitigate its growing gas dependency. Only Western Europe (excluding Poland) has, so far, chosen to avoid this technology and to keep its growing dependency on gas importers. EU gas proven reserves, which have decline 6.6% CAGR over 2001–2011, can only grow if the region decides to go for shale gas. And, European gas market will never be fully functioning without enough domestic shale production.
Also submitted: “After the US shale gas revolution” which deals with all of these issues.
September 2012