Oil & gas project developments in Sakhalin and the Far East of Russia: innovations, efficiency, co-operation

27 - 29 September 2017

“Stolitsa” Business Centre

Sakhaling Oil & Gas blog

Introduction: a break with tradition


It has become a tradition at the Sakhalin Oil and Gas market that there is a session dedicated to an assessment of the current and future prospects for natural gas markets in Asia. Initially, the focus was upon Japan and South Korea, the major markets for Sakhalin’s LNG exports; however, in recent years increasing attention has been paid to the prospects for gas demand in China.  This year, the 21st Sakhalin Oil and Gas Conference will break with tradition and the gas markets session will be replaced by a strategic discussion on the theme of ‘Global LNG: A Revolution in Slow Motion.’ This change of scale reflects the fact that the global LNG industry is on the verge of a significant transition. It is not that the market situation in northeast Asia is no longer important to the future prospects for Sakhalin’s gas industry; rather it is now the case that those prospects must be accessed on the basis of what is happening at a global scale. The session will consider what the changes now gaining momentum will mean of Sakhalin and Russian LNG more generally.


The tasks at hand


This two-part blog sets the scene for our discussions at the conference. The first part considers the short- and medium-term prospects in the upstream (LNG supply). The second part considers the factors likely to influence medium- and longer term LNG demand and assesses the impact of these trends on the ways in which LNG is traded and new capacity is financed. The blog concludes by identifying topics for consideration by the expert panel.


Setting the time


Building an LNG plant is a long-term, capital intensive activity where, traditionally, multi-billion-dollar investment programmes have been underwritten by long-terms sales contracts. Given that it takes around five year to bring a greenfield LNG project to market, it is relatively easy to predict future supply growth over the short-term. However, unexpected shut downs, due to technical problems, geopolitical conflicts, and declining feed gas have impacted on existing production facilities from time to time; and delayed start-up of new projects can also add a marginal degree of uncertainty. As we shall see in Part-Two, the demand side of the equation is proving to be increasingly fickle, the most obvious case being the impact of the Fukushima disaster on Japan’s LNG demand. More recently, the interplay between coal prices and carbon prices has influenced gas demand in Europe, where geopolitical factors are also favouring a growth in LNG demand; although the prospect of the US imposing extra-territorial sanctions on companies involved in building Russian gas export infrastructure may sour EU-US energy relations.


For the purposes of this essay, the short-term means the next 12 months, the medium-term the next five years to 2022, which is also the time frame of the IEA’s recent Gas 2017 analysis (the new name for its Medium-Term Gas Report). This a time frame where only current and under-construction projects can augment global LNG supply. Any final investment decisions made today on the construction of new facilities will likely contribute to global production after 2022; thus, the longer-term is the remainder of the 2020s, into the 2030s.



The supply shock gains momentum


In the aftermath of the Fukushima disaster, a period of increased global LNG demand and a tight supply situation promoted a rapid increase in LNG prices that were already historically high due to the $ 100 oil price. BP’s data show the average Japan LNG price to have been $ 10.91 in 2010, it increased to $14.71 in 2011 and between 2011 and 2014 averaged $16.00. However, this price is oil-indexed and the collapse in oil prices in 2014 saw the LNG price fall to $ 10.31 in 2014 and then to $ 6.94 in 2015. It has stayed around the $6.00, so far, this year. Tight markets and high prices associated with, first, high oil prices post-2008 and then the ‘Fukushima effect’ accelerated a boom in new LNG projects, particularly in Australia. The United States then joined the game as the shale gas revolution produced a supply glut on the North American market. Canada also joined the fray with numerous proposed projects in British Columbia on its Pacific coast, as well as a few on the East Coast. The IEA’s Gas 2017 reports lists all the LNG projects currently under construction as of June 2017, as well as those expected to start production in 2017. With one exception—Gorgon in 2009—they all declared FID (Final Investment Decision) in 2011 or later. The data show that 8 new projects are expected to start operation in 2017. If you compare the 2016 and 2017 data, there have been some delays, due to technical and feed gas issues—but production is slowly ramping up. The IGU’s data show that in 2014-15 global liquefaction capacity grew by 10.5 million tonnes per annum (mtpa); whereas in 2015-16 a further 31.7 mtpa of new capacity was added, taking global capacity at the end of 2016 to 339.7 mtpa. The IGU’s 2017 report suggests that a further 47.6 mtpa of new capacity will be added this year from projects in: the US, Australia, Cameroon, Malaysia, Indonesia and Russia (Yamal first train). Thus, the wave of new LNG is now gaining momentum, especially when you consider that the IGU reports a further 114.6 mtpa of capacity under construction (this includes the second and third trains of Yamal LNG).  Using different units, the IEA reports that total liquefaction is likely expected to grow by 160 bcm by 2020, initially led by Australia (30 bcm) and then by the US (90 bcm). Projects on Sakhalin do not figure in any of this analysis as, so far, there have been no FIDs link to new production capacity.


2016: relative quiet before the storm


In the wider context, developments in 2016 are little more than modest beginnings of what is to come. Overall, according to the IGU, total globally-traded LNG volumes reached a record high of 258 MT, a 13.1 MT increase over the previous years. Perhaps the most significant development during the year was the start up of the Sabine Pass LNG plant on the Gulf of Mexico, marking the beginnings of shale gas-based US LNG exports. As should be clear from the numbers discussed above, this supply growth is modest when compared with what is to come and the new capacity was absorbed as new LNG import-countries have entered the market over the last few years. The number of LNG importing countries has increased from 15 in 2005 to 39 in 2017. In 2015: Egypt, Jordan, Pakistan and Poland joined the list of LNG-importing counties and in 2016 Jamaica and Columbia were added to the list, with Malta joining them at the beginning of 2017. Individually, these are not significant markets, but their combined demand is significant and has helped to absorb the new supply coming onto the market, along with increased demand in China. However, much more significant demand growth is required to absorb the coming wave of new production. The IEA conclude that: “Over supply is only going to grow in the short-term, as demand is lack lustre and more capacity comes on stream.”


The analysis suggests that the beginnings of the expected LNG supply-glut is slowly gaining momentum. Just how long it will take the global market to balance depends on the rate of demand growth over the medium term. New projects anticipating FID in the next year few years—which includes Sakhalin Energy’s third train, Novatek’s Artic LNG (Yamal 2), Gazprom’s Baltic LNG and potentially Rosneft’s Far Eastern LNG—need to identify a ‘market opening’ in the mid-2020s, but they face stiff competition from North America, East Africa and the Eastern Mediterranean, as well as the expansion of established producers such a Qatar.  


Part-One Ends here


Global LNG: A Revolution in Slow Motion (Part-Two)


Michael Bradshaw, Professor of Global Energy
Warwick Business School, UK


The second part of this two-part blog considers the factors driving future LNG demand and then consider the impact of the coming supply glut on the ways in which LNG is traded and LNG projects are financed.


A golden age of gas?


Back in 2011 the IEA produce a report entitled: Are we entering a golden age of gas? The report did not predict a golden age, but speculated about the conditions necessary and the consequences of natural gas playing a more significant role in the global energy mix moving forward than was expected at the time. Read any publication by a gas producer today and they will tell you that natural gas produces about half the carbon dioxide per unit of electricity produced compared to coal, that it has the potential to be a much cleaner transport fuel than dirty diesel and that using LNG as a bunker fuel can help to clean up marine emissions. Furthermore, the rhetoric continues, natural gas power generation capacity can be built more quickly than coal, and is more flexible; making it the obvious solution to the intermittency of renewable solar and wind power generation. All of these claims are true, but there are at least five problems with this argument. First, in all of these sectors natural gas faces stiff competition from other fossil fuel incumbents—oil in transport and coal in power—who are also benefitting from lower prices. This undermines the case for switching, unless there is regulatory intervention. Second, natural gas is facing growing competition from renewables in the power sector due to their falling costs and regulatory support. Third, growing new gas markets for power generation in emerging markets requires substantial investment in new infrastructure and, if having to reply on imports, also exposes consumers to security of supply risks. Fourth, natural gas is a fossil fuel and climate change policy dictates that to avoid catastrophic impacts we must move, eventually, to a zero-carbon system; thus, why invest in new fossil fuel capacity? It is possible to decarbonise natural gas, but this requires the large-scale deployment of carbon capture and storage, which is not available at present. Fifth, the falling cost of electrify storage presents an existential threat to future gas demand. If low cost electricity storage becomes available at scale then the talk of natural gas a ‘transition’ fuel is rendered redundant. Of course, historically, energy system transitions have taken decades—not years to materialise—but the climate change agenda is forcing the pace and the gas industry is one that builds capacity that lasts for decades and takes decades to pay-off. This begs are rather different question, do we still need a golden age of gas?


Show us the demand!


If you are natural gas producer today contemplating the development of a new LNG liquefaction plant that will require billions of dollars of investment and that will not start production until the mid-2020s, you face a very high degree of uncertainty.  As we have seen in Part One of this Blog, the industry is about to deliver an unprecedented surge in production capacity and the market may not rebalance until well into the 2020s—the consequences of this are discussed below. One might ask how this happened?  With the benefit of hindsight, one might suggest that over confidence about the future oil price—as most LNG is oil indexed—and the rate of LNG demand growth—because of the gas as a transition fuel narrative—prompted group-think and an over-confidence about how much LNG would be needed by the end of this decade. A situation seriously aggravated by the shale gas revolution in North America and a desire to export that gas. Now the industry narrative is that this current period of uncertainty has resulted in an understandable decline in new FIDs, an increase in project cancellations (look at British Columbia, for example), and delays and reductions in scale; this means that because demand is going to continue to grow the market will tighten in the mid-2020s and prices will rebound. So back to that difficult FID decision today. To make an investment decision today the key issue is show us the demand?


As with global energy demand more generally, it all hinges on non-OECD Asia. The IEA’s Gas 2017 report echoes their World Energy Outlook in their relative optimism about future natural gas demand growth, they project that over the five-year period to 2022: ‘gas demand will grow by 1.6% per year…. This means that total annual gas consumption reaches almost 4 000 bcm by 2022.” However, almost 90% of that anticipated growth in demand will come from developing economies, led by China which accounts for 40% of total demand growth, potentially, followed by India in the rest of Asia. Of course, much of this growth will come in countries that have their own gas supplies in the Middle East and Africa. For China, the key will be its ability to grow domestic production alongside demand growth so as not to increased import dependency. Nonetheless, China’s import dependency is expected to increase from 30% today to 40%, with half if its imports coming from pipeline gas (including Russia via the Power of Siberia pipeline) and half from LNG.


Traditionally, global LNG demand has been dominated by Japan, and to a much lesser extent, South Korea. In 2016, according to BP’s statistics, Japan accounted for 31.3% of global LNG imports and South Korea 12.7%, followed by China 9.9% and Taiwan 5.6%. Overall, in 2016, the Asia-Pacific accounted for 70% of global LNG imports, Europe 16.3%. The problem is that demand in Japan is set to fall as more of its nuclear power stations come back into production and demand in South Korea is stagnant. There has been some growth in Europe, and there is ample LNG import capacity; but its traditional pipeline suppliers—Algeria, Norway and Russia—will likely compete against LNG imports. It is true that domestic production is falling in Europe, but gas in power is facing growing competition from renewables and significant gas demand growth seems unlikely.  All of this highlights the fact that gas demand growth in Asia will be critical to rebalancing the global gas market. However, for gas demand to grow there must be a plausible narrative to get rid of coal, not just in power, but also in industry; and to replace oil-based fuels in transportation. Finally, much of this energy demand growth is new demand spurred on by rising living standards and urbanisation, as such it requires new import terminal, pipeline transportation, electricity generation and transmission infrastructure to be built, all of which raises the cost of creating new gas demand.


The future of gas in China


A brief examination of the situation in China makes clear the complexity of the issue. It is urban air pollution, rather than concerns about carbon dioxide emissions, that is driving the current political support for increased gas use. The 13th Five Year Plan dictated an increase in the share of gas in the primary energy mix from 5% in 2015 to 10% in 2020 and then 15% in 2030. As with everything in China, one needs to gauge the percentage increases against the absolute physical increases in demand, small percentages result in large absolute increase in demand. The IEA see China’s gas consumption increasing between 2016-22 from around 205 bcm to 340 bcm, an annual growth rate of 8.7%. However, the Chinese Government has already watered down the 2020 target stating that it is now between 8.3 and 10% and it is proving reluctant to make, let alone enforce, the reforms needed to grow gas demand at the expense of coal. In the Tier 1 cities—most notably Beijing—coal fired power has been regulated out of local power generation, but elsewhere it is economics that dominates and coal remains a cheaper alternative to gas. Inroads may be made in the commercial city gas sector and in industrial demand, but large-scale switching from coal to gas seems unlikely, not least because substantial new infrastructure for transport and distribution would be required. Gas is also struggling in the transportation sector where new energy vehicles are dominated by electricity and hydrogen fuel cell solutions. Should the domestic shale industry continue to disappoint, Beijing will also be concerned that increased gas demand will simply result in growing import dependence. Even though its NOCs have done a good job of securing multiple sources of supply, so much so that they have more gas (particularly LNG) than they need. The real problem is price. To be attractive, the domestic price needs to be low, but that low price does not incentivise domestic production, nor does it cover the costs of imports whose price is determined by global markets. The only solution, then, is to use regulatory measures to enable gas to complete at a higher price against coal. One solution would be a carbon market, but that is also making slow progress. On the supply side, policy intervention is also required to support shale gas development. All of this may mean that China’s gas demand growth continues to disappoint and it sidesteps the option of gas as a transition fuel altogether, relegating it to a local solution to problems of air pollution in major urban areas. At the same time, if domestic production was to grow significantly and demand growth disappointed, the net result would be lower imports, with pipeline gas likely holding its share at the expense of LNG. Thus, with the Power of Siberia pipeline scheduled to start by the end of the decade and then ramp up production to 38 bcm a year by the mid-2020s, the prospects for significant LNG demand growth in China need careful consideration. This is not only a key factor in determining when the global LNG market will rebalance, but also the longer-term prospects in the second half of the 2020s.


The challenges that gas faces in China are replicated throughout the developing world, especially in countries that are already using coal and that have substantial renewable energy potential. India fits this bill and is the next battle ground for global gas to complete in. It is noteworthy that BP’s 2017 edition of its Energy Outlook included a ‘slower gas’ scenario where global gas demand growth faltered. They point out that their base case, where gas demand grows at twice the rate of either oil and coal and its share of primary energy increasing to 2035 is predicated on climate and environmental policies tightening so as to benefit gas at the expense of coal. But, if this doesn’t happen, then gas won’t be able to force coal out of the mix and gas demand growth will falter.  The lesson is clear, if gas is to serve as a transition fuel—which is itself is problematic—it must either be price competitive against coal or it must benefit from regulations that constrain coal and promote gas usage. It is air pollution controls that are forcing coal out of the mix in the EU and, until recently at least, the US. The reality is that even at today’s low prices gas cannot compete on price alone, especially if that gas is imported LNG.


All this discussion suggests that future security of demand is the key challenge that needs to be overcome if there is ever to be a golden age of gas. Security of demand must be underpinned by a gas price that is low enough to able gas to complete and grow market share, but high enough to incentivise new production and/or cover the costs of imports.


Nothing like business as usual


This final section considers the impact that the coming supply glut is having on the way that the LNG business is conducted, what the Oxford Institute for Energy Studies has called the ‘great reconfiguration.’


It is worth noting that a large majority of global gas production—just under 70%--is still not traded across borders. Of the 30.5% that was traded in 2016, 30.5% (346.6 bcm) was as LNG.  Although liquefaction makes gas more portable and produces a product more akin to oil, the reality is that the nature of LNG industry has, until recently, served to constrain the industry to operate more like a ‘floating pipeline’ where producers and consumers are tied together over a long period of time by contracts. The reason for this is the capital intensity of the LNG supply chain and the way that the industry has traditionally been financed. A traditional LNG project would involve the development of a stranded gas field that can only be delivered to market via liquefaction. To develop that field requires substantial capital that can only be secured against guaranteed future deliveries of LNG to pre-determined buyers. Thus, for an LNG project to proceed to development it must first secure enough long-term (firm) contracts to fixed destinations at agreed volumes to guarantee a future income stream to cover the costs of capital, plus, it is hoped, an acceptable level of return. In theory, this model ensures a degree of self-regulation as projects are only sanctioned as buyers are lined up. However, in an increasingly competitive market, a developer may proceed having only sold 70-80% of their gas, hoping that they will be able to sell the remainder on the spot and short-term market. The problem is that when a lot of projects proceed on this basis there is a lot of LNG produced with no firm buyer. Added to which, buyers are increasingly requiring flexibility over the levels they must take or pay and sought to remove destination clauses that limit their ability to re-sell gas they don’t need. The net result has been a steady increase in the amount of ‘footloose’ LNG that is available to support spot and shorter term sales. This situation has also been promoted by the emergence of aggregators that have a global portfolio of LNG projects available to supply their customers, as well as the entry into the market of traders who don’t own production capacity, but buy and sell LNG cargoes.  In 2016, short and medium-term LNG trade reached 73.2 MT or 28% of total trade. Although many of the new LNG project are tied to long-term contracts, it is expected that over-supply will promote the further growth of short and medium-term trade or it may result in production being shut in.


As noted earlier, the combination of historically high oil prices and the tight market in the aftermath of Fukushima resulted in high LNG prices, this prompted the major LNG importing countries, led by Japan, to question the logic of oil indexed pricing and the dominance of long-term contracts with destination clauses that predominates in Asia. At the time, the shale gas boom in the US meant that the bench mark Henry Hub gas price was significantly lower than the Japan LNG price. BP data show that in 2012 the average Japan LNG price was $ 16.75, while the average Henry Hub price was $ 2.76. This led some Asia buyers to explore the possibility of using Henry Hub as a benchmark price. However, the subsequent fall in the oil price eased this pressure, in 2016 the Japan LNG price was $ 6.94 and Henry Hub $ 2.46, which means that the full cost of delivering US LNG to Japan is not currently competitive. Nevertheless, the Japanese Government seems determined to introduce greater competitiveness into the Asia LNG business. In 2016, it used it Presidency of G7 to push for a global LNG market and a move away from oil indexation and the long-term fixed contact. This year it has followed this up by banning destination clauses in all future LNG projects, allowing LNG buyers to re-export surplus LNG, adding more flexible LNG to the market. There is also interest in establishing a gas trading hub in Asia to promote gas-on-gas competition, following the trend in Europe where more than half of gas traded in now through such hubs. In the UK, LNG importers must accept the domestic price, NBP. All of this activity suggests that the emergence of significant amount of spot and short-term LNG on Asian markets will accelerate the move away from the traditional model. While this might herald lower prices and greater flexibility for buyers, it may also result in greater volatility and, more significantly, and it will undermine the basis upon which future LNG projects will be financed.


US LNG is a potential game changer


The growth of US LNG exports represents the final piece in the puzzle. There are 6 projects underway, with the first entering into production in early 2016, but there are many more proposed. If Australian LNG represents the first wave of the LNG glut, the US projects are the second wave; but they are very different. First, five of the six first generation US LNG projects are based on brownfield sites that were previously import terminals. This has reduced both their cost and construction time. Second, they are tapping the continental US gas market, rather than a stranded gas field. This gives them greater flexibility with many contracts on a tolling basis whereby the exporting company purchases the option to liquefy from the capacity owner, who may or may not also source the gas. This means that if market conditions are not profitable the option to liquefy may not be exercised. The absence of destination clauses also adds to the flexibility. Thus, US LNG will provide a large amount of flexible LNG that has the potential to be a global game changer. This has significant implications for those already in the market, and poses a major challenge to potential new entrants.


Given current market conditions and the level of uncertainty, making commitments to develop new LNG liquefaction capacity to supply the market in the mid-2020s is challenging to say the least. Witness the decision by the Malaysian NOC Petronas to cancel its project in British Columbia due the ‘challenging environment’; this follows on Shell’s decision to suspend its investment decision on the Canada LNG project until early 2019.  Since then, Qatar has announced that it will lift its moratorium on expansion and increase its production from the current level of 77 mtpa to 100 mtpa in the next 5-7 years. As Qatar is the lowest cost producer with a strategic location and an established reputation, this announcement challenges everyone else looking to develop new projects, as well as Qatar’s current IOC partners—ExxonMobil, Shell and Total. A number of regions are looking to develop or expand LNG to meet longer term demand, these include East Africa, Western Canada, the Eastern Mediterranean and Russia. One solution has been to down-scale and move to lower cost floating LNG systems and smaller scale LNG projects, thus reducing the level of risk and increasing flexibility. What is clear is that cost competitiveness is now the new mantra for LNG producers, as it is for the entire oil and gas industry.


LNG at the crossroads


The global LNG industry is now at the crossroads. The traditional system is under stress, while it has provided certainty to both producers and consumers, this has come with a lack of flexibility and a price that no longer meets the expectations of the buyers and that may not enable LNG to complete in developing markets. What is needed is a system that is sufficiently flexible and price competitive to enable LNG to be cost competitive to grow new markets, while, at the same time, providing sufficient income and certainty to incentivise new production. Such a system has yet to emerge and the only thing that is certain is that business as usual is not the future.




Clearly, the Experts Panel at the 21st Sakhalin Oil and Gas Conference will have a lot of issues to consider and there is bound to be a difference opinion. Participants will also be able to express their views via ‘Live Polling. ‘Among the key question to consider are:


  • When will the global LNG market re-balance?
  • What are the prospects for gas demand in China?
  • How will LNG be traded in Asia in the future?
  • Will an Asia gas trading hub emerge?
  • How will LNG be priced in the future?
  • How will new LNG projects be financed?
  • Will Sakhalin expand its level of LNG production?
  • Will Russia gain a greater share of the global LNG market?
    Will there be a ‘Golden Age of Gas’?


Published on 28 July 2017 by Maria Danilova

The launch of large capacity of new export LNG projects in various countries, such as Australia, USA and Russia, will inevitably lead to changes the way LNG is traded in the global market. Demand exceeded supply and the surplus of LNG is expected to lead to the formation of buyers’ market.

Asia Pacific Markets and Russian Companies

Published on 28 July 2017 by Maria Danilova

Significant changes occurred at Asian markets over the last year. Russian blend ESPO (Eastern Siberia Pacific Ocean) – blend of Russian crude delivered via ESPO pipeline – is most demanded at the Asia Pacific market. China is the principal buyer of Russian crude exported to the east (share of China in Russian crude export exceeds 20%). According to Rosneft, in 2016 Russia became champion in exports to China making almost 14% of China import, bypassing exporters from Saudi Arabia. When ESPO is exported via East Siberia - Pacific Ocean pipeline, Urals is shipped to Asian markets in tankers traversing the Suez or Africa.