The Chinese have driven a hard bargain in closing a 38 bcma supply deal that is priced on a similar basis to Russia’s existing European supply contracts.  But in return, Russia has secured a central role in supplying the Asian gas market over the next decade.  Russia has also thrown down the gauntlet to LNG exporters courting China.

The Russia – China deal and the associated Power of Siberia pipeline should facilitate both:

1. Future incremental sales of pipeline gas to China, both from Gazprom and potentially other Russian producers.
2. The future export of Siberian gas from east coast Russian LNG terminals, on the doorstep of Asia’s largest buyers, Japan & Korea.

These factors present a substantial competitive threat to as-yet-uncontracted LNG producers in Australia, Canada and Africa, particularly given the higher combined production & shipping cost base of these exporters.  The impact of the Russian deal in displacing Chinese LNG demand also increases the likelihood of the LNG oversupply scenario that we set out last month.  As Russian gas starts to flow east later this decade, the Chinese border price could become an important benchmark in driving Asian gas pricing.  China however may have other ideas.

Deal summary

Deal volume & infrastructure

An initial agreement has been reached on 38bcma of gas, which will flow from Russia’s Eastern Siberian gas fields down a new ‘Power of Siberia’ pipeline into gas hungry North Eastern China.  The pipeline within Russia is then planned to continue onto Vladivostok to support future Russian LNG exports.  The route is shown in Chart 1 below:

Chart 1: Route of new gas from Russia into China

Source: Gazprom

The planned pipeline infrastructure may support up to 60 bcma over time.  Wood Mackenzie estimates 125 bcma of gas demand in northern China by 2025, illustrating the growth potential through this and other pipelines.

The deal also opens up east coast Russian LNG exports.  Volumes from the Kovyktinskoye and the Chayanda field could also supply gas to Gazprom’s proposed Vladivostok LNG project.  And the pipeline also facilitates exports from other Russian producers.

But it is early days and there are large capex hurdles to be overcome before gas flow becomes a reality.  The overall cost for the Kovyktinskoye and Chayandinskoye upstream development, Power of Siberia pipeline and processing costs could exceed $40 billion according to Woodmac.

Deal price

A range of analyst views on deal pricing have been circulating over the last two weeks.  The headline reported deal price was somewhere between 350-380 $/tcm, equivalent to 9.5 to 10.4 $/MMBtu.  But some analysts are estimating slightly higher contract prices by the time the gas flows in 2019 (up to around 11 $/MMBtu).  The deal is oil-indexed and full pricing details have not been revealed, so all estimates are subject to uncertainty.   There are also other factors in play that impact deal value e.g. the Russian vs Chinese share of pipe capex and upstream development costs.

But what is important is that the deal price, at somewhere around 10 $/MMBtu, is comparable to current German border prices for oil-indexed Russian contracts (after the various concessions granted to pricing formulae in recent years).  This appears to be marginally cheaper than estimates of Turkmen gas at the Chinese border (11.00-11.50 $/MMBtu).  And importantly, it is well south of recently signed Asian LNG contracts which are closer to 16 $/MMBTu at current oil prices.

The politics

Russia looks to have accepted price concessions to get the deal done at a time when Europe & the US are expressing concerns around security of supply from dependence on Russian energy exports.  It is no coincidence that the deal has been struck in the midst of the political jousting around Ukrainian sovereignty.

But the Russians have exaggerated the level of competition for Russian gas.   Gazprom CEO Alexei recently has stated that “Europe has lost the competition global for LNG, and in a single day it has just lost the competition for the world’s pipeline gas as well”.  Talk like this makes impressive headlines back in Russia, but Russian exports are not a question of ‘either/or’ to Europe vs China.  The gas for the Chinese deal is currently ‘stranded’ in east Siberia with no infrastructure linking it to the West Siberian producing province (which supplies Europe and which has some 100 bcma of excess production capacity).  If there was really such a squeeze on Russian gas, China would not have been able to beat the deal price down to the extent that it has managed.

The deal is important to China but Russia is only one of a diversified mix of supply sources for the Chinese including:

• Domestic production – China has a substantial unconventional gas resources with the government targeting 80 bcma of shale gas production by 2020 (although realistically by 2020 production will likely fall well short of this).
• Turkmenistan, Uzbekistan & Kazakhstan pipeline gas – China is currently importing around 20 bcma a number that could triple by the start of next decade, and with potential to increase further if pipeline capacity can be expanded, given Turkmenistan’s massive reserves.
• LNG – China imported about 25 bcm in 2013 but is rapidly developing more regas capacity and is an investor in a number of upstream and liquefaction projects, both under construction and planned (e.g. in Australia, East Africa and Canada).

Nevertheless, it is reasonable to expect that the pricing of Russian pipeline gas may take on a very important role in influencing pricing in the evolving Asian gas market.

The importance of pricing

The new Russia-China deal at around 10 $/MMBtu (given current oil pricing) suggests Russia is at least initially willing to sell gas at the Chinese border at a similar price level to that of its European supply contracts.  But the deal also facilitates development of Russian East coast LNG sales.  For Russia this deal is a strategic enabler which allows them to:

• Increase future pipeline supply from East Siberian fields to China, at (what Russia hopes would be) higher price levels
• Export LNG to other Asian buyers via east coast terminals on ‘traditional’ oil indexed terms
• Potentially pave the way for the previously tabled Altai pipeline route to transport West Siberian gas into North West China – thus eventually monetising the 100 bcma or so of ‘surplus’ Russian production capacity

The recent Russia-China pipeline deal (which took 10 years to come to fruition) has clearly improved Russia’s current strategic positioning vis a vis the Asian market.  However future developments in the wider supply arena and China’s future strategic positioning may frustrate some of Russia’s aims in this regard.

Firstly, the monetisation of 38 bcma of otherwise ‘stranded’ East Siberian gas represents a reduction in Asian LNG demand of 38 bcma of LNG (all other things being equal) and hence this volume will be available to challenge Russia’s pipeline gas market share in Europe.

Secondly, a mild European and Asian winter has seen European hub prices and Asian spot LNG fall sharply.  And despite the outlook of a slow restart of Japanese nuclear plants, new supply is on the way with the PNG LNG project soon to start up and the first of many new Australian LNG projects coming onstream next year.  As a result, sentiment is moving towards the ‘oversupply’ scenario that we set out in a recent article.

The Third factor is the degree of future success China has in creating supply options and competition, despite the likely continued rapid growth of its natural gas demand.  In addition to further Russian pipeline supplies (from East and West Siberia) these include upside in Central Asian pipeline imports, shale gas development if successful, LNG projects with Chinese interests and future spot and contracted LNG supplies.

While Russia may be hoping that the pricing of volumes of Russian pipeline gas into China may become an important new Asian price benchmark, it is not clear that this suits China’s future requirements.  China’s aims might be better served by maximising its own domestic production and creating competition between different pipeline gas supplies and LNG imports.  It is quite possible that at some point in the next 5 to 10 years, China declares that all imports into the country be priced on a netback basis from its Shanghai hub, regardless of the aspirations of suppliers.  Such a move is more likely to succeed in a well-supplied LNG market.  The recent Russia – China 38 bcma pipeline deal ironically makes such an eventuality more achievable.

This week’s article included input from Howard Rogers, a Senior Advisor with Timera Energy and Director of Natural Gas Research at the Oxford Institute for Energy Studies.

It is ironic that the growing threat of Russian supply cuts has conincided with a sharp decline in European gas hub prices.  Prompt UK NBP prices have fallen more than 20 p/th since the start of the year.  TTF & NCG prices by more than 8 €/MWh.

This price slump is more than a seasonal decline as winter turns to spring.  It reflects a North West European gas market that is substantially oversupplied into the summer.  But what are the drivers behind price falls and are they structural or temporary?

Oversupply in Europe

It has been a mild winter followed by a mild spring across Europe, with gas demand well below average.  As a result storage levels have remained relatively high coming out of winter.  UK storage for example is currently around 65% full vs around 20% this time last year.  Despite lower demand levels, pipeline flows into Europe have held up well, e.g. robust flows from Norwegian fields.  On top of this, significant volumes of Qatari LNG have started to flow back into Europe over the spring.

The resulting decline in gas prices is illustrated in Chart 1 by the green line (spot NBP prices).  It can be seen that as spring has progressed, hub prices have diverged from oil-indexed contract prices (the dark blue line) and moved sharply lower.  It is no coincidence that on the other side of the world Asian spot LNG prices have also plummeted (the red dotted line).  But we come back to that relationship shortly.

Chart 1: Global gas price benchmarks

Source: Timera Energy

Last year we set out a framework for understanding European gas hub pricing dynamics.  This focuses on understanding the behaviour of the key tranches of flexible (price responsive) supply into European hubs.  Applying the framework to the current market conditions provides a good insight into the behaviour of hub prices.

In describing the framework we set out why hub prices typically trade within a loose band around oil-indexed contract price levels:

Of the flexible sources of supply, pipeline contract swing is of principle importance. Russian and Norwegian oil-indexed contracts are particularly important as a provider of swing flex into Germany. Utilisation of this swing flexibility tends to anchor European hub prices within a band around oil-indexed contract price levels. 

This price band is somewhat flexible, but it is also resistant. It can be stretched by prevailing supply and demand dynamics, but the further prices deviate from oil-indexed benchmarks (e.g. the German border price), the stronger is the force acting to pull prices back. As hub prices fall below oil-indexed contract prices, contract owners utilise swing to pull back on contract volumes which supports hub prices. As hub prices rise above oil-indexed levels, swing gas flows increase acting as price resistance.  A similar logic applies to gas storage.

As prices fall, reduction of swing contract volume take and buying of gas to inject into storage facilities, act to support hub prices.  But this impact has limitations, e.g. storage injection will start to dry up as facilities fill by June/July.  The current disconnect between hub and oil-indexed prices indicates that stronger forces are at work driving prices below the oil-indexed price band.  This is where global LNG dynamics are playing a key role.

Europe as LNG balancing market:

Since Fukushima, flexible LNG volumes (e.g. uncontracted production & divertible supply contracts) have mostly flowed to premium markets in Asia and South America.  European hub prices are a less attractive alternative for LNG that can be sold at higher prices elsewhere.  But the LNG spot market is relatively illiquid and when prices are soft, Europe plays an important balancing role in soaking up excess supply.  This is particularly the case in spring periods given seasonal weakness in Asian LNG demand.

Qatar as the world’s largest exporter of LNG plays a key role in determining flows to Europe.  The Qataris have significant volumes of relatively inflexible uncontracted production that needs to find a market.  Most of this LNG flows to Asia.  But when Asian spot prices are weak and liquidity is poor, additional volumes can act to drive prices even lower.  It is not in the Qatari’s strategic interest to drive a slump in spot prices in their primary market.  So surplus LNG is typically sold into Europe, hence the volume pickup in gas imports to the South Hook terminal in the UK over the last couple of months.

European hub prices (particularly NBP) offer a relatively liquid option for selling surplus cargoes and there is easy access to regas capacity.  So the current weakness in Asian spot prices is compounding weakness in European hub prices.  While most of the LNG is being imported into the UK, the impact is quickly transmitted to the Continental hubs (e.g. TTF, NCG).  The IUK interconnector has been flowing strongly to Belgium (with NBP at discount to TTF) and Norwegian flows also act to balance hub differentials.  But perhaps the most important question is what happens next?

Some factors to watch

This year’s spring decline in spot LNG prices is not unusual.  A similar decline was seen in 2012 and 2013 (see Chart 1).  Asian demand has historically recovered to support prices over the summer period (e.g. to hedge air-conditioning load and the start of preparations for winter).  That will be a key factor to watch this year.

The much anticipated Russian supply cuts for gas via Ukraine are also likely to have an effect from June.  We come back to the impact of these in an article to follow shortly.  But Russian cuts should provide price support also (albeit well priced into the forward market).

But a couple of factors that normally provide support at low price levels, are unlikely to help this year.  High storage levels will reduce injection demand this summer (caveat the impact of Russian cuts).  And gas-fired power plants, which typically increase output as gas prices fall, are currently so far out of merit (vs coal plant) that power sector gas demand will provide little support.

As a result, the timing and volume of spot LNG flows into Europe may be very important in determining the extent and duration of the European hub price slump.  The structural Asian price premium over Europe is likely to return into next winter.  But in the meantime the hub price slump may have further to run.  These dynamics are an interesting preview of what will be a much more dynamic global gas market once flexible US LNG exports start to flow later this decade.

A market consensus view has developed that the global LNG market will remain tight for the rest of this decade.  The thesis runs that LNG buyers are nervous about being caught short supply as gas import demand from developing economies surges.  The post-Fukushima squeeze is fresh in mind.  Producers are also projecting a tight market to support their investment cases, given the tens of billions of dollars flowing into new liquefaction capacity.  While this consensus is currently supported by a range of buyers and producers, it is increasingly coming under challenge.

The tight market consensus has developed with some justification. Since the Fukushima disaster and the end of the most recent liquefaction growth ramp in 2011, new supply has struggled to keep up with demand growth. This has driven a structural premium of Asian spot LNG prices over European prices as shown in Chart 1.

Chart 1: Global gas price evolution

Source: Timera Energy

It is not difficult to build a compelling case for market tightness to continue as new production is absorbed by aggressive demand growth across Asia, the Middle East and South America.  However a number of key factors driving the global LNG supply and demand balance remain uncertain. In our view that uncertainty warrants the consideration of alternative outcomes.

An uncertain future

Complexity and uncertainty around the global supply and demand balance increases significantly from 2015. Most forecasts of the LNG market balance show a steady growth in demand met by an equally steady increase in supply (see Chart 2 below where BG has overlaid a number of consultant demand forecasts on its estimates of supply growth).  But the actual outcome, whatever form it takes, may not follow such a smooth path.

Chart 2: Demand and supply growth projections

Source: BG

On the supply side, large and lumpy volumes of new liquefaction capacity are being developed.  As these projects approach FID, much of the gas will have been signed under long term contract.  But many of these supply contracts are with portfolio players rather than the gas being assigned to dedicated demand sources.

In simplistic terms the development of new liquefaction capacity can be viewed as a response to recent ‘price signals’ from the Asian markets.  But it can also be seen as a consequence of:

• the monetisation of Australian projects – both under construction and planned
• the recent ‘surprise’ discovery of a new large gas basin offshore East Africa looking for market
• a push by Russian players to access the Asian LNG market
• the much publicised prospective wave of US LNG projects
• Western Canadian projects also seeking to enter the LNG supply business.

History illustrates the timing risks associated with large new liquefaction projects.  New capacity has consistently faced delays given the cost and complexity of project execution.  This is rightly presented as an argument in support of tighter market conditions.  But it can also result in large volumes of gas coming to market at a similar time (i.e. divergence of actual vs forecast delivery profile).  These volumes can place downward pressure on spot prices even if only on a temporary basis.

There is also the potential for a major new ‘wave’ of supply in the 2018 to 2023 time window (encouraged by the current tight market price levels).  There is clearly significant uncertainty around the magnitude and timing of this new supply.  But once projects are committed, it can be difficult for the industry to respond to developments in market dynamics, given the lengthy (~4 year) liquefaction construction period.

On the demand side, Japan has recently announced its decision to re-start its fleet of nuclear power plant, although the extent and timing of the resulting LNG demand displacement is unclear.  But the elephant in the room is non-Japanese Asian demand.  The strong LNG demand growth projections (shown in Chart 2) are heavily dependent on growth in Chinese and Indian demand.

However uncertainty over the size and impact of a more sustained slowdown in Asian economic growth remains.  China epitomises this problem.  Between recent IEA and Chinese forecasts the uncertainty for 2020 gas demand ranges from 330 to 400 bcma.  The domestic supply situation is unclear and partially driven by views of future shale gas success. The possible use of upside to 65 bcma  in Turkmenistan and Central Asian pipeline imports is perhaps eclipsed in uncertainty level by the ‘Schrödinger’s Cat’ of the deal for Eastern Siberian gas, reported as a 38 bcma deal but with the potential for higher volumes over time .  If China’s LNG imports are the ‘residual’ balancing item in the global market then they reflect a highly uncertain future.

The tight market view

There can be no doubt that the LNG market is currently tight.  There has been little in the way of new liquefaction capacity since 2011 and there have been significant feedgas issues into some existing terminals (e.g. Algeria, Eygpt and others).  This has contributed to the spot price volatility that can be seen since 2011 in Chart 1, although it should be recognised that this volatility is in part driven by the relatively small number of price-disclosed spot sales.  Over the same period Asian demand growth has remained robust (albeit with seasonal variations) and incremental demand has largely been satisfied via the diversion and reloading of European cargoes.  These dynamics are illustrated in Chart 3.

Chart 3: Recent evolution of global LNG market balance

Source: BG

If Asian LNG demand growth continues to outstrip its dedicated supply for the rest of the decade, European LNG supply will likely retain its current global balancing role.  In other words significant spot price premiums over European hub prices will attract cargoes away from Europe, to be replaced as necessary by ‘back-filling’ Russian pipeline supplies.  Spot price volatility will likely remain, as the marginal drivers of LNG arbitrage dynamics change over time e.g. due to seasonal factors and timing of new supply.  So there may be temporary increases in cargo flows to Europe as the global balancing market in times of lower Asian spot prices (with Russian pipeline supplies to Europe providing the buffering mechanism).

Under these conditions of market tightness, oil-indexed contract pricing is more likely to remain dominant, albeit accepted with extreme reluctance by Asian buyers.  The LRMC of new projects in Australia, Canada and East Africa will be an important benchmark when long term contracts are signed.  In other words it is likely to be a seller’s market where Australian and North American export volumes are absorbed without a structural impact on market and contract pricing.

In this world the majority of US exports will flow to Asia.  However the more flexible structure of US export contracts will likely increase the influence of Henry Hub on LNG spot market price dynamics.  US export projects represent the reconnection of the US to the rest of the global gas market and a Henry Hub/NBP driven ‘Atlantic Basin’ price signal is likely to increase over time.

However, underpinning this view of a long-term tight LNG market is the premise that ‘Economics 101 has failed’ in that suppliers, although each hopeful of supplying what they see as a premium market, collectively fail to execute projects to schedule and so in aggregate constrain supply.

A transition to oversupply

There are a number of factors that could derail the consensus view.  But perhaps the most obvious one is a failure of developing economy demand to materialise to the extent that has been forecast.  This could be for example due to an Asian economic downturn (major setbacks in emerging economies are common even if only temporary). Or it could be due to a combination of Japanese nuclear restarts and the displacement of large volumes of Chinese LNG demand by Russian pipeline imports or other supplies from the back end of this decade.  Howard Rogers explored some of the drivers of an Asian LNG demand induced oversupply situation in a previous article.

Whatever the potential causes, the result of an oversupply situation is likely to be the flow of surplus gas into the LNG spot market.  This will place pressure on global LNG prices to re-converge as they did in 2009-10. It would also tend to dampen LNG spot price volatility and could significantly reduce the value of LNG portfolio flexibility (which is currently at a premium).

LNG volumes ‘in excess’ of Asian requirement would find a home in Europe (as they did in 2010 and 2011) placing pressure on Russia to either reduce pipeline supplies to maintain hub prices at ‘target’ levels or alternatively engage in a price war to reduce US LNG exports.  Such dynamics, in addition to seasonal weather effects could increase price volatility albeit around lower LNG price levels.  This is unlikely to be a good outcome for LNG producers and large portfolio players and unsurprisingly some larger players are starting to downplay the risks around an oversupply scenario (perhaps a barometer for concern).

Such an oversupply scenario may be relatively short lived (e.g. the period over 2009-10) as a result of a temporary mismatch in new demand and supply.  But this could be enough to disrupt long term contract pricing dynamics and to shift the balance in favour of LNG buyers.  The 2009-10 period was an important driver of the development of hub prices in Europe.  A similar oversupply situation later this decade could be the catalyst for an increase in influence of hub pricing on Asian LNG supply.  It is interesting to note that anecdotal references to ‘hybrid pricing’ i.e. the inclusion of hub price as well as oil indexation, are starting to circulate in Asian LNG circles.

Commercial implications of the two alternative outcomes

In this article we have set out two views of LNG market evolution.  The current consensus view that market tightness continues until the end of this decade, and an alternative view that there is another period of global oversupply (either on a temporary or more structural basis).  The actual outcome may indeed differ from both of these.  But in our view the level of uncertainty around some of the key drivers of supply and demand warrants the consideration of a range of outcomes.

The value of considering alternative outcomes comes from a realisation that LNG asset and portfolio values may differ substantially depending on the evolution of the global market balance into the end of this decade.  Spot price dynamics, gas flows, the structure of supply contract pricing and the value of portfolio flexibility will all be strongly influenced by market outcome.  We take a more structured look at the commercial implications of a tight vs oversupplied market in an article to follow shortly.

This week’s article was co-authored by Howard Rogers, a Senior Advisor with Timera Energy and Director of Natural Gas Research at the Oxford Institute for Energy Studies.