Author: David Duncan

US exports are now a reality

Posted on by David Duncan

By all reports commissioning of Cheniere’s Sabine Pass terminal has been progressing smoothly and will export its first cargo in the next few weeks. This marks the start of the ‘1st wave’ of North American export capacity that will reconnect the US gas market with the global LNG market. More than 80 bcma of US liquefaction capacity is now contracted and under construction. Behind this is a similar volume of ‘2nd wave’ projects that are in an earlier stage of development.

US exports are set to drive a transformation in LNG market trading & pricing dynamics. This is because US export contracts are structured very differently to standard LNG supply contracts. They allow contract buyers to source gas on a Henry Hub rather than an oil-indexed price basis. They also allow buyers complete destination flexibility to respond to prevailing global spot price signals.

It is no coincidence that a substantial majority of US export volumes have been contracted by LNG portfolio aggregators. The inherent flexibility in US export contracts is set to be a catalyst for the evolution of LNG trading. As aggregators utilise contract flexibility it will drive both an increase in LNG market liquidity and in the influence of Henry Hub on global gas pricing.

 

The wave of new US export capacity

There is 83 bcma of committed US LNG export capacity which is contracted, has passed the Financial Investment Decision (FID) hurdle and is under construction. This includes the Sabine Pass, Freeport, Dominion Cove, Cameron and Corpus Christi projects. There has been much anticipation around the first cargo from Sabine Pass. But most of this 1st wave of US export capacity is not scheduled to come on-stream until 2018-19.

In addition to the core 1st wave projects listed above, there are several other projects (Lake Charles, Golden Pass, Jordan Cove) that have negotiated offtake contracts but have not yet given a clear commitment to proceed. The current state of oversupply in the global gas market will not help these projects, particularly when it comes to securing financing, but for the moment we include them as potential 2nd wave candidates. All except Jordan Cove are ‘brownfield’ investments adding to existing facilities of regas import terminals which were ‘built in haste’ prior to the realisation of the shale gas boom.

Chart 1 shows a build-up of 1st wave US export volumes, with the less certain projects on top. The bottom section of the chart shows a breakdown of capacity ownership for these projects. Some volumes have been contracted by Asian utilities. But the majority have been signed up by LNG aggregators & portfolio players. LNG export contract structures and a lack of fixed destination restrictions will greatly enhance the liquidity of LNG trading in the back end of this decade and early next decade.

Chart 1: Ramp up in US LNG exports

US Export Capacity 

Source: Howard Rogers (OIES)

Impact of falling gas prices on US exports

There has been some confusion amongst LNG market commentators and the trade press as to how the current fall in global gas prices will impact US export projects. It is important to separate the impact of falling gas prices on:

  1. Investment: i.e. the ability of new US export projects to contract and reach financial close, and
  2. Flow: i.e. the LNG flow dynamics of committed projects once they come online.

Given that current Henry Hub prices are depressed by excess supply relative to US demand, one should not assume that by 2020, when the US may be exporting 80+ bcma of LNG, that Henry Hub will remain at present levels. Although estimates vary, $4/mmbtu is a more realistic view of the Henry Hub price needed to support the US production levels required to satisfy US demand and LNG exports in the longer term.

The Long Run Marginal Cost (LRMC) hurdle for new US LNG export projects is around $8.5 – 9.5 /mmbtu. This assumes a future long-term sustainable Henry Hub price of $ 4/mmbtu, the 15% premium to cover transport and feed-gas process consumption ($0.6/mmbtu), the export facility tolling fee of around $3/mmbtu and shipping/regas costs ($0.5 to $2.0/mmbtu). US netback price levels from current Asian and European LNG prices are well below this cost, meaning that new projects are going to struggle to reach FID until gas prices recover.

However this does not mean that the 1st wave US export terminals will not flow gas when they come online. The flow decision for US export contracts will be driven primarily by two factors:

  1. The variable cost (or SRMC) of US export contracts i.e. the Henry Hub gas price plus the (~15%) premium to cover transport and feedgas process consumption
  2. The US netback from global spot price signals that represent the market value for exported gas, adjusted for appropriate shipping and regas costs from the US.

Chart 2: US Export flow utilisation and pricing dynamics

LNG Pricing Dynamics

Source: Timera Energy

As illustrated in chart 2, As long as market conditions are such that 2. exceeds 1. then US gas will flow into the global market, constrained by the volume of US export capacity. The sunk capacity cost component of US export contracts (~3 $/mmbtu) will have no impact on flow decisions.

On a variable cost basis, US exports in the near term are still relatively cheap. Front month Henry Hub futures prices closed 2015 at around 2.35 $/mmbtu. Adding a 15% variable liquefaction cost premium gives an all in variable export cost around 2.70 $/mmbtu .

Falling fuel and vessel charter rates mean shipping & regas cost benchmarks are currently around 0.50-1.00 $/mmbtu to Europe and $1.50-2.00 to Asia. At the end of 2015, European spot hub prices are around 5.00 $/mmbtu and Asian JKM spot prices around 7.00 $/mmbtu. That means US netback prices of around 5.00 $/mmbtu. In other words US export contracts are still around $2.00 $/mmbtu in the money.

 

What US exports mean for the global gas market

The ramp up in US exports will have an important impact on the traded LNG market. Currently only a relatively small volume of global LNG supply has the contractual flexibility to respond to market price signals. BG estimates that only about 13% of contracted supply volumes are currently flexible as shown in Chart 2 (this is higher if you include uncontracted Qatari production volumes). US exports are estimated to almost double the amount of flexible contracted LNG to 25% by 2025.

Chart 2: Evolution of flexible (price responsive) LNG volumes

BGflexVols

Source: BG

This ramp up in flexible LNG volumes will be a shot in the arm for LNG market liquidity. But flexible US export volumes will also have an important impact on global pricing dynamics by acting to drive:

  1. Global price convergence: given US LNG will tend to flow to the highest price market on a netback basis.
  2. Reduced LNG spot price volatility: given US exports will increase the volume of flexible gas to respond to fluctuations in global spot prices, dampening volatility.

It was assumed when US export contracts were signed that gas would primarily flow to Asia. But the Asian vs European price convergence that has prevailed in 2015 suggests that a substantial volume of US exports will now be sent to Europe, given a more attractive netback price.

The current discount of Henry Hub to Europe & Asia implies a baseload export profile for US LNG. But as LNG oversupply intensifies with the ramp up in new liquefaction capacity later this decade, it is possible that there is further compression in regional price spreads.

If spot LNG prices in Europe and Asia fall to the extent that they no longer cover variable liquefaction and shipping costs from US export terminals, it will start to choke off LNG flow from the US. This US export ‘shut in’ dynamic may become an important global price support mechanism if oversupply intensifies.

Article written by David Stokes, Howard Rogers & Olly Spinks

 

Global LNG and European gas workshop

Timera Energy offers tailored workshops exploring the evolution of the global LNG and European gas market fundamentals and pricing dynamics.  These workshops involve Howard Rogers who, as the Director of the Gas Programme at the Oxford Institute for Energy Studies, is acknowledged as a leading industry expert in the global gas market.

If you are interested in more details please email olly.spinks@timera-dev.positive-dedicated.net

The UK’s dual capacity markets

Posted on by David Duncan

There is an acute and increasing capacity shortage in the UK power market caused by the retirement of older gas and coal plants. This is being driven by ongoing weakness in thermal generation margins, due in part to increasing volumes of renewable output.

In response to security of supply concerns, the UK government introduced a capacity market in 2014. The aim of this intervention was to provide a reliable stream of income to support the flexible thermal capacity required to backup intermittent renewable output. But so far the capacity market has had the opposite effect.

Low capacity prices have contributed to the closure of existing thermal plants. At the same time the capacity market has incentivised delivery of very little in the way of new capacity. So the UK’s system reserve margin, rather than stabilising, continues to fall.

Security of supply is instead being maintained by a stop gap secondary ‘market’ for capacity known as Supplemental Balancing Reserve (SBR). SBR was designed as a temporary measure for the system operator to acquire emergency reserve while the government implemented a real capacity market. But SBR is increasingly becoming the real UK capacity market, by default rather than design.

 

Round two of the official capacity market

Quite a bit of analysis on the second auction outcome has already been published. So we do not intend to do a detailed deconstruction here. But we highlight a few important headline facts:

Clearing price:

In the client briefing pack we published before the 2nd auction, we set out our expectations for the price to clear in the 10-15 £/kW range. We also set out a 20 £/kW upper bound driven by CCGT fixed costs and 5 £/kW lower bound driven by the risk adjusted value of waiting to the T-1 auction. The auction cleared at 18 £/kW towards our upper bound (as shown in Chart 1), driven by the bidding behaviour of older CCGTs. This was marginally below the 2014 auction but broadly in line with market expectations.

Capacity exit:

5.1 GW of older existing capacity was unsuccessful in getting capacity agreements. This consisted of 2GW CCGT and 3.1 GW coal plants. In many ways this is the most important outcome of the auction. Without capacity payments, the economics of these older plants is unviable, in the absence of other regulatory support.

New build:

Genuine new build capacity consisted of 1.1 GW of smaller scale peakers, with 0.5GW of DSR. A significant volume of this was in the form of diesel generator sets, causing the government some embarrassment from an emissions perspective. The 810MW Carrington CCGT was also successful in bidding for a one year ‘new build’ agreement, although this plant was only new build in a technical sense, given it is already close to completion.

Exited capacity:

A relatively high volume of capacity (around 8GW) exited the auction above 50 £/kW as can be seen in Chart 1. This included the larger scale new build CCGT projects in an indication that under the current market rules, the capacity price will need to rise significantly to incentivise CCGT new build. The new UK-Belgium NEMO Link interconnector project also failed to secure an agreement. This was unexpected given that the link will presumably be developed anyway given healthy economics & other regulatory support.

Chart 1: 2015 T-4 capacity auction outcome

FinalCMchart

Source: National Grid

In summary there were no real surprises from the auction outcome. Much more interesting will be what happens to the 5GW of existing plants that exited the auction. This capacity joins a growing list of older coal and CCGT plants that are queueing up for life support from the SBR mechanism.

 

The UK’s other capacity market

In 2015 around 5GW of capacity announced its intention to close, after failing to secure a capacity agreement in the first auction. Another 5GW of capacity has now been added to the endangered list after the second auction. That leaves a cloud of uncertainty hanging over security of supply in the UK power market.

Through this cloud there are two things that are clear:

  1. The UK cannot afford to lose 10GW of capacity. This would send the system reserve margin deep into negative territory.
  2. Neither the capacity nor the energy market is currently incentivising older flexible plants to remain open.

This is where the UK’s unofficial secondary capacity market comes in. The results of National Grid’s procurement of SBR capacity for Winter 2016-17 were released just before the T-4 capacity auction. These show Grid paying an average of 34 £/kW for 3.6GW of capacity, close to double the clearing price in the last two T-4 capacity auctions. In fact one large unit (500MW+) appears to have been paid an 88 £/kW capability price (higher than the price cap of the T-4 auction). In addition to these costs, Grid must also pay utilisation fees if the units are called on to run.

 

Can the status quo really continue?

A cynic could be forgiven for questioning the logic of these dual capacity markets. The main T-4 capacity auctions have been incentivising capacity to close, given clearing price levels below the fixed costs of thermal assets. But at the same time, the SBR mechanism is paying a substantial premium to ensure that the same plants remain open once they have failed to secure an agreement in the T-4 auction.

The inconsistencies and distortions that have plagued the UK power market since the implementation of the Electricity Market Reform (EMR) policies continue. The UK government seems to be wandering along an expensive path towards an increasingly centrally planned capacity mix. There has to be a smarter way to run a power market!

We suspect that the fallout from the 2015 capacity auction and SBR procurement will cause the government to step in with further policy interventions in 2016. We will come back shortly with our thoughts on how this may impact the UK power market going forward. But the winners from a changing rule book are likely to be the developers of larger CCGT assets, with the losers likely to be high emissions diesel and coal generators.

Article written by David Stokes & Olly Spinks

Hub pricing in a converging global gas market

Posted on by David Duncan

There has been a pronounced downward revision of future price expectations across the global gas market as 2015 has evolved. This has been reinforced by falling oil price expectations. There is now growing acceptance that the current oversupply of gas is more than just a temporary phenomenon. Demand growth projections are weakening at the same time that large committed volumes of new supply are ramping up. The world is getting used to a new phase of lower and more convergent global gas prices.

At the start of this year we wrote about two key drivers of European gas pricing dynamics in an oversupplied world:

  1. Falling oil prices, given the oil-indexation of long term European gas contracts
  2. Increasing LNG imports, as Europe acts as a sink for surplus volumes of flexible LNG

In today’s article we revisit those drivers to assess the current state of the gas market, as well as looking ahead to implications for 2016.

 

Oil is weighing on hub prices

European hub prices have fallen from levels around 7.50 $/mmbtu at the start of the year to 5.50 $/mmbtu in Dec 2015 as shown in Chart 1.

Chart 1: Evolution of key global gas price benchmarks
GasPriceChartDec15

Source: Timera Energy

So far there has been almost no evidence of the usual seasonal price recovery as winter approaches. That is partly due to a mild start to winter. But it is also driven by the fact that falling oil prices have dragged down oil-indexed gas supply contract prices as the year has progressed. This is illustrated by the falling German border price proxy for Russian supply contracts in Chart 1 (the purple line). The typical 6-9 month lag in contract indexation means that the oil price declines of summer 2015 are still feeding through in the form of lower gas contract prices.

We have set out previously why lower contract prices weigh heavily on hub prices. In the boxed section below we recap the importance of oil-indexed contract prices in driving hub prices.

Who cares about oil?

Oil-indexation remains a powerful influence on European and Asian gas prices, although one that is gradually eroding as long term contracts expire.  In Asia, almost all LNG contract volumes are indexed to crude benchmarks (e.g. JCC, Brent). In Europe, despite a much publicised trend towards the spot indexation of gas, the majority of long term pipeline swing contracts also remain indexed to oil (primarily gas oil & fuel oil) – albeit moderated via price formula concessions and rebates which have become prevalent post 2008.

Oil-indexation has a particularly important influence on spot prices in Asia and Europe because of its influence on the exercise of contract volume flexibility.  The ability to vary swing contract take is optimised based on the differential between oil-indexed contract prices and spot gas prices.  When spot gas is cheaper than oil-indexed contract prices, contract volume take is reduced and incremental hub gas purchased (and vice versa).

This means that oil-indexed contract prices act as an important longer term anchor for gas prices.  This relationship is a loose one over a shorter term horizon given the influence of other supply and demand factors.  But oil-indexed prices act as a ‘magnetic ceiling’ and typically draw spot gas prices back in line in a reasonably balanced market.  That said, a very tight market can see spot gas prices ‘break through’ this ceiling (UK in 2005/2006) although such occurrences are rare and transitory.  Alternatively an oversupplied spot market can see hub prices disconnect below contract prices (e.g. as in 2009-10).

 

Another interesting dynamic across 2015 has been the shaping of ‘take or pay’ volumes of contracted gas. Gas buyers have utilised contract volume flexibility to shape volume take into the second half of the year. This is because of the price lag in oil-indexed contracts.

At the start of the year oil-indexed contract prices were at a significant premium to hub prices (given the delayed impact of falling oil prices). This provided a clear incentive to reduce volumes earlier in the year. But it has meant a ramp up in contract volume take as the year has progressed in order to comply with take or pay constraints. This is now weighing on prices as 2015 draws to a close.

 

Europe now at the center of the global LNG market

The current global oversupply of LNG increases the importance of the linkage between the European and global gas markets. Europe’s role as a market of last resort for surplus LNG means that European hub prices are a key driver of spot LNG prices globally. In turn, the evolution of oversupply in the global LNG market is having an important influence on European hub price dynamics.

Chart 1 provides a practical illustration of this linkage. Asian spot LNG price levels started 2015 above 9 $/mmbtu. But as LNG demand waned into spring, an absence of buyers saw spot prices quickly fall to NBP/TTF levels, reflecting the price at which European hubs could absorb surplus LNG cargoes.

LNG spot prices have stabilised across 2015 in a 6.50-7.50 $/mmbtu range. This represents a slight premium to European hub prices, but one that barely covers the transport differential to Asia. As a result, LNG import volumes into Europe have increased significantly.

The linkage between LNG and European hub prices is also being reflected in contract pricing terms, with NBP becoming the global benchmark for transaction price levels. For example pricing of the Egyptian and Jordanian tenders held in the second half of 2015 was driven by NBP, even though the contracts have been struck on a Brent indexed basis.

The Egyptian tender reflects another interesting dynamic in 2015. Although the much anticipated ramp up in global liquefaction capacity started in earnest this year with about 15 bcma of new supply coming online, there has been almost no net growth in LNG supply in 2015. This is largely because of a reduction in supply from existing exporters, particularly in the Middle East and North Africa e.g. Yemen, Egypt, Oman & Algeria.

But don’t expect this dynamic to continue into 2016! More than 40 bcma of new Australian and US LNG exports are due to come online across the next year, combined with an anticipated return in the Angola LNG plant. The wall of new supply to be commissioned from 2016-18 is set to become the real test of European hubs as a global gas price floor.

 

What does this mean for supply contract pricing?

Market conditions heavily influence the balance of power in gas supply contract negotiation. Gas producers held all the cards in the three years that followed the Fukushima disaster (Q2 2011 to Q2 2014). But price falls over the last 18 months have seen the balance of power shift firmly back in favour of contract buyers. Evidence of this shift can be seen via the increasing success buyers are having in purchasing gas contracts on a hub based pricing terms.

In the LNG market, hub indexation is becoming standard for the sale of short to medium term supply volumes (typically on an NBP or TTF basis). This has been helped by a number of LNG portfolio players which have been caught with surplus gas and been willing to offer relatively flexible indexation terms to shift volume. This has forced producers to follow suit in order to sell uncontracted LNG volumes. European buyers (e.g. E.ON) are now gaining traction in demanding hub indexation on long term LNG supply contracts into Europe.

Producers have also been granting concessions on European pipeline contract pricing. This is indicative of increasing competition between sellers in an oversupplied market. Falling prices have meant that LNG is now a credible alternative source of incremental supply for European gas portfolios. LNG contracts offer diversification benefits and increasingly flexible terms and European buyers no longer need to pay a premium to secure these. It is Russia that most acutely feels the threat posed by cheap LNG.

We end our thoughts for 2015, reiterating the importance of Russia’s strategy in an oversupplied gas market. Gazprom appears to be responding to increasing competitive pressure in a lower price environment. Oil indexation remains its headline policy for the moment, but beneath the ice the tide may be turning. Gazprom’s recent concessions on hub price indexation to a consortium of European suppliers supporting the development of the Nordstream 2 pipeline is a case in point. An increasingly flexible stance on pricing is not a case of Gazprom conceding defeat. It is just a pragmatic commercial response to an oversupplied market.

This is our last article for 2015. It has been another year of substantial growth in readership for the blog. We appreciate your support and are enjoying meeting an increasing number of you face to face at industry conferences and events. We are back at the start of January 2016. In the meantime we wish you all the best for the festive season.

Article written by David Stokes & Olly Spinks

Global LNG and European gas workshop

Timera Energy offers tailored workshops exploring the evolution of the global LNG and European gas market fundamentals and pricing dynamics.  These workshops involve Howard Rogers who, as the Director of the Gas Programme at the Oxford Institute for Energy Studies, is acknowledged as a leading industry expert in the global gas market.

If you are interested in more details please email olly.spinks@timera-dev.positive-dedicated.net

Commodity price perspective: a 3 chart view

Posted on by David Duncan

A seismic shift in commodity markets began in Q4 2014. From an energy market perspective this was focused on crude oil breaking out of its trading range above 100 $/bbl and plunging to under 50 $/bbl. But this was not an isolated oil market event. Global commodity markets have weakened in a highly correlated fashion suggesting that a bigger story is evolving. As Q4 2015 draws to a close, we take a step back to reflect on some key market benchmarks and what they may be point to in 2016.

What happened to the super-cycle?

Our first piece of evidence speaks for itself. Chart 1 shows the path of probably the most widely recognised global commodity index, the Reuters/Jefferies CRB Index.

Chart 1: The rise and fall of the super-cycle: CRB Index (1980-2015)

CRB

Source: StockCharts.com

As 2015 draws to a close, the CRB Index has broken below the level of its post-financial crisis plunge in 2008-09. In fact the commodity price index is back at the level of the 2001 trough in commodity prices (when oil prices fell under 20 $/bbl).

As striking as the absolute level of commodity prices is their rate of decline. The only commodity price fall that is comparable over the last 30 years is the 2008 collapse that followed the default of Lehman Brothers.

We have set out previously how the latest price decline has been caused by a substantial re-rating in forward projections of commodity demand, particularly in relation to China. This has been exacerbated by production development lead times, with new supply coming to market based on investment decisions made at much higher price levels several years ago.

This looks like a China problem

Our second piece of evidence is a key barometer of the health of the Chinese economy. Chart 2 shows the evolution of the Chinese Purchasing Manufacturers Index (PMI). Readings below 50 represent contraction. After bumping along at low growth rates for the last four years, China’s PMI looks to be heading into a more pronounced contraction as 2015 progresses. This is particularly the case for Chinese manufacturing output which is of key importance for commodity demand.

Chart 2: China Output PMI

PMI

Source: Markit, Caixin

Strengthening USD undermines a commodity price recovery

Our third exhibit relates to currency movements and their impact on commodity prices, specifically in relation to the US Dollar (USD). We described the key negative correlation between commodity prices and the USD in a previous article this year. This is illustrated in Chart 3 which shows an overlay of the USD Index versus front month WTI crude prices since 2000.

The chart shows that the sharp decline in crude prices in Q4 2014 coincided with a rapid strengthening of the USD against other major global currencies, most importantly the Euro. USD strength against the Euro in late 2014 was driven by the ramp up of European quantitative easing to support weakening economies, against a backdrop of a relatively resilient US economy.

Chart 3 shows the USD starting to rise sharply again in Q4 this year, reflecting expectations for ‘more of the same’. The US Federal Reserve now looks likely to embark on a rate hike cycle starting in December. But the European Central Bank appears increasingly inclined to move in the opposite direction, with more monetary easing on the horizon in 2016. If the USD continues to strengthen into 2016 it will provide strong headwinds for any recovery in commodity prices.

Chart 3: The inverse correlation between crude and the US Dollar (2000-2015)

WTI vs USD

Source: StockCharts.com

Looking ahead to 2016

The three charts above paint a pretty pessimistic picture of commodity prices heading into 2016. In fact together they present a reasonably compelling case for commodity price weakness to continue in 2016. But there are strong self correcting forces that tend to drive the cyclical behaviour of commodity markets.

Demand response to lower commodity prices is an important factor to watch. Future resource requirements can now be sourced at a fraction of the cost of even early last year. Ultimately sharp commodity price declines are supportive of economic growth in manufacturing intensive economies such as China and India. On the supply side, falling prices are choking off investment in new capacity.  These factors are likely to form the foundations of the next cyclical recovery in commodity prices. But this may take some patience beyond 2016.

Next week we return to take a closer look at global gas pricing dynamics heading into 2016.

Article written by David Stokes & Olly Spinks

Russia’s strategic response to an oversupplied gas market

Posted on by David Duncan

The oil market is currently focused on the Saudi dominated OPEC’s strategic reaction to lower prices. There is no ‘gas OPEC’ per se; but there are important strategic questions around how Russia responds to lower gas prices.

The importance of Russia is not just the scale of its production and reserves, but that it is a key supplier of gas to both Europe and (in the future) Asia. Russia also has an important production cost advantage over new LNG liquefaction projects. But what are the drivers of Russian strategic thinking and how may these playout to influence global gas prices?

 

Russia: the world’s key gas producer

Russian domestic market gas consumption has stagnated, declining from 424 bcm in 2011 to 409 bcm in 2014. At the same time non-Gazprom Russian gas producers have progressively competed for the Russian market; in 2014 their domestic market share reached 30%.

Gazprom’s long term contract exports to Europe have been confined in a 140 to 160 bcma range since 2009. Its exports to FSU countries have fallen from around 80 bcm in 2011 to some 43 bcm in 2014. This has meant Gazprom’s upstream Russian production has been on a downward trend since the beginning of this decade.

It is important to distinguish ‘production’ from ‘production capacity’. In anticipation of higher European demand growth and continued dominance of the domestic market, Gazprom invested in the Bovanyenko Yamal gas field and currently has some 100 bcma of excess productive capacity.

In Asia, Russia’s only current export channel is the Sakhalin 2 LNG project (14.5 bcm in 2014) selling to Japan and South Korea with minor volumes to China, Taiwan and Thaliand. Gazprom has a 50% ‘plus one share’ stake in this project.

Two pipeline projects are in development to supply Russian gas to China. The first is a reduced version of an integrated scheme ‘the Power of Siberia’. This would develop currently discovered, but stranded, East Siberian fields to supply 38 bcma of gas to north east China. It was also intended to provide feedgas to a new LNG terminal at Vladivostok, although the LNG element has now been put on hold. The second, termed the ‘Altai pipeline’, connects 30 bcma of the current West Siberian ‘gas bubble’ of excess productive capacity to north west China. The timing of this potential 68 bcma of pipeline supply to China is uncertain, as indeed is whether both projects will ultimately proceed.

One factor driving this uncertainty is the future gas demand trajectory of China in the ‘new normal’. The second is the impact of sanctions on Russia on access to external financing. Although LNG technology is not specifically targeted by current US sanctions, the apprehension that it might in future become so, and the challenge of raising finance for such projects has in effect limited new LNG projects to the Novatek-led Yamal project.

Russia’s ‘Pivot to Asia’ has thus hit the buffers of reality in today’s lower Asian demand and gas price world with the additional restrictions imposed by current and potential future sanctions.

 

Russia’s role in the global gas market

In an increasingly LNG-connected world, Russia’s strategic position is impacted by global gas market fundamentals. This is despite (or perhaps because of) Russia’s pre-eminent position in terms of gas reserves, export markets and productive potential. Chart 1 shows the global LNG balance from 2008 to 2030 in schematic fashion. The dashed line represents global LNG supply from existing and FID’d projects. The period to 2020 sees a huge increase in supply from the US, Australia and other projects. Asian demand in this timeframe is uncertain (Chinese economy and Japanese nuclear restarts in the main); the space between the Asian demand bar and the dotted line represents LNG which will flow to Europe.

Chart 1: Global LNG Balance

Global LNG Balance

Source: Howard Rogers, OIES

In the recent past Russia has dismissed the US shale gas boom as a short term, unsustainable phenomenon. Russia strategic focus has been pre-occupied with the long-running Ukraine transit imbroglio, frequent adaptations of its plans for South and North Stream pipelines and its response to the DG Competition inquiry. But Chart 1 suggests that the threat of a surge of European LNG imports has probably now become a ‘real and present danger’ to Gazprom’s European gas market share. On a cost basis, Gazprom’s supplies to Europe are very competitive as shown in Chart 2.

Chart 2: Comparison of Russian Pipeline Gas, US and Non-US LNG delivered to Europe

SRMC

Source: J Henderson & D Ledesma, OIES

Chart 2 shows the long run marginal costs of ‘new’ West Siberian Gas in the range of $10/mmbtu (pre rouble devaluation) to $6.50/mmbtu (post rouble devaluation). But this is academic as it already has some 100 bcma developed which could flow to Europe border and cover variable costs and export tax at a border price of $3.80/mmbtu.

Once competing LNG projects are FID’d and committed however, they will flow at short run marginal costs of ‘Henry hub plus shipping and regas costs’ in the case of US projects and probably just shipping and regas costs in the case on non-US projects. Russian adherence to oil-indexed pricing to date has arguably encouraged competing LNG projects. Will it now adapt its price-volume strategy to limit further competition from new LNG?

 

How may Russia respond to lower prices and competing supply?

Gazprom has to date required its European mid-stream buyers to take delivery of (at least take or pay) contractual volumes at prices linked to oil-products. The majority of these contract volumes are delivered at border flange delivery points. Gazprom has however negotiated ad-hoc concessions and rebates relative to hub prices, to ease cost pressure on suppliers. This model is illustrated in the upper section of Chart 3.

Chart 3: Alternative Russian Contractual Sales Strategies

Russia Contract Models

Source: Howard Rogers

Gazprom’s in-house marketing and trading capability gives it the option to pursue an alternative strategy in response to the emerging gas supply glut. The first logical steps would be:

  • Move delivery points to the existing European gas trading hubs
  • Move contract pricing terms to hub pricing
  • Meet buyers’ nominations with a mixture of physical gas transported from West Siberia and gas bought off the hubs.

This is termed the ‘hub re-delivery model’ and is already used in UK medium terms contracts. It is depicted in the lower half of Chart 3.

In this manner Russia could influence the level of European hub prices through taking control of the scale of physical gas transported to the European gas market. Keeping European hubs (and by arbitrage Asian LNG spot prices) at prices below those supporting new LNG projects, acts to deter competing supply.

Over time the currently anticipated LNG ‘glut’ will be absorbed by a combination of Asian and new market LNG demand. Europe also faces the need to offset domestic production decline in Europe with new imports. As a result it is reasonable to expect European hub prices to rise again as these factors take effect into next decade. Gazprom then has another important strategic choice:

  • If Gazprom allows European hubs to exceed $9 to $10/mmbtu, new LNG projects will achieve FID. Once new projects are launched, production SRMC is then very low.
  • If Gazprom increases exports to keep European hubs below $9 to $10/mmbtu, new LNG FID’s will likely be delayed.

These dynamics leave Russia in a very strong position to dominate the sale of incremental gas supplies into Europe.

Pulling back to the bigger picture, it is worth noting that any idea on Russia’s part of compensating for disappointing European sales/prices by threatening to take its gas to Asia is flawed:

  • Eastern Siberian gas is ‘stranded’, it is not connected by infrastructure to European markets,
  • West Siberian gas delivered by the Altai line to China would be 30 bcma of the 100 bcma of ‘surplus productive capacity’; this would not impact deliveries to Europe,
  • Additional supplies of Russian gas to Asian markets, whether pipeline gas or LNG, all other things being equal, merely displaces an equivalent volume of LNG from those markets which would likely end up in Europe.

As yet it is unclear whether Russia recognises the challenges set out above and is willing to adapt its strategy accordingly. But look out for changes in long term pricing terms and delivery points to hubs as the first signs of such a move.

Article written by Howard Rogers, David Stokes & Olly Spinks

Global LNG and European gas workshop

Timera Energy offers tailored workshops exploring the evolution of the global LNG and European gas market fundamentals and pricing dynamics.  These workshops involve Howard Rogers who, as the Director of the Gas Programme at the Oxford Institute for Energy Studies, is acknowledged as a leading industry expert in the global gas market.

If you are interested in more details please email olly.spinks@timera-dev.positive-dedicated.net

Implied vs historical gas price volatility

Posted on by David Duncan

European gas hub markets are maturing. This can be seen via the increase in range and liquidity of traded products. Growth in trading activity is focused on the UK NBP and Dutch TTF hubs, with TTF challenging the traditional dominance of NBP.

Consistent with maturing hub markets is a growing liquidity in traded gas options. There has also been growth in the penetration of shorter term flexible capacity products which contain embedded optionality (e.g. gas storage capacity). This means that gas price volatility is becoming a more transparent driver of value in energy portfolios.

In today’s article we look at two different volatility benchmarks (historical and implied). We also do a practical comparison of the evolution of these benchmarks over the last three years and consider their impact going forward.

Historical vs implied volatility – the basics

If you are familiar with these measures of volatility feel free to jump ahead to the next section.

Historical volatility

Historical volatility involves a retrospective calculation based on observed market prices over a defined period in history. It is a statistical measurement of the realised price dispersions of a specified contract over a specified time period. For example: “Day-Ahead volatility in Apr 2015 was 55%”.

Historical volatility is measured based on a dataset of realised historical price return observations. The wider the distribution of historical price returns, the higher the volatility measurement (and vice versa).

Implied volatility

The level of volatility expected by the market can be ‘implied’ from the prices of traded gas options. For example: “the Jan 2014 ICE NBP gas call option contract has an implied volatility of 50%”.

The key to being able to imply volatility from traded asset prices is that the level of volatility is an input into the standard pricing formula (e.g. Black Scholes) used to value optionality. Option prices are a function of strike price, underlying gas price, time to expiry and volatility. So if the price of an option is known, then implied volatility can be backed out using the option pricing formula.

 

Applications of historical vs implied volatility

The key advantages of historical volatility as a measure are its transparency and objectivity. There are minor variations in the way that historical volatility is calculated, but it represents a relatively simple and accessible statistical measure.

EnergyStock, the Dutch fast cycle storage operator, has recently started publishing a volatility dashboard which contains a set of historical volatility indices on TTF gas prices. The dashboard provides a new and useful source of data on rolling and annual indices for the TTF day-ahead and month-ahead contracts.

Publication of reliable volatility indices is an important step in developing market liquidity in products with embedded optionality. Gas traders need middle office sign off in order to do any transactions. And middle office in turn require an independent & objective volatility benchmark for P&L and risk measurement calculations (either as a simple input to benchmark the value / risk of vanilla option portfolios or as guidance for stochastic parameters required for more complex flex valuation models).  Most speculative trading companies (e.g. hedge funds) do not permit traders to take exposures in a market until there is an established objective risk benchmark.

Robust implied volatility benchmarks have only recently emerged in the European gas market. The reason is that the meaningful measurement of implied volatility requires a critical mass of traded option liquidity. Implied volatility indices are well established in the oil market (e.g. the CBOE OVX index). But it is only over the last 3 to 4 years that gas options liquidity in Europe has supported the measurement of implied volatility.

The advantage of implied volatility over historical volatility is that is represents a current (forward looking) market view on the level of volatility. As such, reliable implied volatility data is highly valued by traders and risk managers.

Gas options price data is harder to come by than straight gas price data (used to calculate historical volatility). Marex Spectron, Europe’s leading gas options broker, has been developing a comprehensive dataset* covering volatility surfaces for key NWE hubs. ICE also publishes an implied volatility surface for the NBP and TTF hubs but the Spectron surfaces more accurately reflect the current market. This is because they include option bid / offer data where as the ICE implied volatilities are only based on the traded option prices on the exchange (some of which can be quite stale given sparse liquidity across some strike / maturity combinations). We have used this dataset in the next section to run a numerical comparison of historical vs implied volatility.

 

Running the numbers on NBP volatility

Chart 1 shows a comparison of:

  1. Historic 30 day rolling volatility on the ICE NBP Month-Ahead Futures contract
  2. Implied volatility from ‘at the money’ Month-Ahead NBP gas options

Chart 1: NBP month ahead volatility benchmarks

Impled vs Hist Vol

This comparison provides an interesting illustration of the different characteristics of historical vs implied volatility. The most obvious initial observation is that implied volatility is generally higher than historical. This is because implied volatility incorporates a risk premium (reflected in the option price) as well as capturing within day price movements (historical volatility is calculated off a single end of day price).

Chart 1 also provides some interesting examples of how the two measures of volatility react to market events. Take the March 2013 NBP gas price spike as an example. The reaction of implied volatility to market events is immediate. The prices of options rise as risk premiums increase as can be seen with the spike in implied volatility in Mar 2013 on the chart. The impact of a market shock on historical volatility is more delayed as it feeds through the historical gas price series used to calculate volatility.

A jump in implied volatility can disappear as quickly as it came. This can also be seen in Mar 2013 where implied volatility rapidly returned to previous levels as new supply was diverted ensuring the market impact was temporary. The historical volatility series however averages in the impact of the price spike as long as higher gas prices remain in the historical 30 day price data window.

These characteristics do not necessarily mean implied volatility is a more reliable measure. Implied volatility represents an expectation of average volatility up until expiry, so can fluctuate significantly closer to contract expiry. Implied volatility is also dependent on the consistent availability of reliable options price data. Limited data over a given period can produce spurious changes in volatility.

Implied volatility benchmarks can be of limited use as a source of direct input data for complex pricing models.  These models can require a number of non intuitive parameters far beyond simple implied volatility benchmarks (limited to standard option products).  For example, a gas storage model may use spot volatility, mean reversion and price jump diffusion parameters to describe stochastic price behaviour.  There is no clean method to generate these parameters from a single monthly implied volatility benchmark.

 

Volatility set to become increasingly important

As the European gas market continues to evolve, understanding the impact of volatility on asset value will become increasingly important. European energy portfolios have large underlying exposures to the level of gas price volatility. For example flexible volume customer contracts, pipeline swing contracts, storage capacity and transport capacity all contain embedded optionality, the value of which is driven by volatility.

The evolution of the benchmarks we have referred to is providing increased market transparency on the level of gas price volatility. Take a look at other more mature commodities markets (e.g. oil & metals) for an indication of the way forward. Gas hub prices are already firmly ‘on the radar’ of most industry participants. Gas price volatility levels are soon to follow.

Article written by David Stokes & Olly Spinks

*For more information about the Spectron implied volatility data please contact Richard Frape.

Last week’s UK power price spike

Posted on by David Duncan

The tightening UK system capacity margin has been a theme of this blog over the last 4 years. This manifested itself last Wednesday in a period of magnified system stress and spiking power prices. The system operator, National Grid, took a number of defensive actions, paying up to 2500 £/MWh in the balancing mechanism to bring capacity online and ensure continuity of supply.

The issues last Wednesday related to a specific set of circumstances, but these were by no means an extreme event. High demand was not the issue. Several thermal asset outages combined with reduced interconnector flows and very low wind levels to cause the capacity squeeze.

System stress eased as capacity came back online with little impact on forward prices. But Wednesday’s events are an indication of more to follow as the system capacity margin continues to tighten over the next two winters.

The more enduring impact of this event is likely to come from the news headlines it attracted. It is this unwelcome media attention that is set to increase the UK government’s focus on security of supply, particularly as more plant closures loom in 2016.

 

The spike deconstructed

Chart 1 illustrates UK generation output on Wednesday in the context of the three proceeding days. Demand conditions were relatively benign, with peak demand lower than Monday or Tuesday. Wind levels were low across last week, but particularly low on Wednesday (with output falling to less than 1% of potential). The impact of coal unit outages and a reduction in French interconnector flows can also be seen.

The combination of these events was unusual but not extreme. But the market price impact was magnified by the UK’s low system capacity margin.

Chart 1: UK generation output Wednesday 4th Nov

Gen Stack NISM

Source: Timera Energy (data from Gridwatch)

National Grid issued a Notification of Inadequate System Margin (NISM) at 13.30, a fairly rare event (the last being in 2012). The NISM called for an additional 500 MW of capacity across the 16:30-18:30 period. Grid then took a number of balancing and reserve actions to address the shortfall, including procuring capacity at up to 2500 £/MWh in the balancing mechanism. It also resorted to the ‘last resort’ use of 40 MW Demand Side Balancing Reserve contracts across the 18:00-18:30 period (a mechanism we explain in more detail below).

The prices last Wednesday can be seen in the context of adjacent days in Chart 2. The red and blue lines show the balancing mechanism system sell and system buy prices respectively. There are indications of some system stress via balancing prices on the two preceding days (given low wind levels and thermal outages). But the balancing price shock became much more pronounced on Wednesday as Grid took more aggressive actions to procure capacity.

Chart 2: UK prompt power prices around Wed 4th November

Spot & Bal Prices

Source: Timera Energy (data from Elexon and N2EX)

This in turn fed through into higher day-ahead power prices (in the N2EX auction) on Wednesday, shown by the black line. However the temporary nature of this event can be seen as conditions reverted back to more normal levels on Thursday.

Chart 2 also shows the UK balancing mechanism transitioning from a dual to a single cashout price from 5th November.  This one of a number of measures being implemented over the next couple of years under the supervision of Ofgem to ensure sharper balancing price signals in the UK power market.

The events of last week are empirical evidence of a tightening system capacity margin causing higher and more volatile prompt prices. This is exactly the sort of situation that we foreshadowed in the final sentence of our article UK capacity new build challenges two weeks ago.

 

Reserve capacity buffer is increasingly important in the UK power market

Price spikes do not necessarily reflect the imminent threat of blackouts, despite last week’s news headlines suggesting otherwise. This is because Grid (under the supervision of the UK government) has implemented a mechanism to procure a buffer of emergency reserve capacity. This emergency reserve buffer comes in two categories:

  1. Supplemental Balancing Reserve (SBR) – provided by older power plants that agree to be withdrawn from the wholesale energy market in exchange for payments as reserve capacity
  2. Demand Side Balancing Reserve (DSBR) – provided by large energy users who are able to reduce their demand during peak periods in exchange for payments

Grid has contracted 2.5 GW of reserve capacity under these mechanisms for the coming winter (2015/16). This volume is dominated by SBR (less than 200 MW of it is DSBR), which is provided by aging power plants. A total of 8 plants have been contracted to provide SBR, all of them on the ‘endangered species’ and hunting for any form of return to contribute to fixed cost recovery.

This buffer of SBR/DSBR reserve capacity has become the key tool to manage the UK capacity crunch. From a security of supply perspective SBR acts to reduce the risk of blackouts. It is therefore included in Grid’s calculations of system reserve margin, which is almost zero without it.

But because SBR can only be called as a last resort, it does not prevent sharp rises in prompt power and balancing prices during periods of system stress. Events such as last Wednesday are evidence of this in action, but only a prequel to a much tighter market as capacity continues to close in 2016.

The UK capacity market is yet to deliver a price signal that covers the fixed costs of existing CCGT capacity (let alone the delivery of new capacity).  That shifts the focus of plant owners & investors on to the energy and balancing markets. But investment decisions are not made based on volatile balancing prices alone.

A recovery in forward market generation margins (sparkspreads) is required to stem the tide of plant closures and encourage new investment.  And as the system capacity margin continues to tighten, it is only a matter of time until the UK forward curve starts to reflect higher returns in the prompt market.

Article written by David Stokes & Olly Spinks

UK capacity price may clear in single digits

Posted on by David Duncan

The system reserve margin in the UK power market is at an unprecedented level of tightness coming into the second capacity market auction in December. Last year’s inaugural capacity auction delivered little in the way of new capacity. In fact the low auction clearing price (19.40 £/kW) crystallised the economics of a number of older thermal plants which have since indicated they will close. So whatever the outcome of the 2nd capacity auction next month, the system reserve margin is set to tighten further into winter 2016.

If you had no knowledge of the UK power market and somebody explained this landscape to you, what would you anticipate would be happening in the capacity market? You would probably assume that prices would clear at a level that prevented the further closure of existing plants. You may even expect a capacity price that incentivised the delivery of large scale new capacity build. Our take on the second capacity auction is that neither of these things are going to happen.

The 2nd auction is for delivery of capacity over the Q4 2019 to Q3 2020 period. As for any market, the auction outcome is driven by the interaction of supply and demand. Demand is determined by the government’s capacity target. Supply is driven by a prequalification process where different sources of capacity are accepted into the auction subject to a defined set of conditions. A firm view on the volume and type of prequalified capacity only became available two weeks ago. So with this in hand we now have all the information required to undertake a robust analysis of the 2nd auction outcome.

In this article we provide an overview of:

  1. The auction supply and demand balance
  2. New factors in play this year
  3. The drivers of capacity price outcome
  4. Our view on capacity price range in the 2nd auction
  5. The broader implications of the auction outcome for the UK power market

As for last year, the information in this article is a higher level summary of more detailed analysis that we have undertaken of auction drivers and pricing dynamics. Detailed projections of the 2nd auction pricing dynamics and implications for the UK power market are available in our client briefing (details below).

 

Supply & Demand balance

The 19.40 £/kW capacity price in the 1st auction last year was well below the market consensus view (around 45 £/kW). This outcome was driven by an oversupply of existing capacity relative to the government’s demand target. These conditions remain in the second auction.

The government’s demand target is 44.6 GW this year, with a similar demand curve structure to last year where demand varies depending on clearing price. Demand increases by up to 1.5 GW above the target at zero price, or decreases by up to 1.5 GW below the target at the 75 £/kW price cap. The demand curve can be seen in Chart 2 below.

On the supply side, there is around 50GW of existing capacity (including capacity that is already committed and under construction). So the market is oversupplied again this year and this will again act to supress prices, in the absence of a material shift in the bidding behaviour of existing plant owners. An overview of the supply and demand balance is shown in Chart 1 which breaks down supply by capacity type.

Chart 1: 2nd capacity auction supply & demand summary view

UK CM2 Summary Stack

Source: Timera Energy

 

What’s new in this year’s auction?

If you are not particularly interested in the drivers of capacity pricing and just want a view on market outcome then you can skip to the next section.

In this section we focus on five important factors that change the competitive landscape in the 2nd auction. There are also a number of more technical rule changes that have been implemented into the second auction. These are not dealt with in this article.

  1. Interconnectors: This year’s auction has an additional 2.4 GW of de-rated interconnector capacity that was not eligible to participate last year. Interconnectors have been included in the auction on the basis of quite steep capacity derating factors to reflect flow uncertainty. But both existing and new interconnectors will likely be bid at zero price, given healthy energy margins (driven by higher UK power prices vs those on the Continent) and other regulatory support (e.g. the cap & floor revenue structure). In other words inclusion of interconnectors will act to displace existing capacity.
  2. Supply reduction: 7.6 GW of existing capacity has opted out of the 2nd auction. 5.8 GW of this capacity has opted out because owners have indicated an intention to close plants by the delivery year (2019/20). In addition there is 3 GW of capacity from last year’s auction that will not participate this year given it received 3 year refurbishing agreements (EDFs Cottam and West Burton coal units). The removal of these plants from the auction has significantly reduced the number of older thermal plants from the capacity supply stack. This makes analysis of this year’s auction somewhat easier.
  3. New build penalties: Only one new CCGT was successful in last year’s auction. We have written about the problems encountered by Carlton Power’s Trafford CCGT project. As a result of the issues with the Trafford project, the government has introduced a range of stronger penalties for owners which fail to meet their capacity obligations. In practice this means that new build CCGT projects are likely to bid at higher price levels than in last year’s auction. In fact in an oversupplied market, we would be very surprised to see any new build CCGT project successful in the 2nd auction, aside from the 810 MW Carrington CCGT project which is already under construction and is therefore capacity price insensitive.
  4. Bidding behaviour: The other important factor that influences this year’s auction is clearer information on competitive bidding behaviour. There is a bidding track record from last year that is useful in inferring how owners may bid assets this year. This is particularly important for the older coal and CCGT assets that are likely to dominate marginal price setting in the auction. We know which generation units bid above and below last year’s 19.40 £/kW clearing price. We also know that:
    1. Forward market energy margin conditions for CCGT plants are broadly similar to those going into last year’s auction (suggesting that CCGT bidding behaviour may be similar).
    2. Forward energy margin conditions for coal plants have deteriorated as dark spreads have declined with falling power prices in 2015 (suggesting that coal plant owners may bid at relatively higher levels than last year).
  5. Marginal bidding: The other dynamic demonstrated by last year’s auction outcome is that unless owners are prepared to close their plant if their bid is unsuccessful, they are strongly incentivised to bid zero. In other words capacity bids are likely to reflect the true incremental return required to keep assets open. This dynamic is important coming into the second auction because it appears to us that the volume of capacity that is likely to bid at (or close to) zero price comes close to meeting the government’s demand target.

The five factors above combine to play an important role in driving the dynamics of the second auction outcome.

 

Auction result comes down to older coal & CCGT plants again

We developed a comprehensive analytical tool kit for analysis of the UK capacity market in the lead up to the first auction last year. We used this to publish a client report in mid-November 2014 that contained the following key conclusions on the 1st auction (quoted from the Executive Summary):

  • “Marginal plant: 3 key plant types are likely to drive the 1st auction outcome (older coal, older CCGT, low capex peakers).”
  • “Pricing: Our analysis indicates a 1st auction capacity price around 30 £/kW if participants bid rationally to recover costs. But the 1st auction outcome will come down to EM (& CM) expectations (diverse range likely across players).”
  • “Downside risk: The low 1st auction target and ‘Fear of Missing Out’ dynamics may lead to a lower clearing price than expected. These factors could easily combine to reduce the 1st auction clearing price by 5-10 £/kW.”

These dynamics remain relevant into the 2nd auction but with greater pressure on prices.  In order to provide an overview of 2nd auction pricing dynamics we start with a supply and demand chart. It is important to note that Chart 2 does not represent our projection of the auction outcome (as was inferred by several readers when we published a similar chart last year). This is reserved for our client briefing. Instead it shows a credible scenario based on groupings of assets into categories.

Chart 2: A grouped plant 2nd auction scenario with a 10 £/kW capacity price

UK CM2 Supply Stack

Our modelling framework allows the analysis of pricing dynamics at an individual asset level. But for the purposes of this, we consider market dynamics based on the grouping of plants of similar technology, age and efficiency. This helps in demonstrating the key drivers of marginal pricing dynamics.

The first observation from Chart 2 is that there is a large volume of ‘price insensitive’ capacity bidding around zero price. This is made up of existing capacity that owners do not intend to close by 2019/20, regardless of capacity price outcome.

For example, it includes existing hydro, nuclear, interconnectors, peakers/DSR, higher efficiency coal and mid to high efficiency CCGTs. It also includes new interconnectors, the 810 MW Carrington CCGT (under construction) and around 500 MW of small scale new build peakers and DSR (assumed to be economic based on other revenue streams e.g. ancillaries & triad avoidance revenue). In the scenario shown, this capacity makes up around 43 GW of the 44.6 GW target. That does not leave much room for a high capacity price outcome.

It is likely to be the plants sitting directly to the right of this price insensitive tranche in the supply stack that determine the outcome of the 2nd auction. Like last year these are likely to be a mix of lower efficiency coal and CCGT plants, interspersed with more competitive new peaker/DSR projects.

But if our assumption of around 43 GW of price insensitive capacity is correct, there may only be a requirement for two or three additional thermal plants to clear the auction. In volume terms a maximum additional capacity of 3 GW would be required to clear the auction, from an overhang of about 7 GW of existing capacity and maybe 1-2 GW of competitively priced new peaking/DSR capacity. It is this level of competition around the margin that is in our view set to supress prices.

 

Capacity price outcome & bounds

We think the capacity price is likely to fall within a 0-25 £/kW range. The upper bound of this range is driven by the fixed cost recovery of less efficient CCGTs. There are around 5 GW of these plants competing around the margin and it is our view that a significant portion of this capacity will be priced at or below fixed costs (given capital costs are already paid down). In other words if the auction price rises to the 25 £/kW level there is likely to be more than enough supply to clear the auction.

The lower bound is more complex. It could be that there is enough price independent existing and new capacity to clear the auction at zero. However we suspect that the owners of marginal older assets may baulk at bidding units so low. This is because:

  1. The alternative option to bid capacity into the T-1 auction (in 2018) looks increasingly attractive as existing capacity continues to close in the absence of a new build price signal.
  2. The big six utilities have a portfolio consideration where it may make sense to bid marginal assets at positive prices to increase the capacity price return across the rest of the portfolio (even if it means the marginal plant are unsuccessful in securing a capacity agreement).
  3. By accepting a capacity agreement in the Dec auction at zero price, owners forfeit the option to close before 2020. That option has some value for marginal older plant and is likely to be reflected in positive bid prices.

So while the risks remain to the downside in this auction given the overhang of existing capacity, we would be surprised to see a zero price outcome.

Where could we be wrong with the logic set out above? The biggest risk is around the volume of price insensitive capacity we have assumed (e.g. 43 GW in the scenario in Chart 2). If that volume is higher e.g. due to a higher volume of competitive new build peakers/DSR, then it pushes price risk further towards the downside. If the volume is lower, then it reduces the overhang of capacity competing to clear the auction. But we struggle to see a margin of error that absorbs the 5 GW+ overhang of CCGTs and competitively priced new peakers/DSR capacity.

 

Broader implications for the UK power market

If there is another low capacity price outcome in the 2nd auction we would expect a continuation of the fallout from the 1st auction. This may mean the closure of another 2-4 GW of lower efficiency coal and CCGT units (on top of the plant closures already announced). That would leave the UK power market in a precarious state.

The chances of rolling blackouts have fallen with the implementation of the Supplementary Balancing Reserve (SBR) mechanism managed by the system operator (National Grid). Contracted SBR capacity acts as a buffer of emergency reserve and Grid will presumably step up the purchase of SBR capacity as the system reserve margin heads towards zero. What is unattractive about this outcome is that SBR risks becoming a proxy capacity market, but one that lacks a robust and transparent rule book.

However, SBR capacity (given its emergency status) should not stand in the way of higher and more volatile power prices as plants continue to close. This appears to be the path down which the government is steering the UK power market, whether intentionally or otherwise. And that would provide a rare glimpse of blue sky through the fog of EMR policy intervention. Sharper price signals in the wholesale energy market are exactly what is required to address the impending capacity shortage.

This article was written by David Stokes & Olly Spinks

2nd Auction Client Briefing

We are offering a client briefing service that provides a more detailed analysis of the 2nd auction dynamics, pricing outcome and implications for the wholesale power market and future capacity auctions. This service also includes a conference call to discuss analysis and any specific issues of relevance.

If you are interested in more details please email david.stokes@timera-dev.positive-dedicated.net

Global gas price evolution: 5 key drivers

Posted on by David Duncan

The global gas market has been turned on its head over the last 18 months. In Q1 last year, Asian spot LNG prices were breaking records with the Platts JKM marker above 20 $/mmbtu. Behind this was a structural divergence across regional gas prices in Asia, Europe and the US, with flexible LNG supply diverted to Asia to cash in on premium prices. The market consensus view was that market tightness and higher gas prices were here to stay.

Fast forward to Q4 2015 and global gas prices have slumped. Asian and European prices have rapidly converged in a relatively tight range above 6 $/MMBtu. US gas prices remain below 3 $/mmbtu, but the price differential between the US and Europe is gradually being eroded by oversupply. The approaching northern winter, usually a driver of higher seasonal prices, has failed to have an impact so far.

We pointed to the start of a new phase of global gas market oversupply in September 2014. But what are the drivers that are going to determine the dynamics and duration of this new phase and the evolution of gas prices into next decade? We set out the five key factors that we are watching below.

 

1. Impact of crude pricing

Oil-indexation remains a powerful influence on European and Asian gas prices. In Asia, almost all LNG contract volumes are indexed to crude benchmarks (e.g. JCC, Brent). In Europe, despite a much publicised trend towards the spot indexation of gas, the majority of long term pipeline swing contracts also remain indexed to oil (primarily gas oil & fuel oil) – albeit moderated via price formula concessions and rebates which have become prevalent post 2008

Oil-indexation has a particularly important influence on spot prices in Asia and Europe because of its influence on the exercise of contract volume flexibility. The ability to vary swing contract take is optimised based on the differential between oil-indexed contract prices and spot gas prices. When spot gas is cheaper than oil-indexed contract prices, contract volume take is reduced (and vice versa).

This means that oil-indexed contract prices act as an important longer term anchor for gas prices. This relationship is a loose one over a shorter term horizon given the influence of other supply and demand factors. But oil-indexed prices act as a ‘magnetic ceiling’ and typically draw spot gas prices back in line in a reasonably balanced market. That said, a very tight market can see spot gas prices ‘break through’ this ceiling (UK in 2005/2006) although such occurrences are rare and transitory. Alternatively an oversupplied spot market can see hub prices disconnect below contract prices (e.g. as in 2009-10).

On this basis, the length and depth of the current decline in oil prices is a key factor that will determine how gas prices behave into next decade. We have recently set out our view on oil prices. Crude prices should recover over time given they are currently well below LRMC benchmarks. But there may first need to be a period of lower prices to interrupt the US shale oil investment cycle.

 

2. Asian LNG Demand

Asia represents the main source of uncertainty on the demand side of the global gas market. In summary across the large and growing Asian gas consumers:

  • Japan: Lack of clarity on the pace and scale of nuclear restarts
  • South Korea: Uncertainty around gas vs coal usage in the power sector
  • India: Questions over infrastructure, domestic pricing and affordability of gas vs coal

That leaves the most important market China.   The key source of uncertainty around Chinese demand is the scale of potential demand growth.  China’s LNG requirements are the ‘balance’ required after:

  • Domestic production (uncertain volumes of conventional, shale, coal bed methane and syngas from coal)
  • Pipeline Imports from Turkmenistan, Central Asia & Myanmar
  • Russian pipeline gas from Siberia

We know demand growth will be large. But the difference between large and very large has a substantial impact on the global gas demand.   It is also unclear how Asian demand (particularly from buyers with lower contract cover like China and India) will respond to lower spot LNG prices. We illustrate the uncertainty around Chinese LNG demand via an illustrative ‘high’ and ‘low’ LNG demand growth case in Chart 1.

Chart 1: Asian LNG demand growth scenarios

Asian LNG Demand

Source: Howard Rogers OIES

 

3. European demand recovery

European gas demand has fallen almost 20% this decade. Around half of this decline occurred in 2014 due to an outlier warm weather year across Europe. Weather normalisation aside the main drivers of the evolution of European demand are the rate of economic growth and the extent to which there is a recovery in gas fired power plant load factors.

Two illustrative scenarios are shown for ‘steady’ vs ‘low’ gas demand growth in Chart 2.

Chart 2: Illustrative European gas demand evolution scenarios (includes Turkey)

EU Gas Demand

Source: Howard Rogers OIES, Timera Energy

The ‘steady’ growth scenario assumes:

  • Some SRMC driven coal gas switching as gas hub prices fall (particularly in UK)
  • Emissions legislation driven retirement of coal plant (LPCD & IED)
  • Planned retirement of nuclear plants (Germany important)
  • A slowdown in renewable investment over the next decade

The ‘low’ case assumes:

  • Coal remains ahead of gas in merit order
  • Some coal & nuclear retirements delayed
  • Renewables investment pace maintained
  • No effective carbon pricing mechanism

The more than 100 bcma difference in demand by 2030 illustrates the uncertainty involved.

 

4. Impact of new liquefaction capacity

There is more than 150 bcma of liquefaction capacity that has already reached Final Investment Decision (FID) sign off and is set to be built by the end of the decade. 140 bcma of projects are already under construction, with more than 55 bcma due to be commissioned by the end of 2016, across Australia, Malaysia, Indonesia and the first US export trains at Sabine Pass.

We have written in some detail about the mountain of new LNG liquefaction capacity that is being developed. So we won’t labour the point in this article. But suffice to say that current oversupply in the global gas market is in large part due to the overhang of committed new capacity.

 

5. Russian response to oversupply

There is no OPEC in the gas market. But Russia is certainly large enough to influence the global market balance. Particularly important will be how Russian producers (primarily Gazprom) react to the growing global oversupply of gas.

The challenge Russia faces can be broken down into two key Issues:

  • Russia’s price / volume strategy in Europe
  • Russia’s influence on timing of new LNG project investment decisions

As global LNG supply increases, European LNG imports are set to rise as Europe’s hubs absorb gas as a market of last resort. These import volumes have the potential to push global gas prices down towards US Henry Hub levels. But Russia has the ability to support hub prices via influencing the volume of gas it sells into Europe. It can achieve this via granting a range of (likely temporary) concessions on its contract prices (as seen in 2011-13). This Russian price/volume strategy may be a key factor determining how deep and prolonged the current price slump will be.

Looking into next decade, as the surge in Australian & US LNG exports is absorbed, the global gas market will tighten again and hub prices in Europe will rise. This leaves Russia with an important longer term strategic challenge:

  • If Gazprom allows hubs to exceed $9 to $10/mmbtu, new LNG projects will achieve FID. Once launched the SRMC on these projects is very low.
  • If Gazprom increases exports to keep European hubs below $9 to $10/mmbtu, new LNG FID’s will be delayed. This would appear to be sensible strategic behaviour but may be hard to sustain, particularly in a world of significant oil price recovery.

 

Making sense of the global gas market

In our view there is little merit in trying to analyse the global gas market on a ‘bottom up’ basis (i.e. by trying to build up a robust view of all individual sources of supply and demand). Changes in the 5 key factors set out above mean that analysis at this level of detail is spurious at best.

Instead we take a ‘top down’ scenario based approach where we group key tranches of global supply and demand. We focus particularly on:

  1. the key tranches of flexible supply that drive marginal pricing
  2. the interaction between prices across different regions to clear the global market
  3. potential ranges in the evolution of demand by region
  4. the overlay of strategic considerations from large market players with pricing power (e.g. Russia and China)

The attraction of this approach is it is easily digestible and transparent. But our analysis points to the fact that the influence of Russian strategic decisions are more important than is often recognised. So in an article to follow shortly, we will return and explore Russian price/volume strategy in more detail.

Global LNG and European gas workshop

Timera Energy offers tailored workshops exploring the evolution of the global LNG and European gas market fundamentals and pricing dynamics.  These workshops involve Howard Rogers who, as the Director of the Gas Programme at the Oxford Institute for Energy Studies, is acknowledged as a leading industry expert in the global gas market.

If you are interested in more details please email olly.spinks@timera-dev.positive-dedicated.net

Article written by David Stokes, Howard Rogers & Olly Spinks

The UK CCGT new build challenge

Posted on by David Duncan

Carlton Power was the only bidder in the UK’s first power market capacity auction that secured a capacity agreement to build a new CCGT (in Dec 2014). Carlton Power’s Trafford CCGT, a 1520 MW project in Manchester, received a 15 year agreement at the clearing price of 19.40 £/kW.

But the Trafford plant was bid into the capacity auction without finance and without a long term tolling agreement to back it. An interview Carlton Power did with the Telegraph last week suggests that the project is struggling to secure an offtake contract and financing and may not be able to deliver against its 2018/19 capacity agreement.

The problems associated with Trafford highlight the challenges that CCGT developers face given current weakness in generation margins.   A 19.40 £/kW annual capacity payment barely covers the direct fixed costs of a new CCGT. So making a Financial Investment Decision on a new plant means finding someone to take on the market risk around the substantial recovery in energy margin required to make the project profitable. It appears that lenders and tolling counterparties are reticent to take on that risk.

 

Challenging economics at £19 capacity price

It has not all been bad news for CCGT project developers. They have benefited from falling capex costs as turbine manufacturers slash unit costs and bulk up guarantees in order to try and recover sales.   Whereas 5 years ago benchmark CCGT costs were around 700 £/kW, project developers are now claiming costs can be reduced to around 500 £/kW.

But even with capex this low, our analysis indicates a generic new build CCGT project needs more than 40 £/kW under a 15 year capacity agreement in order to be economic. Chart 1 provides an overview of this analysis. There may be some benefits that specific projects can claim to reduce this (e.g. locational reduction of TNUoS), but these are unlikely to mean more than a 5-10 £/kW reduction in required capacity payment.

Chart 1:  Illustrative UK new CCGT build economics at 500 £/kW
CCGT bid A
Source: Timera Energy

 

Tough to get a toll & finance

The big six UK utilities are the natural buyers of tolling agreements. But most of these portfolios already have significant existing exposure to CCGT margins via their own generation fleet. A number of utilities are also sitting on their own CCGT development options.

Historically, banks and commodity traders have also been potential tolling counterparties. But these players are pulling back on long term power price exposure driven by balance sheet constraints and tougher regulatory measures. This is contributing to the shrinking availability of market participants even willing to discuss longer term tolling contracts.

Market players are also increasingly wary of taking on tolling contract exposure beyond a 5 year duration. This is due to a combination of:

  • regulatory uncertainty (e.g. lack of clarity around SBR contracting, Capacity Market changes, abolition of LECs)
  • the threat of other new entrant capacity (e.g. peakers, interconnectors)
  • CCGT load factor erosion by renewables

That makes the financing of CCGT projects difficult. Lenders are looking for the security of a significant portion of net margin to be contracted over a 10-15 year horizon.

 

Capacity market issues

The Trafford experience has demonstrated a design issue with the UK Capacity Market. Developers can treat capacity agreements as an option to develop projects, contingent on securing finance & a toll. In the case of Trafford the cost of this option is around £8m which is quite small in the context of the scale of the project. The government has been quick to point out that there will be a range of new rules to discourage this in future.

If the Trafford project does not proceed, the UK market faces a 1.5GW capacity hole in 2018/19 that needs to be plugged via the year ahead (T-1) auction in 2017. The supply stack in this auction is likely to be considerably steeper given the limited number of options to deliver capacity at a year’s notice. It is also likely to favour peaker and DSR capacity providers.

But a more important issue is the closure of 5-10GW of coal and CCGT plants over the next 18 months as we have set out previously. Yet the Capacity Market is not sending a price signal that supports development of large scale new capacity this decade. This highlights the dependence of the Capacity Market outcome on government (& system operator) forecasting of the supply and demand balance in 4 years time. If they are wrong, then the second line of defence is the SBR mechanism (lacking transparency) and year ahead auction (limited supply).

The System Operator (National Grid) seems comfortable about the coming winter in their Winter Outlook published last week, despite noting a historically low system capacity margin of 5.1%. But that comfort comes from their ability to contract emergency reserve via the ill-favoured SBR mechanism.

We will come back to overview the outcome of this year’s capacity auction shortly. But like last year the capacity prequalification data shows the capacity market has more existing capacity than required by the government’s target level. So capacity prices are unlikely to provide much joy for new CCGT projects in December.   Ultimately a lack of price signal from the Capacity Market is likely to play out in the form of sharper price signals in the wholesale energy and balancing markets.

Article written by David Stokes & Olly Spinks