Evolving roles and risks in the European gas market

Posted on April 20, 2015January 15, 2020 by David Duncan

Much industry analysis and discussion has been directed at European gas price formation, specifically the transition from oil indexation to hub pricing. But there has been less focus on the changing roles and risks of the key players. In this article we examine the drivers of European hub prices and attendant uncertainties and also the risks of key players compared to the pre-liberalisation era.

Revisiting the hub price framework

With hub prices eclipsing those of oil (product) indexation as the key wholesale reference price it is natural to ask the question ‘What are the determinants of European hub pricing?’ We have addressed this question previously in articles that set out and then applied a framework for the analysis of hub price behaviour. Two important conclusions from this framework approach are:

If demand in Europe, which is linked by infrastructure to liquid hubs, is met at the margin by Russian pipeline gas above take-or-pay levels, then hub prices will gravitate towards the Russian oil-indexed contract price.
If, however, demand is depressed and/or supplies of flexible LNG represent the marginal supply tranche for ‘liquid’ Europe, then prices fall below Russian oil-indexed contract prices. The exact hub price level depends on supply and demand dynamics and market sentiment, but important price support exists at levels where gas displaces coal in the power generation sector.

Historical analysis shows the framework approach to have worked reasonably well to the beginning of 2014, as shown in Figure 1. For 2012 and 2013, the annual average NBP price was $9.36 and $10.63/mmbtu respectively.

Figure 1. A Supply Stack for North and Central Europe, 2012 and 2013

Source: Rogers & Stern, OIES

Two areas that are more challenging with the framework approach from a practical viewpoint are:

In order to project the volume of LNG available for Europe, it is necessary to evaluate the global balance of LNG supply and demand which is subject to a significant degree of uncertainty.
With the introduction of ad-hoc concessions on price formulae, take or pay levels and rebates relative to hub prices on an individual contract basis, it is extremely difficult to define what the ‘Russian contract oil-indexed price’ is.

In early 2014, continuing to the present time, hub prices have fallen and remained below estimates of Russian contract price based on historic relationships to lagged oil product pricing. In mid 2014, NBP fell to levels where it demonstrably displaced coal in the UK power market. The forward curve for NBP and TTF appears to broadly re-converge with the consensus view of Russian contract prices in the 2^nd half of 2015. But if substantial volumes of LNG keep flowing into European hubs, realised spot prices may again fall below contract price levels (a risk which we explored last week). We will return to the price exposure risks for midstream companies presently.

Evolution of European gas players

At the birth of the continental European gas industry the challenges in introducing natural gas as a new fuel were essentially to establish:

a pricing mechanism which would price gas into the energy mix at an advantageous level relative to oil products (without undue market disruption); and,
national (or sub-national regional) champions (monopolies) to contract supplies from domestic and increasingly foreign producer/suppliers on a long term basis such that the financing of pipelines and distribution systems could be undertaken.

With the continuing strong growth in European gas demand up to the mid to late 2000s, this model proved highly successful for upstream and midstream participants. Demand growth effectively passed on the residual price risk to end consumers (power generators and industrials), who until relatively late in the day were unaware of this.

In the 2000s however, the First and Second Gas Directives, the Energy Sector Enquiry and the subsequent Third Package and Gas Target Model resulted in radical changes to the status quo. Network unbundling, entry/exit tariffs for transportation and the end goal of delivery of gas to hubs represented significant changes to the regulatory landscape. At the same time and partly in response to such changes, a wave of mergers created pan-European players. Significantly these were primarily power and gas utilities, dominated by power generation and management teams with more of a ‘trading mentality’.

In this new landscape the following changes can be observed in the roles of the key players in the gas supply chain:

Producers and Exporters: Their primary role is largely unchanged; however they now have the option to sell directly to large end-users – either via medium term contracts or as trading counterparties on the hubs. They may wish to continue with existing long term contracts and to sign new contracts if undertaking large new upstream projects.
Network Companies: Transmission System Operators (TSOs) and Distribution System Operators (DSOs): These are new players, the product of unbundling pipeline assets from the Midstream Gas Companies. They enjoy low (regulated) rates of return but bear arguably little risk.
Local Distribution Companies: Although they have lost their physical networks, LDC’s have not yet been subject to serious competition for their ‘captive’ customers due to low levels of customer switching.
Mid-Stream Gas Companies: These became the gas departments of energy utilities. They retained their long-term supply and transmission contracts. The supply contracts are subject to continual arbitration/renegotiation with upstream producers (unless they have been changed from oil- to hub indexation). The customer base is under attack from upstream producers and downstream LDC’s. Depressed demand also serves to increase the risks of not achieving take or pay commitments as well as creating potential financial exposures on send or pay in long term transmission capacity contracts.

The market landscape evolution described above has served to migrate risks into what were formerly Mid-Stream Gas Companies. The challenge they face is to continue to generate a margin on sales volumes given:

A flat or at best low demand growth environment and competition for market share from LDC’s and new entrants.
The exposure to price on their contracts with upstream producers (and the continual management distraction of renegotiations and arbitrations), if these have not been moved to hub indexation.
The need to meet take or pay and send or pay commitments in supply and transmission contracts.
The costs incurrent, not just in terms of sales management overhead but also the cost of transporting gas from the delivery point to the customer or hub.

Exposures can be mitigated (but not always eliminated) by trading portfolio optimisation for the liquid portion of the forward curve. But the midstream players effectively need to pay a ‘hub minus’ price to the producers on the basis that they supply an aggregation function which has inherent value. At present it is not clear:

Whether an upstream producer with an in-house trading capability recognises the value of aggregation versus direct hub sales; and,
Whether exposure to midstream risks through intense mitigation activity is sustainable for the remaining life of long-term supply and transmission contracts, some of which run into the late 2020s.

European gas players looking forward

Looking to the future, there are three scenarios that can be envisaged:

Scenario 1: The ‘hub-minus model’ is successful and accepted by producers. Midstream players continue with a smaller but profitable merchant business and with some difficulty are able to continue with their long term contracts to expiry.

Scenario 2: The ‘hub-minus model’ is not accepted by producers. Midstream players are unable to establish a profitable business and cannot continue to the end of their long term contracts. Intense competition results in a consolidation, with companies leaving the sector leaving 6 or fewer serious players (‘the British model’).

Scenario 3: The existential threat to midstream gas players raises governmental concerns in some countries where the collapse of long term supply and transmission contracts is viewed as unacceptable. Financial support in some form is made available to enable existing contracts to be managed until expiry.

The current level of hub prices in Europe (around $7/mmbtu) may help midstream companies in terms of demand stimulation and meeting take or pay (or send or pay) commitments. However some of the problems described above primarily relate to the spread between oil indexed contract prices and hub prices. Although such spreads may reduce in the second half of 2015 it is difficult to predict whether this will be reflected in the spot market at that time or whether such a convergence will endure. The inability of players to hedge exposures beyond the liquid portion of the forward curve will unfortunately ensure that such problems are likely to recur throughout the remaining life of these contracts.

This article was drafted by Howard Rogers and is based on the findings and conclusions of the following paper:

The Dynamics of a Liberalised European Gas Market: key determinants of hub prices, and roles and risks of major players (Jonathan Stern and Howard V Rogers, OIES, December 2014).

The tipping point in the gas market

Posted on April 13, 2015January 15, 2020 by David Duncan

The global gas market balance has swung from Asia back towards Europe as oversupply in the LNG market has taken hold. European hubs are providing key global price support as a market of last resort for surplus LNG flows. But how much surplus LNG can Europe absorb without driving hub prices sharply lower?

The ability of European hubs to absorb LNG is driven primarily by supplier flexibility to ramp down pipeline contract volume to take or pay levels. But at the point that contract swing flexibility is exhausted, hub prices may disconnect from oil-indexed contract prices and fall substantially, firstly to levels that induce gas vs coal switching in European power markets and then ultimately towards price support from Henry Hub (as was the case in 2008-09). This is what we refer to as the tipping point.

Current global balance

Forward market prices do not yet anticipate this ‘tipping point’ being reached. Forward hub prices remain broadly in line with oil-indexed contract price proxies. But the global market currently looks to be finely balanced. In Chart 1 we show our summary view of the supply and demand balance in the European vs global LNG market for 2016.

Chart 1: European vs LNG market balance (2016)

The left hand side of the chart shows the supply and demand balance at European hubs. The right hand side of the chart shows the global LNG market balance. LNG supply in excess of Asian demand (and the relatively small non-Asian emerging market demand), will need to be absorbed by Europe.

Some of this European volume is via non-divertible LNG supply contracts, primarily into Southern Europe. But as new volumes of LNG liquefaction capacity are commissioned in 2015 and 2016 they look to be exacerbating the oversupply situation in Asia. Under conditions of oversupply, divertible European LNG contracts and surplus spot LNG cargoes will flow into European hubs.

The ability for European hubs to absorb surplus LNG volumes is driven primarily by the displacement of flexible pipeline contract volumes, most of which come from Russia. As surplus LNG flows act to push hub prices below oil-indexed strike prices, suppliers are incentivised to minimise pipeline contract volumes to the annual contract ‘take or pay’ (ToP) levels.

Chart 1 illustrates the volume of pipeline swing contract flexibility above ToP. Swing flexibility has traditionally been about 85% of annual contract volume. However suppliers have negotiated additional ToP flexibility through contract reopener processes over the last 5 years, although it is difficult to know exactly how much given confidentiality of negotiations.

The important thing to note is that with swing flexibility around this level, European hubs do not appear to be far from the tipping point we describe above. This tipping point could be tested over the next two years if European and Asian gas demand remains soft in the face of the rapid ramp up in new LNG supply.

A simple European supply stack view

There has been a rapid transition in European hub pricing over the last six months as crude prices have fallen and European LNG imports have increased. These conditions warrant revisiting our framework for analysing European hub prices, to gain some perspective on how prices may evolve going forward.

The purpose of our hub pricing framework is to simplify the complex interaction between sources of supply and demand that drive European hub pricing dynamics. As summarised in our previous article:

There are two important considerations that can be used to greatly simplify the problem:

Grouping sources of supply with similar pricing and flow dynamics

Focusing on the flexible volumes of gas that drive hub pricing at the margin (i.e. around the intersection of supply and demand)

The first of these tasks is helped by the fact that most sources of European supply are under long term contracts that use a similar structure. The second task is assisted by the fact that only a relatively small volume of total European supply actually has the flexibility to respond to changes in market price.

Chart 2 illustrates the key tranches of supply that are currently interacting to set hub prices at the margin. It is important to note that the chart contains a simplified view of both supply and demand, in order to get across the key concepts. It should also be noted that inflexible ‘must flow’ volumes of gas (e.g. domestic production and contracted ToP volumes) are assumed to sit to the left of the supply stack at zero price.

Chart 2: Summary European gas market supply stack (2016)

The demand curve (in red) shows a simplified representation of pan-European gas demand in 2016. Projected demand at current price levels is around 530 bcm. The demand curve is downward sloping at lower price levels. This is driven primarily by an increase in gas demand as coal plant output switches to gas plant output as gas prices fall. The shaded red range around the demand curve reflects uncertainty around factors that influence demand such as coal price levels. The Henry Hub price level represents a floor price for European hubs given the US gas market can ultimately assume the role of LNG market ‘sink’ for surplus cargoes (as it did in 2008-09), although this situation may act to push US gas prices lower.

We have simplified pan-European supply by grouping flexible sources of gas into four main tranches as set out in the table below (again more logic here in our previous article). This provides a basic view of supply source interaction which is enough to describe key hub pricing dynamics. This can then be enhanced relatively easily by adding more detail on volume and pricing as required (e.g. sub-tranches of supply).

Tranche	Description
Pipeline swing contract volumes (BLUE)	This volume consists predominantly of Russian swing contract flexibility (and matches the top bar in the EU supply column in Chart 1). The pricing and flow dynamics of this gas are heavily dependent on oil-prices given contract indexation. We show an estimate of price ranges on the contracts that make up this swing supply (6.50 – 7.75 $/mmbtu) using a current proxy based on oil prices. Current volume dynamics in 2016 suggest that most annual swing volumes above ToP will be displaced by flexible LNG flows into Europe (as described in Chart 1). The price level of just above 7 $/mmbtu is consistent with current NBP forward prices for 2016.
Flexible LNG (GREEN)	This volume consists of both divertible European LNG supply contracts and surplus spot LNG cargoes not required by Asia. These Flexible LNG volumes are currently displacing Russian pipeline swing contract volumes (as described above). The volume of this Flexible LNG that flows into Europe will depend on Asian spot LNG prices in 2016, which we have approximated based on forward Asian LNG price proxies (note this is not a ‘transactable’ forward price benchmark). The important dynamic around this tranche of gas is that it will flow into European hubs as a market of last resort if not required in Asia.
Norwegian spot linked supply (BROWN)	In this tranche we have grouped (i) uncontracted Norwegian production (optimised against hub prices) and (ii) spot indexed Norwegian contract sales. We assume this gas is priced at (or marginally below) spot hub prices. In other words while the pricing/flow of this gas is optimised within-year against spot prices, annual volumes are sold to ensure Norway’s annual production targets are met and contract volume requirements are fulfilled. Hence this tranche is assumed to sit ahead of the other flexible tranches of supply.
Uncontracted Russian production and Asian LNG diversion (ORANGE)	We have grouped the remaining higher priced supply sources on the far right of the supply curve. The two most important sources here are (i) uncontracted Russian production and (ii) flexible LNG volumes that could be diverted from Asia given an adequate premium of European hub prices over Asian spot LNG prices. We do not give detailed consideration to the pricing of this gas for the simple view presented in this article. But as a guide on pricing, Russia is unlikely to sell additional volumes of uncontracted gas unless all of its contracted volumes have been lifted (i.e. pricing ranges above the swing contract tranche at $7.75+). Similarly a significant European price premium would be required to induce LNG demand reduction in Asia.

This simplified annual supply stack view provides a useful summary of some of the key drivers of hub price evolution given current market balance. While it is easier to observe these dynamics at an annual level, there are more complex dynamics at work behind this at a sub-annual level (e.g. seasonal price & flow behaviour). A particularly important dynamic here is the fact that there is additional within year flexibility in swing contracts (over and above the annual flex above ToP levels shown in the chart). These sub-annual dynamics do not invalidate conclusions at an annual level, but are important to bear in mind.

Conclusions on price dynamics

The price declines at European gas hubs over the last six months have been consistent with the fall in oil prices. In other words gas hub prices have remained broadly linked to long term oil-indexed contract prices. But this linkage is threatened by a limited volume of swing contract flexibility which can be displaced in order for hubs to absorb higher LNG inflows. At the point that contract swing flexibility is exhausted, hub price levels can disconnect from oil-indexed contract prices. At this tipping point, prices may fall sharply lower to levels that support the increase in demand required to absorb higher LNG inflows.

The supply stack in Chart 2 highlights the two key tranches of gas supply that will determine whether the European gas market reaches its tipping point. At current hub price levels (~7 $/mmbtu), European hubs cannot absorb both flexible LNG imports (the green tranche) and significant volumes of swing contract volumes above ‘take or pay’ levels (the blue tranche). This leads to the conclusion that increasing LNG inflows are likely to ensure that hub prices remain below oil-indexed contract price levels (i.e. flexible LNG will sit below swing gas in the supply stack).

Once European swing contract flex has been fully displaced by higher LNG imports, tipping point dynamics are driven by price inelastic volumes of demand and supply. Surplus LNG supply sold into Europe as a market of last resort is relatively insensitive to hub price levels. LNG will flow into Europe as long as NBP/TTF prices are more attractive than LNG spot price alternatives (e.g. in Asia). Similarly it may take significant gas price falls to induce higher European hub demand from gas vs coal plant switching. The inelasticity of these supply and demand volumes is an important factor that can drive sharp moves lower in hub prices.

The evolution of overall European gas demand levels will also be a key determinant of whether hubs reach the tipping point. If medium term demand is lower than the levels we have assumed, due to weather, continued economic stagnation, further general erosion of power sector gas burn by coal and renewables, this reduces the scope for European hubs to absorb LNG imports while meeting Russian take-or-pay volumes. This underlines the importance of keeping the assumptions within this framework refreshed as views of European demand change.

If Asian LNG demand remains weak over the next two years, the tipping point dynamics we describe in this article may take center stage. Global liquefaction capacity is set to increase by 55 bcma by the end of 2016. If a significant volume of that increase in LNG supply flows into Europe, it will test the ability of European hubs to ramp down swing contract take in order to absorb increasing LNG inflows. Under these conditions, the switching of coal for gas plant in the power sector will become a key driver of marginal hub pricing dynamics. We will come back shortly to focus on a more detailed analysis of coal vs gas switching dynamics.

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

This article was written by David Stokes, Olly Spinks and Howard Rogers

UK gas storage capacity restrictions

Posted on April 7, 2015January 15, 2020 by David Duncan

It is almost a decade since a fire at Centrica’s Rough storage site sent shock waves through the UK gas market. Market infrastructure has evolved since the fire, with significant increases in gas import capacity reducing the UK’s dependence on Rough flexibility. But Centrica’s recent announcement of the temporary withdrawal of more than 25% of Rough capacity caused a notable market reaction.

The Rough news was followed by an announcement by SSE that it would mothball 33% of withdrawal capacity at its Hornsea storage site. SSE, one of the largest investors in UK storage capacity over the last decade, cited ongoing weakness in UK storage market returns. SSE’s unwillingness to invest in maintaining Hornsea’s capacity illustrates the challenge the UK is facing in ensuring new fast cycle storage capacity is developed to shore up security of supply as import dependency increases.

Nature of capacity reductions

Centrica has announced it needs to reduce pressure at the Rough facility to 3000 psi for up to six months while it resolves a ‘well integrity issue’. The practical impact of this will be to restrict gas stored to between 29 and 32 TWh. This represents a ~25-30% reduction in capacity versus a maximum historical volume of 41 TWh in 2014.

Centrica has stopped the sale of further capacity (SBUs) for the 2015/16 storage year to ensure it remains within this capacity constraint. This does not preclude Centrica from selling additional capacity into next winter if the issues are resolved within six months (e.g. in October). But the late sale of this capacity would restrict the length of the injection/withdrawal cycle. And there is also presumably a risk of capacity restrictions being extended beyond six months if the well issues are more serious than anticipated.

SSE’s announcement on Hornsea impacts deliverability rather than space. Withdrawal capacity at the site will fall by 6 mcm/day. While this is relatively small in an overall market context, deliverability is the real constraint the UK gas market faces in winter periods. SSE’s decision is also an important signal as to the appetite for storage owners & developers to commit to further investment spend in an environment of weak market price signals (i.e. low seasonal price spreads and volatility).

Scale of potential market impact

Rough is the UK’s slow giant. It makes up about 70% of total UK storage space, but given relatively slow cycling, only about 25% of the UK’s daily deliverability. So the 25-30% capacity reduction at Rough equates to a roughly 18-20% reduction in UK storage space. But importantly, the capacity restrictions at Rough will not impact deliverability (Rough SBU withdrawal rates are not dependent on inventory levels).

The impact of the Rough restrictions can be visualised in Chart 1 which summarises UK storage capacity. The vertical axis shows deliverability across all of the UK’s operational storage sites. The horizontal access shows how many days that deliverability can be maintained assuming maximum withdrawal.

Chart 1: UK storage capacity deliverability

Source: National Grid

The capacity restrictions on Rough, to the extent they reduce gas stored for next winter, will proportionately reduce the length of the brown area at the bottom of the chart. In principle this acts to support seasonal price spreads at NBP. But in practice the impact is likely to be relatively subdued given the UK’s access to ample seasonal flexibility on the Continent. That said, the UK gas market would be more exposed to a prolonged cold spell next winter.

Rough deliverability, the height of the brown area in the chart, will not be impacted. Storage deliverability is an important factor that acts to dampen prompt NBP price volatility. So the volatility impact of the reduction in Rough pressure is likely to be negligible.

The impact of SSE’s Hornsea announcement on the other hand is all about deliverability. The 6 mcm/day reduction of deliverability at Hornsea means a 4% reduction in UK storage deliverability. This is relatively small in an overall market context, but not trivial. For example it is equivalent to about one third of the deliverability from SSE’s latest fast cycle storage facility development at Aldbrough.

Storage announcements in context

As UK import dependency increases, the primary concern from a security of supply perspective is storage deliverability. This plays an important bridging role over the two to three week period that it can take for the LNG import supply chain to respond to a major infrastructure outage or prolonged cold spell.

The Rough and Hornsea issues are likely to have a relatively small impact on UK seasonal price spreads and prompt volatility. The potential for a pronounced pickup in the seasonal flow of LNG imports, for example, is a much higher impact factor currently looming on the horizon. But Centrica and SSE’s recent announcements do highlight that the UK is more sensitive to interruptions in storage asset operation and investment than its Continental neighbours.

The Rough and Hornsea assets are the oldest in the UK fleet. The current issues at each highlight a broader problem facing owners of older facilities in the UK and across the continent. It is not a straightforward decision to commit to spend significant maintenance / renewal capex to extend the lives of older facilities in an environment of low volatility and spreads. This unwillingness to invest in existing facilities may ultimately contribute to the market price signal recovery required to support investment in new storage infrastructure.

The dangers of mixing forecasts and forward curves

Posted on March 30, 2015January 15, 2020 by David Duncan

Forward market liquidity has steadily developed with the evolution of traded gas and power markets in Europe. This has supported traders and asset managers to hedge forward asset exposures, reducing portfolio earnings volatility.

Energy price forecasting on the other hand has not undergone the same evolution. The track record of industry price forecasters today is no better than it was a decade ago. Perhaps in recognition of this fact, price forecasts have become cheaper to obtain. But we are still not aware of any forecasters who are prepared to publish a ‘mark to market’ back test of their historical accuracy.

The US Energy Information Administration (EIA) does deserve an honourable mention in this regard, given it allows access to its past forecasts. The EIA price forecasts have been as consistently and strikingly erroneous as any other, as they freely acknowledge. But the EIA also regularly compares its price predictions to those of other forecasters, showing that they rarely fall much outside of a reasonably tight ‘consensus’ band. This neatly demonstrates the poor track-record of the price-forecasting community. It is understandable given these circumstances that the energy industry looks elsewhere for a view on future pricing outcomes.

At first glance, forward curves offer an attractive alternative, given they provide a transparent and objective view of market price. As a result many companies (and price forecasters) have adopted the forward curve as a spot price forecast, on the basis that it represents the market’s consensus view of future spot price outturn.

In our view this logic is a capital error, and in a short series of articles we set out to explain why. We also address the question – if the forward curve is not to be seen as a forecast of spot prices, how are we to interpret it? In this article we use the animation of Brent crude pricing history that we published recently to illustrate some of the dangers of using the forward curve as a spot forecast.

The differences between forward curves and forecasts

The two terms ‘forward curve’ and ‘forecast’ certainly both start with the letters F-O-R, but that is just about where the similarity ends. One might also remark that the axes on which forward curves (FC) and forecasts are plotted look the same. Certainly, the y-axis in both cases is price: but closer examination of the x-axes reveals a critical difference.

While both are denominated in units of future time, the x-axis of a forecast is a time-series continuum, generally of daily granularity across the chosen forecast period; while the x-axis of a FC is contiguous ‘time-buckets’, often starting with months, then becoming perhaps quarters, or seasons (winter / summer), and eventually years. It may be common practice to interpolate a baseline FC into common, more granular time divisions to give a smooth curve, but it should always be borne in mind that such a transformation signals a modelling-based step away from the raw input of forward prices coming from the market.

These time-buckets match the currently-traded forward instruments available in the market being reported upon: and the corresponding prices recorded on the FC are a snapshot of the various prices currently reflecting that traded market, as of the date on the curve. To be even more precise, they are prices from a series of related but individual markets: the forward market for month n, the forward market for month n+1 etc. With several months till delivery, ‘August gas’ (for example) is a different commodity to ‘September gas’.

To make the point even more strongly: in April the ‘August gas market’ is a market for pieces of paper on which appear obligations relating to deliveries of gas in August. ‘August gas’ only becomes the same commodity as ‘September gas’ if and when both have been delivered and are sitting in the same gas storage facility. Some August gas contracts will be liquidated before August arrives, and thus never go to delivery – they were never gas, and they were never cashed in for gas. Some August contracts were always to be financially, rather than physically settled, and were never destined to turn into gas at all – just a difference-payment, i.e. cash.

And there could be many more August gas contracts by volume than there will ever be physical gas either produced or consumed in August. August gas contracts have laws of supply and demand of their own – the supply and demand for pieces of paper with obligations written on them – which we discuss in terms of the liquidity of the forward market. For the most part these are quite independent of the physical realities of what will happen in the spot market in August which will be driven by physical supply-and-demand characteristics.

The spot versus forward price relationship

Of course there are connections between spot and forward markets, but some are fairly trivial. For example:

Spot prices are generally used to settle forward contracts. This follows directly from the original purpose of forwards as hedges against uncertain future spot prices.
The price of the nearest forward contract converges with spot price. This is generally true, but not a remarkable phenomenon because over short periods the spot and near-forward markets are readily arbitraged via storage and other means of temporal exchange.

Other connections are more interesting. For example:

As neatly illustrated by the Brent animation (shown again in Chart 1), from day to day the biggest influence on the forward curve along its entire length is the spot price.
Indeed, the most common phenomenon in forward curve dynamics is the ‘parallel shift’, with the entire curve moving up or down almost in parallel, even if over the medium-term the gradient of the FC itself gradually changes, sometimes significantly.

Chart 1: Evolution of Brent crude spot and forward prices

Source: Timera Energy (based on ICE Brent Futures settlement prices)

These phenomena clearly undermine the logic that ‘the forward curve is a forecast of spot prices’. Why would a three-year forecast change every day, and by the same amount across the whole forward period, and by the same amount as today’s spot price change? Who changes their long-term forecasts every day? Who thinks that an increase in today’s spot price, perhaps caused by the weather or a well-understood physical event in the supply chain, has any bearing whatsoever on prices three years from now? What kind of implicit fundamental modelling would give rise to such a result?

The Brent price animation illustrates a very simple test: has the FC been a good predictor of Brent spot prices? The answer is that it has clearly been a very poor predictor indeed.

In the articles to follow in this series we will consider a number of econometric theories as to how the FC relates to physical markets. We will see that they often bear very little relationship to reality: and that the dynamics of FCs is a subject best studied empirically.

This article was written by Nick Perry (Senior Advisor).

Falling fuel prices and thermal plant margins

Posted on March 26, 2015January 15, 2020 by David Duncan

There have been some big moves in commodity prices and currencies so far in 2015. Sharp declines in oil, gas and coal prices have reduced the fuel costs of European thermal generators. But have these fed through into improved margins for gas and coal plant owners? The answer to this question is somewhat market and asset dependent. In this article we explore how commodity price movements are influencing generation margins in Germany and the UK.

Market moves in Q1 2015

The sharp correlated decline in oil, gas and coal forward curves that started in Q4 2014 continued through January. There was some respite in February as crude prices bounced in anticipation of US production curtailment. This triggered a recovery in European gas hub curves, reinforced by the threat of Groningen production cuts. Even long suffering ARA coal prices managed a brief February rally, as Glencore’s announcement of global production cuts hinted at a supply side response to price weakness.

But oil, gas and coal prices are falling once again across March. The February bounce looks to have been a temporary phenomenon rather than the start of any structural recovery. The Brent curve is sliding again, with the front month contract falling back towards its January lows around 50 $/bbl. NBP and TTF curves are falling in sympathy, with prompt prices weakening into a mild spring. And ARA coal prices remain below 60 $/t and close to a nine year low as shown in Chart 1.

Chart 1: API2 2015 coal futures price chart

Source: Reuters

Generator fuel prices have also been buffeted by big moves in currency markets. While coal prices have fallen sharply in USD terms, this has been significantly offset by USD appreciation against the EUR. The USD has risen approximately 20% against the EUR since last September (about 10% against GBP).

The speed and scale of USD appreciation over the last six months is unprecedented over the last 30 years. It suggests a structural shift towards a stronger dollar as major European and Asian countries scale up monetary expansion in an attempt to fight economic weakness and deflation. Implied FX volatility has also increased sharply over this period, a red flag that it is prudent to place an increased focus on FX risk within energy portfolios.

Forward spread dynamics into 2015

While absolute commodity prices are of interest to generators, the primary driver of plant margins is relative moves across power, fuel and carbon prices. Charts 1 and 2 illustrate some interesting dynamics in the evolution of forward market implied gas and coal plant generation margins so far this year.

Chart 1: Germany clean dark and spark spreads

Source: RWE

German coal plant margins: As we have set out previously, coal plants dominate the setting of marginal prices in the German market. This explains the relative stability of German forward Clean Dark Spreads (CDS) in Chart 1. The gradual decline in forward spreads over the last three years reflects the increasing penetration of renewables as well as the commissioning of new and more efficient thermal capacity.

German CCGT margins: With coal plant setting marginal prices, the big decline in forward gas hub prices in Q4 2014 (as oil fell) has fed through into a significant bounce in Clean Spark Spreads (CSS), albeit still in deeply negative territory. Chart 1 shows the CSS recovery reversing somewhat across February. But the chart (using forward price data from Mar 2nd) does not show the subsequent increase in CSS over the last two weeks as gas prices have once again fallen.

Chart 2: UK clean dark and spark spreads

Source: RWE

UK coal plant margins: The UK shows quite different margin dynamics given gas-fired plant dominate marginal price setting. Unlike in Germany, oil/gas price declines feed through directly into lower forward CDS as can be seen in Chart 2. This dynamic hints at tough times ahead for UK coal generators as they are faced by headwinds from both falling gas prices and an increasing carbon price floor (which will jump to 18 £/t in April).

UK CCGT margins: With CCGTs on the margin in the UK, CSS are relatively stable. The gradual recovery in gas-fired generation margins across the last 12 months reflects the tightening UK capacity balance. Although two mild winters (13/14 & 14/15) have helped to cap forward CSS recovery to date.

Overall the margin environment for gas and coal fired generators is still fairly bleak. However this is continuing to translate into capacity closures, good news for the margins of remaining generators. For example in the UK, Centrica and E.ON have recently announced their intentions to close CCGT plants after missing out in the first capacity auction. Weakness in forward CDS is also making life increasingly difficult for UK coal generators without capacity contracts. But commodity price movements may also have an impact on the relative value of gas versus coal plant.

Watch for gas vs. coal switching going forward

The last four years of commodity price evolution have firmly favoured coal plant margins over gas plants. Current market pricing still favours coal plants. But gas vs coal plant switching may yet become an important story in 2015.

Global coal prices are now at levels where significant volumes of production are being curtailed. US coal producers look particularly vulnerable as the USD strengthens. This may act to stem further price declines even if global demand remains weak. Oversupply in the global gas market on the other hand is a relatively recent phenomenon. And rather than being curtailed, supply is ramping up substantially over the next 3 years (as we set out here).

The risk of further falls in European gas hub prices has been one of our key themes this year. These may act to close the gap between gas and coal plant competitiveness to the point that switching takes place again. The UK power market is the ‘canary in the coal mine’ for switching, given the penal impact of the carbon price floor on coal plant competitiveness. We will come back to analyse gas vs. coal switching dynamics in more detail soon.

The mountain of new LNG supply

Posted on March 16, 2015January 15, 2020 by David Duncan

Despite current conditions of oversupply, the LNG market is set to embark on a growth spurt over the next five years. The relatively long lead times for liquefaction terminal construction provide good visibility of supply volume growth towards 2020. And volume growth will be substantial even if it is only limited to projects already under construction.

More than 100 mtpa (138 bcma) of new LNG capacity is currently being built, half of this in Australia. More than 40 mtpa (55 bcma) of that volume is due to be commissioned by the end of 2016, across Australia, Malaysia, Indonesia and the first US export trains at Sabine Pass.

After several years of limited growth in new liquefaction capacity there is a mountain of new supply entering the LNG market. What is less clear is whether anticipated Asian demand growth will arrive in a timely fashion to absorb new supply.

Where is the new LNG coming from?

Chart 1 shows more than 150 bcma of liquefaction capacity that has reached Financial Investment Decision (FID) sign off and is set to be built by the end of the decade. The majority of this export volume will come from Australia and the US, both of whom are vying to substantially increase their presence as gas exporters. In addition, there is a ‘second wave’ of US export projects which are at an advanced planning stage but still awaiting FID sign off. If these volumes are included potential supply growth by the end of this decade swells to over 200 bcma.

Chart 1: A mountain of new supply over the next 5 years

(source Howard Rogers)

Australia vying for the heavy weight title

By the end of this decade Australia is set to overtake Qatar as the world’s largest LNG exporter. Projects under development can broadly be split into two groups:

Queensland: Three separate projects are being developed on Curtis Island (off the coast of Gladstone) to export coal seam methane (connecting the eastern Australian gas network to the global gas market).
Western Australia: The Chevron led Gorgon and Wheatstone LNG projects off the Pilbara Coast and the Japanese led Ichthys project in the Browse Basin will add to Australia’s existing WA based liquefaction capacity.

In total these projects account for almost 70 bcma of new gas exports under construction, the majority of which is scheduled to be delivered by 2018.

In theory Australia has the potential to grow its LNG exports further via the expansion of existing terminals as well as the development of new ones. But Australia has a cost problem given a strong currency, high labour costs and difficulty in accessing gas. It has become renowned as the most expensive place in the world to develop new LNG projects (e.g. 20-30% more expensive than the US & East Africa).

The recent decline in the Australian dollar may be starting to assist with this cost problem. But cost recovery on any new Australian export capacity will likely to require contract prices of at least 11 $/mmbtu for brownfield expansions, rising to in excess of $14/mmbtu for further greenfield projects.

The new waves of US export capacity

A first wave of about 50 mtpa (70 bcma) of US export capacity is under development for delivery by 2019. This consists of the first four trains at Sabine Pass, as well as the Freeport, Cameron and Dominion Cove projects, all of which have FERC approval and have secured long term capacity contracts.

However the current global oversupply environment may be exacerbated by the delivery of a ‘second wave’ of US liquefaction projects. This additional 50 mtpa of ‘second wave’ US projects are either contracted or covered under ‘heads of agreement’, but are yet to reach FID and commence construction. Until market conditions recover, this second wave of US projects are likely to face delays or even cancellation. However at current Henry Hub prices, this capacity does look to be the most competitive source of new LNG capacity beyond the projects currently under construction.

In the short to medium term, the project economics of other US export projects that are yet to find buyers looks to be very challenging indeed. Intrinsic margins from US exports to Asia and Europe have collapsed over the last 12 months, reducing the willingness of buyers to pay for capacity. Contract buyers are likely to be hard to find until crude prices recover and the current wave of new LNG supply has been absorbed.

Will the anticipated demand turn up?

New LNG supply volumes can be projected with relative confidence given liquefaction projects are already contracted and under construction. But there is much greater uncertainty over the timing and volume of anticipated growth in LNG demand. This opens up the possibility of a significant timing mismatch between new supply and demand which tips the global gas market out of balance.

New liquefaction capacity is being developed against a backdrop of a structural increase in global gas demand, particularly in Asia. However a significant volume of new LNG is being contracted by portfolio players, rather than on a destination specific end-user basis. In addition, a number of higher growth importing nations (e.g. China and India) have relatively low long term contract levels.

The greatest demand side uncertainty sits with China. Over the last 12 months, China has been dampening industry expectations around its much anticipated increase in LNG demand. This is consistent with the signing of 68 bcma of framework agreements for pipeline imports from Russia. But the ongoing development of Chinese regas capacity is setting up the option for significant growth in LNG imports at the right price.

More broadly, Asian LNG demand is also vulnerable to a weakening global economic growth outlook and the prospect of Japanese nuclear restarts. Falling LNG prices may induce some demand response, particularly from more opportunistic buyers such as China. But when committed new supply is overlaid on a weakening demand outlook, the global gas market looks to be heading into a period of pronounced oversupply towards 2020.

Monetising the value of flexible gas & power assets

Posted on March 9, 2015January 15, 2020 by David Duncan

Flexibility value is a term often loosely used in association with gas and power asset optionality. It is a simple and widely accepted principle that asset flexibility has an associated value. But the practicalities of quantifying and monetising this flexibility value are often more complex.

Flexibility value has become much more important in European gas and power markets over the last few years. This is because of an increasing prevalence of assets with ‘at the money’ and ‘out of the money’ optionality.

For example most European gas-fired power plants have a variable cost at or above wholesale power price levels. Gas storage capacity has ‘at the money’ value characteristics given the weakness in seasonal hub price spreads. Similar logic applies for LNG supply contract diversion rights given regional spot price convergence.

Quantifying and extracting the value of asset optionality depends on the monetisation strategy adopted by the asset owner or investor. There are a range of monetisation strategies that are commonly applied which are distinguished by level of sophistication and risk/reward trade off. These include passive contracting strategies as well as more dynamic hedging and optimisation strategies.

In this article, the first in a series on value monetisation, we summarise five common strategies applied to the monetisation of flexible assets, using practical examples as an illustration. Then in subsequent articles we will undertake a comparison of the pros and cons of each of these strategies. We will also explore practical considerations in developing an appropriate monetisation strategy for a specific asset or portfolio.

Five ways to skin a cat

The five most common strategies for hedging and optimising flexible assets are summarised in the table below, followed by a summary description of each. We use the term ‘assets’ in a broader sense to capture physical infrastructure as well as contracts. Some of these strategies are more commonly applied than others given more palatable risk/reward characteristics. However we describe a full spectrum of strategies to highlight contrasting approaches.

Strategy	Description
1. Spot optimisation:	Intrinsic & extrinsic value managed against spot prices
2. Static Intrinsic:	One off intrinsic hedge (& matching asset dispatch)
3. Static Intrinsic + Extrinsic:	Sale/contracting of intrinsic + extrinsic value
4. Rolling intrinsic:	Rolling adjustments to intrinsic hedge (when profitable)
5. Delta Hedging	Dynamic hedging of exposures in response to price changes

Chart 1 then illustrates a stylised comparison of risk/reward tradeoffs across the five different strategies (something we will revisit in more detail in the next article in this series).

Chart 1: Value frequency distributions for the 5 strategies (source Timera Energy)

1. Spot optimisation

In many ways the purest asset monetisation strategy is optimisation of an asset against current and expected future spot price levels. Under this strategy no forward hedging is undertaken. The advantage of this is that there are no associated hedging costs. The disadvantage is the strategy results in a relatively wide distribution of asset returns (i.e. higher earnings risk).

This strategy is often implemented out of necessity rather than choice. This is the case for ‘out of the money’ assets e.g. gas peaking plant or for assets with a high proportion of extrinsic value e.g. very fast cycle storage assets. In both cases, hedging beyond the prompt period (i.e. close to dispatch) is difficult.

Implementation of a spot optimisation strategy requires a strong stochastic asset modelling capability to analyse price behaviour and decisions on exercise of asset optionality. This is particularly the case with assets which have more complex inter-temporal flexibility (e.g. gas swing / storage). In addition a capable prompt trading function and associated supporting functions, systems and processes are required.

A pure spot optimisation strategy represents one extreme of the value monetisation spectrum. But in practice, spot optimisation is usually matched with some form of forward hedging where possible.

2. Static Intrinsic

The other end of the value monetisation spectrum is represented by the static intrinsic strategy. This is a simple strategy where the asset is optimised and hedged on a ‘one off’ basis. This strategy is focused on locking in intrinsic value. It does not allow capture of extrinsic value and is subject to market timing risk. The strategy is therefore limited in its application.

The advantage of a static intrinsic strategy is that it requires very little commercial organisation capability beyond a basic operational support function and back office. It also has a relatively low associated earnings risk (e.g. residual availability and credit risk). This strategy was historically applied in the classic project finance structures for early independent power projects, read this post here for you to know what strategy and other stuff about your funds and how you finance your business. It is still occasionally used for ‘deep in the money’ assets with little extrinsic value.

However the management of intrinsic asset value is typically accompanied by some form of static or dynamic strategy to facilitate the capture of extrinsic value.

3. Static intrinsic + extrinsic

This strategy is a variation of the static intrinsic approach, but one which enables up front monetisation of asset extrinsic value. This is achieved by selling asset optionality to a third party (assuming a buyer can be found). The strategy can be executed on a one off basis e.g. signing a long term tolling contract on a CCGT asset, or as a series of contracts e.g. a storage asset owner selling capacity contracts of different durations/configurations on a single asset.

The strategy can be implemented either on a physical contract basis or using ‘virtual’ or ‘synthetic’ deals. It may also be adopted in response to a regulatory requirement where asset Third Party Access (TPA) is mandated e.g. for gas transportation capacity and some storage assets.

The strategy is attractive in that there is generally a relatively low residual earnings risk over the horizon for which the asset is contracted. Although residual risk may increase with more dynamic capacity sales strategies, e.g. depending on contract timing and the degree to which the owner retains market risk.

This strategy is very common for more risk averse asset owners such as independent producers or smaller portfolio players. Implementation requires a commercial support capability (e.g. sales strategy / product development). But importantly it does not require a trading capability (and associated cost/complexity). Given the costs and risks of extrinsic value monetisation sit with the contract counterparty, the asset owner will often incur a substantial value discount.

4. Rolling Intrinsic

Probably the most common strategy adopted for monetisation of flexibility value is the rolling intrinsic strategy. Asset flexibility is optimised & hedged against the forward curve, with the owner ‘rolling’ or adjusting hedges if better opportunities present themselves. In other words re-optimisation and hedge adjustment is only undertaken if profitable (i.e. adjustments are risk free). Most importantly it enables the capture of some extrinsic value on an ongoing (rather than a one off) basis.

The owner does not retain any downside market risk as the intrinsic hedges are only unwound if profitable adjustments can be made to the strategy. This reduces the market timing risk problem associated with the static strategies (2 & 3). But it means that the asset owner retains some earnings variability, given access to upside is a function of market price dynamics.

A rolling intrinsic strategy requires an active trading capability. But it does not require sophisticated dispatch and hedge modelling. The strategy represents a practical way of extracting extrinsic value while limiting downside earnings risk. As a result it is a very common strategy employed to monetise value of power, gas and LNG assets. This is particularly the case in illiquid markets where significant transaction costs can be cleanly accounted for when identifying profitable adjustments.

5. Delta hedging

The delta hedging strategy is a more sophisticated approach for the dynamic hedging of asset optionality. Asset flexibility is optimised against current & expected future spot prices as for the spot optimisation strategy (1.). But in this case, probabilistic forward ‘delta’ exposures are also calculated and hedged using linear products (i.e. fixed price/volume futures or forwards) in the underlying market.

The delta hedging strategy can be described using a simple CCGT example. Asset dispatch is optimised against spot power, gas and carbon prices (e.g. via the day-ahead or within-day markets). But in addition a probabilistic calculation of forward ‘delta’ sparkspread exposures is undertaken across the time buckets of available traded contracts. This is typically deconstructed into the gas, power and carbon legs that can be liquidly traded. The forward delta exposures are then hedged and hedges are dynamically adjusted as deltas change with market price movements.

The benefit of a delta hedging strategy is that it targets capture of the ‘full’ option value of an asset, whilst reducing earnings risk when compared to a spot optimisation strategy. But the owner still retains exposure to downside market risk as asset exposures are not fully hedged until delivery.

Trading desks often favour this strategy as it creates:

Liquidity – by generating a requirement to dynamically adjust hedges in the market
Cash – given hedge adjustments involve buying the underlying at lower prices and selling them back at higher prices (monetising volatility)

However, successful delta hedging requires a capable and experienced trading function and a sophisticated analytical capability (e.g. to calculate forward delta exposures). It is also not suited to all assets in all market conditions. Delta hedging requires relatively stable delta exposures and reliable market liquidity. But most importantly, theoretical or modelled value can be killed by market transaction costs. This means the successful implementation of delta hedging requires the combination of sophisticated but practical commercial and analytical expertise.

Comparing strategies

In our next article in this series we come back and undertake a more detailed comparison of the pros, cons and pitfalls associated with these five strategies. Strategy application is typically a case of ‘horses for courses’. No one strategy is best and in many cases the actual monetisation strategy adopted may be a combination of several strategies, particularly in the case where the asset sits within an integrated portfolio. This means it is important to pro-actively develop a monetisation strategy that is tailored to the risk/return tolerance and organisational capabilities of the asset owner.

Power capacity payments are coming across Europe

Posted on March 2, 2015January 15, 2020 by David Duncan

European power markets are slowly but steadily moving towards implementing capacity remuneration mechanisms for flexible generation. A consistent pan-European solution for capacity remuneration looks unlikely. Instead the approach and pace of implementation is being driven by security of supply concerns in individual countries. However a regulatory consensus is emerging as to the need for some form of remuneration for flexible capacity as renewable generation volumes rise.

Theoretical discussions are raging across Europe as to the ‘missing money’ problem of under remuneration of peaking capacity, the academic basis for capacity payment intervention. But ultimately capacity remuneration implementation is likely to be driven by practical rather than academic considerations.

In the absence of capacity payments (or much higher power price volatility), renewable capacity subsidisation across Europe will squeeze flexible generator margins to the point that assets close. The current capacity oversupply situation across much of Europe may provide a temporary buffer, but ultimately plant closures will undermine security of supply.

Different approaches across Europe

Capacity payments in power markets are not a new concept. Several markets in the US have implemented capacity markets with varying degrees of success. There are also European markets that have some form of capacity payments e.g. Ireland and Spain. But for the larger North West European power markets, the design & implementation of capacity payment mechanisms is a relatively new step.

There are broadly three forms of capacity remuneration model being considered:

Central buyer solution: for example as has been implemented in the UK in 2014 (for capacity delivery in 2018/19), driven by security of supply concerns over a rapidly tightening system capacity margin.
Supplier obligation solution: for example as is being implemented in France in 2015 (for 2016/17), driven by concerns over capacity to meet peak winter heating load.
Strategic reserve payments: for example the ‘Strategic Generation Reserve’ contracts that have been awarded in Belgium in the lead up to the current winter to address system tightness concerns after nuclear outages.

Chart 1 provides a summary of the approach to capacity payments across Europe.

Chart 1: Capacity remuneration across Europe

Source: EY

Strategic reserve payments are being used as a convenient temporary (or ‘stepping stone’) solution to address system capacity issues. There is typically a lower regulatory hurdle for introducing these payments compared to transitioning to a more structural capacity market solution. The payments are being introduced under the guise of greater powers for the system operator to contract reserve. But there is increasing disquiet within the industry as to the lack of transparency around remunerating capacity in this way.

For example, the UK Supplemental Balancing Reserve (SBR) payments are being used as a somewhat opaque ‘stop gap’ means of remunerating capacity over winter periods, while the more structural capacity market solution is rolled out. Germany has taken a different but equally controversial approach by mandating certain assets of strategic system importance remain open for reserve purposes.

Oversupply in Continental power markets has reduced the immediate urgency for structural capacity remuneration solutions. But as time passes, increasing renewable output will only further compromise the economics of flexible peaking assets. It is unlikely that politicians and regulators will be willing to stomach the power price volatility required to keep adequate peaking capacity on the system. And local transmission constraint issues (e.g. in markets like Germany) are also pressuring regulators to respond.

A number of countries across Europe are now openly considering more structural capacity remuneration solutions e.g. Germany, Belgium, Poland and Italy. The momentum for capacity remuneration is only likely to increase over time with interesting implications for asset margins and investment returns.

Commercial lessons learned from UK capacity market implementation

The UK led the way in Europe with implementation of traded wholesale gas and power markets. This was driven primarily by a pro-liberalisation regulatory agenda. The UK again finds itself leading the way with the design and implementation of a capacity market. But this time it is driven more by reactive necessity than proactive ideology. The UK is facing a rapid decline in system capacity margin, at the same time growth in renewable output threatens to close a number of thermal assets required to provide peaking capacity.

The UK capacity market implementation is not a shining example of how to design and deliver capacity support from a policy perspective. But the commercial ‘lessons learned’ by UK generators in the lead up to the first auction have a broader relevance for generators across Continental power markets as they prepare for capacity payment mechanisms.

The transition to capacity remuneration may in some ways appear to be a relatively minor tweak to market design. But in practice capacity payments have an important structural impact on thermal asset risk/return profiles and generation portfolio dynamics. The following are some higher level observations on the transition to capacity payment support:

Capacity vs energy circularity

Capacity payments add a more stable margin stream for flexible thermal assets. But they tend to have an important adverse impact on wholesale energy margin by supporting higher levels of system capacity. This tends to increase competition to provide the marginal MW of capacity and therefor reduce energy market rents. Analysis of the interdependence between capacity and energy pricing and the associated impact on generation margins, provides an important foundation from which to understand the commercial impact of capacity payments.

Investment, technology and costs

As capacity constraints begin to bind, the cheapest source of incremental flexible capacity will typically be provided by keeping open existing thermal plants that have a competitive fixed cost structure and that have capital costs which are already paid down (e.g. less efficient CCGTs). Capacity payment support can fundamentally change the economics of these assets (most of which are currently cash flow negative).

Once existing capacity options are exhausted it is important to understand the economics of new build options. Capacity payment mechanisms may skew new build investment economics. Capacity payments tend to favour lower capex small scale peakers (e.g. diesel generators, reciprocating engines and small gas turbines) ahead of more efficient but more capital intensive technologies (e.g. new CCGTs).

Capacity payments also impact the financing opportunities for new plants. A consensus is emerging across lending banks that debt sizing should be based on the capacity payment margin stream, with equity required to support the balance of the investment.

Capacity pricing dynamics

There are some good benchmarks for capacity pricing that can be derived from a combination of technology costs and historical price data from existing capacity markets. Conclusions on capacity pricing bounds can be drawn to some extent independently of the capacity mechanism design. For example:

Lower price bound: A reasonable lower bound benchmark for the capacity prices (in a market that faces a capacity constraint) is provided by the fixed costs of thermal peaking assets that would otherwise close (e.g. less efficient CCGTs).
Upper price bound: Reasonable upper bound benchmarks can be derived from the costs of delivering incremental new flexible capacity. It is important to note however that capacity mechanism design may skew this benchmark towards lower capex smaller scale peaking assets rather than CCGT.

Asset lifetime horizon

Perhaps the most important conclusion from preparations for the UK capacity market is to develop a strategy for capacity remuneration over an asset lifetime horizon. It is human nature to focus on the most immediate problems to hand. In the case of capacity payments this can mean focusing on capacity returns over a near term horizon e.g. defining a specific bidding strategy for the next capacity auction. But it is much more important to develop generation portfolio and investment strategies around the interdependent evolution of wholesale energy and capacity margin streams over a longer term horizon. This means deriving capacity bids based on a risk adjusted asset lifetime ‘Net Present Value’ view.

It is easy to ignore capacity remuneration until there is greater certainty around policy design and implementation. But the UK capacity market experience suggests that the specifics of policy design do not preclude generators from taking proactive steps to alter their investment and generation portfolio strategies. In fact there is a clear first mover advantage from anticipating the structural impacts of capacity payments on asset margins, portfolio structure and investment strategy.

European hub prices under pressure in 2015

Posted on February 23, 2015January 15, 2020 by David Duncan

After several years of relative stability, the European gas market has entered a more dynamic transition phase. Spot prices at European hubs have faced strong downward pressure since summer last year. The threat of Russian supply disruptions provided some temporary support for forward prices in advance of the current winter. But hub price declines have extended along the NBP and TTF curves into 2015.

There are two main factors driving spot and forward price declines:

A reduction in oil-indexed contract prices due to the recent slump in oil prices
Surplus flows of LNG cargoes into Europe due to weak Asian spot prices

Overlaying the fact that European gas demand has been relatively weak given a mild winter and it appears that hub prices have held up surprisingly well in Q1.

Prices have been supported in Q1 by oil-indexed supply contract volume profiling. But as 2015 progresses, this effect is set to reverse, causing renewed downward price pressure on hub prices into the summer.

Hub price drivers into 2015

The sharp oil price declines of Q4 2014 & Q1 2015 are yet to fully flow through into long term oil-indexed contract prices. That means contract prices are currently significantly higher than hub prices. Most contracts have a six month indexation lag to oil, which provides good forward visibility of a sharp fall in contract prices in Q2 & Q3 2015 (towards 6-7 $/mmbtu). The blue range in Chart 1 illustrates the downward move in contract prices as 2015 progresses relative to NBP forward prices in green.

Chart 1: European gas pricing in a global context

Source: Timera Energy

The current premium of contract over hub prices provides a strong incentive for contract buyers to profile their annual contract take. Volume take in many contracts is currently being minimised in Q1 (given hub gas is cheaper) in anticipation of higher contract volume take at lower oil-indexed prices across the remainder of the year (once price lags feed through fully).

Volume profile optimisation varies by supply contract. While European pipeline contracts broadly have a uniform structure (e.g. annual take or pay, daily swing constraints, oil products indexation), the pricing and volume terms of individual contracts vary significantly. But while specific volume take incentives may vary across contracts, the rapid decline in oil prices has caused a sharp reduction in pipeline gas flow into Europe across Q1 to date (in the order of a 40% y-o-y reduction in Russian volumes in Jan 15).

Reduced volumes of pipeline contract supply are currently being offset to some extent by:

Higher storage withdrawal volumes (a temporary effect over the Q1 withdrawal season – see Chart 2)
Higher flows of flexible LNG supply into European hubs (as we set out last week)

But the scale of contract volume profiling is definitely a factor currently supporting spot prices.

Chart 2: European aggregate storage inventories

Source: Gas Infrastructure Europe

Renewed downward pressure as the year progresses

After sitting at a premium to hub prices for most of the last decade, long term contract proxy price benchmarks have actually fallen below forward hub prices for the majority of 2015 (the blue range crossing over the green line in Chart 1). This suggests the contract volume profiling dynamics described above will reverse as 2015 progresses.

Once contract prices fall below hub prices, contract buyers have the incentive to maximise contract volume take, selling any surplus gas at the hubs to secure a premium. It is this arbitrage dynamic that acts as a strong force to maintain hub prices within a range of oil-indexed contract prices. But as the year progresses, contract prices are set to swing from being a source of hub price support in Q1, to a significant drag on prices across Q2 and Q3.

There are a couple of factors that may provide some hub price support as the year evolves. The potential for earthquake related reductions in production at the large Groningen field in the Netherlands were announced last week. But the volumes are relatively small compared to the scale of pipeline contract and LNG import volumes. The Groningen reduction (still subject to political debate) is in the order of 5 bcm reduction (less than 1% of European gas demand).

In addition supply contract negotiations over recent years (e.g. with Gazprom) have resulted in increased annual take or pay constraint flexibility. This means that contract owners have a greater ability to reduce gas volume take during periods of oversupply.

But the big incremental pressure on European hubs in 2015 may come from the LNG market. Hub prices are facing additional pressure from falling Asian spot & long term contract LNG prices (the red lines in Chart 1). Lower Asian LNG prices make Europe a more attractive market for flexible LNG supply volumes. The flow of surplus LNG cargoes into Europe is likely to build into the summer as a result of:

The seasonal reduction in Asian LNG demand (the pronounced seasonal spot price shape can be seen over previous summers in Chart 1)
The ramp up in new liquefaction capacity as projects come online (in Australia, Indonesia and Colombia)

The combination of pipeline contract profiling and surplus LNG cargoes suggests to us that the risk around European hub prices is firmly to the downside as 2015 progresses.

Europe is now the hub of the global gas market

Posted on February 16, 2015January 16, 2020 by David Duncan

In the three years following the Fukushima crisis, LNG supply played a relatively limited role in influencing European hub prices. Flexible LNG supply volumes flowed away from Europe to Asia, with Asian LNG spot prices providing the key global spot price signal.

These dynamics have changed in quite dramatic fashion since the summer of 2014. Asian spot LNG prices have declined rapidly to converge with European hub prices at around 7 $/mmbtu. As the global LNG market tips into a state of oversupply, surplus LNG cargoes are flowing back into Europe and European hub prices are acting as a key global price support.

LNG market oversupply

Q2 2014 marked the start of a new phase in global gas pricing. As a warning sign, Asian spot LNG prices halved across the first half of 2014, from 20 to just above 10 $/mmbtu as illustrated in Chart 1. This was exacerbated by a lack of underground gas storage and limited tank storage in Asian LNG importing countries.

Chart 1: Asian spot LNG vs European and US hub prices

Source: Reuters

European hub prices slumped in sympathy. This was driven partly by surplus LNG flowing back into Europe, but also by the withdrawal of high European storage inventories given the loss of 57 bcma of demand (y-o-y) as a result of a mild winter. LNG spot prices made a brief recovery in Q3 in anticipation of winter. But as confirmation that a structural transition was taking place, spot prices continued their decline into the winter of 2014-15, with the crude price slump and a surplus of spot LNG cargoes adding to downward price pressure. Last week Asian spot prices slumped below European hub prices with buying interest in Asia having dried up.

Price declines have not been limited to the spot market. Oil-indexed Asian contract prices are also set to fall towards 7 $/mmbtu this summer as the lagged impact of the crude price fall feeds through into contract price formulas. This means that the structural Asian price premium over European hubs has essentially disappeared. The global market looks to be entering a new phase of lower and more convergent regional gas prices.

The role of Europe in an oversupplied global market

LNG market oversupply may be a temporary effect due to a mismatch between the timing of global demand growth and new supply. But it is also possible that the global gas market may be entering a more structural phase of oversupply lasting a number of years. The nature of this period of oversupply will have important implications for global LNG and European hub prices.

In order to makes sense of the commercial impacts of an oversupplied world it is important to have an analytical framework from which to understand global gas pricing dynamics. The foundation of such a framework can be built on a depiction of the global gas market as three separate regional markets, each cleared by a regional spot market:

The US – cleared by Henry Hub spot prices
Europe – cleared by spot prices at European hubs
Asia – cleared by spot LNG prices

Flexible LNG supply sources are then the key mechanism which clears the global market across the three regions. Flexible LNG supply consists primarily of divertible LNG contracts, uncontracted LNG production and US exports (from 2016). This often comes in the form of flexibility to move gas within the portfolios of larger energy companies which have broad LNG supply chain exposures (e.g. BG, Shell, Chevron, Exxon).

During the post Fukushima phase of market tightness, flexible LNG supply volumes flowed away from Europe to Asia, driven by a significant Asian spot price premium. Now in an oversupplied global market, flexible LNG is flowing back into European hubs. Europe’s ability to soak up surplus flexible LNG volumes is set to be the key driver of pricing dynamics through the period of global oversupply.

Chart 2 illustrates the projected European versus global LNG market balance in 2016. The left hand section of the diagram shows the supply and demand balance for the European gas market. The right hand side shows the global LNG market balance. In the current oversupplied world, European hubs need to absorb surplus LNG supply. In practice this means LNG flows displace flexible Russian gas volumes (e.g. swing contract volumes above take or pay).

Chart 2: Projected European vs global LNG balance in 2016

Source: Timera Energy

But at the point that the volume of surplus LNG flowing into Europe exceeds flexible pipeline supply volumes, European hub prices may need to fall substantially in order to clear the market. Practically this would likely be achieved by a combination of:

Reduced Russian pipeline exports to Europe (e.g. negotiated take or pay concessions)
Gas displacing coal in the European power sector (important for CCGT margin recovery)
A reduction of US LNG exports if European hub prices do not cover variable export costs (once US export flows come to market in 2016)

Europe’s ability to soak up surplus flexible LNG volumes will become an important driver of global pricing dynamics through the current period of global oversupply. In turn LNG flows are set to become a key driver of European hub pricing dynamics. The volume of LNG flow into Europe will influence absolute hub price levels. The profiling of flow patterns will also impact summer/winter hub price spreads and price volatility. Across the space of the last six months, the evolution of the global LNG market has rapidly taken centre stage as a future driver of the European gas market.

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.