Author: David Duncan

UK CCGT margins take off, coal plants bleed

Posted on by David Duncan

Some important structural changes are taking place in the UK power market supply stack.  2016 has seen a pronounced shift in favour of gas-fired generators.  The flipside of the recovery in CCGT margins and load factors is that UK coal plants are being driven out of merit.

In last week’s article we looked at the changing fuel price relationships behind a recovery in the fortunes of CCGT plants across Europe.  These same drivers are at work in the UK but are being magnified by three additional factors:

  1. A very tight UK system capacity margin
  2. The dominant role of CCGTs in setting power prices
  3. The UK carbon price floor

Excluding emergency reserve (SBR) capacity, the UK capacity reserve margin as measured by National Grid is now zero (0.1% if you want to be pedantic).  In other words there is a significant possibility that system stress this winter will require Grid to call emergency reserve capacity to maintain security of supply.  That prospect is now feeding through into forward spark spreads.

The price setting role of CCGTs in the UK has meant that falling gas hub prices in 2016 have had a direct impact in reducing power prices.  The combination of falling power prices and the UK carbon price floor has sent spot UK coal plant margins well into negative territory.

Coal generators are now structurally out of merit in the UK.  But coal units remain critical for UK security of supply until the Capacity Market starts to deliver large scale new gas-fired capacity from 2020. This leaves the UK’s coal units setting prices in the year-ahead capacity auctions at levels that allow them to cover fixed costs and avoid closure.

What is happening with UK generation margins?

Chart 1 shows the historical evolution of spot CCGT and coal plant generation margins (CSS and CDS), as well as current spark and dark spread forward curves.

Chart 1: UK historical spot and forward CSS & CDS

uk-css-cds

Source Timera Energy (49% HHV CCGT efficiency, 36% coal efficiency)

A sharp uptick in CCGT margins (spot CSS) can be seen in Summer 2016.  This has been driven by falling gas prices given oversupply across European hubs (as explained last week).  This oversupply has been particularly pronounced in the UK gas market because of the Rough storage injection outage.

Summer maintenance on Norwegian export lines to the Continent has seen gas diverted to the UK rather than have production shut in.  Exports from the UK to the Continent in summer often run at maximum interconnector capacity anyway, and without Rough to soak up the resulting surplus, NBP prices have fallen to clear the UK market.

While these dynamics are an interesting short term phenomenon, there is a more important structural change taking place with spark spreads.  The recovery in spot CSS across the summer has been accompanied by an increase in forward CSS, particularly for the coming winter (16/17).  Winter CSS is now trading around 9 £/MWh, with average forward spark spreads over the next 12 months rising above 6 £/MWh.  These levels represent a return to CCGT margins not seen since early this decade.

The events of 2016 have crushed coal plant generation margins. Spot baseload CDS has fallen into negative territory over the summer as gas prices have weakened.  The CDS forward curve has so far just managed to remain in positive territory when measured on a market basis (i.e. only including fuel and carbon costs).   But once variable coal transport and system costs are accounted for, forward baseload coal generation margins are also in negative territory.

As a result, the more efficient and flexible UK coal units have been relegated to a peaking role, eking out small margins from within-day price shape.  Older coal units are sitting idle as reserve capacity.

Driving coal-fired generators out of the capacity mix was one of the key reasons for the UK government introducing the carbon price floor.  The price floor in combination with shifting commodity prices has done that job well.  But this has left the UK power market with a major security of supply issue.

Winter 16/17 – CCGT margins may recover further

Winter sparkspreads are foreshadowing what could be a more significant jump in spot outturn CSS this winter.  The UK may be insulated from the risk of rolling blackouts by the 3.5 GW of Supplemental Balancing Reserve (SBR) capacity which the system operator (National Grid) has contracted over the coming winter.   But SBR capacity does not participate in the generation supply stack and should only be called by Grid under threat of system emergency.  This leaves room for the zero system capacity margin (ex-SBR) to drive significant increases in power prices and volatility to the benefit of CCGT margins.

The other factor that is helping UK CCGTs is the fact that coal plants are becoming more expensive on a variable cost basis.  As well as covering variable fuel, carbon and system costs, coal plants also need to recover relatively high start costs.  Because coal plant generation margins (CDS) are so weak, power prices are needing to rise in peak periods to incentivise coal plants to run.  These factors act to drive increasing CCGT margin rents.

The UK will likely scrape through this winter without flickering lights given a 5% system reserve margin including SBR capacity.  But it is the non-SBR zero reserve margin that will drive wholesale market pricing dynamics.  The extent to which this translates into market fireworks will of course depend on variables such as cold weather, wind conditions, outages and performance of the debilitated Rough storage facility. But Winter 2016/17 is set to be the tightest period of the UK power market’s two decade history.

2017 and beyond

SBR will be discontinued from Summer 2017, with the new year-ahead 2017/18 capacity auction the mechanism used to procure an adequate system reserve buffer.  This will have an important impact on wholesale pricing dynamics.  Unlike SBR, capacity contracted in the year-ahead auctions will participate in the supply stack.  In other words the units that make up the system reserve buffer will compete with other generators on a variable cost basis.

All other factors being equal, this should act to dampen power price levels and volatility when compared to the SBR scenario of Winter 16/17.  But the relative behaviour of commodity prices will also play an important role.  If weaker gas prices mean coal plants remain out of merit, then CCGTs may continue to earn healthy rents as coal unit variable & start costs act to increase power prices above CCGT variable costs.

Coal units will also play a key role in setting capacity prices in the next three year-ahead auctions (17/18, 18/19 & 19/20) before new supply comes online in 2020.  Plants such as Fiddlers Ferry West Burton & Cottam are currently only recovering a fraction of fixed costs in the wholesale market.  This means they will need to bid at capacity prices levels that allow fixed cost recovery in the year-ahead auctions.  Competition to supply incremental megawatts will be particularly limited in 18/19 and 19/20 T-1 auctions given most generators already have capacity agreements from the four year ahead (T-4) auctions.  Don’t be surprised if these auctions clear at a significant premium to previous ones.

Implications for asset owners & investors

The UK government is targeting the closure of all coal plants by 2025.  It is unlikely that they will need to wait that long.  The carbon price floor and the shifting relationship between gas and coal prices appear to be sending coal plant generation margins into terminal decline.

The UK may lose one or two more coal stations by 2018.  But the remainder of the coal fleet is likely to remain on capacity market life support until 2020 when new gas plants come online.  Despite being driven out of merit, coal units are set to retain an important influence on marginal pricing in both the capacity and wholesale energy markets over the next 3-4 years.

Coal plant woes are good news for UK CCGT owners.  Structural gas price weakness and a tight system reserve margin are driving CCGT margin recovery.  The relegation of coal in the UK merit order also means higher CCGT load factors, higher average efficiency and lower start costs.  These factors contribute additional value over the headline spark spread recovery.

The recovery in the fortunes of UK CCGT plants is attracting plenty of investor interest.  Utilities are eyeing the sale of existing CCGTs as a way of raising capital to sure up their balance sheets.  And a bolstered capacity target for the December 2016 four year ahead auction has seen a frenzy of activity around CCGT development projects.

There have been a number of false dawns to the CCGT recovery story which has been anticipated for several years.  Conditions for UK CCGT have improved steadily since gas prices started to weaken in 2014.  But 2016 looks to be confirming the start of a more structural recovery.

Continental generation margins: Gas is back

Posted on by David Duncan

‘Positive baseload generation margins for German CCGTs?  That’s not possible!’

Exclamations such as this have echoed across European power markets this summer.  At the start of 2016, the concept of CCGTs displacing coal plants in the merit order was off the radar. Raising such an idea in front of a Risk or Investment Committee in January would have raised sceptical eyebrows.  Yet CCGTs all over Europe are back in action this summer… for the moment anyway.

We set out the logic behind why we thought gas vs coal switching was going to be a key mechanism for clearing surplus gas at European hubs in an article this spring.  This summer’s revival in European CCGT load factors is an illustration of gas vs coal switching in action.  Across Europe we estimate up to 40 bcma of potential CCGT switching demand as gas prices fall.

Germany is arguably Europe’s most hostile power market for CCGTs given the dominance of cheap coal and renewables.  So in today’s article we focus on the German market to illustrate the drivers behind the sudden shift in competitive balance that has taken place between gas and coal plants.  But the logic extends across all European power markets.

 

Plant margins & fuel prices: a summer 2016 case study

Enormous energy is exhausted attempting to conquer the fundamental modelling of European power markets.  The basic techniques of supply stack modelling have hardly evolved over the last 20 years.  But the evolution of processing power and data management have enabled the complexity and granularity of power market modelling to increase exponentially.

These developments have led to the insightful analysis of factors such as the impact of a strong breeze at 03:30 on Sunday the 29th January 2037.  But behind the overheating processers and ever expanding databases a simple fact remains:  power plant margins are predominantly driven by the relative behaviour of fuel prices.

Summer 2016 is a good example of this and you don’t need a complicated power market model to understand it.  Chart 1 illustrates the recovery in baseload German clean spark spreads (CSS) so far this summer.  Baseload CSS has risen from around -8 €/MWh in May to over 3 €/MWh by the end of August.  That is an increase of more than 10 €/MWh in the space of three months.  Over this period, coal plant generation margins (CDS) have remained at close to zero levels as coal plants dominate marginal price setting.

On a forward basis baseload spark spreads decline back into negative territory.  However peak German spreads remain positive across the coming winter.

Chart 1: German baseload coal and CCGT generation margins (CDS and CSS)

base spreads DE
Source: Timera Energy (gas efficiency 49% HHV, coal efficiency 36%)

Chart 2 shows the primary cause of the recovery in CCGT margins, a pronounced shift in relative gas versus coal prices.

Chart 2: ARA coal prices vs German NCG gas hub prices
fuel prices

Source: Timera Energy

Let’s consider this relative fuel price shift a leg at a time.  European gas hub prices have come under renewed pressure across the last quarter.  Owners of oil-indexed gas contracts have been strongly incentivised to take high volumes of gas given 6-9 month price lags which are capturing the low Brent prices from the start of 2016.  In addition, summer gas demand for storage injection has been relatively subdued, with the UK’s Rough storage out of action and healthy Continental storage inventories.  A gradual flow of LNG cargoes continues into North West European hubs, although Europe has so far not yet felt the fuller impact of surplus LNG as ramp up issues have continued with several new LNG liquefaction projects.

In sharp contrast, global coal prices have undergone a pronounced recovery across Q2 and Q3 2016.  As usual with the coal market, China is in focus.  There have been ongoing cutbacks in Chinese coal production in response to overcapacity.  These have been reinforced by temporary weather related issues such as unusually hot weather (boosting coal-fired power demand) and heavy rain (impacting coal production).  A tightening in the Pacific Basin coal market has boosted Atlantic Basin prices as European buyers need to compete for supply.

The shift in relative fuel prices has been reinforced by poor nuclear availability in the French power market this summer, which has supported healthy German exports.

 

Looking beyond this summer – what is happening with forward prices?

The recovery in prompt CSS has not lifted forward baseload spark spreads into positive territory (forward CSS can be seen around -5€/MWh across Winter 16/17 in Chart 1).  The current downward slope of the forward spark spread curve is driven by two factors:

  1. Gas curve contango: there is a pronounced upward slope to European gas hub curves, in sympathy with Brent curve contango
  2. Coal curve backwardation: the coal curve remains in backwardation, reflecting an anticipated easing in the conditions that have tightened supply over the last few months

Gas curve contango reflects a market anticipation that the pronounced oversupply of Summer 2016 is a temporary phenomenon that will ease into the coming winter.  This is reinforced by the upward pull that oil-indexed gas contracts exert on European gas forward curves, as the 2016 oil price recovery feeds through into contract prices and the Brent curve remains in contango.  Coal curve backwardation on the other hand reflects an anticipated easing in the conditions that have tightened supply over the last few months.

It is however important to note that the forward spark spread curve is not a good forecast of future spot spreads.  If you are not convinced you can find evidence in animation here and an explanation of the logic behind this here.

 

What factors are likely to determine the evolution of European generation margins going forward?

One important factor is that coal plants remain the dominant setter of Continental power prices.  That can be seen in Chart 1 via the relative stability in German generation margins (CDS) across 2016 i.e. power prices are moving in a correlated fashion with coal prices.  This means that further falls in gas hub prices (or rises in coal prices) will translate into higher spark spreads.  So if spot gas hub prices remain weak (rather than recovering in line with gas curve contango), this will support the CCGT margin recovery story.

There are two drivers worth watching as an indication of further weakness in European gas hub prices over the next 2 – 3 years:

  1. LNG imports: The volume of surplus LNG that flows into Europe as new global liquefaction capacity ramps up, will play an important role in determining whether hub prices recover back towards oil-indexed benchmarks.
  2. Henry Hub: The US gas market represents important price support for European hubs, with Henry Hub dynamics increasingly linked to European hubs by the hedging and optimisation of US LNG export volumes.

The recovery in CCGT margins and load factors will likely ease into the coming winter given seasonal gas price shape.  But the events of Summer 2016 illustrate the growing importance of gas vs coal switching in clearing an oversupplied European gas market.

We have focused on Germany this week as the last cab off the rank when it comes to CCGT margin recovery.  The story for CCGTs in other Continental power markets improves with the power price spread over Germany.  But the UK power market is a clear first cab off the rank. The impact of relative fuel price shifts on UK CCGT margins has been magnified by an anaemic system reserve margin and gas plants returns have taken off this year.  We return to focus specifically on the situation for generation margins in the UK next week.

Article written by David Stokes and Olly Spinks

Rough storage issues remain a structural threat

Posted on by David Duncan

The UK gas market was hit by a major shock in July in the form of an extended outage at its largest gas storage facility. The immediate impact of Centrica Storage Limited’s (CSL) suspension of injections at the Rough facility was a spike in winter gas prices. Winter prices eased again last week as CSL announced that it would bring back the majority of Rough wells online, allowing existing gas in store to be withdrawn from November.

Rough accounts for more than 70% of the UK’s working gas volume. It is a seasonal storage asset with a relatively low cycling rate. But the scale of storage working gas volume means Rough plays a key role in providing supply flexibility to the UK. Rough is also large enough to be important in a broader North West European market context.

The curtailment of Rough does not create a significant seasonal flexibility issue in the UK market. But it does exacerbate the UK’s gas deliverability issues. During periods of high demand or supply outages, the UK can face constraints in delivering enough gas into the network to meet demand. It is the loss of Rough’s deliverability, rather than working volume that poses a problem for the UK market.

The market may have breathed a sigh of relief last week as CSL’s announcement alleviated worst case fears for the coming winter. But the potential loss of Rough capacity remains a structural threat for the UK gas market.

 

An update on events leading into this winter

Rough is a partially depleted offshore field that was converted to storage operations in 1985 so has been operating for over 30 years. A number of issues have surfaced around the ageing Rough facility over the last 18 months which have impacted storage operations:

  • 18 March 2015: routine inspection identified ’a potential issue with well integrity’ and resulted in a 25% potential reduction in working gas volume from 3.7 bcm to 3.1 bcm.
  • 22 June 2016: a full shutdown was announced for 42 days due to a containment envelope failure in one of the wells at a lower pressure than expected. This was discovered during the testing programme prompted by the March 2015 outage.
  • 15 July 2016: the full shut down was extended until March / April 2017. CSL stopped selling capacity (SBUs) for the 2017/18 storage year but is investigating the possibility of making some wells and limited withdrawal capacity available over winter 2016.
  • 4 August 2016: scenario curves released by CSL indicate that it believes that Rough will be able to meet a minimum withdrawal rate of 6 mcm/day (vs a 42 mcm/day flow rate at full output).
  • 22 August 2016: CSL announced that it expects 20 wells (of a total of 30) to return to service by Nov 2016, likely to support a maximum deliverability of around 35 mcm/day.

Chart 1 illustrates the UK’s total storage deliverability over the coming winter under three different scenarios for Rough availability:

  1. 100% Rough availability i.e. assuming full injection would have been possible over the summer – blue shaded area
  2. A ‘best case’ scenario for the restrictions on Rough coming into the current winter (based on a constant 35 mcm/day withdrawal) – solid red line
  3. A scenario without the Rough storage facility (i.e. 0% availability) – dashed red line

Chart 1: Impact of Rough availability on total UK gas market storage deliverability

Rough deliverability

Source: Timera Energy (storage facility data from National Grid)

The chart illustrates the daily volume of gas deliverability (vertical access) assuming maximum rate withdrawal from full inventory over time (horizontal access). Rough as a slow cycle seasonal facility sits at the bottom of the chart. Despite Rough’s dominance of UK working gas volume, its slow withdrawal rate means that it contributes proportionally less to UK deliverability (and takes a long time to empty). Faster cycle storage facilities (such as Holford, Stublach & Aldbrough) sit higher up in the chart. These provide much higher deliverability relative to working gas volume, but empty more quickly.

There are some important points to note about CSL bringing wells back online for this winter. Estimates of potential deliverability (around 35 mcm/day) may actually be significantly lower in practice across the winter. Rough withdrawals will likely be impacted by:

  1. Lower delivery rates as inventory volumes fall
  2. More pronounced profiling of Rough volumes into higher priced periods given the relatively low level of inventory (e.g. in Q1 2017 when the UK is more vulnerable to cold weather and supply disruptions)
  3. Ongoing caution by CSL in how they operate the facility

So estimates of headline withdrawal rates (and the solid red line in Chart 1) are likely to overstate the deliverability that Rough will be able to provide this winter.

Rough is also constrained this winter by the fact that current inventory levels are a third of normal levels (1.26 bcm vs 3.73 bcm at the start of last winter), due to the injection restrictions.  This leaves the UK market significantly exposed to any more prolonged periods of system stress (e.g. as was seen in 2013).

 

Out of the frying pan into the fire – Rough remains a structural problem

The partial availability of Rough for the coming winter may have calmed the market temporarily. But the bigger issue facing CSL is that revenue from current seasonal price spreads is unlikely to support the lifetime renewal capex required to maintain Rough operation. This leaves the UK market contemplating the red-dashed line in Chart 1.

Visually the biggest impact of the loss of Rough capacity is the reduction in the number of days of gas in store (comparing the blue shaded region with the red-dashed line). But the UK market’s vulnerability is actually focused on the volume of deliverability over a shorter 2-3 week period, i.e.  on the left hand side of the chart.

A loss of Rough capacity decreases the UK’s daily deliverability of gas from storage by almost 25%. This can be seen via the red dashed line (0% Rough) intersecting the vertical access 42 mcm/day below the blue shaded region (100% Rough). And it is this threat of loss of deliverability that is of most concern to the UK market given its vulnerability to periods of system stress e.g. a cold snap or infrastructure outage.

The logic can be summarised as follows:

  • Well interconnected: There is more than adequate import capacity to bring gas into the UK (e.g. via the Norwegian Continental shelf, the BBL and IUK interconnectors and LNG terminals). But there can be significant supply chain lead times to attract adequate volumes of gas imports, particularly for LNG.
  • Deliverability squeeze: The UK market is most vulnerable to a shortage of deliverability over a 2-3 week horizon, as a result of high demand and/or supply disruptions. A classic example of this was in Mar/Apr 2013 when cold weather, field and interconnector outages caused an NBP gas price spike for several weeks, eventually alleviated by the diversion of LNG cargoes in response to higher prices.

If the UK loses Rough capacity it will have a knock on impact for the utilisation and value of other storage assets. Other storage facilities will likely operate to a more seasonal pattern to backfill loss of Rough capacity. This in turn reduces the volume of deliverability flexibility that the UK market has to dampen price fluctuations. In other words it supports prompt gas price volatility and the value of faster cycle storage capacity. This is a dynamic that is likely to support gas volatility across the European gas market.

Rough is not alone. It is only one example of ageing European flexible gas supply infrastructure. Around 5% of European storage capacity has been closed this decade. There is also the prospect of significant declines in supply flexibility from maturing gas fields (e.g. Groningen and Troll). As these factors come into play they are likely to drive a recovery in the market price signals required to support the economics of incremental flexible supply infrastructure, particularly prompt gas price volatility.

It is unlikely that large volumes of new seasonal storage capacity will be developed. The supply flexibility requirement in the European gas market is evolving with increasing interconnection, growing market liquidity and the more flexible use of gas-fired power plants to support intermittency. These factors all point towards the increasing importance of deliverability (versus seasonal flexibility). And this is likely to mean a shift in focus towards faster cycle storage assets, LNG import infrastructure and demand side response.

Article written by David Stokes and Olly Spinks

French Carbon Price Floor

Posted on by David Duncan

As the European carbon price continues to languish below 5 €/t, France has decided to take action. The French government announced in April that it would follow the UK in unilaterally implementing a carbon price floor targeted at 20-30 €/t.  Subsequently in July, an advisory committee commissioned by the government released a report with a strong recommendation to implement a domestic mechanism to increase the carbon cost for coal plants.

France’s unilateral action reflects its frustration at the absence of any meaningful European initiatives to strengthen carbon pricing. But unlike the UK, France is also focused on spurring other European countries into action in an attempt to build some momentum behind the COP21 agreement.  The French government are actively promoting the idea of a EU wide ‘carbon price corridor’ to maintain an ETS carbon price above 20 €/t from 2020.

The French are right in challenging the status quo. The European ETS carbon price signal has spent the last three years hovering around 5 €/t, a level which is essentially meaningless for inducing significant emissions reduction.  But the impact of implementing a price floor in France versus more broadly across Europe are two very different things. In this article we explore the impact of (i) higher carbon prices in France and (ii) higher carbon prices across Europe, focusing on the potential impact of these scenarios on power market pricing and asset value dynamics.

 

A summary of the French proposal

The French government initially proposed a uniform carbon price floor to operate on a ‘top up’ basis, similar to the existing UK carbon price floor. In other words a defined domestic price premium would be added to the EUA ETS price.

However, a French government advisory committee, which reported back in July, recommended an alternative approach to specifically target and penalise coal (to incentivise a shift to lower carbon intensity gas-fired generation).  This could either be done via an increase taxation on coal-fired power plants or by imposing tighter carbon emissions standards.  The French environment minister, Ségolène Royal, has not yet made a formal policy announcement but has reiterated the Governments commitment to introduce some form of domestic policy measure from January 2017.

Royal has also indicated that France will propose that Europe introduces a European ‘carbon price corridor’ that will allow EU nations a degree of flexibility to set their own carbon pricing terms within a broader European framework.  The current French proposal is for a European carbon floor price of between 20 €/t and 30 €/t in 2020 with annual increases of 5 – 10% with a target of 50 €t by 2030.  The proposed price ceiling would start at 50 €/t in 2020 and increase at a similar annual rate to the floor price.

 

Impact on the French power market

The primary effect of a uniform carbon price floor policy would be its impact in increasing the variable costs of coal and gas fired generators. Chart 1 illustrates the incremental cost increase for a CCGT 50% HHV and a coal plant 40% HHV.

Chart 1: Short run marginal cost impact of 30 €/t carbon price floor (Cal17 on 10th Aug 16)

FR CPF SRMC

Source: Timera Energy

This will clearly have an adverse margin impact on French thermal generators, particularly coal plants. However an attractive aspect of implementing a carbon price floor from a French perspective is that it is likely to have a limited impact on wholesale power prices. This is because domestic thermal (coal and gas fired) power plants play a relatively small role in setting marginal prices in the French market.

France has low installed volumes of coal (3GW) and gas (6.5GW) fired generation capacity. And the pricing impact of this capacity is limited, given interconnector flows play a dominant role in setting French power prices, particularly on the German border.

The carbon price floor is most likely to impact winter and peak prices when French thermal plant can influence marginal power prices. The policy should have little impact on summer and offpeak prices which are currently driven by coal priced imports from Germany.

If France imposes a carbon price measure on coal plant only as recommended by the advisory committee report, then the wholesale power market impact will be even more muted.  One of the reasons the committee made this recommendation was to prevent the closure of gas-fired plant required for security of supply.  Gas plants would benefit from somewhat higher load factors if the government pursued a coal only carbon charge.

Any increase in domestic (or neighbouring) power prices will be warmly welcomed by the French nuclear giant EDF, given this will flow straight to the bottom line of their nuclear power portfolio. The benefits of the price floor policy for EDF may not be a coincidence either. The French government owns a majority stake in EDF and is in the process of raising capital to support the utility’s nuclear development ambitions. Increasing wholesale power prices would certainly help to ease EDF’s balance sheet issues.

 

Possibility of a broader European roll out?

The French push to implement broader carbon price support across Europe is likely to come up against much stronger headwinds. But if successful, it would also have a more meaningful impact on wholesale power market pricing dynamics.

Germany is key. The German electorate is certainly open to proactive environmental policy. But given coal plants dominate wholesale price setting in the German power market, higher carbon prices will be passed through directly into higher wholesale prices.

German policy makers are already contending with a strong industry lobby pushing against the impact of renewable support in raising power bills and eroding German competitiveness.   This lobby is unlikely to welcome measures to support a higher carbon price. The strong German coal and lignite industry lobby will also be hostile. However the German Energy Ministry so far appears to be at least engaging in a conceptual discussion of a policy shift to support to a minimum carbon price, even if so far it is from behind closed doors.

Several other European countries may be open minded in considering implementation of a carbon price support policy (e.g. Ireland, Netherlands, Belgium, and Norway). The degree to which carbon price support gains traction across other EU nations will likely be an important factor in influencing the German debate.

 

What does a broader price floor rollout mean for power market pricing dynamics?

Let’s leave aside the policy debate and focus on the pan-European impact of higher carbon prices. This could be driven by a broader implementation of carbon price support mechanisms or by measures to support the EU ETS price (a much cleaner way of addressing the problem).

The relative impact of higher carbon prices is greater for coal plants than for gas plants, given the carbon emissions intensity for coal plants is more than double or CCGTs (0.85 t/MWh for 40% a coal plant vs 0.4 t/MWh for a 50% CCGT), as illustrated in Chart 1. This drives several knock on effects:

  1. Short run competitiveness: the relative increase in gas plant competitiveness vs coal on an SRMC basis, supports gas vs coal plant switching (or substitution of gas for more expensive coal plant generation).
  2. Long run competitiveness: The erosion of coal generation margins, combined with other regulatory hurdles that coal plants are facing, would likely bring forward asset closure dates.
  3. Gas burn: Power sector gas demand in Europe would be positively impacted, by 1. in the short term (given gas for coal switching) and by 2. in the longer term.

The UK power market provides a useful case study for implementation of a carbon price support policy. All three factors can be observed in progress.

The impact of higher carbon prices on absolute power prices and generation margins is more complicated. This depends on the degree to which carbon prices are passed through via the marginal plants setting wholesale power prices. Chart 2 however illustrates some important upper and lower bounds to consider, based on an example of a 30 €/t price floor in the German power market.

Chart 2: bounding the impact of a 30 €/t carbon price floor in Germany

FR CPF CDS CSS

Source: Timera Energy (Cal17 prices on 10th Aug 16)

The impact of higher carbon prices on wholesale power prices depends on the marginal (or price setting) generation unit.  The two key asset classes that dominate power price setting in Europe are:

  1. CCGTs: which generate CO2 at an intensity of approx. 0.40 t/MWh of power produced
  2. Coal plants: which generate CO2 at an intensity of approx. 0.85 t/MWh of power produced

Because coal plants have a much higher carbon intensity than CCGTs, the pass through of carbon prices to wholesale power prices is greater when coal plants are marginal (setting prices). But a carbon price floor would also change the dynamics of price setting plant. It would act to push coal plants out of merit, increasingly the influence of CCGTs in setting marginal prices.

Chart 2 illustrates the impact of higher carbon prices on German Calendar 2017 power prices and generation margins. The chart shows the impact on (i) the Clean Spark Spread (CSS) generation margin of CCGTs (left hand column) and (ii) the Clean Dark Spread (CDS) generation margin of coal plants (right hand column). Two scenarios for carbon price pass through are considered:

  1. 100% coal pass through (upper bound): If coal plant is setting prices, then the higher carbon intensity of coal plants translates into:
    • CSS: a significant rise in CCGT generation margins (from -6 €/MWh to more than 7 €/MWh), given power prices rise by more than the increase in CCGT variable costs (left hand column)
    • CDS: no change in coal plant generation margins, given power prices rise by the same as the increase in coal plant variable costs (right hand column)
  2. 100% CCGT pass through (lower bound): If CCGTs are setting prices, then the lower carbon intensity of CCGTs translates into:
    • CSS: no change in CCGT generation margins, given power prices rise by the increase in CCGT variable costs (left hand column)
    • CDS: a significant fall in coal plant generation margins (from 4€/MWh to -9 €/MWh), given power prices only rise by the much lower increase in CCGT variable costs (right hand column)

The dominance of coal plants in setting power prices in Germany means that higher carbon prices translate into three important effects:

  • Higher power prices: The influence of the greater carbon intensity of coal generation feeds through to create a significant uplift in wholesale power prices.
  • Gas for coal switching: Higher carbon prices act to shift the competitive balance towards gas plants, increasing CCGT load factors and pushing coal plants up the merit order. This to some extent counteracts the impact of coal plant pass through of higher carbon costs to power prices.
  • Higher CCGT generation margins: The increase in power prices acts to significantly increase CCGT margins (given a lower CCGT carbon intensity).

A unilateral French carbon price floor is likely to have a limited impact on the European power market landscape. But a floor price implemented in Germany could have a transformational effect on thermal asset generation margins and coal plant closures across Europe.

Article written by Olly Spinks and David Stokes

Utility asset sales: where are the value opportunities?

Posted on by David Duncan

The article below is our last before the summer break.  We will be back with more in late August.

Three weeks ago we set out the case for an unprecedented sale of conventional supply assets by European utilities. French and Italian utilities alone have announced their intention to sell upwards of €30 bn of assets. And this is only part of a larger pool of assets earmarked for sale across Europe, as utilities & producers shift their strategic direction and respond to balance sheet constraints.

The sheer scale of asset sales should open up substantial value opportunities, as well as paving the way for new entrants. Value is supported by a lack of utility buyers and cyclically depressed conditions in some markets. But potential buyers face the challenge of finding & pricing undervalued assets, while avoiding assets that are in terminal value decline.

In this week’s article we set out our view on two specific value opportunities:

  1. Gas-fired power assets
  2. Mid-stream gas assets

We focus on these because we see structural market changes that support value and offer asymmetric upside. But a robust investment case does not need to be based around a bet on a broader recovery in asset values. Ultimately value creation comes down to buying well chosen assets that are play a structural role in market operation… at the right price.

Value opportunity 1: Gas-fired power assets

European gas plant values have been decimated this decade. This has happened against a backdrop of general overcapacity in European power markets, caused largely by post financial crisis weakness in power demand growth and capacity overbuild. But beyond this, gas plants load factors and margins have suffered specifically from:

  1. Renewables: The erosion of load factors & prices by rising low variable cost renewable generation
  2. Cheap coal & carbon: Relatively weak coal and carbon prices have favoured coal plant competitiveness over gas plants.

The consensus view amongst utilities is for more of the same. But this ignores some key structural drivers that support a recovery in gas plant load factors, summarised in Table 1 below.

Table 1: Value thesis on European gas-fired power plants

Asset class: Gas-fired power assets
Asset types: CCGT, CHP, gas peaking plants
Status quo: Load factors, margins and asset value have been eroded by cheap coal, increasing renewable output and low carbon prices.
Value thesis:
  • Capacity payment mechanisms are being implemented across European power markets to stem the closure of flexible thermal assets required to back up intermittency.
  • Other revenue streams such as balancing and ancillary services payments are increasing as renewable growth creates transmission systems stress. CHP revenue streams can also provide downside protection.
  • Gas plant competiveness is increasing as gas prices fall (relative to coal prices) in a structurally oversupplied global gas market. Carbon price support may help this.
  • Rising gas plant load factors, margins and new build are set to be a feature of the early-mid 2020s given regulatory intervention to close large volumes of coal and nuclear plant.
Sellers: Potential buyers:
European utilities Funds (infra, PE), smaller utilities/producers

 

Case study: Continental CCGT assets:

CCGTs in Continental European power markets are widely regarded as value toxic. In many cases this is justified. A number of older, less flexible and/or locationally disadvantaged gas-fired assets are ripe for closure. Even owners of brand new merchant CCGTs in markets such as Germany and the Netherlands are suffering from several years of negative cashflows. Buying assets like this based on the thesis of a sparkspread recovery in the 2020s takes quite a specialised investor risk/return profile.

To build a more stable investment case it is important to target assets that have access to revenue streams that can ‘top up’ wholesale energy margin to cover fixed costs. This incremental revenue can come in the form of capacity payments, balancing & ancillaries revenue or pre-contracted revenue streams (e.g. CHP steam and onsite power contracts). There are also structural factors protecting plant energy margins in some markets e.g. the price setting dominance of CCGTs in UK and Italy and the requirement for gas-fired peaking capacity in Belgium and France.

But covering fixed costs is about buying time for value recovery. There are three important structural shifts taking place that support value upside:

  1. Capacity payment mechanisms are in the process of being implemented across Europe, adding an additional source of revenue that should rise as market capacity balances tighten.
  2. Regulatory driven closures of large volumes of coal and nuclear plants across Europe should increase gas plant load factors and margins in the early to mid 2020s. A number of existing newer/flexible CCGTs are set to become key for security of supply as this happens.
  3. Gas plant competitiveness is improving again as the global market transitions into a period of structural oversupply and gas prices fall. This may be further supported by actions to increase the EU carbon price signal (e.g. the French proposal to implement a carbon price floor).

Relatively new assets that will be critical for security of supply in the 2020s can be bought for a fraction of new build cost (e.g. 15-20%). But the premium that owners pay for access to value upside includes plant fixed costs. The challenge in buying Continental CCGTs is ensuring protection from negative cashflows, while understanding and pricing the risk/return distribution of assets.

Value opportunity 2: Midstream gas assets

The value of midstream gas assets (e.g. pipelines, gas storage & LNG regas terminals) has also suffered this decade. Weak gas demand has been a big factor behind this, particularly as a result of declining CCGT load factors (for the reasons set out above). There are two key price signals for midstream supply flexibility value:

  1. Price spreads: the signal for the value of supply flexibility e.g. seasonal spreads for storage, locational spreads for pipelines.
  2. Prompt price volatility: the signal for the prompt deliverability of gas e.g. in response to demand swings or supply disruptions.

Both price signals have declined to historically low levels this decade, falling from levels that support investment in new gas storage assets, to levels that are forcing the mothballing and closure of existing flexible assets. The consensus view among utilities is again for a continuation of current market conditions.

Table 2: Value thesis on European midstream gas assets

Asset class: Midstream gas assets
Asset types: Gas storage, gas pipelines, LNG regas terminals
Status quo: Asset pricing reflects current historically weak market price signals for gas supply flexibility (price spreads and price volatility).
Value thesis:
  • Import dependency is increasing as European domestic gas production declines, increasing Europe’s reliance on Russian gas (political risk) and LNG imports.
  • Renewable intermittency is supporting gas swing demand as renewable output rises and gas-fired power plants are increasingly required to provide flexible backup.
  • Ageing infrastructure is resulting in the retirement of flexible infrastructure as owners cannot justify investing in life renewal capex.
  • Low fixed costs help support positive cashflows and protect value downside.
  • Asset utilisation is increasing supported by import dependency.
  • Other value support can often be found (e.g. via legacy contracts for pipelines or financing/structuring opportunities around cushion gas for storage assets).
Sellers: Potential buyers:
European gas utilities; oil and gas producers Funds (infra, PE), producers, LNG players

 

Case study: Faster cycle gas storage assets:

 Midstream gas assets have traditionally sat in utility portfolios. But as utilities refocus strategy and sell supply assets, the midstream transaction flow is increasing.

The value upside story for midstream gas assets is driven by a structural transition in the European gas market. As domestic gas production declines, Europe is becoming increasingly reliant on importing gas from outside its borders (e.g. via LNG and Russian gas), creating an associated midstream flexibility requirement. A growing requirement for gas-fired plants to backup renewable intermittency is also set to flow through into higher demand for gas supply flexibility.

This is happening against a backdrop of ageing infrastructure. An estimated 5% of European storage capacity has been closed this decade. The future of a number of other storage facilities is threatened by market price signals that do not cover renewal capex costs (most prominently the large Rough storage facility in the UK).

A feature of midstream assets that makes them attractive to investors is low fixed costs. The overheads and maintenance costs for pipelines and storage assets are typically a fraction of those for power plants. This means that good assets (e.g. that play a structural role in supporting security of supply or portfolio risk management) are likely to retain positive cashflow as owners wait for value recovery.

Challenges in getting the deal done

 In a low yield investment environment, infrastructure investors are increasingly interested in European energy assets. The investment thesis around some asset classes has attracted a widening interest, with asset pricing starting to reflect this (e.g. UK CCGTs and peakers which we have written about now for several years).

However other classes of assets in the utilities sales queue are less well understood e.g. Continental CCGTs and midstream supply assets. In our view these may now offer better value and more competitive transactions price opportunities. But there are three key challenges in building a watertight investment case.

The first challenge is finding some form of downside protection to cover asset fixed costs, while maximising access to value upside (ideally of the asymmetric variety). Upside does not need to be a bet on a broader market recovery but can be built around specific asset benefits (e.g. location, flexibility or barriers to competition). The assessment of the ‘tail value’ of asset margin distributions plays an important role here.

The second challenge is quantifying asset risk/return distributions in order to define a risk adjusted valuation. A robust valuation is built on an understanding of the interaction between the risk/return dynamics of different revenue streams. Infrastructure investors are likely to feature strongly as potential buyers (albeit in partnership with utilities/producers as offtake counterparties). This fragmentation in ownership is likely to require new contracting and business models to support value monetisation and asset operation.

The third challenge is transaction price, given asset value is ultimately a function of price paid. This is where gas-fired plants and midstream supply assets are a particularly interesting prospect. Current pricing appears to reflect an overhang of assets for sale, set against a relatively small pool of potential buyers. That swings negotiating power in favour of asset buyers.

Article written by David Stokes and Olly Spinks

UK coal plants & security of supply

Posted on by David Duncan

The UK government announced in November 2015 that all UK coal plants would be closed by 2025. This was a logical decision in the context of UK emissions policy, and a transition to CCGTs seemed easier in a world of falling gas prices.

Few details were provided at the time about how these coal closures would be achieved. But the government certainly did not anticipate that 6 months later, the whole UK coal fleet would be driven to the wall by falling gas and power prices.

Since the Nov 15 announcement, 4.3 GW of coal plants have closed. Another 4.3 GW remain on life support in the form of (ancillaries and SBR) reserve contracts with National Grid. And most of the remaining 9GW of UK coal plant are now cashflow negative, suffering from plunging dark spreads. There is also uncertainty hanging over the ‘renewable’ status of biomass units at coal stations which could further exacerbate closures.

These events are happening against a backdrop of an historically tight UK system reserve margin. Government support for renewables is steadily delivering new capacity. But because this is predominantly intermittent in nature, new flexible gas fired plants need to be developed to replace retiring coal plants.

This is where the UK government has painted itself into a tight corner. New gas fired plants require support from the Capacity Market which has a 4 year delivery lead time. That means as things stand there will not be substantial new baseload capacity until 2020.

So the government is in the awkward position of working to close all coal plants by 2025, while critically depending on the same units for security of supply until 2020. The way that this conundrum is resolved is set to drive generation margins and capacity pricing in the UK power market across the next 5 years.

 

Current outlook from a coal plant owner’s perspective

A combination of the UK carbon price floor and falling gas prices has done the damage to coal plant margins. The carbon price floor stepped up to 18 £/t last year, against a backdrop of falling gas prices. Falling gas prices mean falling power prices, given UK power prices are set by CCGTs. So coal plant generation margins have been squeezed on both the cost and revenue sides. The impact on baseload clean darks spreads (CDS) can be seen in Chart 1.

Chart 1: UK baseload clean dark spreads (CDS) and clean spark spreads (CSS)

UK Spreads Jul16

Source: Timera Energy (ICE data)

The sharp gas price decline from Q4 2015 to Q1 2016 has been particularly harmful for dark spreads, which can be seen falling below zero in 2016 in Chart 1. When variable fuel transport and network costs are added in (not included in Chart 1 CDS), the UK’s coal plant fleet is predominantly out of merit on a variable cost basis i.e. power prices are not covering short run marginal costs.

The impact of this can be seen in Chart 2 which shows UK coal generation output plunging in 2016, to the benefit of CCGT load factors.

Chart 2: UK coal vs CCGT generation (2013-16)

coal vs gas gen

Source: Timera Energy (Gridwatch data)

Coal plant economics are undermined by low load factor operation. This is not so much because units are not technically able to operate flexibly, but because coal plant fixed costs are relatively high. Annual fixed costs range from 40-60 £/kW (vs 20-25 £/kW for CCGTs), depending on factors such as locational transmission charges and the treatment of overheads by utilities.

Coal plants cannot recover these fixed costs from the wholesale energy market under current conditions. The impact of weak dark spreads is exacerbated by the fact that coal plants incur relatively high starts costs when running at low load factor. This leaves plant owners with the prospect of weathering negative cashflows in the absence of some other source of revenue (e.g. ancillaries or capacity payments). It is these other revenue streams that will likely determine the extent and pace of coal plant closures, in the absence of a recovery in dark spreads.

Two other important considerations impact the lifetime economics of coal units:

  1. IED constraints: Under EU emissions policy, plants either need to incur capex costs associated with fitting SCR equipment to reduce NOx emissions by 2020 or face run hour constraints.
  2. Decommissioning costs: The costs of closing a coal plant is significantly higher than a CCGT and there can sometimes be interesting economic incentives to keep plant open in order to avoid the immediate impact of these.

On top of these issues, the 1.7 GW Aberthaw plant in Wales is facing its own unique problems. A European court has ruled against a UK government exemption for Aberthaw NOx emissions which leaves the plant in breach of IED legislation and at risk of closure. The announcement of this last week had a noticeable impact on UK forward power prices, particularly across the coming winter, illustrating how tight the market currently is.

 

Capacity payments or lights out

In the midst of the uncertainty surrounding coal plant economics, one thing is clear. The UK cannot afford to lose 5-10 GW of coal plants from a security of supply perspective. The government (in the form of DECC & Ofgem) are acutely aware of that. What they appear less clear on is how to prevent it from happening.

Life support for coal plants to date has come in the form of Supplemental Balancing Reserve (SBR) and ancillary services contract payments (e.g. to Eggborough and Fiddlers Ferry). But these have been controversial. The government has announced it that the SBR scheme will be discontinued after the coming winter, driven by the adverse incentives it gave coal plant owners to announce closure and sign up for life support. The level of competition & transparency around ancillary services contracts has also been a source of industry discontent.

This places an emphasis on the capacity market to keep coal units open. The government’s recently announced additional auction for the 2017/18 capacity year should be sufficient to ensure security of supply until Q4 2018. But pricing in this auction is likely to be significantly higher than the two T-4 auctions that have been held to date, with the clearing price likely to be set by the incremental cost recovery requirement of marginal coal units.

The increased capacity targets DECC announced last week for this year’s T-4 auction should help stabilise security of supply from 2021/22.  But the 2018/19 and 2019/20 capacity years in between are the problem.  Delivering incremental capacity in these years comes down to the year ahead (T-1 auctions). But the government is likely to find it does not have a lot of leverage in procuring capacity at a year-ahead stage.

Most coal units already have capacity agreements across the 18/19 and 19/20 years from previous T-4 auctions. These were taken on by plant owners at low capacity prices given an anticipation of much higher dark spreads. The remaining units that do not have capacity agreements for these years are the most economically marginal i.e. the most expensive to keep open (e.g. Eggborough and Fiddlers Ferry).

However it should be noted that EDF’s Cottam & West Burton plants have now indicated they will pull out of the 3 year refurbishment agreements they bid for in the 1st T-4 auction.  This means they will revert to 1 year agreements for 2018/19 but then be able to bid into the 19/20 T-1 auction.

What is in play

DECC appears to be genuinely spooked about security of supply now. This comes after plenty of industry warning that a capacity crunch was on the way (not least from this blog) and that much of its EMR policy agenda was hindering rather than helping the problem.

Given where the government finds itself, the path through the remainder of this decade is likely to be a messy business. If we consider the likely options, they appear to fall into three categories:

  1. Carbon price floor relief: the scale back or abolishment of the UK carbon price floor could be used to provide some relief for coal plant generation margins.
  2. Capacity market tweaks: the government may implement changes to the capacity market (either temporary or permanent) that support existing coal plants e.g. releasing units from existing agreements to bid into the T-1 auctions (although timing is tight for this).
  3. Backdoor payments: the government (likely via the TSO National Grid) may resort to support payments for ancillary or reserve capacity, either through existing services or potentially the definition of a new reserve requirement.

If the UK government is to maintain investor confidence, it is critical that they handle this well, particularly given the potential impact of Brexit on confidence.

Some common sense basic principles for a solution would appear to be:

  • Transparency: Openly recognising the problem and engaging the industry to resolve it, rather than trying to disguise a solution via stop gap measures.
  • Price signals: Minimising the impact of any measures taken on market price signals, particularly avoiding any actions that may adversely impact the generation margins required to keep existing plants on the system and support investment in new assets (e.g. by supporting an overhang of uneconomic coal plant in the wholesale energy market).
  • Target the problem: implement specific measures to retain an adequate volume of coal plant to ensure security of supply (without interfering with market price signals).
  • Focus on capacity market: The capacity market has been designed and implemented to ensure security of supply and should be used accordingly as the focus of a solution.
  • Define closure policy: If measures need to be implemented to keep uneconomic coal plant from closing before 2020, they should be done so in the context of a clear policy on closures beyond.

The way the government decides to resolve the coal plant problem will impact both the wholesale energy and capacity markets. The policy path chosen is set to define the evolution of UK thermal asset returns across the remainder of this decade. It will also determine the willingness of investors to develop the baseload capacity required to sure up UK security of supply.

Article written by David Stokes & Olly Spinks

Brexit impact on European energy markets

Posted on by David Duncan

The Brexit ‘Leave’ vote was a genuine market shock.  On the day of the referendum, markets were pricing in a more than 80% chance that the ‘Remain’ vote would prevail.  The surprise result has been reflected in financial market volatility since votes were counted on Friday 24th June.  This volatility has in turn fed through into energy markets.

It is difficult to draw strong conclusions on the impact of Brexit given the level of uncertainty that remains.  Two key sources of this uncertainty are:

  1. The nature of the new relationship that the UK will negotiate with the EU (and other major trading partners)
  2. The impact of the UK exit decision on the future stability of the EU, and potentially more broadly on global growth

It will likely take months rather than weeks for clarity to emerge on these.  However there are some important observations that we can already make about the way that markets are reacting to Brexit.

In today’s article we compare movements in key prices impacting European energy markets ‘1 day after’ the referendum with ‘1 week after’.  This does not help to divine the future.  But it does demonstrate some important market relationships.  We finish the article by considering the broader consequences of Brexit for UK and EU energy policy.

 

Market impact: 1 day vs 1 week

Chart 1 shows the percentage price impact of Brexit on different markets, based on market closing prices ‘1 day after’ and ‘1 week after’ Brexit (June 24th vs July 1st).

Chart 1: Post Brexit percentage change for key prices driving European energy markets

Brexit price movements

Source: Timera Energy (using ICE, EEX & ECB data)

Currencies

The foreign exchange (FX) market is the headline barometer for the Brexit market reaction, given currency movements reflect a broad range of factors such as capital flows, interest rate movements and macroeconomic conditions.

The British pound (GBP) fell sharply straight after the referendum and has continued to fall. This reflects a rise in political and economic uncertainty in the UK as a result of the Brexit vote.  But it also reflects the Bank of England’s indication mid last week that it plans to pursue further monetary expansion (quantitative easing) this summer, a factor that should act to depreciate the pound.

Chart 1 shows GBP has fallen more against the USD than the EUR.  This reflects the fact that the Brexit result has also weakened the EUR and driven a general ‘flight to safety’ towards the world’s reserve currency the USD.

FX implied volatility, particularly for GBP currency pairs, has risen substantially over the last month as a result of the Brexit referendum.  FX risk exposures in energy portfolios have increased accordingly.

Oil and coal

Prices of globally traded commodities such as oil and coal weakened sharply 1 day post Brexit result.  This was driven partly by a stronger USD (consistent with the negative correlation between commodity prices and the dollar).  But price weakness also likely reflected market concern over the potential for broader fallout from Brexit to weaken global growth and therefore commodity demand.

It is interesting to note that 1 week later, coal and oil prices had recovered back to pre-Brexit levels.  This was consistent with a broader recovery in global commodity and share markets as last week progressed.  These moves were not mirrored in FX and bond markets, where Brexit damage in the form of weaker GBP and lower interest rate yields remained a week after the event.  This divergence in market reactions suggests that global markets are anticipating more central bank monetary easing (which places downward pressure on currencies and bond yields) to dampen the impact of Brexit.

European gas markets

Currencies play a very important role in driving the Brexit impact on gas hub prices.  NBP is a GBP denominated market (with gas contracts traded in p/th).  TTF is a EUR denominated market (with gas contracts traded in EUR/MWh).  Yet high volumes of interconnection capacity ensure relatively tight arbitrage in price differences across the English Channel.

NBP gas prices look like an anomaly in Chart 1.  NBP continued to rise in GBP terms as last week progressed even, while TTF continued to decline.  But this almost entirely reflects a weakening GBP against the EUR.  In EUR terms, UK gas prices have fallen by similar percentage terms as TTF prices.

The impact of GBP volatility on NBP prices since the onset of Brexit may have important implications for hub liquidity. The GBP currency exposure implicit in NBP gas positions will likely provide further support for the ongoing strengthening of TTF liquidity at the expense of NBP.

European power markets

We have used the UK and Germany to illustrate the power market impact of Brexit in Chart 1.  The fall in Cal 17 German power prices 1 day after Brexit, reflected the fall in ARA coal prices, given prices are predominantly set by coal plants.  But German power prices recovered with coal prices as last week progressed.

The rise in UK power prices reflects the dominance of CCGT plants in setting prices. In other words weaker GBP, means higher NBP gas prices and higher power prices (all else being equal).

But as is the case for NBP gas prices, if we consider UK power prices in EUR terms they are much more stable.  The healthy spread between UK and Continental power prices has weakened slightly since the referendum.  But the majority of the impact of EUR-GBP exchange rate fluctuations is neutralised through adjustments in fuel prices.

 

Brexit and UK energy policy

Taking a step back from the market and considering the impact of Brexit over an asset investment horizon, UK energy policy is another area that has come into focus over the last week. It is clear that there will be a period of political fallout in the UK following the referendum, including perhaps a new election.  The Conservative party will take on new leadership as well as a revised policy platform. These will likely shape the UK’s approach to negotiating EU extraction regardless of an election, given the Labour party is in disarray.  But from a UK energy policy perspective there are unlikely to be any major shifts.

The UK has been relatively autonomous in its shaping of energy policy to date, given a domestically driven policy platform to liberalise and decarbonise.  It has also typically been a leader rather than a follower in facilitating liquidity, promoting competition and implementing market design changes (e.g. the UK’s 2014 capacity market implementation, which ironically has been the only one accepted by the European Commission so far).

Brexit is also unlikely to derail the EU vision for a ‘single energy market’.  The EC’s big policy push for greater cross-border interconnection and inter-market compatibility is driven by security issues for gas (especially a fear of Russia) and by grid balancing concerns for power.  Both worries are EU-membership-neutral, and the EC will continue to promote maximum interconnection across the greater European region.  This includes the UK, which is the EU’s second biggest energy market and very significant provider of gas import capacity and general liquidity, whether it is in or out of the EU.

But most importantly, the UK government is well aware of the infrastructure investment challenge it faces over the next 5 years to maintain security of supply across power and gas markets.  If anything Brexit should only strengthen the government’s willingness to support investment in UK infrastructure.

Article written by David Stokes and Olly Spinks

LNG imports & European gas pricing dynamics

Posted on by David Duncan

The role of LNG imports into Europe is changing as the result of an oversupplied global gas market. Higher LNG flows into Europe are set to erode the dominance of oil-indexed contracts in driving marginal hub pricing dynamics. This should result in a much more direct relationship between European hub prices and the flow and pricing of LNG cargoes.

The much anticipated rise in surplus LNG flowing into Europe has proven somewhat slow to materialise in 2016. This is partly due to setbacks with large new liquefaction projects (e.g. Gorgon, Sabine Pass), as well as a delayed return of Angolan LNG production. There is also a post commissioning ramp up time for new export terminals to reach full production capacity, which can typically take 6 to 9 months. Chart 1 shows how LNG import volumes have started to rise in Q1 2016, but the impact so far has been small relative to the potential ramp up over the next three years.

Chart 1: European LNG Imports
chart

Source: Timera Energy (IEA flow data)

Stepping forward to 2019, there is little doubt as to the scale of new liquefaction capacity coming to market. The global gas market will need to absorb 150+ bcma of new LNG supply from projects currently being commissioned or under construction. Around 80 bcma of this will come in the form of highly flexible US export volumes. In an oversupplied global market, liquid European hubs will be the natural home for this gas. So how will LNG imports impact European hub pricing dynamics?

 

European supply and demand: 2016 vs 2019

We consider the impact of rising LNG import flows by looking at a view of supply & demand in the European gas market in 2016 and comparing it to 2019.

2016 supply and demand

In Chart 1 we show a stylised view of supply & demand at an annual level in 2016.   The supply curve is developed by grouping categories of flexible gas supply as we set out in April. The demand curve shape reflects the gas vs coal switching volume analysis we set out May.

Chart 1: European gas market S&D balance 2016

2016 EU Supply Stack

Source: Timera Energy

The most important characteristic of the 2016 supply and demand balance is that as surplus LNG pushes into Europe, it is displacing flexible pipeline contract volumes above ‘take or pay’ levels. This means that rising LNG import volumes are eroding the influence of oil-indexed pipeline swing contracts on hub pricing.

The power sector is the frontline mechanism that enables Europe to absorb rising volumes of surplus LNG. This means European hub prices are increasingly being influenced by gas to coal switching in the power sector.

2019 supply and demand

Stepping forward to the end of the decade means making a number of assumptions on market evolution. For example, the volume of Asian and European gas demand and the level of oil and US gas hub prices will all have an important influence on the European gas market balance.

In Chart 2 we illustrate the European supply and demand balance in a scenario where:

  • European non power sector gas demand remains relatively stable
  • Asian LNG demand growth reflects a continuation of the more recent weakness in Asian gas demand (against a backdrop of weakening Chinese growth)
  • Oil prices and US Henry Hub gas prices are consistent with recent forward curve levels for 2019

Chart 2: European gas market S&D balance 2019

2019 EU Supply Stack

Source: Timera Energy

Under this scenario European hubs would likely need to absorb significant volumes of surplus LNG. The key mechanisms to absorb the global surplus of LNG exports to balance the market are:

  1. European power sector gas vs coal switching
  2. Asian demand response at lower prices
  3. The shut in of US exports

Gas vs coal switching within Europe is relatively price insensitive and Asian demand response volumes are likely to be limited in the shorter term. This means it is the shut in of US exports that may need to do the heavy lifting to clear the temporary global surplus of LNG towards the end of this decade. This is illustrated in Chart 2 where US exports are setting hub prices in Europe (at an annual level).

Under a scenario of US shut ins, European hubs would fully converge with US Henry Hub and the global LNG price support role would transition from Europe to the US. In our view this could mean a trans-Atlantic gas price spread of less than 1 $/mmbtu as we set out previously. Under these conditions, US export volumes are likely to be very sensitive to changes in the trans-Atlantic price spread e.g. a move in the spread of 0.5-1.0 $/mmbtu may be the difference between US exports flowing at full capacity and US exports being completely shut in.

 

Impact of LNG imports on price dynamics and volatility

Russian oil-indexed pipeline contracts have been the predominant driver of European hub prices since market liberalisation. The transmission mechanism for the influence of Russian gas has been flexible oil-indexed swing volumes above take or pay. But these swing volumes play a limited role in the world of surplus LNG depicted in Chart 2.

While these conditions prevail, Russia’s traditional influence on European gas pricing diminishes. Until the surplus of global LNG is eroded, LNG imports are likely to become the dominant drive of European hub prices. This would also mean a strong influence of Henry Hub given the importance of flexible US export volumes.

So how would European hub pricing dynamics differ with LNG imports dominating marginal pricing? Let’s consider some likely dynamics:

Global linkage:

The evolution of global spot LNG prices will directly impact gas flows and prices at European hubs. But there is likely to be an asymmetry in price impact. Henry Hub will provide strong downside price support. But there may be periods of temporary upside divergence in regional LNG spot prices which impact European hubs e.g. if there is a temporary shortage of LNG in Asia or South America.

Chunky volumes:

Pipeline swing is fast and flexible in its response to hub price evolution. LNG cargoes on the other hand are large, and often have significant supply chain lead times (e.g. over two weeks) to respond to market prices, given factors such as shipping times and access to berthing slots. Terminal storage provides some flexibility but this does not fully compensate for the chunky nature of flows. For example the arrival of 5 cargoes into NW Europe in warm week may depress prompt prices, whereas a gap in cargo arrivals during a high demand period may cause a temporary price jump.

Alternative flexible response:

With Russian swing volumes relegated to the backseat, power sector gas vs coal switching becomes an important source of flexibility interacting with LNG import volumes. But the power sector is relatively unresponsive to price changes i.e. larger gas price swings are required to induce substantial changes in gas demand (this is illustrated via the inelasticity or slope of the demand curve in Chart 2). The interaction between LNG imports and the power sector will be an important factor to watch, with storage acting to smooth price dynamics on a within year basis.

The prevailing view is that an overhang of flexible LNG supply should act to dampen price volatility. This is a compelling argument at a headline level. It seems logical that an oversupply of flexible and price responsive LNG, should act to dampen price swings.

But we are not sure the outcome will be as simple as this, particularly given gas price volatility is currently at historically low levels. The ebbs and flows of European LNG imports may support periods of more pronounced prompt gas price volatility given the factors set out above. This is likely to combine with higher CCGT load factors providing a transmission mechanism for renewable intermittency through to gas price volatility. In our view it is a mistake to assume oversupply and lower gas prices equate to lower volatility.

Article written by David Stokes and 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

European utility asset sales are ramping up

Posted on by David Duncan

European utilities have taken a battering so far this decade. Most utilities are suffering balance sheet hangovers from a pre financial crisis spate of aggressive acquisitions and optimistic asset developments.

The pain suffered by utilities has been compounded by losses on thermal power assets over the last 5 years, as generation margins have been eroded by commodity price dynamics and increasing renewable penetration. Gas supply costs may add further balance sheet stress if gas hub prices continue to diverge from long term oil-indexed contract prices.

European utilities have written down more than €100bn of asset value since 2010 according to estimates by Jefferies, €30bn of this in 2015 alone. Chart 1 shows a breakdown of impairments this decade by company.

impairements

As a result, utilities are embarking on a transformational shift in strategic direction. The way forward is focused on renewables, networks and customer services. The vision for these businesses is a stable income base to repair balance sheets. Growth is anticipated to come from the development of renewable assets, both within Europe and further afield.

In order to raise capital and de-risk earnings, utilities are selling and spinning off conventional supply assets from their portfolios. This is supporting a pronounced ramp up in transaction activity in European energy markets in 2016. Value opportunities are also improving as utilities revise down asset price expectations.

There is an increasing queue of thermal power assets for sale across Europe this year. Activity is also rising around the sale/restructure of midstream gas assets (e.g. storage, pipelines and some LNG assets). Utility asset sales are likely to gain momentum over the next 2-3 years, as the current pipeline of planned sales is implemented and balance sheet pressure continues to intensify.

 

Germans spin off, while the French and Italians sell

Germany’s two biggest utilities have been the most prominent advocates of the asset spin off approach. E.ON completed the spinoff of its supply and trading business into a separate company (Uniper) in January 2016. RWE has also taken the spin off route, although it is approaching this via creating a subsidiary (RWE International) containing its renewables, networks and retail businesses, with a view to IPO the subsidiary later this year.

The large French and Italian utilities are focusing more on direct asset sales. Engie is top of the impairment list in Chart 1 and is also leading the sales charge. The French based giant has earmarked €15-20 bn of assets for sale over the next 3 years in an attempt to “reduce the share of activities that are exposed to price fluctuations of commodities and to increase the share of contracted or regulated activities”. Engie has already sold a portfolio of its US generation assets. European upstream and generation assets are tagged to follow.

EDF is following suit with plans of up to €10 bn of asset sales over the next five years to help stabilise its balance sheet which is suffering from the additional stress of its nuclear misadventures. ENEL has a target of €6bn of asset sales by 2019, with more than €1bn marked to go in 2016.

The ‘top 5’ utilities reflect an industry trend that extends across a broader base of European energy companies. Sale of merchant assets, reduction in commodity price exposures, strengthening of balance sheets and refocusing on core & regulated activities.

 

What is different in 2016?

The prospect of asset sales by European utilities is not a new phenomenon. Expectations have been building as the decade progresses. But utilities have not shown any particular urgency in progressing sales, partly because balance sheet damage has been shielded by favourable debt and equity market conditions (thanks to quantitative easing).

The key development in 2016 is the bid-offer spread for assets appears to be narrowing. The prices at which utilities are prepared to sell is falling as impairments are realised and pressure to sure up capital positions increases.

Utilities now look to be more willing to sell thermal power and mid-stream gas assets at a steep discount to their purchase or development costs. Lower prices are partly due to the fact that structural market changes and poor investment decisions are now reflected in asset write downs. But prices are also starting to reflect cyclically depressed market conditions (e.g. low commodity prices, weak margins and low flexibility premiums).

 

Sales pressure may intensify

Growing impairments are a powerful factor driving utilities to sell assets. But while sellers are motivated, in some cases highly motivated, they are not yet distressed. The evolution of sales processes has so far been relatively orderly, in contrast to some of the asset fire sales that took place in the post Enron period in the early 2000s.

However the balance sheets of European utilities remain under pressure. Gas hub prices in 2016 have showed signs of diverging again from oil-indexed contract prices. Growing oversupply in the LNG market may intensify this dynamic over the next 2 to 3 years.

Gas vs oil price divergence caused significant financial pain to utilities in 2009-10, given a mismatch of gas sales on a hub price basis versus a cost base driven by oil-indexed contracts. Renegotiation of long term contracts this decade has reduced this threat to some extent, but utility balance sheets are also significantly weaker now than 5 years ago.

Another factor worth considering is that utilities are starting to crowd the exit door. If motivation to sell assets transitions to distress, this is likely to be reflected via falling prices. Those are the ingredients for a feedback loop where lower asset prices may result in a greater urgency to raise capital.

 

Who is going to buy the assets?

Lower prices are a key ingredient to flush out potential buyers. This is particularly true given the notable absence of potential utility buyers. Historically other European utilities have been the natural owners of conventional supply assets, but most companies are currently looking to sell rather than buy assets.

Instead it is infrastructure investors who are circling on the buy side. These include funds (infrastructure, private equity and pension), but also large Asian infrastructure companies and sovereign wealth funds. Utilities are not renowned for their market timing and infrastructure buyers smell an opportunity. This coincides with growing pools of capital being allocated to infrastructure investment in a search for yield, against the backdrop of an historically low interest rate environment.

While the risk profile of merchant assets can be challenging for infrastructure investors, value opportunities are improving with increasingly motivated sellers. In many cases the sellers are prepared to retain some market risk to offset against other portfolio exposures, as well as offering route to market services. Infrastructure capital is also being supported by low borrowing costs and the development of financing structures that are compatible with some exposure to market risk.

The conditions appear to be in place for a transformational restructuring of European energy asset ownership over the remainder of this decade. This process is likely to accelerate the mothballing or retirement of assets that are currently uneconomic. But there are also a growing number of attractive value opportunities around assets that are an integral part of Europe’s energy supply chain.

Article written by David Stokes and Olly Spinks

Has the 2016 commodity price recovery got legs?

Posted on by David Duncan

Crude oil has doubled in price since February.  The rally in oil has coincided with a broader recovery in global commodity prices including coal.  Higher commodity prices have also started to feed through into gas and power markets in Europe.

Power prices in Continental markets have risen strongly in Q2.  German Calendar Year 2017 baseload prices have risen 25% since the start of March (from 21.50 to above 27.00 €/MWh last week).  Higher coal prices are the primary driver, given coal fired power plants currently dominate marginal price setting in Continental Europe.

European gas hub prices have been more subdued in 2016, weighed down by high storage inventories, robust domestic production and growing LNG import volumes.  But the influence of higher oil prices has helped gas prices rise over the last month, with NBP rallying from below 4.00 $/mmbtu towards 4.70 $/mmbtu.  This has in turn fed through into a similar rally in Asian spot LNG prices which are pricing off European hubs in an oversupplied global gas market.

In today’s article we take a step back and look at the 2016 commodity price rally in the context of the much bigger price decline over the last 3 years.  We do this in the context of the question in everyone’s mind: is this rally a temporary bounce or the start of a more structural recovery?

 

The rally in perspective

The doubling in the price of oil since Q1 is less impressive in a 3 year context. The price of the key US WTI crude benchmark has risen from 26 $/bbl at its low point in February to 52 $/bbl last week.  But prices remain at half of the 100+ $/bbl levels that were the norm until summer 2014.  The top panel of Chart 1 shows the evolution of crude over the last 3 years.

Chart 1: WTI crude oil prices vs the CRB index & US Dollar index
WTIC vs CRB vs USD

Source: stockcharts.com, Timera Energy

The two bottom panels on Chart 1 show the evolution over the same time horizon of:

  • The Commodities Research Bureau (CRB) price index, the most widely followed broader global commodity price benchmark
  • The US Dollar index, the most widely followed index of US dollar strength versus a trade weighted basket of currencies

We have included these indices to illustrate some key relationships:

  1. Oil price vs CRB index: The global slump in oil prices in 2014-15 has been accompanied by a broader correlated plunge in global commodity prices. This has reflected poorer prospects for global commodity demand, particularly due to a weakening Chinese economic outlook.  Similarly, the rally in oil prices since Q1 2016 has mirrored a recovery in the broader commodity index.
  2. Oil price (& CRB) vs US index: We have published previous articles on the importance of the relationship between the US dollar and commodity prices. The inverse correlation between oil and the USD can clearly be seen in 2014-15. A weakening dollar in 2016 has helped support the rally in oil and other commodities.  Dollar weakness this year relates primarily to the relative balance of monetary policy behind key global currencies.  Despite plenty of rhetoric, Europe and Japan are failing to gain much traction with their attempts at further monetary expansion and currency depreciation.  The US Federal Reserve on the other hand appears to be struggling to deliver the interest rate increases that were behind the big rally in the USD in 2014-15.

The key global macro relationships in Chart 1 do not detract from the importance of the supply and demand dynamics in individual commodity markets.  But the chart does illustrate how individual market balances operate against a powerful backdrop of global economic drivers.

 

What next for energy prices?

We published an article in February titled 5 market surprises for 2016.  Three of the potential surprises we put forward were:

  1. Oil prices form a multi-decade bottom
  2. Continental power prices also form a bottom
  3. The European gas market converges with Henry Hub

Its only June, but let’s do a quick status check on these.

Oil prices

The strength of the recent oil price rally suggests to us that oil prices may be forming a multi-decade low in the 25-30 $/bbl range.  That does not however mean that prices rally straight back towards the Long Run Marginal Cost (LRMC) of production (e.g. 70-80 $/bbl).  The crude market currently looks to be facing a stiff test of resistance in the 45-50 $/bbl range.  With the US rig count rising again over the last two weeks, this level may cap the crude rally for the moment.  Even If crude breaks through this level, there is more tough resistance above 60 $/bbl (as shown on Chart 1).

In fundamental terms, further recovery in the WTI price is likely to support renewed US shale drilling, with an associated increase in supply dampening prices.  Until the overhang of inventories and cheap US shale is worked off, crude is likely to remain range bound at levels well below LRMC.

Coal prices

As we described above, a view on Continental power prices requires a view on coal.  Much has been made of the potential for a pan-European carbon price floor (being pushed by the French).  But the power price impact of this is so far a secondary consideration relative to coal.  Like oil, it is hard to build a bullish case for coal in the short to medium term.  But importantly the investment cycle for coal is more advanced than for gas.

Coal mines have been closing in response to weak prices (e.g. Glencore’s recent closures in Australia).  In contrast, global gas supply is set to balloon over the next 3 years given the large pipeline of new liquefaction under construction.  This in our view is likely to support a recovery in gas plant competitiveness versus coal plants in European power markets (another one of our 5 surprises from Feb).

Gas prices (on a relative basis)

Finally we come to gas hub prices.  The recent rally in European hub prices has not significantly impacted the evolving dynamics of US vs European price convergence.  In other words Henry Hub prices have rallied alongside NBP and TTF, maintaining a trans-Atlantic price spread of around 2 $/mmbtu.  Convergence pressure on this spread remains as the mountain of new LNG liquefaction capacity comes to market.

This means the risk for gas prices on a relative basis over the next 3 years remains to the downside.  In our view it also means it is important to challenge the portfolio exposure impacts of gas prices weakening relative to both coal and oil prices.

We will come back at the end of the year and do a ‘full time’ check on our 5 market surprises.

Written by David Stokes & Olly Spinks