Author: David Duncan

Battery investment 2: Monetising battery value

Posted on by David Duncan

2019 may be the breakthrough year for merchant battery investment in the UK.  Battery developers have re-focused investment cases on wholesale market returns, given declining ancillary revenues, cuts to embedded benefits and the slashing of battery capacity derating factors.

As other sources of margin recede, the UK battery investment case has shifted to focus on merchant value capture from price volatility. Batteries have unparalleled stealth in responding to price fluctuations. But there are some important practical constraints around value capture.

It is one thing to forecast lofty battery returns in a spreadsheet.  It is quite another thing to turn those forecasts into cold hard cash.

We published our 1st article in a series on UK battery investment in early September looking at the transition in UK battery business models.  In today’s 2nd article in the series, we look at how merchant batteries capture value in the wholesale market and Balancing Mechanism (BM).  Then in a 3rd article to follow we consider the challenges that investors face in quantifying battery returns and building a robust investment case.

No need to reinvent the wheel

The challenge battery owners face in capturing merchant value may appear to be unique at first glance.

But there are two other energy assets that have very similar value capture dynamics:

  1. Fast cycle gas storage: A salt cavern gas storage facility is essentially a gas battery. Value is focused on short term (day-ahead & within-day) cycling to capture price volatility.
  2. Pump hydro: Pump storage is a water battery. It typically has longer duration than lithium-ion batteries. But the cycling constraint dynamics driving value are very similar.

A short duration battery has the same valuation characteristics as these other storage assets.  It is just faster cycling and can store a relatively small volume of energy.

The storage value of a battery is driven by relative differences in short term prices. The battery essentially gives the owner a very granular strip of ‘time spread’ options (the option to capture price spreads between different time periods).

As with all storage assets the variable cost of cycling is key to capturing value.  As long as a price spread exceeds this variable cycling cost hurdle, positive margin can be generated by charging & discharging.

In the case of a battery, the variable cycling cost hurdle is a function of:

  1. Full cycle efficiency costs (i.e. energy loss from cycle)
  2. Variable supplier/grid charges
  3. Market transaction costs (there can be significant bid-offer spread & liquidity costs in securing illiquid prompt prices)
  4. Variable degradation cost of cycling (i.e. an explicit charge to reflect impact of cycling on reducing battery life).

Some of the techniques currently being applied to value & optimise merchant batteries are ignoring a huge depth of expertise that already exists on valuing and monetising other types of energy storage assets.

Merchant battery value capture

Wholesale market & BM value capture can account for 50-80% of required returns for a merchant battery project (depending on business model adopted). To access this value, it is hard to side step significant exposure to market price risk. This is because there are no liquid products that allow an owner to hedge battery optionality on a forward basis.

A small portion of ‘arbitrage value’ can be hedged at the day-ahead stage. For example a 1 hour duration battery can buy the lowest price hour and sell the highest price hour in the day-ahead auction.  But this arbitrage value for a short duration battery only represents a very small portion of required returns.

The lion’s share of battery returns is generated by optimising cycling to capture value from responding to volatility across cascading day-ahead, within-day and BM prices.

Chart 1 provides a simple illustration of battery value capture across a 24 hour period. It shows Day-Ahead (DA) wholesale price and BM cashout price evolution and two cycling examples.

The 1st cycle shows dynamic response to capture a cashout price spread. In reality a battery may be cycled multiple times within a day to capture cashout price differentials that exceed the battery variable cost hurdle.

The 2nd cycle shows value that can be hedged at the day-ahead stage (e.g. via N2EX prices).

Chart 1: Illustration of day-ahead and BM battery value capture


Source: Timera Energy

Merchant battery margin is primarily generated by extracting value from price volatility in the BM (as illustrated by the 1st cycle in Chart 1). BM value capture is currently focused on responding to forecast cashout price differentials – also know as NIV (Net Imbalance Volume) chasing.  The advantage of this strategy is it avoids the set up and ongoing operational cost & complexity of submitting bids and offers into the BM (currently the realm of larger utility/IPP trading desks).

However, the volumes of flexible battery and gas engine capacity adopting this strategy are likely to quite quickly dwarf UK market imbalance volumes. This is set to increase risk and erode returns from NIV chasing. It will likely force battery (and gas engine) owners to fully participate in the BM to capture value (via bid / offer submission). Some of the larger UK flex operators are already doing this.

The forecasting problem

Battery owners face an inherent risk in capturing value from the volatility of uncertain market prices.  Battery cycling decisions rely primarily on forecasting differentials in prices as they cascade near to delivery (day-ahead to within-day to BM).

Forecasting techniques are improving but no-one has a crystal ball. Forecast errors mean losses as well as profits, a factor which is not always properly reflected in projections of battery value capture.

This problem of forecasting prices is illustrated in Chart 2 which shows how dramatically prices can deviate between the Day-Ahead (DA) stage and cashout (delivery).

Chart 2: Distribution of price deviations from Day-Ahead to cashout


Source: Timera Energy

To develop the chart we have split price data into two buckets based on whether the system was long (red) or short (blue). This is easier to view than a combined distribution.

Take the blue distribution as an example. The expected differential between Day-Ahead and cashout prices was ~15 £/MWh (across periods when the system was long).  But individual observed differentials fluctuated from -35 to +100 £/MWh. No matter how good your forecasting is, price swings that large cause forecasting errors that results in losses.

The sophistication of short term price forecasting techniques is improving rapidly (e.g. via applying machine learning). But as increasing volumes of battery (& engine) capacity are rolled out there are two factors making value capture more challenging:

  1. Value erosion: large volumes of flexible capacity responding to price signals in parallel may ‘cannibalise’ each other’s returns (a similar issue to that facing merchant wind & solar).
  2. Forecast error: price forecasting (particularly for cashout prices) is likely to become more challenging as volume swings from flexible capacity trying to capture prompt price moves increases.

These value capture challenges are not always robustly reflected in the quantification of battery economics.  We return in our next article to look at the challenges investors face in quantifying battery value and building a robust investment case for merchant batteries.

Building an energy trading capability

Posted on by David Duncan

To trade or not to trade. This has been a philosophical question confronting energy company boards since the liberalization of energy markets.

Trading is the core focus of some company business models e.g. Vitol and Mercuria.  But other companies have historically had a strong cultural aversion to trading. Perhaps the most prominent of these is Exxon, where for many years trading has been a dirty word.

But markets are changing and business models with them.  Asset value is increasingly being monetised via traded markets closer to delivery.  This is true for example in:

  • Power markets – renewables driving increase in value from capturing prompt price shape & volatility
  • Gas & LNG markets – increase in traded market liquidity and decline of long term contracts
  • Oil & products markets – impact of shale in shortening investment cycles and facilitating new entrant players

These trends are changing the attitudes of company boards to energy trading.

New entrant players are building trading functions to allow portfolio value & risk management (e.g. in the UK, new entrant retailers such as Smartest Energy and flex providers such as UKPR & Limejump).

Large producers are looking to acquire trading businesses as a way to expand their footprint and enter new markets (e.g. Equinor’s acquisition of power & gas trader Danske Commodities).

But perhaps the biggest strategic shift of all is that of Exxon which has announced plans to develop a trading business. In today’s article we look at the Exxon case study as well as setting out 5 key challenges that energy companies face in building a robust and profitable trading business.

Case study: Exxon’s shift to embrace trading

Exxon has for decades had a deep-rooted cultural aversion to trading as a source of enhancing margin.

It has been a company that has focused on excellence in engineering: delivering complex upstream projects on time and on budget. This has been underpinned by a very strong ‘controls culture’ which has become part of the psyche of the company.  Trading has been at odds with this culture i.e. ‘if you give the toys to the boys, the boys will play with the toys’.

That is why, when it signaled its change of heart by hiring several industry leading traders to build up a trading function, Exxon made global headlines this year.

Exxon has historically left its production virtually unhedged, selling at spot (or 1 month forward). This has been a coherent alternative business model to the more common trading-hedging model of many of Exxon’s competitors (e.g. BP & Shell).  As evidence of the effectiveness of this model, Exxon has maintained a AAA credit rating from 1949-2016 (when S&P dropped it a notch to AA+).

The ‘no hedging strategy’ approach has been sold to Wall Street as a ‘pure oil-price play’.  As long as Exxon’s balance sheet has been strong enough to ride out the bad times, the company saves on the ‘insurance premiums’ associated with hedging.

So why the change of heart – as a ‘non-trader’, what might Exxon have been missing? Profit growth is the obvious angle e.g. in the increasingly liquid LNG market where Exxon has a strong position.  The long term growth outlook for plain vanilla hydrocarbon production is increasingly uncertain in a world of decarbonisation (even if Exxon is notoriously averse to admitting this in public).

A trading function can also bring entrepreneurial benefits, driving innovation and commercial evolution within a company. These are likely to be valuable for a company that has suffered from introversion and commercial blind spots.

Exxon also has an abundance of capital and lines of credit. These are valuable attributes to support a trading function and can be a big differentiator when dealing in derivatives and structured products.

But perhaps the biggest factor in Exxon’s favour is the intangible value arising from the market information available on the substantial physical commodity flow associated with its business.  Leveraging physical portfolio flexibility has been the clearest route to trading function success in other energy companies.

Practical challenges in getting it right

Whether it is a giant corporation like Exxon or a small new entrant retailer, there are some key success factors that underpin the development of an effective energy trading business. We summarise five of these in Table 1.

Table 1: Key success factors in developing an energy trading capability

Success factor Considerations
Culture shift Traders are different people, by temperament and working practices, than engineers and traditional commercial staff.  Neither are easily able to manage the other for best results.  Successful trading businesses need adequate representation at a senior management & Board level, particularly if core company focus is elsewhere.
Investment & capital allocation A ‘trading lite’ approach is not a viable option for energy desks. Setting up a trading function requires sufficient investment in people, systems, data, analytical capability. Most importantly it requires the allocation of risk capital (whether implicit or explicit) to support P&L swings.
Risk appetite, limits & measurement Traders require genuine commercial freedom/flexibility to operate within the clearly defined constraints of a well drafted statement of Board risk appetite. A robust risk limits structure underpins the delegation of risk-taking capacity. Limits in turn rely on an adequate risk measurement capability.
Incentivisation & performance measurement Incentive structure is key for trading staff.  Well framed bonus schemes drive results.  Poor incentives schemes can engender dysfunctional trader behaviours and be divisive within the organisation.  A classic flaw is allowing traders to ‘skim’ profits from other divisions, either inadvertently or deliberately, to bolster trading results.
 Governance A trading desk is typically the only function within an energy business that can harm the company overnight (safety incidents aside). Trading must be within a top-to-bottom governance framework, including oversight by sufficiently knowledgeable, commercially independent senior management.

 

There have been a number of success stories where a physically focused business has successfully applied these principles to develop a strong trading capability (e.g. EDF Trading, Gazprom Marketing & Trading).

There have also been some spectacular company downfalls, led by trading related problems (e.g. Noble’s recent problems and the Enron related collapse of energy traders such as Dynegy, Williams and TXU in 2000-01).

Most energy companies sit somewhere in between success and failure. This often reflects the challenges of evolving a trading function within a company that has its cultural and commercial roots elsewhere. But it also sets up tangible opportunities to bolster profits and improve the integration of trading functions by tackling the 5 success factors above.

Carbon surge driving up TTF & spot LNG prices

Posted on by David Duncan

A carbon price surge in Europe pulling up LNG prices in China? This may sound like a case of the butterfly effect. But the current tandem rise in carbon and gas prices reflects an important linkage through the European power sector.

The carbon vs gas price relationship has come into focus this year as the result of surging carbon EUA prices. Carbon prices topped 25 €/t last Monday, a 142% move higher from the start of Q2 2018 (when prices were 13 €/t).

As carbon prices have increased, so has price volatility. After peaking on Monday last week, EUA prices fell 20% by Friday to close the week just under 20 €/t.

The TTF gas curve and Asian spot LNG prices have risen in parallel with carbon since Q1. They also fell in sympathy with the steep decline in EUA prices across last week.

The mechanics of this linkage between gas and carbon prices is underpinned by gas vs coal plant switching in European power markets, as we set out in this week’s article.

What is driving carbon higher

Carbon prices have rallied this year in response to finalisation of the Market Stability Reserve (MSR) measures.  The MSR has been a long time coming, but represents a clear mechanism to reduce the surplus of carbon credits that has built since the financial crisis.

Under the MSR, surplus carbon inventory will be removed at the rate of 24% a year across 2019-23. Culling of EUAs will then continue beyond this at a 12% rate.

The net impact of the MSR has been to reignite the requirement for market driven emissions abatement from the power sector.  In other words, the EUA market anticipates a shortage of emissions allowances, which needs to be cleared via higher prices.

The key mechanism driving carbon abatement at the margin, is the switching of coal units for CCGTs. Germany is particularly important given its large switching potential, with 28GW of installed hard coal capacity and more than 20GW of gas-fired capacity (currently running at relatively low load factors).

Switching linkage between gas & carbon

Rising carbon prices hurts coal plant competitiveness versus gas.  The carbon intensity of coal-fired units is more than double that of CCGTs (e.g. 0.85 vs 0.35 t/MWh of power produced). This means the variable cost of coal plants rises faster than CCGTs in response to a carbon price increase.

Everything else being equal, this carbon induced shift in competitiveness in favour of gas plants results in higher CCGT load factors. This in turn causes higher gas demand which acts to pull up European gas hub prices.

Movements in forward prices anticipate this relationship. In other words, a move higher in carbon prices is typically accompanied by a move higher in gas prices to maintain similar gas vs coal switching levels.  This dynamic can be observed in Chart 1.

Chart 1: Relationship between front month EUA and TTF prices

Source: Timera Energy

Front month carbon & EUA prices have been 94% correlated since the start of Q2 (with daily price returns 41% correlated).  The ratio of carbon vs gas price moves is not a ‘1 for 1’ relationship as it depends on the relative impact on gas vs coal plant variable cost.

The detailed mechanics of this carbon vs gas price linkage are quite complex.  They depend on the relative variable costs of coal vs CCGT units taking into account gas price seasonality, different unit efficiencies and supply stack variances across markets.

This complexity means there is not a simple formula that defines the relationship between carbon and gas prices. It requires detailed modelling of pan-European power markets as we set out here.

But there is a clearly observable correlation between carbon and gas forward prices that is driven by European power market switching boundaries.

The connection to LNG spot prices

The carbon vs TTF price relationship also extends to impact spot LNG pricing. We recently set out the price relationship between the European gas market and Asian LNG spot prices. Spot LNG cargoes in Asia are priced at a spread to TTF.  In other words, the volume of LNG flowing into Asia is primarily driven by the relative level of Asian spot prices above TTF, not the absolute level of Asian spot prices.

Strong Asian LNG demand this year has opened up an Asia/TTF spread that has been ranging above the 1.50 $/mmbtu level required to divert significant volumes of LNG from Europe to Asia. Asian spot prices must rise with TTF to support this spread level, in order to maintain cargo diversions to meet Asian demand.

The fact that Asia is pulling LNG away from Europe strengthens the importance of switching levels in driving TTF pricing. When Asian and European gas prices are converged, LNG imports tend to dampen rising European hub prices.

But in 2018, cargo diversion to service inelastic Asian demand has created somewhat of a vacuum above European hub prices. That has seen the carbon price rise translate more directly into higher TTF prices.

How fuel & carbon prices are driving switching

Posted on by David Duncan

Switching dynamics of gas for coal plant has been a key theme of this blog.  Power sector switching is one of three key mechanisms currently setting marginal prices at European gas hubs. The relative variable cost of gas & coal plants is also a key driver of European power price levels and price shape.

In this week’s article we use three simple charts to explore the evolution of the fuel & carbon components of German coal & CCGT plant variable costs.  We then look at the evolution of the competitiveness of coal vs gas plants.

Rising coal plant costs

Chart 1 shows the evolution of the variable cost of an older German coal plant, split into carbon and fuel cost components. For simplicity variable O&M costs are not shown as they are relatively low (~ 1 €/MWh) and stable over time.

Chart 1: German coal unit fuel & carbon variable cost (40% efficiency)

Source: Timera Energy

European coal prices have doubled since the start of 2016 (52 – 103 $/t).  Most of this move higher happened in 2016 as can be seen in Chart 1.

The big increase in coal plant variable costs this year has been driven by carbon.  EUA prices have risen 250% this year (8 – 20 €/t).

The combined impact of these price moves has been a more than doubling of coal plant variable costs since commodity prices bottomed in 2016. More than half that increase has happened in 2018.  That is why power prices across Continental Europe have also soared this year.

Gas plant costs & switching levels

Chart 2 shows the evolution of fuel & carbon variable cost components for a newer CCGT plant in Germany. The black line overlaid on the chart is the total variable cost of the 40% coal unit from Chart 1.

Chart 2: German CCGT unit fuel & carbon variable cost (52% HHV efficiency)

Source: Timera Energy

There is a stronger seasonal shape to gas plant variable cost, driven by hub price seasonality. This means that CCGTs tend to be more competitive than coal units across the summer months.

As Chart 2 illustrates, there have been periods across the summers in 2016 & 2017 when there has been structural switching of newer CCGT units for older coal plants (shown with arrows). That has not been the case over the current summer.

In 2018, the impact of a sharp move higher in gas hub prices on CCGT variable costs, has outweighed the impact of higher carbon prices on coal plant costs.  We explored the factors driving this move higher in gas prices in a recent article.

In Chart 3 we shift our focus to the future. The chart shows the gas vs coal plant competitive balance implied by current forward prices.

Chart 3: Forward implied variable costs of CCGT (52%) vs coal unit (40%)

Source: Timera Energy

The move higher in gas prices this year has shifted the whole gas curve higher, although pronounced backwardation remains.  Rising gas prices are increasing the relative competitiveness of coal vs gas plants (and causing a move higher in dark spreads).

But it remains to be seen whether this trend will continue. Switching is a naturally reverting process where as CCGTs are pushed out of merit, the associated fall in gas demand tends to weigh on hub prices.  At the same time higher coal burn also feeds through into higher carbon emissions and EUA prices.

That is why, despite periods of temporary divergence, there is a strong relationship between the variable costs of coal and gas units.

UK battery investment 1: business model transition

Posted on by David Duncan

Battery storage broke through the investment viability barrier in the UK’s 2016 capacity auctions.

200MW of batteries were successful in the 2016 Enhanced Frequency Response (EFR) auction. Battery bids were so low that they caused the price for 4 year frequency response contracts to crash below the prevailing shorter term price for Firm Frequency Response (FFR), despite EFR being a faster response service.

A further 500MW of batteries gained capacity agreements in the 2016 T-4 Capacity Auction. This wasn’t just a big story in Europe, but a huge boost to the global deployment of storage as an economic source of flexible capacity.

But UK battery developers have been forced to regroup after this initial surge. The viability of the business model that underpinned 2016 success has been eroded by three factors:

  1. FFR: The sharp reduction in Firm Frequency Response (FFR) market prices as battery penetration has risen.
  2. EB: Policy intervention to reduce the level of embedded benefits (EB) for distribution connected assets.
  3. CM: Steep reductions in the de-rating factors applied to short duration batteries in the UK Capacity Market (CM).

As a result, battery developers and investors are now refocusing on generating margin from price arbitrage in the wholesale market and Balancing Mechanism (BM).

In this week’s article we explore the different business models that battery developers are adopting and look at the economics of storage investment.  In an article to follow we consider the practical challenges of value capture from wholesale price arbitrage.

Battery business models

The success of batteries in 2016 was underpinned by frequency response and capacity market returns.  Substantial reductions in these sources of income have forced developers to evolve their business models.

The current range of battery projects being developed vary widely in both scale and business model. However, business models can be broadly grouped into 4 categories:

  1. Behind the meter
  2. Distribution connected
  3. Transmission connected
  4. Hybrid

We summarise each in Table 1 below.

Table 1: Summary of four battery business models

Business Model Description
Behind the meter Batteries are being deployed behind the meter to optimise onsite load, reduce supplier charges and provide DSR services. Behind the meter deployment presents specific opportunities and challenges. Each site is typically relatively small in scale. Business models typically focus on avoiding supplier levies which requires a thorough understanding of customers load profiles and supply contract terms.

Batteries also often interact with onsite load to create value. The economics of behind the meter energy are ‘use case’ specific and hence business models tend to focus more on client engagement, onboarding and technology allowing control over multiple sites efficiently and effectively.
Distribution connected The advantages of distribution connection of batteries are driven by embedded benefits revenues (e.g. triads, GDUoS). Business models are therefor more closely aligned to those for gas engines, where opportunities for embedded benefits are driven by location and site/connection specific factors. As the opportunities for lower voltage connections are becoming increasingly competitive and as policy changes have eroded embedded benefits, the gap between transmission and distribution connected battery economics has narrowed.
Transmission connected The advantages of transmission connection lie principally in connection costs and scale economics.  Grid connection precludes access to embedded benefits. But there can be cost advantages with grid connection as well as the opportunity to generate TNUoS related revenues from location in the right locations. Scale also typically brings down project costs, particularly in relation to supporting technology and infrastructure.
Hybrid There are also several hybrid approaches being adopted where batteries are deployed in conjunction with other assets e.g. Limejump’s recent Virtual Power Plant. These include siting batteries alongside wind and solar projects, as well as integrating with gas engines and EV charging stations. The benefits of such hybridisation lie in shared infrastructure (e.g. grid connections) and different risk profiles which may tip a borderline investment case into the green.

 

Battery economics & margin stacking

Beyond these four basic business models, lies the question of how a battery investment can capture adequate value across different margin buckets. Solving this margin stacking problem underpins a viable investment case (as it does for gas reciprocating engines).

But the original margin stacking model adopted in 2016 has been transformed by the reductions in FFR, EB & CM margins (described above).

As a result, battery developers are transitioning to merchant business models that focus on capture of market price fluctuations in the prompt wholesale market and BM.  Chart 1 shows a breakdown of margin required to support a merchant battery project.  A merchant gas engine breakdown is shown for comparison.

Chart 1: Battery technology & economics

Source: Timera Energy. CM = Capacity Market. WS/BM = Wholesale/BM. AS = Ancillary Services. EB = Embedded Benefits.

Chart 1 is based on a 1 hour duration lithium-ion battery project. At the moment, the cost advantages of batteries of around 1 hour duration outweigh the revenue benefits of higher volume load shifting from longer duration batteries (e.g. 4-6 hours). This could change in the 2020s depending on the relative pace of decline in storage technology cost curves.  But for now, short duration L-ion batteries are the big player in town.

The ‘all in’ costs for short duration battery projects are in the order of 400 £/kWh (i.e. 400 £/kW for a 1 hour duration battery). That means an average annual real return of about 80 £/kW/yr is required (assuming a mid-life refresh of battery units to boost performance).

Capacity market margins for shorter duration batteries took a big hit from last year’s policy change to reduce derating factors. This means that battery investment returns are now even more focused on wholesale & BM value capture than for gas engines (typically 50+ £/kW/yr of margin required).

This brings us to the two biggest challenges that battery developers are currently facing:

  1. Quantifying a realistic level of wholesale market & BM value capture
  2. Presenting a robust view of asset risk/return profile to investors to raise capital

We come back to explore these value capture considerations in an article to follow shortly.

European gas hub linkage to the LNG market

Posted on by David Duncan

LNG imports account for about 10% of European gas supply (~60 bcm in 2017). Remaining supply is split fairly evenly between domestic production (dominated by Norway, UK and the Netherlands) and pipeline imports (dominated by Russia).

LNG imports may seem a relatively small portion of the supply mix. But they have a disproportionate influence in setting hub prices. This is because of the flexible, price responsive nature of LNG supply into Europe.

These characteristics also mean that European LNG import volumes ebb and flow based on market prices. The benchmark price signal driving LNG flows is the spread between TTF and Asian LNG spot prices. In today’s article we look at the recent evolution of this spread and its impact on European hubs.

Europe vs Asian price spread

The grey line in Chart 1 shows the evolution of the spread between a Singapore LNG spot price marker and the front month Dutch TTF hub price (against the right hand axis).  If you prefer to think of spot prices in North Asian terms then you can add 0.5 $/mmbtu to the Singapore price as a rule of thumb.

The bars in Chart 1 show European LNG reload volumes (against the left hand axis). Reloads have a clear relationship to the price spread, particularly in 2017 & 2018, with volumes typically rising significantly with spreads above 1.50 $/mmbtu. But there are other logistical and contractual factors that can incentivise reloads at lower spreads. For example, in 2016 a number of cargoes reloaded from France related to contractual incentives to on sell volumes to Japan (despite a relatively low prevailing spot price spread).

Chart 1: Asia vs TTF front month price spread & European LNG reload volumes


Source: Timera Energy, ICIS, SGX, Spectron

There has been a pronounced seasonal profile to the Europe vs Asian price spread over the last three years. This has reflected stronger Asian demand for LNG in winter given relatively low volumes of domestic storage (particularly in China).  To attract additional winter volumes, Asian LNG spot prices rise above European hub prices, creating an incentive to re-route or reload European LNG cargoes to Asia.

Until this year, Asian spot prices had tended to re-converge with TTF over the summer months. But 2018 has seen a sharp move higher in summer price spreads given unseasonably strong Asian demand.

LNG demand in Asia was up 12% (y-o-y) in H1 2018. Demand growth was driven by China (+5 mtpa), India (+3 mtpa) and Sth Korea (+3mtpa). This demand growth trend has extended over what has been an unusually hot summer.

In addition to strong Chinese & Indian demand across summer, Japanese LNG demand (subdued in H1) has surged across July & August as heatwaves have seen air-conditioning driven demand depleting gas inventories.

So what does all this mean for European hub prices?

LNG swing one of 3 marginal hub price drivers

European hub prices are currently being set by the interaction between 3 key drivers at the margin:

  1. Power sector switching: As coal and carbon prices have risen in 2018, they are lifting gas for coal plant switching levels. This is increasing gas burn in the power sector and pulling up hub prices.
  2. LNG supply flexibility: Asian vs TTF price spread dynamics (described above) are driving the volume of LNG flowing into European hubs. Higher Asian/TTF spreads across 2018 have seen LNG supply diverted away from Europe, also helping to lift hub prices.
  3. Russian flows: The supply gap resulting from switching (1.) and LNG diversions (2.) is largely being met by Russian imports. This is via a combination of oil-indexed swing contract volumes (increasingly being managed via the TTF price window mechanism that Gazprom has conceded in a number of major supply contracts) and Gazprom’s sale of additional uncontracted volumes at European hubs.

We have explored the pricing dynamics of 1. and 3. in previous articles. Today we focus on 2.

3 price states driving LNG supply flexibility

The behaviour of LNG supply flexibility can be related to Asian/TTF spread ranges in Chart 1. There are broadly three states of this price spread as described in Table 1 below.

Table 1: 3 states driving LNG supply flexibility

State Spread range Flow dynamics
Converged 0.0 – 0.5 $/mmbtu

(grey in Chart 1)

 TTF/Asian spread does not compensate for the incremental variable cost of moving LNG to Asia. As a result flexible LNG supply tends to flow to Europe, putting downward pressure on hub prices. TTF typically act as a floor for spot LNG prices given hub liquidity to absorb surplus cargoes.
Ranging 0.5 – 1.5 $/mmbtu

(blue in Chart 1)

 Spreads in this range signals Asian requirement for incremental LNG supply. Flexible supply is diverted from Europe accordingly in order to balance the LNG market. Cargo reloads typically start to become viable towards the top of this spread range.
Diverged 1.5+ $/mmbtu

(red in Chart 1)

 A spread blow out above ~1.5 $/mmbtu typically signals a temporary constraint in supply flexibility to service Asia. Higher prices are required to incentivise diversion of less flexible cargoes & more expensive reloads.

 

It should be noted that the spread ranges in Table 1 are approximate only. Flow drivers for individual cargoes can be much more complex, depending on factors such as internal portfolio costs, contractual incentives and charter rates.

Spread behaviour and arbitrage dynamics

The structural Asia vs European price divergence that characterised 2011-13 is gone. Arbitrage response from rapidly growing volumes of flexible LNG supply and liquidity ensures that spread divergence is now only a temporary phenomenon.

Think of the Asia vs TTF price spread as a rubber band attached to a heavy but movable object. The spread can temporarily stretch to respond to higher Asian demand. But there are strong market forces acting to alleviate spread divergence (or release tension from the band). Diversion of flexible LNG from Europe puts upward pressure on TTF and downward pressure on the Asian spot price.

Fluctuations in the Asia/TTF spread are set to remain, particularly if Asian demand strength continues. Spread volatility reflects inherent constraints or inertia in the LNG supply chain to respond to market price signals.

The influence of these LNG price moves on European hub prices is set to grow over the next 3 years. This is a natural consequence of a steep rise in flexible LNG supply volumes (particularly from US exports). This makes the Asia/TTF price spread an increasingly important barometer to watch in Europe.

 

European emissions: Germany in focus

Posted on by David Duncan

European carbon emissions have declined 10% over the last decade, mainly driven by a reduction in power plant emissions. Renewables have led policy efforts to decarbonise the European power sector. But renewable deployment has not been the primary factor driving national emissions performance.

Germany has led the renewables investment charge. The renewable share of German generation output has increased from 15% to 33% across the last decade, a huge rise given the scale of capacity roll out required. Yet Germany is one of Europe’s worst performing countries when it comes to emissions reductions, with only a 5% decline (2008-17).

The best performing country from an emissions reduction perspective is the UK, with a 29% drop across the last decade. The UK has had steady (if somewhat wayward) policy support for renewables. But this has not been the primary driver of emissions reductions. The heavy lifting has been done by the UK carbon price floor, which has effectively driven coal out of the generation mix.

Germany’s poor emissions performance is about to make its mark. Domestic and international pressure to address emissions is driving a shift in Germany policy focus. This will have important implications for the German power market and knock-on effects across neighbouring power markets.

European emissions in numbers

Chart 1 shows the emissions performance of a grouping of Europe’s major countries and regions over the last decade.

Chart 1: European carbon emissions % change (2008 vs 2017)

Source: Timera Energy, BP statistical review

Although Turkey sits within European borders, it has characteristics that are more consistent with emerging economies. Turkey’s increase in emissions has been driven by rapid economic growth, fuelled predominantly by coal.

Turkey aside, it is Germany’s poor emissions performance that stands out. This has become the source of much public debate within German borders and abroad.

Germany in focus

Germany is heading towards a big miss of its 2020 emissions target. This is forcing the new German government to confront emissions policy.

A recently published German Climate Projection Report estimates that Germany will only achieve a 32% reduction by 2020 (vs 1990 levels), compared to the 40% target. The Agora Energiewende think tank suggests the reduction could be as low as 30%.

That would represent a humiliating 25% shortfall against Germany’s headline climate change target.

Germany’s emissions problems do not just relate to the power sector. Increasing economic growth & immigration related population growth are causing higher emissions across all sectors. Emissions in the German transport sector have been particularly poor due to the slow roll out of lower emissions vehicles.

However, as we pointed out in our previous article on global emissions performance, it is the power sector that will do the heavy lifting if Germany’s emissions performance is to improve.

German power sector: what has gone wrong?

Germany’s power sector challenge is illustrated in Chart 2.

Chart 2: Gross German power generation by source (2008-17)

Source: Timera, AG Energiebilanzen

Almost 60% of emissions reductions from renewables deployment have been offset by the closure of nuclear power plants across the last decade.

At the same time lignite output has increased as new plants have been built, despite lignite’s very high emissions intensity. Hard coal output was also relatively steady across the last decade, excluding the dip in 2017 which related to coal to gas switching given higher coal prices.

In summary, Germany’s renewable efforts have been undermined by closing nuclear plants and doing nothing to reduce net coal emissions.

It is likely that it is politically ‘too late’ to reverse Germany’s nuclear closure program. That is set to magnify the focus on coal plant closures into next decade.

The resilience of coal to date, reflects the strength of local political support for coal in some parts of Germany.  But the emissions target miss is setting up a showdown between Germany’s emissions agenda and its coal lobby.

The German coal plant policy challenge  

Germany does not face an easy challenge to get its emissions performance back on track. But the quickest solution (short of halting nuclear closures) is to close older hard coal & lignite power plants.

The impact of closures is clearly quantifiable. Germany is also already in the process of defining an implementation plan for coal plant compliance with the Industrial Emissions Directive (IED) requirements. Although this is focused on NOx emissions, it provides a powerful policy lever via which to close coal & lignite.

A new German coal commission was launched in June to develop a plan. The commission is anticipated to revert with a set of recommendations before the COP24 Poland climate summit in Dec 18.

Whether it is via this process or subsequent ones, Germany’s coal & lignite plants risk facing accelerated closures. From an emissions perspective they are the low hanging fruit. But closing coal at the same time as nuclear will be challenging from a security of supply perspective.

Knock-on impact of German coal closures

We finish by setting out 5 key implications of German coal closures for European power markets:

  1. Capacity rebalancing: Closing coal and nuclear plants at the same time across the early 2020s will sharply tighten the German capacity balance. This will drive a rebalancing of NW European capacity, particularly given coal & nuclear closures in other markets.
  2. Energy squeeze: Dual coal & nuke closures creates the risk of a significant wholesale ‘energy’ squeeze in NW Europe in the mid to late 2020s. It will be very difficult for a combination of renewables & storage to keep pace.
  3. Flex deficit: Germany by nature of these closures will become more import dependent for both energy and flex. There is a risk that neighbouring markets will also increase their import dependency at the same time
  4. Price setting: Gas will quickly displace coal as the dominant source of marginal power price setting by the early 2020s. That will act to reduce power price differentials across Europe.
  5. Gas market impact: German thermal closures are supportive of European gas demand, given relatively high volumes of underutilised gas-fired capacity. This is set to have a knock-on impact on demand for gas supply flexibility e.g. from gas storage, pipeline & LNG regas infrastructure.

When Germany sneezes, the European power market catches a cold.

Global emissions: running to stand still

Posted on by David Duncan

Decarbonisation has rapidly become one of the driving forces of energy market evolution across the last decade. It is shaping the energy policy landscape, propelling rapid evolution of new technologies and spurring vast investment in new infrastructure.

Yet at an aggregate global level there has been no decarbonisation. Global carbon emissions have risen 10% (3.1 billion tonnes) over the last decade (2008-17). After stabilising for three years (2014-16), global emissions stepped higher again in 2017 (rising 426 Mt).

The COP21 Paris agreement laid out a broadly adopted plan to address decarbonisation, with a view to containing global warming. The current trajectories of policy and technology do not look close to being consistent with achieving the sub 2 degree target.

The lack of results to date is unlikely to erode the decarbonisation agenda. Instead it increases the probability of accelerated action over the next decade. That action will likely have a magnified impact on the power sector, and in turn shape the evolution of global gas markets.

In today’s article we take a step back to try and better understand the potential impact of decarbonisation. Specifically we look at the evolution of:

  1. Global carbon emissions over last decade (broken down by regions)
  2. Generation fuel transition across the global power sector.

Global emissions in numbers

We start with the emissions evidence. Chart 1 shows the trajectory of aggregate global carbon emissions over the last decade. Chart 2 shows the breakdown of emissions across a grouping of 4 major regions.

Chart 1: Global carbon emissions

Chart 2: Global emissions grouped by region


Source: BP Statistical Review 2018

The 10% increase in global emissions across the last decade does not follow a steady path. There are some interesting drivers that influence this:

  • GDP growth is important, given it is fuelled by rising energy consumption e.g.
    • the 2009 dip is driven by the financial crisis (particularly its impact on Nth America & Europe)
    • synchronised global growth has supported rising emissions in 2016-17.
  • Asia is the primary force driving the shape/growth of the global emissions trajectory. The huge emerging economies of China and India are key (although a significant portion of these emissions relate to manufacturing exports to Europe and North America).
  • Coal usage is also important, particularly since it is the dominant fuel for power generation in emerging economies as well as the key fuel source for new generation capacity (e.g. the 2011-13 growth in Indian & Chinese coal plant capacity).

In contrast to rising emissions from emerging countries, emissions have declined across the more developed European and North American economies.

European carbon emissions have fallen by 10% across the last decade driven by lower levels of economics growth, gradual power sector decarbonisation and some improvements in industrial emissions. North American carbon emissions have fallen 8%, largely the result of the shale revolution driving down gas prices and eroding coal generator load factors.

The problem at a global level is that these modest reductions in Europe and North America are being overrun by much faster emissions growth from emerging economies in Asia (+26%) and ‘Other’ regions (+21%, predominantly Latin America).

Decarbonisation momentum

The COP21 Paris roadmap stops short of being a cohesive policy implementation plan to drive global decarbonisation. The policy response across signatory countries has been somewhat sluggish and disjointed, not helped by Trump’s attempts to stall progress.

Yet COP21 has marked a shift in the balance of global political and business wills in favour of decarbonisation. This transition is being supported by market price signals e.g. declining cost of capital for renewables, rising cost of financing coal and the substantial increase in climate change related insurance premiums.

Companies across the US, Europe and Asia smell huge profit opportunities from growth in decarbonisation driven investments such as renewables, CHP, storage, EVs, SMR nukes, smarter appliances & enabling software. Capital markets do too.

5 conclusions on decarbonisation & power sector evolution

The power sector is at the frontier of global decarbonisation efforts. From a technical and cost perspective, power is easier to decarbonise than heat, transport & industry. The sharp impact of market price signals on generation shares can facilitate rapid adjustments (e.g. US shale, UK coal). Power sector decarbonisation also sets up the electrification of other sectors (specifically transport & heat).

Chart 3 shows an interesting analysis of the evolution of generation shares across the global power sector, using data from BP’s latest Statistical Review.

Chart 3: Global electricity generation by fuel share

Source: BP Statistical Review 2018

Drawing on this chart, we believe there are five key conclusions that can shape a pragmatic approach to decarbonisation over the next decade.

  1. Close coal plants – Coal represents the highest share of global generation (38%). It also has the highest carbon intensity (aside from some forms of oil, already in rapid decline). Yet coal’s share of the global generation mix is unchanged over the past 10 years. Closing coal not nuclear should be the global policy focus.
  2. Retain & replace nuclear – The declining share of nuclear across the last decade is driven by post Fukushima reactor closures in Japan and Europe. This has offset much of the carbon impact of renewables. Yet closures look set to continue across next decade. It is much easier to keep existing baseload low carbon capacity than to try and replace it. Extending reactor lives may also bridge the gap to safer and more scalable Small Modular Reactor (SMR) technology from the 2030s.
  3. Accept gas transition – Fighting gas at the same time as coal (& nuclear) is counterproductive. A meaningful switch from coal to gas generation in emerging economies over the next decade, particularly in China and India, buys time for renewable & new nuclear roll out and broader technology innovation. Local pollution problems may be as big a driver of the switch to gas as decarbonisation. Gas leaves a second phase carbon problem mid-century, but it is not insurmountable.
  4. Engage demand – Huge untapped sources of demand side efficiency and flexibility have the potential to substantially reduce the problem of emissions from electricity supply. Part of this depends on rapidly evolving smarter technologies & software. But the largest constraint is regulatory reform to enable & incentivise greater efficiency & participation (e.g. via developing market structures & price signals). This is key to supporting incremental demand growth from electrification of the transport & heat sectors.
  5. Accelerate renewables – Renewables have risen to 8.4% of the global generation mix in 2017, with an accelerating growth rate. Technologies are improving (including storage as a compliment to intermittent renewables), costs are falling and capital is flooding in. ‘Stand alone’ renewable investment may further accelerate growth in the 2020s. But renewables are not enough to be the primary driving force behind global decarbonisation. As a result, expect a policy shift to focus on 1. 2. 3. & 4. in parallel.

In summary, the decarbonisation engine is relying too much on one cylinder… renewables. Watch out for a transition to other cylinders sharing more of the load across the next decade. This will have an important impact in shaping the evolution of both power and gas markets.

This is our last article before the summer break. We will return in mid-August to look at the evolution of carbon emissions in Europe and the implications for European power markets. In the meantime we wish you a sunny and relaxing summer.

How FSRU’s are impacting LNG market evolution

Posted on by David Duncan

Floating Storage and Regasification Units (FSRU) combine the key elements of an LNG vessel and regas terminal in a single unit. This can significantly reduce the capex costs and lead times for connecting LNG to new markets or access points. It also adds commercial flexibility that is increasing in value as the LNG market evolves.

The emergence of FSRU

The FSRU business started relatively recently in 2001 when El Paso contracted with Excelerate Energy to build the first such vessel for the Gulf Gateway project.   FSRUs are closely related to standard LNG vessels.  But they have additional equipment to regasify the cargo and send it out onto customer or gas networks.

For several years FSRUs remained a relatively niche opportunity.  But more recently there has been a significant pick up in deployment of the technology as costs and capability have been optimised and FSRU units are being used to access new markets.

FSRU fleet size

The global FSRU fleet currently consists of approximately 30 vessels. In addition there is an order book of 6 vessels to be delivered by 2020, with options on another 10.

The first FSRUs were based on nominal 130,000 m3 LNG tankers with send out rates of 2-3 mtpa.  However the more recent vessels are larger – typically 173,000 m3 with send out rates up to 6 mtpa. The FSRUs currently under construction provide the same full processing capability as land based terminals including full boil-off gas management facilities using recondensers.

The three key reasons supporting investment in FSRUs are summarised in Table 1.

Table 1: 3 Key FSRU advantages

Advantage Investment drivers
Lower capital cost
  • The cost of a new FSRU can typically represent only 50-60% of an onshore terminal.
  • An onshore 3 mtpa terminal with one 180,000 m3 storage tank is likely to cost $700-800m, compared to $400-500m for a similar capacity FSRU.
  • However lower capex needs to be set against higher opex of FSRU (depending on charter rates).
  • Opex can be between 0.4-0.7 $/mmbtu dependent on commercial terms & load factor.
Shorter lead time
  • FSRUs can be delivered in half the time of an onshore terminal.
  • Lead time is typically driven by construction of onshore infrastructure (not development of the FSRU unit).
  • A new FSRU unit takes around 2.5-3 years to contract and a conversion of a conventional LNG vessel around 1.5 years.
  • But lead times can be accelerated by utilising/moving existing FSRU units e.g. the second Egypt FSRU was completed in just 5 months.
Greater flexibility
  • FSRU can be used as either a floating regas terminal (with storage), a floating storage unit or as a conventional LNG vessel.
  • This additional optionality can add significant value given the right market conditions.
  • FSRU can provide an early gas option prior to a decision to build a permanent onshore terminal
  • There is also an ability to ‘retire’ (& re-use) FSRU infrastructure at relatively low cost which reduces risk around stranded regas assets (4 have been retired to date)
  • Combined FSRU/power combinations (FSRU tethered to a barge with gas-fired generators) are gaining traction in emerging markets
  • FSRU physical flexibility translates into greater commercial flex for operators (e.g. ability to redeploy).

Source: Timera Energy

In addition to FSRUs there are currently 4 floating storage vessels (FSUs) in operation, one in Malta and 2 in Malaysia. All are converted LNG tankers. There is also a small-scale FSU operating in Bali. A further FSU is currently being constructed for Bahrain LNG.

LNG market impact

The main impact of FSRU technology on LNG market evolution is to provide quicker and more flexible access to new sources of demand.

Markets that currently rely on FSRUs to import LNG include Colombia, Pakistan and Egypt. Bangladesh (4 mtpa) and Bahrain (6 mtpa) are currently developing facilities due online in 2018-19.

Potential future locations are focused on emerging markets or locations more isolated from other gas infrastructure.  These include Hawaii, Caribbean, additional Indonesian & Malaysian archipelago markets, Sth Africa, Kenya, Vietnam, Phillipines, Croatia, Myanmar and developing African coastal states.

FSRUs are also supporting the evolution of commercial flexibility in the LNG market.  Commodity traders are targeting FSRU projects because of their flexibility and optionality.  Trafigura and Gunvor are developing projects in Pakistan and Bangladesh.  Vitol is looking to partner with Total to do a further Pakistani project.

This interest reflects the capability of FSRUs to be a significant source of growth in supply chain flexibility.

Timera is recruiting power analysts
We are looking for a Senior Power Analyst and a Power Analyst with strong industry experience. Very competitive & flexible packages. Further details at Working with Timera.

 

Renewables can plug the French capacity gap

Posted on by David Duncan

We recently considered Belgium’s challenges in replacing thermal capacity with renewables.  The conclusion: the viability of this approach is risky at best, particularly given current Belgian policy mechanisms.

Today we shift our focus to the much larger French power market. In contrast to Belgium, France is in a strong position to replace retiring thermal capacity with renewables.  Existing flexibility and high volumes of interconnection support the viability of this solution.

But there is one big caveat: this approach relies on France maintaining a relatively steady nuclear share.

In this article we consider the role of French nuclear, the mechanics of the power market and how France’s capacity mix is likely to evolve over the next decade.

France is heavily invested in nuclear energy

The dominance of nuclear power in the French capacity mix is unique.  France ramped up a vast state nuclear investment program after the 70’s oil shocks, building more than 60GW of capacity between 1977 and 2000.  This was specifically aimed at ensuring competitive and reliable energy and insulating the French economy from a dependence on imported fuels.

French politicians have recently flirted with the idea of reducing nuclear dependence. One of President Macron’s 2017 campaign pledges was to reduce nuclear’s share to 50% of generation output by 2025 (from more than 75% today).  But it took his government just 5 months to release the implications of such a promise for emissions, security of supply and electricity prices, before beating a rapid retreat.

French nuclear closure aspirations have not disappeared.  But targets are likely to remain loose and beyond an actionable policy horizon.  In other words, the policy importance of emissions reduction, security of supply and industrial competitiveness trumps nuclear closures.

The potential threat to this logic is a systemic safety issue with the nuclear fleet.  For example, safety issues resulting in temporary reactor closures in 2016-17 related to components manufactured in the same forge.

While nuclear safety is an unpredictable factor, the French state (85% owner of EDF and 90% owner of Areva) is heavily invested in preserving a nuclear future. In the analysis we set out below we work on the basis that a steady nuclear share can be maintained.  The alternative would almost certainly involve large scale deployment of new gas-fired capacity.

The French power market in a nutshell

At a simple level the France’s capacity mix can be cut into three slices that shape market operation:

  1. Nuclear: low variable cost, baseload and the cornerstone of production, typically accounting for 75-80% of generation output.
  2. Renewables: dominated by hydro (including substantial reservoir storage flex), with relatively low but growing volumes of intermittent wind and solar output.
  3. Thermal flex: dominated by a fleet of CCGTs and gas & oil peaking plant which typically run at relatively low load factors but are important for security of supply.

Chart 1 shows a de-rated view of the current French capacity mix as well as an illustrative scenario for its evolution to 2030.

Chart 1: French capacity mix scenario (derated capacity)

Source: Timera Energy

The key mechanics of the current operation of the French power market are as follows:

  • A significant surplus of generation capacity (~125GW) over peak demand (88GW).
  • Strong structural export flows (40-60TWh a year) across IT, CH, UK, DE, BE & ES.
  • A dominance of nuclear & hydro generation resulting in:
    • low system carbon emissions
    • large volumes of low variable cost output.
  • Marginal price setting dominated by thermal capacity and cross border flows:
    • gas typically drives price setting in winter/peaks
    • German coal driven border pricing has a stronger influence in summer/offpeaks.
  • Flexibility from reservoir hydro, CCGTs, peakers and cross border capacity facilitates system balancing.
  • Flexibility requirements are currently driven more by load swings (given high penetration of electric space heating) than by renewable intermittency.

Over the next decade, the evolution of the French market is likely to be driven by decline in the thermal tranche of the capacity mix, offset by steady growth in the renewables tranche.  In other words replacement of coal, oil and gas capacity with wind, solar and storage. This is not only already in motion, it also appears to be the path of least political resistance.

France’s capacity replacement challenge

As with all European power markets, France’s thermal power fleet is ageing. Coal plant closure has been accelerated under Macron with a complete coal exit (~3GW) targeted now for 2021. Emissions regulations will see oil-fired peaking capacity (~1GW) exiting in a similar time frame.

The retirement profile of gas-fired plants is less certain. 2017 implementation of a capacity market (clearing prices around 10 €/kW) is supportive of plant economics.  But CCGTs typically face major life extension capex around 25 years of age and there is not currently a clear price signal to facilitate this. It is reasonable to assume that France could lose 3-5 GW of gas capacity over the next decade.

Chart 2 sets out an illustrative scenario for replacement of this retiring capacity.  In contrast to Chart 1, capacity volumes are shown in nominal rather than derated terms (to allow a cleaner view of renewable roll out).

Chart 2: Cumulative French capacity replacement scenario (nominal capacity)

Source: Timera Energy

Development of new nuclear plants is back to the drawing board after the problems with the Flamanville plant (which EDF hope will be commissioned by early 2019). But we think it is reasonable to assume the modest ramp up of a ‘new wave’ of reactors from the later 2020s, allowing the older current generation of plants to retire.  If we are wrong on timing here then we expect life extensions to be managed in a way that prevents any major discontinuity in nuclear output. On a net basis we assume a gradual decline in nuclear capacity (i.e. retirements outweigh new build).

This sets up a key role for roll out of renewable capacity. In our illustrative scenario we assume by 2030 the addition of 18GW of onshore wind, 4GW offshore wind and 30GW of solar.  Under Macron, policies are falling into place to support this roll out (e.g. wind & solar capacity auctions). French energy giants EDF and Total have also both announced aggressive targets for solar capacity deployment.

That leaves the flexibility problem.  Incremental gas capacity is likely to be required through the 2020s, but in relatively low volumes (3-5GW) and with a shifting focus towards distribution connected engines.  Storage is likely to play a key role, skewed towards the later 2020s (we assume 5GW by 2030).

France also has strong potential to more efficiently manage its demand side (e.g. via smarter appliances & space heating management) to reduce peak load requirements over time.  But despite this, peak/off-peak price shape is set to increase over time. This is a function of wind and solar output pulling down offpeak prices while high variable cost peaking capacity (engines, batteries & DSR) supports peak prices.

The ultimate security of supply backstop for France is its high volume of cross border capacity (~20GW by 2020). But this may turn out to be a dangerous insurance policy (as Winter 2016-17 illustrated). France’s largest neighbour, Germany, is banking heavily on imported flexibility and there may not be enough to go round in times of system stress.  In an article to follow we will look at the much more challenging problems facing the German power market in replacing thermal capacity.

Timera is recruiting power analysts
We are looking for a Senior Power Analyst and a Power Analyst with strong industry experience. Very competitive & flexible packages. Further details at Working with Timera.