Asian LNG demand stalls in H1 2019

Posted on August 26, 2019January 15, 2020 by David Duncan

For several years we have framed the evolution of the LNG market supply & demand balance around one key driver: Asian demand growth. The ability of the market to absorb more than 100 mtpa of committed new supply across 2015-21 depends on Asia. But Asian demand growth has stalled in 2019.

2019 and 2020 are the peak delivery years for the current wave of new liquefaction projects. Global LNG supply has risen by around 12% in H1 2019 (vs H1 2018). But Asian demand growth has ground to a halt (down 0.2% H1 2019 vs 2018). The Latin America & MENA regions are not helping either, with demand contracting by 21% across the same period (after strong 2018 growth).

That leaves Europe having to absorb the full brunt of incremental LNG supply volumes. This is why LNG imports into Europe have surged this year, with hub prices have been pushed down towards Henry Hub support levels.

What happened to Asian demand growth?

Chart 1 shows the evolution of Asian, Latin American and MENA LNG demand since 2016.

Chart 1: Non-European LNG demand

Source: Timera Energy

Across 2016 and 2017, Asia looked to be on a high demand growth trajectory, led by China. Asian demand was absorbing new liquefaction output as well as pulling flexible LNG supply from Europe (particularly across winter).

Chart 1 shows the steady progression of growth in demand from Winter 15/16 to Winter 17/18. But demand growth weakened into Winter 18/19 and has continued to stall in 2019. It is no coincidence that this has happened at the same time as a sharp decline in Asian and European gas prices since Sep 2018.

Table 1 shows the breakdown of demand in H1 2018 vs H1 2019 as well as % changes.

Table 1: Demand breakdown H1 2018 vs 2019

Source: Timera Energy

Four of the big 5 buyers (Japan, Korea, Taiwan and India) had negative growth (H1 19 vs 18). Chinese demand grew at 21%, but this is only around half the demand growth rate China was experiencing in 2016-17. 50% demand growth in the smaller emerging Asian markets is impressive, but is coming off a low base and is relatively low in absolute volume terms.

One of our 5 surprises for 2019 was a drop in global gas demand growth due to weakening economic conditions. That is what is playing out in Asia, exacerbated by tariffs in a growing ‘tit for tat’ trade war that materially escalated last week.

LNG driving the European price snowplough on

LNG that is surplus to Asian, Latam & MENA requirements, is absorbed by Europe’s liquid & price responsive gas hubs. As we set out in July, the growing surplus of LNG flowing into Europe in 2019 is having a ‘snowplough’ effect on the TTF forward curve as shown in Chart 2.

Chart 2: The snowplough continues to roll towards winter

Source: Timera Energy

The very steep front section of the TTF curve reflects market consensus that the current acute oversupply will normalise as demand picks up into this winter. Recovery is being helped by some output curtailment in late summer e.g. Cheniere’s maintenance outages at Sabine Pass and Corpus Christi.

But as evidence of soft demand & weakening economic conditions has continued to emerge across this year, Winter 2019/20 prices have also been declining. Negative Q2 economic growth in Germany and the UK and looming recession fears across Europe are not helping.

Weak prices now… sharper 2020s recovery?

The cyclical nature of the LNG market is underpinned by 5 year lead times for new liquefaction projects. Final Investment Decisions (FIDs) on LNG projects coming to market now were taken in the first half of this decade in a relatively tight post-Fukushima market. But only a small volume of new FIDs were taken across 2015-2017. Even 2018 FID volumes were relatively low, dominated by the large Shell Canada project.

2019 is shaping up to be a higher volume year for FIDs, with Exxon’s Golden Pass and Andarko’s Mozambique projects already approved. But current market conditions may cause some investors to hesitate or delay on 8-10 other LNG projects that are targeting FID over the next two years. A recovery of European and Asian gas prices this winter will be an important factor here.

Asian LNG demand growth may have stalled in H1 2019, but this is a temporary phenomenon. Supply growth is set to remain strong through 2020 and into 2021, so sluggish demand over this period may see a continuation of weak price conditions.

But beyond 2021, the impact of the liquefaction investment hiatus from 2015-17 kicks in. In other words committed new supply growth is likely to fall behind global demand growth on a run rate basis. It is this period from 2022-24 that could see a tight market if FIDs are delayed over the next year or two.trend.

3 new members join our growing Timera team
Jon Brown joins us from EDF, Steven Coppack from Total & Tommy Rowland from Smartest Energy. As with all of our team members, they have a strong practical background in commercial analytics from their industry roles. More details on Steven, Jon & Tommy on Our Team page.

Evolution of UK balancing flexibility

Posted on August 20, 2019January 15, 2020 by David Duncan

Billions of pounds are being invested in flexible peaking capacity in the UK, as the coal fleet closes and older gas plants retire. The two dominant technologies being deployed are gas reciprocating engines and shorter duration lithium-ion batteries.

Only a small volume of this new peaking capacity currently operates in the UK’s Balancing Mechanism (BM). But the BM is set to become the primary driver of value for both engines & batteries across the 2020s.

In today’s article we look at what types of capacity are currently competing in the BM to provide flexibility services. We also look at how this is likely to evolve given capacity mix changes across the next 5 years.

Why will the BM be so important?

Margin capture for UK engines and batteries is currently focused on:

‘NIV chasing’: forecasting cashout prices & trying to run imbalances to capture margin accordingly (see here for article on battery challenges in chasing cashout prices)
Triads: running in periods of peak demand to help reduce supplier charges
Ancillaries: providing services such as STOR, frequency response (e.g. FFR) and fast reserve

Step forward five years and it is likely that BM value capture will dominate all of these sources of margin capture for most peaking assets. But why such a rapid margin transition?

Market participants increasingly recognise that NIV chasing is a dying game. Average system imbalance volumes in the UK are typically only several hundred MWs. Yet there will soon be GWs of flexible capacity chasing relatively small imbalances. That will increase forecasting errors & risk and reduce returns. The practice of intentionally running large imbalance volumes into gate closure is also likely to attract the attention of regulators, who may implement rule changes to disincentivise this.

Margin from triads and ancillaries is also declining. Triad revenue will largely disappear by 2021 as a result of policy changes already announced. And increasing competition to provide frequency response, STOR and fast reserve services has been driving down returns for these balancing services.

The combination of these factors means the future for flexible peaking capacity is likely to be focused on capturing value in the BM and prompt forward markets (e.g. Day-Ahead and Within-Day markets).

Balancing Mechanism 101

The BM is the mechanism that the system operator (National Grid) uses to balance the UK electricity market in real time. Market participants that are registered as ‘BM Units’ can submit bids and offers in the BM, reflecting prices at which they would be prepared to flex down or flex up respectively.

National Grid then uses a combination of these bids & offers as well as other balancing services contracts to ensure the system balances in real time. This task is becoming more challenging over time as wind & solar intermittency increases. But that is also creating increasing opportunities for flexible assets to capture margin in the BM.

An important distinction between the BM and the wholesale market is that all participants are ‘paid as bid’ not paid the price of the marginal provider of energy. This in combination with volatile prices, means that there can be some very lucrative opportunities in the BM, during periods of system constraint.

The flip side of very volatile prices is a relatively high level of volume risk. Capacity owners do not know when they place bids & offers whether they will be accepted or not. Therefore value capture in the BM often has a significant opportunity cost linked to foregone margin from the wholesale market.

What capacity provides BM flex & how will this change?

Flexibility requirements in the BM can be summarised as:

Flex up: the ability to provide more energy to the system (or reduce demand)
Flex down: the ability to reduce output onto the system (or increase demand).

Chart 1 provides an illustrative scenario of the evolution of the percentage of different technology sources providing Flex up volumes across 2020-25.

Chart 1: Provision of flex up volume in the BM

Source: Timera Energy

Flex up is currently dominated by CCGTs. Increased output can either come from ‘spinning’ units that can achieve an incremental top tranche of output (e.g. CHP), or by starting an idle unit. Coal units have also historically been active in providing flex, but weak dark spreads and high start costs are undermining their ability to compete with CCGTs. Hydro and pump storage also provide some flex.

Looking forward over the next 5 years there are likely to be some substantial changes. Coal will disappear and older CCGTs close. At the same time, the volume of flex provision from both gas engines and batteries is likely to rapidly increase. Engines have very low start costs and high ramp rates. Batteries are almost instantaneous in their ability to flex output.

Chart 2 provides an illustrative scenario of the evolution of the percentage of different technology sources providing Flex down volumes.

Chart 2: Provision of flex down volume in the BM

Source: Timera Energy

CCGTs again dominate provision of flex down currently. This is typically provided by spinning units reducing output to minimum stable generation levels (incurring an efficiency loss) or switching off altogether.

Wind curtailment is also playing a growing role. The reason for this is that high wind output (particularly in northern regions) is increasingly causing Grid to take balancing actions to alleviate transmission constraints (to flow power south). The least cost way to resolve these constraints can be to curtail associated wind output.

The volume of flex down services provided by gas engines and batteries will be impacted by the role of wind curtailment. But there are also other considerations e.g. flex down is more difficult for engines to provide than flex up, because of the relatively low load factors at which units run.

Peaking unit transition to the BM

Transitioning to focus on BM value capture adds complexity to the peaking asset business model. Portfolio scale and a strong commercial & analytical capability are important ingredients of developing a competitive presence in the BM. Without these, individual assets will likely only earn a fraction of the ‘theoretical’ modelled value available in the BM.

Peaking asset owners can try and sidestep scale & capability overheads by outsourcing flex management to a third party (e.g. Centrica, Orsted). But the contract haircuts for BM value capture are typically high.

BM value capture is a different game to triads and ancillaries margin, where flex asset owners could negotiate with third party providers to capture the lion’s share of available margin. The balance of power sits firmly with the service provider for BM value capture. This is because it is significantly higher risk and higher return, with the ability to generate value underpinned by a robust trading & analytical platform.

We have written previously about a more challenging margin capture environment driving further aggregation & consolidation of UK peaking assets. Business model transition to focus on BM margin capture is set to reinforce this trend.

Will European gas prices recover or ‘snowplough’?

Posted on July 15, 2019January 15, 2020 by David Duncan

Time for a simple thought experiment. If you had a ‘one shot’ chance to gaze into a crystal ball and see the evolution of one energy market driver over the next two years, what would you choose?

European gas pricing dynamics would be at the top of our list.

Despite rapidly declining hub prices in 2019, a nascent recovery in the value of gas supply flexibility is taking place, as seasonal price spreads and spot price volatility recover. But hub price evolution is not just important from the perspective of the European gas market.

European gas pricing has an extended influence across other markets and value chains. For example:

Global LNG supply: LNG pricing in a well-supplied market is currently being driven by TTF. So European gas price levels will have a strong influence on FID decisions for new supply projects shaping the next wave of LNG supply into the mid 2020s.
Coal plants: Low hub prices in 2019 have driven coal plant cashflows deep into the red across Europe. If this environment continues into 2020-21, it may cause the accelerated economic driven closure of large volumes of European coal plant capacity.
Renewable investment: Merchant renewable investment is in the early stages of evolution in Europe (e.g. solar projects in Spain). Cost declines are one factor, but power price levels have become a much more important revenue driver. Gas hub price levels are now the primary driver of power prices across Europe and will be an important factor determining how fast merchant renewable investment gathers pace.

Alas we have no crystal ball. So instead, in today’s article we consider 5 key drivers likely to shape the evolution of European gas pricing dynamics.

The recovery versus ‘snowplough’ question

Some unusual and interesting price dynamics have been evident in the European gas market in 2019. Spot hub prices have been in a relentless decline across the first half of 2019. This sits in stark contrast to the steep rise in prices across the first part of 2018, as can be seen in Chart 1.

Chart 1: Global gas price benchmarks

Source: Timera Energy

The primary factor explaining the difference between the path of hub prices into summer 2018 vs summer 2019 is the LNG market. 2018 saw flexible LNG diverted from Europe to meet robust Asian LNG demand. In 2019 a pronounced temporary oversupply in the global LNG market has seen surplus cargoes flooding into Europe.

If you consider the TTF forward curve to be the closest thing we have to a crystal ball, curve shape is consistent with a sharp recovery of prices into the coming winter. But as 2019 has progressed, the front of the forward curve has steadily been pushed lower (at least until the beginning of July which we will come to in a minute). Think of a snowplough steadily cutting into a bank of snow.

Summer 2019 prices started the year above 16 €/MWh. By the beginning of Jul-19 prices had fallen almost 40% to 10 €/MWh as shown in Chart 2.

Chart 2: Snowplough effect at the front of TTF curve

Source: Timera Energy

As Sum-19 prices have fallen at the front of the curve, an ever steeper spread has opened up to Win-19. The market has been pricing in an acute but temporary oversupply of gas across the current summer.

This is the result of surplus LNG flowing into Europe, unusually low storage injection demand and falling coal prices (dragging down power sector switching levels). As Q2 progressed, Winter-19 prices also started to show some signs of weakness (see Jul-19 vs Mar-19 curves in Chart 1).

Then last week saw a sharp rebound in European hub prices, with front month TTF now rising more than 25% since the start of July. This move has caught a very bearish market off guard. Prices of other commodities have also moved sharply higher as global central banks have reaffirmed efforts to try and stimulate growth and inflation.

Price moves like this are driving TTF spot price volatility higher in 2019. But is the ‘July jump’ in prices just noise or the start of an enduring recovery into winter and beyond?

We look next at the five factors we think will determine whether European hub prices recover (as suggested by the forward curve) or continue to ‘snowplough’ (as in Chart 2)?

5 key drivers to watch

LNG demand growth

The strong pick up in surplus LNG flowing to Europe since Q4-18 (shown in Chart 3) is a function of new LNG market supply temporarily outstripping demand growth. Chinese demand continues to grow, although forward contracting has meant Chinese buyers have been less active purchasing spot cargoes. But LNG demand from the rest of the ‘Big 5 Buyers’ club (Japan, Korea, Taiwan & India) is significantly lower in 2019 than 2018. Demand is also down from Latin American and Middle Eastern buyers.

Chart 3: European LNG sendout & the TTF vs Asian spot price spread

Source: Timera Energy

We raised a red flag recently on the potential impact of global economic conditions on gas demand. The trade war appears to be having a particularly strong impact in weakening manufacturing and industrial output. The evolution of LNG demand over the next 1-2 years will be a key factor determining how much surplus LNG will flow into European hubs.

Ramp up rate of new LNG supply

The other side of the LNG market equation is supply. The highest volumes of new liquefaction capacity from the current supply wave are scheduled to come online across 2019 and 2020. But evidence over the last three years has shown that there is significant uncertainty around project delays and ramp up rates.

A number of other projects commissioned across 2015-19 have experienced up to 12 month delays in reaching full output. There have also been unexpected outages. Seasonal production volume dynamics, where output is significantly higher across the colder northern winters, add to supply side volume fluctuations.

European power sector switching levels

The main mechanism for the European gas market to absorb incremental LNG flows is coal for gas plant switching in the power sector. This means that European hub prices are influenced by coal and carbon prices.

One of the factors causing downwards pressure on TTF in 2019 has been falling coal prices (carbon prices have remained relatively strong). This has been pulling down the switching range (that we track in Chart 1) across Q2 2019, which in turn weighs on gas hub prices.

The switching range acts as an anchoring point for European hub prices. Spot prices may temporarily deviate from this range, but the TTF forward curve is strongly linked to switching levels. Keep a close eye on the evolution of coal and carbon prices to understand how this switching range evolves.

European gas demand

European economic growth has slowed sharply in 2019. Manufacturing and industrial output are particularly weak, with Germany leading the decline. The probability of a recession in 2019 or 2020 has risen significantly.

It is unclear:

how much economic weakness will impact gas demand in Europe and
how much of this impact is priced into the TTF market forward curve (recognising growing bearish sentiment across H1 2019).

It is worth keeping an eye on the evolution of European economic growth and gas demand data.

European pipeline supply

Russian flow volumes to Europe hit a new all time high in May 2019, following on from April’s record LNG import volume. Norwegian import volumes have been strong. There has even been a slight recovery in North African imports.

Will pipeline imports remain this strong into winter? Gazprom has not shown any signs of flow sensitivity to low prices yet in 2019. There is however a heavy maintenance schedule on the NCS across the next two months which will temporarily impact Norwegian flows. Market expectations are for strong flow volumes to continue, but any deviation from this (e.g. Russian pull back or major outages) could have significant price implications.

Implications for value of European gas supply flex

After a tough five years, midstream gas asset value is coming back into focus in 2019. Regas terminal utilisation levels have jumped and pipeline flows have been strong. But the most interesting asset class is gas storage.

Seasonal price spreads in 2019 have surged higher, as the front of the TTF forward curve has declined. More importantly for storage asset value, spreads are recovering further out on the forward curve also. Sum 20 to Win 20 TTF spreads have risen above 2.20 €/MWh, with NBP spreads stabilising above 10 p/th.

TTF and NBP spot price volatility have also been steadily rising across 2019, with the ‘July jump’ in prices adding fuel. Conditions of higher volatility and spreads are typically associated with periods of market tightness and rising prices. It is an encouraging sign for storage capacity value that price signals are recovering despite the well supplied, low price environment.

We will be taking our usual summer break from feature articles until mid August. In the meantime we will continue to publish material via our Snapshot and Angle columns on the Blog Home page.

FX movements driving energy prices

Posted on July 8, 2019January 15, 2020 by David Duncan

Global trade & geo-political tensions have been steadily rising this year. For example the US-China trade war (& broader power struggle behind this), US-Iran tensions and Brexit. In parallel, the monetary policy measures of central banks are becoming increasingly unconventional and aggressive (e.g. negative interest rates & structural quantitative easing).

These dynamics are likely to play out in the form of rising currency volatility or even larger scale currency shocks. In this environment it is a good time to consider the impact of FX movements on energy prices.

The EUR-USD relationship is key

The primary driver of currency movements impacting European energy markets is the EUR-USD FX market. This is the world’s most liquid market with in excess of 1 trillion USD daily transaction flow.

Global commodity markets such as oil and coal are traded in USD terms. So if the EUR falls against the USD, commodity costs rise in EUR terms. This has a direct impact on assets exposed to oil, liquids & coal prices. Chart 1 provides some context on the evolution of the EUR-USD exchange rate.

Chart 1: EUR-USD price chart over last 5 years

Source: barchart.com

Interest rate, inflation & economic growth differentials between the US & Europe play an important role in driving EUR-USD levels. The EUR has fallen against the USD since the start of 2018, as interest rates & growth in Europe have been lower than in the US. But the EUR has stabilised in 2019 as US growth has slowed and financial markets have priced in US rate cuts across H2 2019 (Eurozone rates are already negative).

European gas prices & FX movements

The impact of FX movements on European gas prices is more complicated. European gas prices are driven by the TTF hub and essentially priced in EUR terms based on the prevailing supply & demand balance across Europe’s interconnected hub network.

While European gas is priced in EUR terms, coal to gas switching levels are an important marginal driver of hub prices. This creates an implicit USD linkage via the variable cost of coal plants. If the EUR rises against the USD, it reduces the variable cost of coal plants, putting downward pressure on relative switching levels and TTF.

LNG spot prices & FX movements

The impact of currency movements on LNG prices is also more dynamic. LNG is traded in USD terms. But European gas hub prices underpin LNG spot pricing dynamics. So even though cargos change hands in USD, it is TTF (a EUR based market) that is the global spot price benchmark.

If for example the EUR appreciates against the USD, the TTF price level typically rises in USD terms (as can be seen via TTF futures contracts transacted in USD/mmbtu). That in turn can pull up Asian spot price levels which are typically traded on a ‘variable cost plus’ basis to TTF.

There is also a further currency driver that is important to consider given current oversupplied conditions in the LNG market. TTF prices have been driven down towards US Henry Hub ‘shut in’ levels by surplus volumes of LNG flowing into Europe. So TTF is currently effectively trading on a ‘variable cost plus’ basis to Henry Hub.

The current role of Henry Hub as a global spot price floor therefore introduces a USD price linkage to both European hubs and Asian LNG spot prices.

Value drivers for Spanish CCGTs

Posted on July 1, 2019January 15, 2020 by David Duncan

Foreign investor interest in the Spanish power market has ebbed and flowed since deregulation. Over this period, Spain has benefited from substantial foreign ownership and investment in energy assets. But investment conditions over the last 5 years have been tough.

Spain was one of Europe’s leaders in renewables deployment at the start of this decade. But the previous conservative government slashed policy support in 2013 given cost blow outs, with cuts applied on a retroactive basis. Investor’s backed off accordingly with renewable investment grinding to a halt.

A significant overhang of thermal capacity also emerged across the first half of this decade. This was the result of robust investment in new generation last decade, just in time for the financial crisis to erode power demand.

But there are early signs of a shift in the winds. A new minority government is stepping back behind renewable investment (reinforced by a pickup in PPA deals) and is accelerating coal closure timelines. Generation portfolio owners are also mulling over the sale, mothballing or closure of gas & coal fired assets in what could precipitate a major market shake-up.

Action is likely to be centred around Spain’s 26GW CCGT fleet. In today’s article we look at key value drivers for Spanish CCGTs.

Spanish market 101

A 40,000 foot perspective of the current Spanish supply & demand balance is useful background to understand asset value drivers.

Spanish power demand peaked in 2008 and then declined with economic growth after the financial crisis. Demand has however steadily recovered since 2015, in line with economic growth. Demand peaks in the winter, although summer peak demand levels are approaching the winter peak as air-conditioning load increases. Demand is likely to rise in the 2020s due to a combination of the electrification of transport and space heating/cooling.

The Spanish capacity and generation output mixes are summarised by technology type in Chart 1.

Chart 1: Spanish generation capacity (GW) & production output (TWh)

Source: Timera Energy, Red Electrica

The bottom half of the Spanish supply stack is dominated by low variable cost capacity. Nuclear and wind account for around 20% of annual generation output each. In addition there is another 5% of solar output (set to expand as investment picks up again) and 3-5% of net imports (cheaper power from France & Portugal). Coal and gas-fired plants then provide the flexibility required to balance the market.

Spain has substantial swings in hydro output dependent on rainfall & storage levels as shown in Table 1.

Table 1: Historical hydro output versus system demand

Source: Red Electrica

In a dry year (e.g. 2016), Spanish hydro accounts for around 6% of demand. In a wet year that can rise above 15%. The right hand column gives an indication of the probability of exceeding the level of hydro output in each year (low % if a wet year, high % if a dry year). Swings in hydro output are an important driver of gas and coal plant load factors (which rise in dry years).

The other important dynamic that impacts thermal asset load factors is relative commodity price levels. The overhang of capacity and falling demand, pushed CCGTs into a peaking flex provision role by the middle of this decade. But CCGT load factors have started to rise again across 2018-19, as falling gas prices and rising carbon costs erode coal plant competitiveness.

CCGTs have also benefited from a Q4 2018 cut to the ‘green cent’ tax on gas consumption, reducing variable costs (by ~4 €/MWh).

These shifts in competitive balance are reinforcing the importance of gas in setting marginal power prices in Spain.

Key issues impacting CCGT value

From a CCGT owner’s perspective, the list of concerns about value evolution can be grouped into 3 buckets.

1.Capacity payments

As load factors have declined, CCGTs have been ‘kept alive’ via two forms of capacity payment:

Availability payment (~5 €/kW)
Investment subsidy (~10 €/kW)

But this life support is being pulled. The availability payment was suspended last year given government concerns around EU state aid review. Around 70% of Spanish CCGTs will lose the investment subsidy by 2021.

There is a strong lobby voice from CCGT owners against capacity payment removal, with legal challenges underway on subsidy suspension. Some revised form of capacity payment support is likely going forward, but the risk around the timing & level of this is borne by asset owners.

2.Capacity mix evolution

Changes in the Spanish capacity mix will be key to alleviating the current overhang of capacity that is undermining CCGT margins. The ability of the new government to revive renewable investment, will be an important factor across the 2020s. But there are some more immediate factors in play.

Half of the Spanish coal fleet (5GW) will close by Jun 2020 driven by EU emissions legislation, removal of coal subsidies and the closure of domestic coal mines. The new government is now aiming to close the remaining 5GW of coal capacity by 2025. Adverse market conditions (low gas & high CO2 prices) could accelerate this.

Plant owners have also faced regulatory constraints around closing or mothballing CCGTs, exacerbating excess system capacity. But these are likely to be eased as capacity payments are removed. This should see older and less flexible CCGTs coming offline e.g. Naturgy (the rebranded Gas Natural Fenosa) is currently seeking approval to mothball 2GW.

Significant closures of Spanish nuclear plants are likely to start in the second half of next decade.

3.Load factors & wholesale margins

The average load factor across the Spanish CCGT fleet is currently around 20%. Behind the average utilisation of individual assets can vary significantly based on efficiency, flexibility and location. But it is difficult for owners to cover fixed costs with such low load factors.

Closures and mothballing of coal and gas capacity over the next two years will be a key driver of a more structural recovery in load factors. Commodity price evolution will also be important.

But in the meantime, Spain faces a conundrum The market needs CCGT flexibility across the 2020s, firstly to backup increasing wind & solar intermittency and secondly to offset swings in hydro output. This is the case even under the most optimistic scenarios of future battery deployment. Yet under current market arrangements it is not clear how CCGTs will earn an adequate margin to remain open.

That is the essence of the challenge facing both CCGT owners and policy makers.

Building a Spanish CCGT investment case?

The suspension of capacity payments may mark the point of capitulation for many CCGT owners, after 5+ years of poor margins. Naturgy’s decision to pull 2GW of capacity offline is likely to be followed by other asset sales, mothballing or closure decisions.

CCGT ownership in Spain is dominated by utilities with transitioning business models. Boardroom focus is shifting away from conventional thermal generation portfolios towards renewables and energy services. This smooths the way for sale of thermal assets, along with the fact that asset values have already been written down.

The investment case for prospective asset buyers is focused on acquiring cheap options. CCGT capacity assets may transact at less than 50 €/kW (vs new build costs of 500 €/kW+). While that may seem like cheap capacity in a market that has a structural requirement for CCGT flex into the 2030s, some of the 26GW of assets are worthless (i.e. margins don’t cover fixed costs).

The challenge is paying a ‘premium’ for CCGT assets that fairly reflects the value of asset optionality (or flexibility). This premium does not just include the acquisition cost. It also involves paying annual plant fixed costs (~20 €/kW). Defining adequate risk adjusted margins above fixed costs is not a simple exercise.

Building a robust investment case comes down to:

Identifying unique asset benefits (e.g. ramping flex, lower variable & start costs, locational benefits, additional margin streams)
Minimising fixed costs i.e. ‘cost of carry’ of asset optionality (e.g. via renegotiating maintenance contracts & cutting overheads)
Understanding the evolution of the Spanish capacity mix (& associated uncertainty) and the impact of this on pricing and CCGT margin dynamics
Ability to quantify the value distribution of CCGT optionality i.e. flexibility to respond to price fluctuations (via probabilistic dispatch optimisation modelling)
Understanding Spanish regulatory risk and developing an associated management / diversification strategy.

An environment of distressed asset owners and capitulation creates opportunities. But in a nutshell, it comes down to the combination of getting the right assets at the right price. That combination is starting to look more achievable given a growing queue of owners looking to exit.

Resurgence in UK gas storage value

Posted on June 24, 2019January 15, 2020 by David Duncan

Investment in gas storage, like most energy asset classes, has strong cyclical dynamics. Storage cycles are reinforced by relatively long project construction lead times. It can take 3 to 5 years to bring capacity online after making an investment decision, by which time market conditions can have shifted from ‘boom’ to ‘bust’.

The UK gas market (along with other European markets) saw a storage investment ‘boom’ later last decade. This was driven by robust levels of seasonal price spreads and spot price volatility, the two key price signals for storage investment. As a result, relatively large volumes of new storage capacity were commissioned earlier this decade.

This ‘boom’ quite quickly transitioned to ‘bust’. Gas demand across Europe fell by almost 20% from 2010-15, reducing the demand for supply flexibility. On the supply side, new storage capacity contributed to an emerging overhang of flexibility. Seasonal price spreads and spot volatility declined accordingly, creating a tough margin environment for storage across most of this decade.

But this prolonged bust has sown the seeds for the next boom in UK storage. Price signals for supply flexibility in the UK gas market are signalling a tightening market. Both seasonal price spreads and prompt volatility are continuing a structural recovery that started in 2016.

In today’s article we analyse the evolution of UK gas storage margins and set out how and why they have surged across the last two years.

Structural drivers behind UK gas flex recovery

The most important driver of the recovery in the value of UK gas supply flexibility has been the closure of Centrica’s Rough storage asset. Rough accounted for more than 70% of UK working gas volume and 25% of daily deliverability. Its closure upended the UK supply and demand balance for flexibility.

The impact of Rough’s closure has been reinforced by the roll off of long term contracts (with low variable flow costs) on the IUK interconnector in Q4 2018. This has transitioned the IUK to a higher variable cost peaking provider of flexibility. Ebbs and flows in LNG imports across the last two years are also supporting higher NBP price volatility.

Looking forward over the next 5 years, market conditions do not look conducive to another bust. There are 3 important structural drivers that support a continuing recovery in the value of gas supply flexibility:

Increasing import dependency: as domestic production declines, the UK and European gas markets are becoming more dependent on import supply chains which are slower to respond to price signals (supporting price volatility)
Greater power sector flex requirement: rapid growth in intermittent renewable capacity and the closure of coal-fired plants is increasing the requirement for flexibility from gas-fired generators
Ageing infrastructure: Rough is illustrative of ageing gas supply infrastructure across the UK & Europe, with owners reticent to invest in (or even maintain) assets given low margins experienced this decade.

Salt cavern fast cycle storage is the asset class best positioned to respond to recovering market price signals. Margins of existing assets have seen a significant recovery since 2016 (as set out in the section below). Across the last two years, there has also been a strong increase in interest from gas suppliers and traders looking to secure fast cycle storage contracts or offtake agreements.

Analysing UK storage margin evolution

In order to understand the evolution of UK faster cycle storage value we have modelled historical margin capture for a storage asset with the capability to cycle ~6 times per year (30 days injection, 30 days withdrawal).

This analysis does not involve ‘black box’ storage modelling. It is based on a transparent & objective ‘rolling intrinsic’ margin capture strategy that could have been achieved against historical NBP forward curves. In other words analysis does not involve any unrealistic assumptions such as inflated extrinsic value capture or perfect foresight.

Chart 1 shows annual achieved margin capture for each gas storage year (starting Apr, ending Mar) from 2009 to 2018. We calculate storage margin capture by:

Taking daily NBP gas forward curves across the horizon (bootstrapped settlement prices)
On each day, identifying & executing any profitable hedges & hedge adjustments against observable forward prices (accounting for variable cycling costs & BO spreads)
Injecting & withdrawing gas based on final hedge positions
Calculating the annual captured margin as the sum of hedge cashflows minus variable costs across each storage year.

Chart 1: Historical UK storage margin capture

Source: Timera Energy

The chart shows that the first half of this decade was a tough period for UK storage margins, with a steady decline from 2010 to 2015. Both spot volatility and seasonal price spreads fell across this period pulling down storage margins as described above.

But these factors started to reverse from 2016. UK gas demand has steadily recovered, particularly in the power sector. And there have been large net closures of storage capacity (mostly Rough, but some from Hornsea as well).

This has ignited a sharp increase in achieved storage margins, particularly in the 2017 and 2018 storage years. The 2017 storage year (Apr17 – Mar18) value increase was focused on ‘market shock’ events where prices spiked. The most important market shock driver related to price volatility caused by the ‘beast from the east’ weather system in Feb-Mar 2018. The impact of the beast from the east can be seen in Chart 2, which shows the spread between Day-Ahead and Month-Ahead NBP prices (a simple benchmark for prompt margin capture).

Chart 2: NBP Day-Ahead minus Month-Ahead price spread

Source: Timera Energy

Every 3 to 5 years, storage can generate high margins from shock events such as the beast from the east. As the UK gas market becomes more import dependent, these shocks are likely to increase. But there is significant uncertainty around the timing & frequency of shocks occurring. This risk has to be borne by capacity buyers and is reflected in capacity value.

What is interesting about high margin capture in the 2018 storage year (Apr-18 to Mar-19) is that margin capture was not focused on large shock events. Instead value across the year has been the result of higher underlying volatility. We have annotated the chart with some examples illustrating this.

A storage margin recovery trend has been in place since 2016. But 2018 conditions represented a more encouraging stability evolving in margin capture. It would not surprise us to see an investment decision taken on at least one new UK salt cavern storage facility across the next year.

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The relevance of a near zero UK capacity price

Posted on June 17, 2019January 15, 2020 by David Duncan

The latest T-1 UK capacity auction cleared at 0.77 £/kW on Wed last week. That is 87% lower than the last T-1 clearing price (at 6 £/MWh). 77 pence represents back pocket change. If you tipped a waiter this amount you’d risk your having your coffee ‘spilled’ all over you.

Shock is a natural first reaction to a near zero capacity price. How will the market deliver capacity to keep the lights on if there is no price signal?

But there are important reasons why last week’s auction has little relevance as a guide for future UK capacity prices. Today we look at the causes of such a low price and consider implications for the UK power market.

The auction in context

The first important point to note is that the T-1 auctions are essentially ‘top up’ or supplementary auctions to balance any capacity discrepancies from the main T-4 auction. Only about 5% of 2019-20 capacity is actually subject to the 77p price. The remaining capacity will receive much higher T-4 prices, with the main T-4 auction for 2019-20 clearing at 18 £/MWh as shown in Chart 1.

Chart 1: UK capacity market cleared auction volumes & prices by delivery year

Source: Timera Energy

The receipt of any capacity payments (T-1 or T-4) is of course dependent on the reinstatement of the capacity market (currently suspended after the ECJ ruling). But the government has indicated it expects to make retrospective payments on capacity to cover any delays.

Why did the price clear near zero?

The most obvious cause of a low clearing price was that the auction was very well supplied. 9.4 GW of capacity was competing to meet a 3.6GW demand target.

This overhang of capacity was exacerbated by several factors that weren’t anticipated at the T-4 stage e.g. survival of the 1.2GW Peterhead CCGT (as a result of a favourable transmission charge ruling) and the early commissioning of the NEMO interconnector and a number of gas engine and waste energy generators.

All capacity that cleared, except the last few marginal MW, was effectively priced at zero i.e. owners were committed to providing capacity regardless of price outcome. As well as capacity that came online earlier than anticipated, it appears that several of the larger existing thermal units also bid zero e.g. Centrica’s Kings Lynn, Killingholme and Peterborough plants.

This is where the relevance of the auction was undermined by a very short timeline to delivery. An auction in mid June for a capacity year starting in October, represents a 3.5 month lead time. There is very little that capacity owners can practically do in response to the auction price signal over that time frame.

Over the usual 9 month T-1 horizon, capacity owners have more flexibility to consider responses such as mothballing or delaying investment decisions. But at the 3.5 month stage, most costs involved in operating capacity are already sunk (or unavoidable). In that situation the rational response is to bid capacity at or very close to zero price levels. These conditions effectively undermined the purpose of the auction.

Impact & implications of a low price

A near zero price has dashed any remaining hopes of larger thermal units that didn’t secure a 2019-20 capacity agreement at the T-4 stage. 3.5 GW of coal plants will close over the next 9 months: 2GW Cottam (EDF) in Sep-19 and 1.5 GW Fiddlers Ferry (SSE) in Mar-20. West Burton A (EDF) has a capacity agreement in 2020-21, but may have to run at a significant cash loss if it stays open to fulfill this. Another 0.5GW of gas-fired plant (ESB’s Corby and Centrica’s Brigg) are on the highly endangered list.

But beyond these closures, the dynamics driving last week’s T-1 auction have virtually no bearing on pricing of the main T-4 capacity auctions.

The ‘top up’ nature of T-1 auctions mean that supply, demand & pricing dynamics differ substantially from T-4 auctions. T-1 capacity volumes are relatively low, with what are typically steep and ‘chunky’ supply stacks. If the market is oversupplied at the T-1 stage, prices lurch to low levels. But the opposite is also possible if the market is tight e.g. because of unanticipated closures and capacity shortfall at the T-1 horizon.

Step forward to next T-4 auction and there are a number of factors supporting higher capacity prices:

Engine headwinds: Achieved gas reciprocating engine margins across the last 12-18 months have been significantly lower than expected, effectively acting to increase capacity bids on future investments.
DSR: The success of DSR from previous auctions is set to be substantially impacted by revenue reductions resulting from rule changes set to be implemented under the Transmission Charging Review.
Coal economics: The economics of remaining coal units have deteriorated significantly across 2018-19 as gas prices have fallen & carbon prices risen. This will likely lift the bids of the remainder of the UK coal fleet.
Batteries: Steep reductions in battery de-rating factors and declining frequency response returns have stemmed the tide of batteries bidding aggressively into the capacity market.

The 77p capacity price is an unwelcome outcome for the 5% of capacity owners that will receive it across the next year. But it has little bearing on what happens going forward in the UK power market.

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Gas vs coal plant switching practicalities

Posted on June 10, 2019January 15, 2020 by David Duncan

The switching dynamics of European gas for coal plants have never been more important than in 2019. Falling hub prices are tipping the competitive balance in favour of gas-fired plants. Front month TTF prices last week plunged towards 10 €/MWh (3.60 $/mmbtu) as near record volumes of LNG & Russian imports continue to flow into European hubs.

This shift in competitive balance is causing an increase in the influence of gas in setting marginal power prices across Europe. It is also helping support gas demand, allowing European hubs to absorb high gas import volumes.

The importance of relative gas vs coal plant variable cost dynamics means that a lot of attention is currently focused on switching price levels. But the concept of switching levels oversimplifies the dynamics driving the swings in gas and coal plant output. In today’s article we look at some of the practical drivers beneath a simple line on a chart, using a German power market case study.

Switching level is not just a line on a chart

The coal for gas switching price level is often drawn as a simple line overlaid on a gas price chart. This implies a clean transition from gas to coal plants as gas prices shift either side of the switching line.

In Chart 1 we show a switching range as opposed to a line. This reflects a gas price range across which CCGTs displace coal plants, given differences in plant efficiencies and variable costs. But even this significantly oversimplifies underlying swings in gas & coal plant output.

Chart 1: Forward European gas for coal plant switching range

Source: Timera Energy

The ability of the power sector to absorb incremental gas and the importance of gas in setting power prices fluctuates in real time. This is best illustrated with a case study in Chart 2 which shows German generation output across the last 10 days in May 2019.

Chart 2: German hourly generation output by plant type (GW)

Source: Fraunhofer Institut

The variable cost competitiveness of coal vs gas plants is relatively stable across such a short time horizon. In other words, nothing of note is changing on the switching chart. Yet despite of price stability, there are three additional factors that have an important influence on the relative levels of gas vs coal output:

Renewables output

In periods of high wind and/or solar output, both gas & coal units are increasingly being driven out of merit, regardless of fuel costs. In these periods we are increasingly seeing lignite or even nuclear units on the margin in Germany.

Plant level dynamics

There are important factors driving output at an individual plant level that are not related to fuel & carbon prices. For example, there are minimum output levels associated with CHP offtake commitments for both gas & coal plants. There are also a range of other factors that vary widely across plants such as ramping flexibility and coal transport costs.

Power demand

The level of power demand varies on both an intraday and seasonal basis. This (in combination with renewable output volumes) influences thermal plant load factors. If overall power demand is low then there is limited switching potential.

Relative fuel & carbon price levels clearly favour gas over coal plants in Chart 2. When thermal flexibility is required, gas plants are claiming a greater portion of the pie. But the three other drivers described above are just as important in determining how much switching & incremental gas demand volumes are actually occurring in practice.

Decarbonising European gas: value chain impact

Posted on June 3, 2019January 15, 2020 by David Duncan

Decarbonisation of the European gas market will involve very large scale investment across the supply chain, regardless of the pathway via which it is achieved. European energy companies are in a strong position to lead a gas market transition, just as they are currently doing in the power sector.

Gas decarbonisation will require major changes in infrastructure, business models & regulatory frameworks. It will also result in structural changes to the value and risk profiles of existing gas assets.

But decarbonisation brings substantial growth opportunities for companies that are positioned for change. The challenge is that the growth areas going forward may be very different to those of last two decades.

Today we focus on:

how the European gas value chain may be impacted by decarbonisation
what this means for the key categories of market players (producers, network owners, suppliers & midstream flex assets).

We do this with the aim of identifying both risk mitigation actions and growth opportunities for the players involved.

How decarbonisation pathways impact the gas value chain

In last week’s article we set out 3 potential pathways that the European gas market could follow toward decarbonisation (2020s to 2050s). All of these pathways involved structural changes in the gas supply chain by the mid 2030s. A quick recap:

Gas transition: Steady transition to large scale hydrogen networks by 2050s. Transition supported by ‘blending’ of hydrogen (& potentially bio-methane) in existing networks across 2020s-30s. Large scale methane reformation into hydrogen at European border entry points by the 2050s.
Steady displacement: Gas retains a structural role, but with a changing/shrinking footprint. From the mid 2030s gas starts to be displaced by electrification of power/heat/industry (by default). By 2050s, fragmented & localised gas networks are focused on flex backup in the power sector & hard to reach areas of heat/industry.
Rapid displacement: Electrification broadly displaces gas from the energy mix by the 2050s. Displacement from the power sector across 2020s-40s (by electricity storage) & heat/industry across 2030s-50s. The residual role of gas is focused on smaller scale local applications (e.g. biogas), with progressive closure of gas T&D networks.

So what could these different pathways mean for infrastructure & companies across the European gas value chain? In Table 1 we summarise the potential impact.

Table 1: Value chain impact of 3 decarbonisation pathways

Pathway	Value chain impact
Gas Transition	*Headline: Extensive but managed infrastructure & business model transition* Blending of hydrogen & bio-methane supports: (i) continued usage of existing gas infrastructure (2020s to 2040s) & (ii) the role of gas as a transition fuel e.g. displacing coal & lignite across 2020s Existing producer supply chains (e.g. Russia/Norway/LNG) may continue to deliver methane to European borders for reforming to hydrogen Steady transition to hydrogen networks & infrastructure across 2030s-50s, requiring large scale new investment (from production to burner tip) Adaption/upgrade of some existing midstream infrastructure (e.g. storage, regas terminals) to support hydrogen networks
Steady displacement	*Headline: Time for ‘fast movers’ to adapt (or exit) as new role of gas defined* Relatively high utilisation of existing methane infrastructure into 2030s, before displacement by electrification gathers pace in power, heat & industry Steady decline in gas demand & asset utilisation from mid 2030s, with networks & infrastructure becoming more localised/fragmented Flexibility/peaking role of gas infrastructure increases over time as utilisation falls e.g. to support peaking flex in the power sector Asset risk/return profiles change as gas evolves into ‘peaking’ role, with associated changes in regulatory, ownership and business models Significant retirement of existing methane supply chain infrastructure by 2050s
Rapid displacement	*Headline: Industry wide disruption to asset values & business models* Gas infrastructure utilisation starts to decline from late 2020s with a more limited role of gas as a transition fuel Peaking flex role of gas in the power sector diminishes with rapid electricity storage evolution in 2030s & 40s Large decline in gas infrastructure utilisation across 2040s-50s Broad based redundancy of existing methane supply chain infrastructure by 2050s, including stranding of existing assets

Source: Timera Energy

Balancing the 30 year horizon with the 10 year one

At first glance, the impact of these pathways seems to be a major threat to existing gas asset portfolios & business models. But there are some important considerations to balance against this.

Under all three pathways gas could well see somewhat of a resurgence across the next 5 years. There are two key drivers behind this:

Coal & nuclear closures: Substantial volumes of coal, lignite and nuclear capacity face regulatory driven closure over the next decade, much of this over the next 5 years (e.g. Germany 25GW). This is set to increase the load factors of existing gas-fired plants & therefore gas demand.
Low prices: Large volumes of new LNG supply (2019-21) are pushing down European hub prices. This is causing coal to gas switching in the power sector. But it may also induce other demand side response.

In the ‘Gas transition’ and ‘Steady displacement’ pathways there is also a genuine role for gas as a transition fuel well into the 2030s. The EU’s current top priority is driving coal out of the energy mix. A number of countries are in parallel closing nuclear plants (despite dubious emissions logic). In the absence of blistering electricity storage technology evolution, gas will be needed to plug the capacity gap. Beyond that, a combination of biogas & hydrogen from electrolysis may be a longer term necessity.

The ‘Gas transition’ scenario would likely be a very favourable outcome for European energy companies prepared for change. As a result we think this is the path which will garner the greatest industry support. If momentum builds behind blending of hydrogen & biomethane in the early 2020s, this may support both:

Use of existing networks & infrastructure well into 2030s, with increasing blending of hydrogen and biomethane
Very large scale investment in hydrogen production and network infrastructure (& the potential for European companies to lead a global roll out of hydrogen).

Hydrogen production via steam reformation could even actually support European gas demand, given energy required in the conversion process (and to capture CO2) results in a conversion efficiency of some 75 to 80%.

Impact on different players

Next we summarise the potential impact on players across the gas value chain. This draws in part on material from Jonathan Stern’s recent paper on gas decarbonisation.

Producers

LNG producers & aggregators selling into Europe
- will need to watch the potential for declining demand from 2030s
- but they have the potential to sell elsewhere e.g. Asia/Lat America (at least temporarily)
Pipeline linked producers (e.g. Russia, Norway, North Africa)
- More exposed to European demand decline (& tougher prospects for signing LTCs)
- Strong incentives to carve out a role in hydrogen reformation supply chain
Substantial opportunities to develop hydrogen production infrastructure
Both LNG & pipeline producers have incentives to locate hydrogen production at European borders (e.g. regas terminals, pipeline entry points) to preserve existing methane supply chains to the border

Transmission and Distribution Network Owners

Face key risk of erosion of network utilisation
Network location and decarbonisation pathway important in defining value impact
Blending of hydrogen & bio-methane important to support utilisation in 2020s-30s (incentives aligned with producers here)
Transition to different regulatory & ownership structures likely as existing network utilisation declines
Opportunities to develop new hydrogen (& bio-methane) networks, but new regulatory, commercial & investment structures required to support this

Gas Suppliers:

Easier to adapt gas supplier business models than other parts of the supply chain
Issues arise where suppliers own assets/infrastructure that suffer from falling utilisation, which may lead to increasing asset divestment momentum (& the contracting of replacement flexibility)
Strong diversification logic in electricity supply chain presence
Trading businesses will need to evolve with the market, but are relatively well placed to do so (e.g. in supporting flex/peaking role of gas + potentially establishing hydrogen markets), albeit replacement markets may be more fragmented and less liquid than the current pan-European hub market

Midstream gas and power assets:

European midstream asset owners (e.g. regas & storage) & gas-fired power plant owners are already adapting to changing market conditions & lower utilisation
Transition to ‘peaking’ role of these assets is likely to continue through 2020s-30s
As a result, substantial change of ownership likely over 2020s-30s as assets transition to owners with appetite & skill set to manage ‘peaking’ risk/return profiles
Substantial opportunities for new investment in hydrogen (& bio-methane) midstream infrastructure as well as conversion of suitable existing assets (e.g. storage, regas)
There could also be big opportunities in CC(U)S both for hydrogen production and power plants.

Conclusions on how to approach gas decarbonisation

The impact of gas decarbonisation on gas portfolios can be broadly split in two categories:

Impact on value and risk of existing assets
Growth opportunities in the development of new assets & markets

Both need to be approached in a pragmatic way that reflects the uncertainty and timescales involved, using a structured analytical framework.

In our view, the best way to approach this is for companies to develop their own in-house decarbonisation ‘pathways’. These can then be used to analyse & even quantify the impacts of decarbonisation, e.g. by understanding upper and lower bounds on asset value and risk. They can also be used to target lobbying for appropriate policy support.

Doing nothing because decarbonisation is too far off is not really an option anymore. Whatever decarbonisation pathway and timeline you subscribe to, it will involve structural changes in business models, asset values & ownership structures. These are set to commence through 2020s and accelerate in the 2030s.

A consistent framework for analysing risk & opportunities and the readiness & flexibility to act on this are likely to be key to successfully navigating the transition.

Decarbonising European gas: 3 pathways

Posted on May 27, 2019January 15, 2020 by David Duncan

The origins of the European gas market go back to the discovery of large reserves of natural gas, firstly the giant onshore Dutch Groningen field (1959) and then a string of early UK Southern North Sea fields from 1965. In the early 1970s, a nascent European gas network of around 100 bcm was focused on these two countries.

From 1970 to 2010, the European gas market grew beyond all expectations to around 550 bcm (stabilising since). Growth was underpinned by rapid evolution of technology, regulation and commercial structures. This in turn supported very large scale investment in gas infrastructure across what has become a highly interconnected and liquid pan-European market.

Here endeth the history lesson. Today we are going to focus on the next 40 years.

In last week’s article we summarised different potential technologies that can facilitate decarbonisation of gas. In this week’s article we look at 3 potential pathways to decarbonise the European gas market. Next week we then consider the potential impact of these pathways on the gas value chain and its key players in our final article in this series.

Is low carbon gas the 3^rd key pillar of the European energy transition?

The energy transition has to date taken shape around the development and deployment of renewable electricity generation technology. Renewables represent a first key pillar of the transition, given they facilitate large scale generation of low carbon electricity.

Electricity storage is rapidly emerging as a second key pillar. Electricity storage will help solve the challenge of ‘firming’ intermittent renewable output by enabling the movement of electricity across time periods of variable wind and solar output. However storage technology developed to date is focused on short term intra-day balancing and grid services rather than shifting large volumes of energy across weeks or seasons as is required in Northern Europe.

The combination of renewables and storage has provided the tools to kick start decarbonisation of the power sector, albeit with a range of flexibility issues that currently still depend on natural gas. The energy transition will next move to the much broader electrification of other carbon intensive sectors, firstly transport and eventually heat and industry. But there are currently substantial gaps in what electrification can practically achieve in terms of decarbonisation given today’s technology.

As a result, low carbon gas is gathering momentum as a third key pillar. It has the potential to address load shifting in the power sector as well as decarbonisation of heat & industry. Green gas, particularly in the form of hydrogen, has the potential to solve many of the remaining ‘hard to reach’ decarbonisation challenges.

Gas can reach areas that are difficult to electrify

Fully decarbonising the power sector with renewables & storage alone is shaping up to be a difficult challenge. Low carbon gas represents a large scale secondary source of flexibility alongside electricity storage e.g. to tackle weekly and seasonal load shifting.

There are also substantial parts of the heat, industrial & transport sectors which may be easier to solve with low carbon gas than electrification. This includes:

‘on demand’ domestic heating which is difficult to achieve rapidly with heat pumps
industrial process heat where equipment design and electricity cost could render European industries non-viable compared to those elsewhere which are not subject to decarbonisation policy on a comparable scale
decarbonising air transport and heavy shipping (via hydrogen)

So what are the potential paths that the European gas market could follow towards a low carbon future?

3 pathways to decarbonisation

40 years is a long time horizon. Overlay accelerating decarbonisation measures and the pace of technology evolution and it is fair to say that the future of the European gas market looks very uncertain.

The risks associated with this level of uncertainty mean it is important to understand what could happen to the value of gas assets and portfolios. This in turn requires a pragmatic framework to assess potential outcomes while recognising uncertainty.

In Table 1 we have developed 3 high level pathways for decarbonisation of the European gas market by the 2050s. These are not scenarios that pick technologies and outcomes. Instead, each pathway represents a set of drivers that combine to work towards decarbonisation.

Table 1: Pathways to decarbonising the European gas market

Pathway	Summary
Gas Transition	*Headline: Steady transition to large scale hydrogen networks by 2050s* Hydrogen ‘blending’ into existing gas networks in 2020s & 30s supports development of hydrogen technology (e.g. methane reformation with CCS) Blending of hydrogen (& potentially bio-methane) ‘buys time’ to resolve regulatory, commercial & infrastructure transition to hydrogen based T&D networks by 2050s This anchors the future of T&D networks rather than policy-driven abandonment Methane converted into hydrogen at European borders (or at source) Potential support from wider CCS deployment e.g. in power/industry sectors
Steady displacement	*Headline: Gas retains a structural role, but with a changing/smaller footprint* Large scale hydrogen production not achieved by 2050s Gas continues to play a key role displacing coal & lignite into the 2030s From mid 2030s gas starts to be displaced by ‘default’ electrification of power/heat/industry Gas retains a structural role focused on flex backup in power sector and parts of heat/industry sectors that are difficult to electrify Gas market transitions to more localised & fragmented low carbon gas networks (e.g. biogas, smaller scale hydrogen, power sector CCS)
Rapid displacement	*Headline: Electrification broadly displaces gas from the energy mix by 2050s* Gas displaced in the power sector across 2020s-40s (e.g. via faster evolution of electricity storage technology) Gas broadly displaced from heat and industry across 2030s-50s possibly through offshoring to US, Asia. Pace of electrification reduces momentum behind low carbon gas R&D and investment Residual role of gas focused on smaller scale local applications (e.g. biogas, ‘green’ hydrogen from electrolysis) Progressive closure of gas transmission grids

Source: Timera Energy

The 2050s time horizon for these pathways is driven by the increasingly recognised requirement to achieve net zero carbon emissions by mid century. If you are sceptical about achieving decarbonisation over this time horizon, the pathway horizons can be extended relatively easily (e.g. via slippage to 2060s, 2070s).

The key point is that under any of the pathways, the European gas market is likely to undergo an unprecedented transformation over the next 10 to 20 years i.e. within an asset investment horizon.

Ignoring the reality of the decarbonisation is effectively betting on European policymakers performing a structural policy ‘U turn’. That is a high stakes bet which poses an existential threat.

Interpreting the 3 pathways

The ‘Gas transition’ pathway is potentially a very positive outcome for the European gas industry. The blending of hydrogen (& potentially bio-methane) in existing gas networks buys time to develop cost effective hydrogen production solutions, as well as a regulatory & commercial framework to underpin market transition to hydrogen. This can allow a managed supply chain transition to hydrogen focused networks. It would also likely mean that European players dominate a global transition to low carbon gas (as is happening now for renewable power).

The ‘Steady displacement’ pathway sees a steady reduction & likely fragmentation in the European gas footprint by the 2050s. Gas retains a structural role in areas that are hard to electrify, with a focus on flexibility (e.g. load shifting in the power sector). This would likely involve substantial changes in regulatory & ownership structures, utilisation of infrastructure and company business models. But change happens at a pace that can allow the industry to adapt and evolve accordingly.

The ‘Rapid displacement’ pathway represents a much faster disruption of the gas industry. Electrification happens at a pace that effectively leap frogs the requirement to develop wide spread low carbon gas solutions. This is unlikely to be a comfortable outcome for current gas asset owners given the speed of disruption. Its probability may not be high, but it is quite plausible. As such this outcome represents an important downside pathway which is worth understanding.

Applying the pathways

Understanding what could happen over the next 20-30 years is one challenge. But it is just as important to consider how this could impact the gas asset value chain and company business models.

We explore this in next week’s article by looking at the potential value chain impact of the 3 pathways we have set out today. Understanding this provides a basis for working out how to react to mitigate risks and define growth opportunities.