The Spanish press is outraged. The government’s vaunted gas price cap — known as the ‘Iberian exception’ — has failed to lower energy bills. In fact, Spanish and Portuguese consumers seem to be paying more than they were before the mechanism was introduced. But there are mitigating circumstances: namely, a heatwave-induced power demand spike, and soaring EU gas prices. The upshot is an inconclusive outcome of the excepción ibérica, leaving the merits of intervention open to interpretation. So where does this leave hopes for meaningful reform of broken EU energy markets?
For a refresher on how the cap is supposed to work and why intervention was deemed necessary, see ‘The rain in Spain’ (parts one and two)
For a background briefing on marginal pricing in EU electricity markets, see ‘Clear as mud’ from May
If you’re curious about the wider EU discussion around electricity market reform, this hot-take is a good starting place
Today’s article dissects the impact of the gas price cap mechanism on the Spanish power pool, the Iberian gas market and Spain-France energy trade. This is supported by the usual peppering of original charts using data from Spanish grid operator OMIE. It then examines the assumptions upon which the mechanism is deemed by some to have failed, and ends with a discussion about the political ramifications for EU energy market reform in the context of the brewing winter gas crisis.
Que pasó en el <pool>?
Let’s start with what happened last week when the cap was introduced. The mechanism came into force in the Iberian power pool day-ahead auction held on Tuesday 14th June, with results affecting market outturn the following day. The cap of €40/MWh on thermal generators (gas, coal and combined heat and power plants) duly lowered clearing prices, albeit by less than hoped.
The average wholesale price on 15th June was €165.59/MWh, a reduction of €48.46/MWh (-23%) on the previous day. However, this price does not include the cost of subsidising thermal plants. The so-called ‘adjustment cost’, which covers the difference between the cap and the market price of fuel (i.e. natural gas), comes on top.
The cap was supposed to deliver a net saving to consumers by lowering wholesale prices significantly more than the additional cost of subsidising thermal plants. As the chart above shows, this did not happen. Prices still rise and fall in tandem with the amount of power sector gas burn.
The adjustment cost of nearly €60/MWh erased the wholesale savings, resulting in a ~5% net increase in the total system price to €225/MWh. The same happened on the following two days: the adjustment cost drove up the system cost by +17% and +1% on 16th and 17th June.
Prices fell over the weekend of 18-19th June, but were higher than the previous Saturday and Sunday. As demand returned on Monday 20th June, gas-fired power generators ramped up output and both wholesale and adjustment costs shot up again.
Que decepción
Ministers promised the cap would save consumers a much-needed 15-20% on their bills. Spanish newspapers are keeping a close eye on pool prices because around one-third of households in Spain are on a tariff that moves with wholesale gyrations. Consumers on this so-called ‘PVPC’ tariff (see part 2) were primed to expect a reduction but saw the opposite happen. Cue widespread apoplexy.
The feelings of dismay and anger are understandable, but they do not tell the whole story. The situation is far more complex than it first appears.
Article stats: ~2,500 words / 5 charts & graphs / 12-minute reading time
Spaniards were cranking up air conditioning in response to an early summer heatwave that pushed peak temperatures as high as 43 degrees Celsius. This followed the hottest and second-driest May this century that has helped to drain Spanish hydro reserves to 48.2% of capacity, with the hottest and driest summer months still to come.
Total system demand rose with the mercury, pushing up Spanish daily generation by 27% over five scorching days to hit 847 GWh on 16th June 2022. This is well above seasonal norms: daily generation in the month of June averaged 651 GWh over 2018-22.
A high-pressure zone of hot, still air sweltered western Europe and decimated wind power production. Spain’s world-beating fleet of wind turbines was becalmed. Wind’s contribution fell from 170 GWh on 13th June to 78 GWh on 15th June, just as power demand was soaring. The hot, hazy weather also diminished solar thermal and PV generation.
Gas batiendo récords
The upshot? Natural gas had to bridge the gap, with a record 764 GWh of gas delivered to the electricity sector on 15th June. This translated into 321 GWh of electricity from Spanish combined cycle turbine generators (CCGTs) on the day that the gas cap came into force.
The mechanism was a contributor to the extra gas burn. With their fuel costs covered by the adjustment, CCGTs were expected to fire at full pelt to grab as much market share as possible. This is precisely what seems to have happened. See how the pool mix shifted as the cap came into effect:
How much of the extra gas burn was due to the cap, and how much to market conditions? This cannot be quantified, but certainly the cap does not deserve all of the blame. Gas did not really take market share from other sources. Wind and solar fell the most, not because they were displaced by subsidised gas (they are zero marginal cost generators so enjoy priority dispatch in pay-as-clear auctions) but because their availability dipped at an inopportune moment.
The Spanish government said the final price of €225/MWh on 15th June would have been around €240/MWh without the cap. If might have been even more: gas was covering 40% of demand and was paid €60/MWh in adjustment costs. If that extra cost had been applied to the other 60% of generation as well, the wholesale price could have been €150/MWh higher (100% = €60/MWh x 2.5).
El gas es carísimo!
The other mitigating factor is that natural gas in Europe is still unbelievably expensive, so the cost impact of any increase in gas-fired powergen will be magnified by high fuel costs. Wholesale prices on Dutch TTF, the continental EU gas benchmark, soared above €100/MWh once again last week as Gazprom curtailed flows to Germany, Italy and many other countries citing (highly questionable) technical constraints related to sanctions.
Germany is now taking unprecedented measures to reduce residential, industrial and power sector gas demand to mitigate the risk of winter shortages. Ironically, Berlin is doing the precise opposite to Spain and Portugal: the Iberian exception is contributing to record gas burn, which in turn is driving prices higher on the peninsula.
Iberia is something of an energy island due to its limited connectivity with the rest of Europe. MIBGAS, the Iberian wholesale gas market, often trades at a discount to TTF thanks to Spain’s oversized gas pipeline and LNG import capacity, disproportionately small gas storage capacity and constrained pipeline export capacity with France. In theory, any market intervention that drives gas burn higher in Spain and Portugal will reduce the MIBGAS-TTF discount.
It is conceivable that the gas cap mechanism will erode its own savings by inflating MIBGAS prices. MIBGAS is the benchmark used to calculate the adjustment cost — the top-up between the price cap (currently €40/MWh) and the fuel cost of thermal generators. If MIBGAS rises significantly then the adjustment cost will rise too.
It is too early to tell if this will happen, but keep an eye on the MIBGAS-TTF spread. If the Iberian discount flips into a structural premium for the duration of the gas cap, it will be hard to conclude that the mechanism did not precipitate this.
Viva Francia!
The big winner in all of this is France. Regardless of how much Spanish and Portuguese consumers ‘save’ against any counterfactual theoretical world without the cap, the inescapable reality is that they are subsidising the price of gas being exported over the Pyrenees into France.
The adjustment cost is paid for almost entirely by Iberian consumers, which lowers the wholesale price of electricity in the Iberian power pool. A small amount is clawed back from ‘congestion rents’ accrued from cross-border power trade, but this does not cover the differential.
The Iberian exception is creating an exceptional arbitrage between Spain and France that traders are duly exploiting. The result? Physical flows of electricity are now heading in only one direction: northbound. With the French nuclear fleet facing extended downtime, Spain’s newfound status as a net electricity exporter to France is likely to persist for the foreseeable future.
Situación perversa
If the MIBGAS discount evaporates and Iberian power pool prices remain depressed by the cap, it is possible that this leads to a rather perverse situation in which electricity is cheaper in Spain than France, but gas cheaper in France than Spain.
If so, gas molecules would flow from north to south to generate power in Spanish CCGTs, which then export electricity from south to north for the benefit of French consumers. But it wouldn’t be entirely ridiculous; a potential benefit of this situation would be increased utilisation of Spanish LNG terminals, which are unable to help alleviate regasification bottlenecks elsewhere in Europe due to limited pipeline interconnector capacity (see ‘Infrastructure overkill?’, April 2022).
Maximising the utilisation of Spain’s sizeable fleet of CCGTs in lieu of gas storage capacity and then exporting gas-fired electricity into an overheated French power market makes a weird sort of sense. This is particularly the case when LNG vessels are struggling to secure slots to unload cargoes in north-west European ports and the UK is being used as a land bridge to get LNG into the continent.
When weighing up the effectiveness of the Iberian exception, would this market contortion count as ‘failure’ or ‘success’? This is entirely open to interpretation. Spanish and Portuguese consumers are on the hook for CCGT adjustment costs but Europe as a whole is benefitting from increased energy security, and Iberian electricity prices are claimed to be ‘lower than they would otherwise have been’. Perhaps there will be a case to argue for an EU-level contribution to reimburse adjustment costs levied on Iberian energy bills — but don’t hold your breath.
Ahora que?
Liberalised energy markets are complicated and interventions inevitably have unintended consequences. The Iberian exception is, well, no exception to this rule. Since there is no clear-cut conclusion to be drawn over the gas price cap, the effectiveness of the policy is ripe for politicisation.
This would be the worst possible outcome. At a time of extreme uncertainty, EU energy policymakers need clarity — not more partisan diatribes or politically-motivated revisionism. Success is always desirable, but a categorical failure would have been preferable to an inconclusive outcome that can be painted as success or failure depending on one’s predispositions.
There is always tension between the European Commission and member states. Spain and Portugal originally called for powers to cap power pool prices, which would have been a much more drastic intervention. Faced with a concerted push to effectively break up the EU’s single market for electricity, Brussels sought a compromise that protects EU integrity while (potentially) lowering energy bills.
The EC’s acquiescence to the Iberian exception was couched in conditionality: it is strictly temporary, and may apply only in EU power markets dominated by gas and with limited interconnectivity. It is unlikely that Brussels wanted to see the policy fail to protect the status quo, because there is growing acknowledgment of the need for reform. But a roaring success would have prompted other countries (Italy? Greece? Romania?) to push for their own exceptions.
Those calls will for now be tempered by the inconclusive outcome from the Iberian experiment. But storm clouds are gathering over EU energy markets as Russia turns the screw on gas exports. More price spikes, volatility and some gas rationing are to be expected in the coming winter.
More consumer pain means more political pressure from member states for EU-level reforms. Whether these ultimately mimic the gas cap or take another form is not yet clear — but change is coming, one way or the other. After a baking summer, Europe is going to endure a long, dark winter followed by much political turmoil and sustained demands for regulatory reform. Expect more exceptions.
Seb Kennedy | Energy Flux | 20th June 2022
POSTSCRIPT: What about ‘the rain in Spain’?
I started researching this topic out of curiosity over the bidding behaviour of dammed hydroelectric power stations, which were clearly gaming the pay-as-clear system to inflate revenues prior to the gas cap. (See ‘The rain in Spain’ parts one and two). If you’re wondering how the gas cap has influenced hydro, the short answer is: it’s too early to tell.
On 15th June, when the cap came into force, hydro was the principal price-setting technology in the power pool — prompting commentary from analysts that strategic bidding was undermining the effectiveness of the cap. But that has since given way to more consistent price-setting by CCGTs, suggesting hydro generators adjusted their strategy to bid below gas. Whether this is due to hydrological, commercial or reputational considerations, or simply a function of learning from the first auction under the new regime, is an open question.
I realise that I omitted to mention emissions anywhere in this post. I imagine some folks might be wondering what the emissions impact is of the gas cap. Since we can't quantifiably disentangle the primary causes for greater Spanish gas and coal burn (i.e. heatwave, low renewable generation and price cap), it is hard to say definitively whether and by how much emissions rose as a result of this policy.
I cited Aurora modelling in a previous post: https://www.energyflux.news/p/the-rain-in-spain-part-2
The modelling suggests emissions impact would be very low since some coal projects are pushed out of the merit order. But that same modelling also showed a huge decrease in wholesale prices, which hasn't really happened. So who knows.