The main European Gas Hub Index TTF closed with a record 115 euros/megawatt-hour (MWh) price on 5th October. A year ago, gas trading was stable for months around 15 euros. Record gas prices also lead to record electricity wholesale prices all-over Europe due to the electricity market model of the EU where the highest marginal cost sets the price (most of the time natural gas-fired power plants). Politicians and experts have listed various causes for the extreme price volatility. In this article, I would like to highlight only two, which are politically sensitive and interrelated: the role of Russia and the role of the EU energy and climate policy.
The dilemma of Russian manipulations in natural gas
When measuring the relative quantity of Russian gas on the European market in 2021, the best way is to compare the current level of supplies with 2018, the last normal year of Russian exports. In 2019, Gazprom oversupplied the EU, filling storages above 100 per cent due to the expiry of the Russian-Ukrainian gas transit contract on 31 Dec 2019. After the agreement, in 2020 Gazprom supplies decreased due to the high level of the available amount of storage gas in Europe and the economic effect of the COVID-19 pandemics. In the first 9 months of 2021, Gazprom supplied 145,8 billion cubic metres (bcm) to the EU and Turkey, not significantly down from the record 149,2 bcm in 2018. It seems that the lack of Russian gas on the EU market is not the only or even main cause for the high prices. We can assume that the production cost of Gazprom has not significantly changed last year, so it is still somewhere around 40 US dollars/thousand cubic metres (tcm), which goes up to 100 US dollars/tcm with transport, for example, the breakeven price at the EU border is roughly 10 US dollars/MWh or around 8-9 euros/MWh. Why could Gazprom sell its cheap gas produced in Northwest Siberia at such exorbitant prices? For answers, we have to look further West.
When the concept of the Third Energy Package was laid down, a global natural gas market was non-existent: the importing regional gas markets (Europe, East Asia) were fragmented and often dominated by pipeline gas or LNG with long-term oil-priced contracts. The goal of the European Commission was to establish a level playing field on the European market, making it impossible for Gazprom/Moscow to set political gas prices for each EU member state. From 2010, Gazprom’s European consumers also initiated many arbitration cases to lower take-or-pay requirements, which affected other pipeline gas exporters, like Sonatrach as well. Over the course of several years, most Gazprom contracts were reformed to include the gradually higher weight of gas spot prices in the formulas, many even reset to fully spot-based pricing, most often Dutch TTF. European transparency and solidarity won and gas became detached from oil quite reasonably. Applause. 2020 in Europe saw record low gas prices and temporary Henry Hub (USA price anchor)–TTF–JKM (Northeast Asia spot LNG reference) parity, so everybody was happy apart from Gazprom and some green groups who feared the low gas price weakens decarbonisation incentives in heating and industry.
However, one important thing has been overlooked. The low price environment in Europe due to the COVID demand shock and the global LNG glut was possible due to the globalization of natural gas markets, with spot LNG shipments quickly reacting to demand fluctuations across continents. Due to the expansion of LNG export capacities in Qatar, the USA and Russia, many exporting companies arose who could easily shift LNG cargoes between the two main import centres, Europe and East Asia. This led to LNG becoming the price setter in main consumption centres in the absence of additional pipeline gas. While reaching the positive outcomes of higher market liquidity, harmonised regulation and more interconnections among Member States, the European Union has managed itself into a position, where gas prices in the main hubs are mainly affected by Gazprom supply flexibility and global LNG flows and pipeline gas pricing is also fixed to these LNG-affected hubs. Simply put, the EU has reached its goal of a single gas reference price all-over Europe, but it deprived itself of any leverage on how these prices are set. The advantages of large EU members/companies from the long-term partnerships with Gazprom or Equinor – providing long-term stability and leverage – were lost in those cases who opted for total market flexibility, the largest suppliers now rightly pointing out that their pricing is transparently based on liquid European hubs. Welcome to market realities.
Conclusion number 1: Russians are happy and gaining from the high gas prices but are not the main cause of it. Russia was exporting the usual amount of gas to Europe until November without additional flexibility services due to filling up domestic storages. Even after 8 November, it cannot increase export to such quantities that would entirely substitute the decline of domestic gas production and re-routed LNG shipments – whether through Ukraine or Nord Stream 2.
The misunderstood role of European climate policies
Commission Vice President Frans Timmermans correctly pointed out that the ETS CO2 price hike is only responsible for 20 per cent of the electricity price rise. This does not mean that the remaining large part of the phenomenon is independent of the EU policies. For the security of constant electricity supply, one has to balance the variable production of intermittent renewables highly exposed to the weather with additional capacities of energy storage (pumped hydro or modern batteries) or flexible electricity generating capacities (mostly natural gas). From all these, until the availability of large, industrial-scale power storage options, gas-fired power plants are the most mature, scalable and easiest-to-install technology with the least controversial environmental impact.
New intermittent RES capacities also need extensive grid infrastructure development, which is not covered by the energy wholesale prices but are accounted for in the regulated tariffs. The real cost of variable renewables for the energy system is much higher than the near-zero marginal production cost of PV or wind farms. Measuring the systemic cost of renewables, we should add to the equation the cost of complementary dispatchable production as well as the necessary grid investment, which would be higher in many hours than dispatchable baseload. This means that the more intermittent RES are put in the electricity system, the higher the cost of maintaining the energy system. The suggestion from the European Commission to put, even more, weather-dependent RES on the market would unfortunately not result in lower energy prices. One can argue that at high prices, industrial-scale energy storages would replace gas-fired plants or hydrogen, but they would never be cheap. As more and more coal (rightly) and nuclear (wrongly) capacities are forced out of the system, the RES+balancing+grid ratio in the final price grows, leading to ever-higher systemic costs.
Conclusion number 2: green energy is not cheap energy from a systemic perspective. The concept of accelerated green transition by the Commission is meeting cruel market reality. It is easier to blame Russia than to admit policy mistakes.
Potential solution and the way forward
Neither politicians nor consumers like skyrocketing energy prices in net importer countries. Market design and regulation could constantly be updated, taking into account new lessons from new realities. How to aim for long-term gas price stability?
Let’s move from oil indexation or fully spot gas prices to a sound formula that is connected to long-term reality. Upstream companies project the cost of extraction, sales volumes and revenues before they start developing a new field and they prefer stability in selling volumes and having stable revenues. TSOs know the costs of transporting the gas. So why not contract specific amounts of gas (for example, 70-80 per cent produced) from a given field for the economic life-cycle of the given field according to a formula which includes reasonable profit for the producer and long-term price stability and long-term planning transparency for the customer? Like in the case of baseload electricity, baseload gas (for example, 70-80 per cent of procurements) could be contracted for long-term in line with real fixed and operational costs and for the remaining flexibility the spot market would remain applicable. This would facilitate long-term strategic partnerships among producer and consumer companies, detached from oil price cycles.
As for electricity, all CO2-free production options should be supported, and support should prioritize dispatchable technologies. It is high time to include nuclear and natural gas into the sustainable finance taxonomy.