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The decarbonisation of natural gas and Europe’s energy security

The envisioned decarbonisation of the European economy by 2050 is set to change the very nature of the internal gas market, raising questions about the pertinence of supply security and a potentially renewed paradigm regarding the EU’s relations with existing and emergent suppliers.

Following the Russia-Ukraine gas tiffs of 2006 and 2009, the concept of supply security rose in prominence. A legislative round, introduced with the Third Energy Package, consequently aimed at the establishment of a well interconnected and diversified EU gas market. Special attention has always been paid to the extension of this acquis communautaire to membership aspirants, or simply partner countries, of the Western Balkans and Eastern Europe.

The role of natural gas in a decarbonisation context

In light of its Paris commitments, the EU has, since 2015, listed decarbonisation among the five closely related and mutually reinforcing Energy Union dimensions. Concerning the gas sector, this dimension translates into progressively higher penetration of green gases into the system (including biogas, biomethane, syngas, natural gas-sourced/renewable electricity-sourced hydrogen).

In order for European gas to sustain its flexibility in the thick of decarbonisation, a cross-sectoral market and system approach, interlinking electricity and gas, or else sector coupling, would be of value.

In this context, it is believed that, by 2030, gas-fired generation can offer a cost-effective way to reduce CO2 emissions and a needed back-up to RES, especially during peak demand periods. Towards 2050, it will have to be gradually replaced by green gases.

Existing and proposed gas infrastructures (interconnectors and storage facilities), supported or paid for by the EU for supply security and market integration purposes, may initially serve as accommodators of biomethane or hydrogen admixtures and, subsequently, be retrofitted into dedicated infrastructures, instead of being turned into stranded assets.

Throughout the transition to liquid and competitive markets in green gases, reliance on regulation pertaining to unabated gas represents a natural starting point. Ahead of the release of the Gas Decarbonisation Package in 2021, proposals by the European Commission on a hydrogen strategy and the revision of the 2013 Trans-European Networks for Energy (TEN-E) regulation do some rudimentary groundwork in this respect.

Issues deserving greater consideration range from network operators’ role in an early market development stage, depending on precise definitions of activities such as the conversion of renewable electricity into hydrogen or hydrogen storage – once hydrogen is designated for re-electrification – to certification and tariff configuration, subject either to the broadening of the scope of the recast renewable energy directive (RED II) or the review of gas legislation.

Regarding the infrastructure per se, the questionable cross-border relevance of small-scale projects integrating green gases, as well as the involvement in a decentralised energy system of an array of market participants other than TSOs, on which the Ten-Year Network Development Plan (TYNDP) scenario process is based, highlight the need for a broader optimisation of the EU toolkit by means of time-limited derogations and tailor-made provisions for project promoters to kick-start the market.

Detailed analysis of the regulatory outlook can be found in sections 4 and 5 of my latest USAEE/IAEE working paper.

Challenges towards conventional gas market integration

Until the gas decarbonisation policy components are refined, conventional gas market integration, entailing both software and hardware challenges, should not be abandoned.

Implementation of transboundary infrastructures (interconnectors and LNG terminals), encapsulated in the Southern and Vertical Gas Corridor projects and promotion of gas-on-gas competition are especially important for the seamless depoliticisation of gas trade in the vulnerable regions of Southeast and Central and Eastern Europe, easing their bottlenecks and granting Europe as a whole access to alternative (Caspian, US and the Black Sea) gas supplies.

Moreover, adoption of software precepts, safeguarding liquidity, competition and price integration, will be critical, particularly for ill-liberalised countries in the discussed regions, so as to ensure a level-playing field for market actors wishing to enter the decarbonising gas market.


Implementation status of the EU gas market acquis in the Energy Community. Sources: ECS and author’s personal notes kept during the 15th Energy Community Gas Forum. Presented in: M. Ydreos and M. Liakopoulou, 2020. Gas Market Integration and Decarbonisation in SEE and CEE. IAEE Webinar Series: https://www.iaee.org/en/webinars/webinar_liakopoulou.aspx

Towards a new external gas policy paradigm for the EU

The first question arising is whether a less concentrated energy system, which shall alone be flexible enough in stress incidents thanks to domestically generated green gases, leaves room for external suppliers. The answer is that localised production and self-sufficiency will have to be complemented by cross-border trade.

Traditional low-cost suppliers, such as Russia and Norway, are experimenting with NG-sourced hydrogen through carbon capture and storage and pyrolysis projects. This may lead to regional concentration of trade in green gases via repurposed natural gas links.

The emergence of new suppliers will depend on factors such as production locations, transport technologies and the distance from – and infrastructure at – reception points. For instance, typical oil and gas transit states, like Belarus and Ukraine, may assume biomethane and hydrogen exporting roles. Also, countries with abundant renewable energy, like Morocco or Algeria, have comparative advantages in RE-sourced hydrogen production and can turn Mediterranean M-S into future hydrogen hubs.

Meanwhile, large-scale system decarbonisation through green gases could alter the conventional energy security motif into one of geopolitical competition over the production of energy resources, rather than over mere access to them, as exemplified by the EU-China competition over global supremacy in electrolyser manufacturing.

The penultimate question relates to the optimum governance model for third-country gas dossiers. Given the open-ended development of technologies surrounding green gases and the relatively sketchy mapping of coalitions that the EU is able to make at this point, a composite pattern, involving both the Commission and the Council, may prove beneficial so as to keep the policy and regulatory dialogue open with potential third-country exporters to the EU.

Final question: can geopolitics prevail over sustainability in the EU’s future external gas relations? The answer is no, as long as the regulation builds “security valves”, like guarantees of origin (GOOs) and the carbon border adjustment mechanism (CBAM), safeguarding compatibility of traded green gases with specified GHG standards and pressuring third countries to eventually limit the amount of CO2 they export to the EU.

Conclusions

During a transitional period, in which policy-makers and consumers will be dealing with regulatory questions on sector coupling, the EU is prompted to address relations with its key external gas suppliers by:

  • Ensuring finalisation of strategic infrastructures, symmetrical geographic dissemination of the acquis and smooth depoliticisation of gas trade by 2030;
  • Identifying suppliers’ role between 2030-2050. These could act either as producers and exporters of green gases or as mere providers of the infrastructure to transport these gases, given the “insourcing” characteristic of the latter within a decentralised energy system.

This op-ed is a summary of the author’s latest working paper for the Research Paper Series of the US Association for Energy Economics and the International Association for Energy Economics, which can be accessed here.

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