Security of Supply in the Decarbonization Era: Assessing an Emerging External Gas Policy Paradigm for the EU
1. Evolution and goals of the EU gas market
Against the backdrop of the 2006 and 2009 interruptions in Ukrainian transit, the EU has progressively equipped itself with the institutional tools to ensure steady gas supplies, the equitable application of competition rules in the internal market and the implementation of the Churchill-enunciated diversification concept, in order to reduce the scope for political uses of energy, a long-time thorn in its external gas relations.
From the transition to the new market approach of the Third Energy Package (TEP), whereby vertically integrated undertakings would no longer simultaneously control production, supply and transport activities, to the adoption of its Network Codes, the Bloc has remained firm in its determination to establish an interconnected market characterized by:
a) Multiple entry points and reverse flows;
b) Mature and liquid hubs in its less liberalized zones, namely Southeastern and Central and Eastern Europe (SEE/CEE), by completion of vertical (South-North) and horizontal (East-West) gas corridors, which will, furthermore, be supported by flexible, short-term LNG trading, in order for the various market operators to be able to balance their positions and for cross-country price convergence to be effectuated;
c) A spirit of solidarity and regional coordination to avoid or mitigate the impact of a potential malfunctioning of the gas system in one or several Member-States (M-S).
2. Decarbonization as an Energy Union dimension
Meanwhile, its 2°C, and possibly 1.5°C, commitments under the Paris Agreement have led the EU to encompass decarbonization among the Energy Union dimensions, abreast of energy security, internal market, research, innovation and competitiveness. In this context, it ramped up work on the Clean Energy for all Europeans Package that introduces efficiency and renewable targets for 2030, both subject to upward revisions in light of the new Commission’s Green Deal, as well as an improved electricity market design in support of the penetration of renewables in the energy mix.
It also links the security aspect concerning the utilization of existing and incremental pipeline capacity, the deployment of which mostly depends upon the Union’s external suppliers, with the so-called Integrated National Energy and Climate Plans (NECPs).
3. Security of supply in an electron-based world
Therefore, it is evident that the aforementioned gas market restructuring, in conjunction with the regulatory initiatives for an electron-based future, entail broad implications for the security-of-supply architecture on the road towards the climate- neutral economy of the 2050s, as envisaged in the Commission’s homonymous long-term strategy.
Despite the fact that the in-country generated renewables do not form part of security-of-supply discussions, unlike the largely commoditized natural gas, it is of particular interest to examine whether the European gas market’s flexibility challenge moreover necessitates a cross-sectoral market and system approach, covering both electricity and gas transmission infrastructure. Sector coupling, i.e. the interlinkage between the gas and electricity sectors with the aim of integrating the growing share of variable renewable energy, has already been presaged in the 2013 TEN-E regulation, the 2015 Gas Target Model, the 2018 and 2019 joint assessment scenarios by the ENTSOs on their ten-year network development plans (TYNDPs), and is going to be a key component of the 2020 Gas Decarbonization Package.
Amid the phase-out of coal under the Emissions Trading System (ETS), gas-fired generation offers a cost-effective way to reduce CO2 emissions and a needed back up to renewables, especially during peak demand periods. The relatively low capital costs of new plants and its ability to ramp generation up and down quickly – a fundamental feature in systems with abundant solar and wind power- are gas’ main advantages for power generation. On the other hand, the ability of the fast developing zero-marginal-cost solar and wind generation to put downward pressure on wholesale electricity rates for fossil fuel plants in liberalized markets experiencing either flat or declining power demand is not to be overlooked.
Still, gas can serve as a long-term low carbon solution if converted to blue hydrogen, via carbon capture and storage (CCS) technologies, and/or if surplus renewable energy is converted to green hydrogen, via power-to-gas technologies. The same goes for the locally nurtured biogas production and biogas-to-biomethane upgrading techniques, like anaerobic digestion and thermal gasification, although these appear costlier than the present natural gas price.
Europe’s gas network, gradually extended with investments featuring on the Projects of Common Interest (PCI) lists, could be the means of transporting clean gas to remote areas (interconnectors) and of managing the temporal and intermittent nature of renewables in order for demand to be met (storage facilities). It is believed that the role gas has to play particularly in the EU’s mobility and industry sectors will provide the reliable, baseload demand that can underpin upstream and midstream activity by external supplier countries.
4. Natural gas and the energy transition
Large-scale value chain co-operation is a sine qua non for gas market decarbonization, so that networks and customers become receptive to low-carbon gases. Current and prospective gas infrastructures that have been supported or paid for by the EU for security of supply and market integration reasons, and are capable of shipping appreciable volumes efficiently over long distances, should be taken on board throughout the establishment of the new energy policy paradigm, instead of being turned into stranded assets. At the same time, this shift should not undermine the functioning of the internal market. To this end, attention should be placed on regulatory issues, such as:
a) The application and adaptation of the unbundling principle, in terms of the access of TSOs and/or DSOs to the system;
b) The potential for inclusion of power-to-gas projects in future integrated TYNDPs;
c) Possible modifications of the Network Codes on Capacity Allocation Mechanisms and on Harmonized Transmission Tariff Structures, so that TSOs are able to consider the entailed expenses and the specifications of bids while elaborating their regional investment plans, as soon as these will end up covering the future gas grid, which will be capable of accepting either biomethane or hydrogen, or a mixture of both, along with unabated gas;
d) Transparency and non-discrimination in connecting renewables to the gas network and evaluation on the part of M-S of the need to extend their grids for this purpose, in line with the recast RES Directive;
e) The management of cross-border trade restrictions, resulting from different gas quality standards, with the help of the Network Code on Interoperability and Data Exchange and/or with the incorporation of a binding target for renewable and decarbonized gases in the Gas Decarbonization Package. In this respect, the re-evaluation of the parameters set out as part of the mandate to the European Committee for Standardization in the field of gas qualities bears special importance for producers and final consumers alike;
f) The replication of a standardized guarantees-of-origin system, like the one already in place for electricity, upon which certificates enabling the tracing of renewable gases for the purposes of a smooth subsidization process will be based;
g) The adjustment of the solidarity principles provided for by the 2017 Security of Supply regulation, so as to handle possible shortages of the new products, to be carried by national and regional networks;
h) The regulation of gas-on-gas (GOG) competition, generated through traded hubs, in the early decarbonization phases, when clean gas sources will still be scarce.
5. Towards a new external gas policy paradigm for the EU
Until the above points are dealt with, the EU has to take several shorter-term steps regarding the overhaul of its conventional gas market as we know it.
Bearing in mind both the reduction of the excessive number of carbon allowances under the reformed ETS and the fall in indigenous output (which might to a certain extent be offset by power-to-gas innovations) in the aftermath of the Groningen gas caps, M-S are bound to remain reliant on gas imports from third countries like Russia, Norway, Algeria and the Caspian littoral states. It is for this reason that supply diversification has to be attained until 2030, a period where unabated gas demand (with its distinctive seasonal behavior) is expected to stay above 400bn m3/yr.
Finalization of or progress on the initiation of transboundary projects (interconnectors and LNG terminals) is critical, mainly for vulnerable parts of the continent, namely M-S of SEE and CEE, the Western Balkan accession aspirants and the Energy Community contracting parties, where gas demand has room for growth and where single-source dependency apprehensions trump economic concerns emanating from the international low commodity price environment.
This is also where the northwestern market pattern, indicating the moving away of price formation from oil indexation to GOG competition, needs to be exported, in view of the forthcoming expiry of long-term contracts (LTCs), signed by European companies with external producers at the onset of the 21st century to assure governments of their reliability in furnishing security of supply, in fear of a future significant gas deficit.
The Southern Gas Corridor (SGC) and Vertical Gas Corridor (VGC) supply chains constitute la raison d’être for the building-up of the discussed infrastructure, opening the doors for alternative (Caspian, US and Black Sea) supplies to Europe and contributing to the achievement of a “fully interconnected and shock-resilient gas grid by 2020 or shortly thereafter”, as conceptualized in the Fourth Report on the State of the Energy Union.
Apart from putting the necessary hardware in place, the EU must also monitor the even implementation of the energy acquis by M-S and membership hopefuls alike, in order to seamlessly depoliticize its external gas relations. The advancing endorsement of the TEP-associated Network Codes and Guidelines in both electricity and natural gas by the Energy Community represents a strong example of this.
Consequently, two essential questions arise:
a) Will the EU’s traditional suppliers willingly abide by the state of play in the internal gas market, dictating an even geographical diffusion of software and hardware precepts?
b) Will they manage to find a place for themselves in the post-2030 situation of the internal market, or will imported unabated gas be massively replaced by indigenous electrons, that is, renewables exclusively produced within the EU?
6. Possible scenarios
The answer to the first question would probably be positive, based on factual evidence. The recent resolution of long-standing commercial disputes, most notably the settlement of the Commission’s antitrust case against Gazprom without fines, serve as proof that the gas group has become aware of the emerging competition between LNG and pipeline gas, and is gradually opting for a more flexible, destination-free marketing approach. This is further reinforced by the spot indexation of a tangible amount of its LTCs and the launch of its Electronic Sales Platform in late 2018.
The answer to the second question varies according to different parameters. For one thing, a decentralized energy system with numerous vectors is alone able to demonstrate greater flexibility in stress incidents. This especially relates to the local, small-scale production of biogas and biomethane that have similar qualities with natural gas and require minimum infrastructural adaptations, compared with hydrogen.
As per the ENTSOs’ joint Scenario Report for the TYNDP 2020, decarbonization will lessen the EU’s primary energy import dependency to circa 20%-36%, however imports of competitive natural gas resources outside the EU territory are expected to have an impact on the future energy supply until 2030. Simultaneously, the potential for imports of green gases remains on the horizon, bringing along the usual supply security implications.
For instance, a study by van Melle et al. (Ecofys, 2018) suggests that Ukraine and Belarus, two countries with existing pipeline connections to the EU, could contribute up to 20bn m3/yr of biomethane to the intra-EU output. But what about the EU’s traditional (quantitively and strategically) gas suppliers?
In theory, Russian firms could respond to demand for clean gas by decarbonizing at the extraction points and by shipping to Europe through the existing and under construction (Nord Stream 2, second string of Turk Stream) northern and southern pipe corridors.
Nevertheless, this also presupposes major changes in their export business models, and in Russia’s domestic market itself, which certainly require time, as well as intensified multilateral deliberations on the level of the EU-Russia Gas Advisory Council and/or other formats. For instance, technologies for CO2-free hydrogen production from methane, already pondered by Gazprom, could sustain European gas import demand and minimize the need for expensive CCS investments, however they’re still stalled at their R&D stage, while uncertainty prevails over the technical modifications required to pipelines.
Norway’s Equinor, taking into account the lifecycle of its North Sea assets, is more active in pursuing CCS practices, in partnership with international oil companies (IOCs). It came as no surprise that the idea of Equinor, Shell and Total on the very first cross-border CO2 storage project, originally linking Eemshaven in the Netherlands and Teeside in the UK with Norway’s Northern Lights storage site, won the support of a number of industrial companies during the first European high-level CCS conference, that took place in Oslo in September.
As the executive vice-president for sustainability at SINTEF, Scandinavia's largest independent research institute, Nils Anders Røkke, recently stated, Norway could convert about 850-950 TWh (out of the 1,400 TWh of natural gas it currently exports to Europe) into blue hydrogen, stored in the country.
At the other end of the spectrum, such diversification strategies are yet far from the agenda of the hydrocarbon-rich Caspian countries, the first gas from where (Azerbaijan’s Shah Deniz 2 project) is scheduled to reach Europe in 2020 via the Trans Adriatic Pipeline, the SGC’s European segment. A plausible explanation for this has to do with their under-explored deep-sea acreage, made all the more unattractive to IOCs by to the appeal of the short-cycle shale hotbeds and to public pressure to decrease their greenhouse gas (GHG) footprints. This is topped by the region’s complex geopolitics, involving US, Russian and Chinese influence over the littoral countries that have so far prevented the already available gas from getting to Europe, preferably via a subsea Trans-Caspian pipeline.
Finally, questions naturally surround the sanctity of the contracts already in force between the EU and each of its chief gas suppliers, in terms of likely violations of provisions safeguarding the quality of the gas delivered, able to bring about either an outright refusal of the final product or fines by purchasers and/or TSOs. The setting of clear-cut targets referring to the injection of low-carbon gases into the grid, in step with the afore-described policy recommendations (Section 4), will facilitate the conclusion of such supply contracts in the future.
7. Conclusions
The EU’s vision for a decarbonized economy by 2050 is foreseen to induce appreciable changes in the condition of its gas market, where a homogeneous fuel is presently distributed via a uniform grid. The Gas Decarbonization Package promises to give a greater sense of direction to policy makers and citizens apropos of regulatory questions associated with sector coupling.
This transitional phase will prompt the EU to redefine its external gas policy paradigm vis-à-vis its key suppliers in two steps:
a) by finalization of strategic infrastructures, symmetrical dissemination of the acquis and complete depoliticization of gas trading by 2030,
b) by identification of the suppliers’ role between 2030-2050, either as producers of decarbonized gases, or as mere providers of the infrastructure that will be used to transport these gases, given their “insourcing” trait in the context of a less concentrated energy system.
The EU’s relations with external suppliers are therefore set to tighten in light of the positive stimulus to unabated gas consumption because of the phase-out of coal, the declining European production and the need for a complement to fluctuating renewables. That is why Europe is compelled to evenly promote gas market integration to its most vulnerable geographical areas in order to safeguard security of supply. In the medium-term, diverse factors, ranging from the outcome of gas market decarbonization in the EU to corporate and political developments in supplier countries, will determine the ability of the latter to deliver sustainable, secure and clean energy products.
Full text available online at: https://www.naturalgasworld.com/eu-decarbonization-security-of-supply-gas-policy-74708
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