In the past few weeks, capacity mechanisms have been one of the most widely debated issues both in European political energy circles and even among policy-makers in North America. On 15 November 2018, the European General Court (EGC) issued a landmark ruling leading to the suspension of the UK capacity market, while later that month, the US Federal Energy Regulatory Commission (FERC) unanimously rejected a proposal from independent generators in favour of establishing a capacity market for the California ISO (CAISO) area.
Early December, just before COP24 in Katowice, Poland, disagreements on the future of European capacity mechanisms prevented EU negotiators from agreeing on the proposed Directive and Regulation on the internal market for electricity. The next round in Brussels is scheduled for 18 December…
Landmark EGC decision suggests that it might be time to rethink capacity market design
On 15 November 2018, the EGC issued a landmark Ruling, which led to the suspension of the UK capacity market. The Ruling was based on the grounds that the EC had not adequately scrutinized the British proposal when it was originally sanctioned under EU State Aid rules in July 2014 (see news of November 15, 2018; “Landmark ruling in favour of DSR provider Tempus Energy confirms generation bias in UK capacity market design.”).
The EGC found that the EC’s assessment of the compatibility of the UK aid measure gave rise to doubts within the meaning of Article 4 of Regulation No 659/1999. This should have led the EC to initiate the formal inquiry procedure referred to in Article 108(2) TFEU. The EGC further identified the inadequacy of the length and circumstances of the pre-notification phase, and the incomplete and insufficient content of the contested Decision as evidence that the EC adopted its position despite the existence of doubts.
It is important to note that the UK capacity market was the first to be sanctioned under the new European Guidelines on State Aid for environmental protection and energy (EEAG) 2014-2020 (OJ 2014 C 200/1), which, for the first time, included compatibility criteria for generation adequacy. Since then, the EC has applied the new EEAG in six other investigations into capacity mechanisms, namely in Belgium, France, Germany, Greece, Italy and Poland, all of which were approved in February 2018.
The EEAG (para. 224(b) (3.9.2), ‘Need for State intervention’) require the EC to take account inter alia of the “assessment of the impact of demand-side participation, including a description of measures to encourage demand-side management”.
The EEAG (para. 226 (3.9.3) also require that measures “should be open and provide adequate incentives to both existing and future generators and to operators using substitutable technologies, such as demand-side response or storage solutions. The aid should therefore be delivered through a mechanism which allows for potentially different lead times, corresponding to the time needed to realise new investments by new generators using different technologies. The measure should also take into account to what extent interconnection capacity could remedy any possible problem of generation adequacy”.
In addition, a “competitive bidding process on the basis of clear, transparent and non-discriminatory criteria, effectively targeting the defined objective, will be considered as leading to reasonable rates of return under normal circumstances” (EEAG para. 229 (3.9.5)).
The EEAG finally require that “the measure should be designed in a way so as to make it possible for any capacity which can effectively contribute to addressing the generation adequacy problem to participate in the measure, in particular, taking into account (…) the participation of generators using different technologies and of operators offering measures with equivalent technical performance, for example, demand side management, interconnectors and storage” (Para. 232(a) (3.9.6)).
The EC Decision at the time sanctioned 15-year capacity agreements for new generation plants based on the results of a study on capacity market design conducted by the UK government and system operator, National Grid. Said study also found that existing plants and demand-side response (DSR), in view of their lower capital cost requirements (indicative of a reduced need to secure financing) should not benefit from longer contract periods. The Decision thus appears to assume that shorter contracts do not put existing plants and DSR at a disadvantage compared to new generation.
The DSR provider Tempus Energy Ltd.’s recourse before the EGC in first instance was built upon the claim that the EC unlawfully deprived the applicant of its right to participate in the investigation procedure by failing to open a formal investigation into the compatibility of UK capacity market design with the EEAG, notwithstanding the question of whether the capacity market itself was compatible with the internal market within the meaning of Article 107(1) of TFEU. On this last point, the applicant cited, in particular, long contract durations awarded to new generators and the importance of the distinction between price takers and price makers as potential factors that the EC should have examined more closely when coming to a Decision.
Tempus Energy’s second action before the EGC included two additional pleas, namely (i) the alleged failure by the EC to provide adequate reasoning for its Decision, thereby violating Article 108(2) TFEU, which enshrines in Treaty Law the principles of non-discrimination, proportionality, and legitimate expectation; and (ii) the EC’s alleged failure to adequately assess the facts by not opening a formal investigation per Article 93(2) TFEU.
In response to written questions put by the EGC, Tempus Energy confirmed that it did not contest the establishment of a capacity market as such. Rather, Tempus Energy was contesting the assessment of the elements provided by the UK regarding the role of DSR in accordance with the EEAG, as well as the procedures envisaged to allow DSR operators to participate in the capacity market. This has implications for any examination of the potential for interconnector capacity and the participation of the following DSR technologies in the capacity market: (a) direct load control; (b) embedded generation; (c) standby generation; (d) demand response; (e) energy efficiency; (f) fuel substitution (e.g., burning gas instead of electricity); (g) interruptible loads; (h) integrated DSM project (such as using the batteries of parked electric cars as reserve power); (i) load shifting; (j) smart metering; and (k) power factor correction.
Furthermore, Tempus Energy argued that the amount of generation capacity available from the first T‑4 capacity market auctions (which contract capacity for a four-year ahead period) should have been reduced to avoid wasting public resources and to avoid over-investment in new generation capacity. The fact that DSR operators could participate in T‑1 auctions (which contract capacity for a maximum of 1 year) was insufficient to compensate for that situation, given the low capacity reserved for those auctions and the government’s commitment to reduce, if possible, the ‘amount of capacity to procure in the year-ahead auction planned in 2017’. Under such circumstances, generation from fossil fuel plants would be ‘locked in’ from the outset, thereby potentially limiting capacity that may otherwise have been provided by growing shares of DSR.
Tempus Energy also argued that an entry threshold of 2 MW for DSR aggregators wishing to participate in the capacity market (which applies exclusively to DSR operators) is far higher than for capacity markets elsewhere, such as the Pennsylvania Jersey Maryland (‘PJM’) capacity market and the New York Independent System Operator (‘NYISO’), where the entry threshold is 20 times lower at 100 kW.
Since 2014, the EC has been reviving efforts to address the uncoordinated proliferation of capacity mechanisms, both from a regulatory and a competition perspective. These efforts led the EC to launch a public consultation in mid-2015 on a new energy market design and to issue a questionnaire on risk preparedness in the area of security of electricity supply. On 29 April 2015, the EC’s Directorate General for Competition also opened a sector inquiry into State aid rules (the results of which were published on 30 November 2016) so as to gather information from Member States and other stakeholders on the design and use of capacity mechanisms as well as their potential to distort cross-border trade and competition.
The EGC ruling rightfully suggests that governments at all levels would do well to take into account the potential of DSR technologies to minimise the overall cost of ensuring security of supply. To realise said potential, regulators will have to re-examine the fundamental principles that underlie any capacity mechanism assessment, including: (i) how to define bidder eligibility; (ii) how to set the price of capacity and select providers; and (iii) the nature of the obligations and penalties on contracted parties. While the challenge of establishing as much for such a new and distributed technology is significant, policy-makers must respect the fundamental role that European competition law ought to play in facilitating energy market liberalisation, increasing the competitiveness of European industry, and decarbonising the EU economy.
The EU capacity mechanism debate in light of COP24
The contentious future of capacity mechanisms in Europe is also one of the key points still to be negotiated at the sixth trilogue (18 December) on the proposals for a Directive and Regulation on the internal market for electricity. On 05 December, an all-night fifth trilogue negotiation failed mainly due to major disagreements on capacity mechanisms between the EP and the Council.
The primary issue of divergence is the EC’s proposal to set a CO2 emission limit of 550gr CO2/kWh for participants in a capacity mechanism, which some Member States have set up to remunerate stand-by power plants to be used if needed to meet electricity peak demand.
The 550gr CO2/kWh limit essentially excludes from the mechanisms the most polluting power plants, such as coal-fired power stations. While both EP and Council negotiators agree with the proposal in terms of the temporary nature of the mechanisms and the CO2 limit concept, they do not agree on the timeline for its effective implementation and eventual phase out.
The EP is pushing for generation plants that started commercial production after the date of entry into force of the Regulation to be eligible to participate in a capacity mechanism only if their emissions are below 550gr CO2/kWh, with the exception that “strategic reserves generation capacity emitting 550gr CO2/kWh or more shall not be committed in capacity mechanisms after [5 years after the entry into force of the Regulation]”. This proposal is roughly in line with the original 2016 EC proposal when the “Clean Energy for All Europeans” Package was first published.
On the other hand, the latest Council proposal supports the position that a generation plant “emitting more than 550 gr CO2/kWh of energy and more than 700 kg CO2 on average per year per installed kW that started to provide electricity to the grid after [date of entry into force of the proposed Regulation] shall not receive payments or commitments for future payments under a capacity mechanism as of 31 December 2025”. Additionally, a plant with similar characteristics which “started to provide electricity to the grid before [date of entry into force of the proposed Regulation] shall not receive payments or commitments for future payments under a capacity mechanism as of 31 December 2030, except for contracts with a remaining duration of not more than 5 years concluded before 31 December 2030”.
This latter proposal essentially extends the phase-out date up to 2035, putting it on a collision course with the EP’s more short-term focused position and also making it not fully aligned with the EU’s climate and carbon reduction targets for 2030 and beyond, as exemplified by the previously adopted files of the Clean Energy Package and the recent EC proposal for a 2050 EU Climate Strategy.
Despite the EC’s efforts to strengthen the EU climate position ahead of the 24th Conference of the Parties to the UN Framework Convention on Climate Change (COP 24) in Katowice, Poland (see news of December 04, 2018: ‘The new EC Climate Strategy – a rocky road to climate neutrality’), the failure to reach a sustainable solution for the future EU internal power market taints the climate leadership ambitions of the bloc.
During the major two-week climate summit, policy-makers from around the world adopted a framework for the implementation of the Paris Agreement goal of keeping global warming “well below 2°C”, which also includes agreement on the financial for financing climate mitigation efforts. Overall, many observers consider the achieved agreement on the so-called “rulebook” as disappointing and not ambitious enough.
These battles over capacity markets in Europe showcase the impact that increased penetration of RES has on the finances of conventional generators and the present energy system order. Some capacity mechanism proponents point out that by supporting further renewable energy policies and limiting traditional existing generators, policy-makers are increasing the electricity price for their constituency who pay for the development of new RES.
Such higher prices, which tend to be unpopular with some layers of society, can be mitigated to some extent by using extra capacity temporarily provided by existing gas power plants in the short-term. Capacity mechanisms should be used only as a last resort and phased out as soon as possible. Given the current market design, regulatory framework and financial issues in some EU Member States, opting for a temporary capacity mechanism should also not obstruct the development of needed flexibility tools.
Considering the urgency of appropriately tackling climate change, policy-makers need to quickly align and eliminate all kinds of subsidies that would continue to provide undue and unnecessary advantages to polluting fossil fuel plants.