A RAP Power System Blueprint Deep Dive
Capacity markets — six mitigations for six drawbacks
Dominic Scott, Bram Claeys & Zsuzsanna Pató
Summary
This deep dive — accompanying RAP’s Power System Blueprint for a clean, reliable, equitable and affordable power system by 2035 — provides insights on drawbacks of and accompanying mitigations for different capacity remuneration mechanismscapacity remuneration mechanisms A regulatory scheme under which payments are made to generators, load and storage (and often interconnectors) to provide capacity availability during a specific time period (to top up revenues earned in energy markets) with the aim of ensuring resource adequacy. Costs are usually recovered from customer bills via retail suppliers. (CRMs).Over the last decade Europe has witnessed the growth of CRMs — tools intended to provide added confidence of adequate resource when demand is forecasted to peak.
RAP has documented long-standing concerns with certain CRM interventions, in particular, forward capacity market auctions. RAP advocates instead a more transparent and consumer-focused energy adequacy approach that is better suited to the needs of a decarbonising power grid, including implementation of administrative reserve scarcity pricing, a mechanism that values reserves in real-time energy prices equivalently as in operation planning timeframes. As part of a coherent suite of measures, such a mechanism provides confidence that prices and price volatility will adequately reflect the increasing risk of loss of load and the associated opportunity costs of an additional unit of energy demand as resource margins tighten. This mechanism thereby incentivises both sufficient security of supply responses in real time and investment by market buyers and sellers in cost-effective additional supply or demand-side measures.
While recent European regulations promote reserve scarcity pricing as a baseline design feature and, ideally, a superior solution to resource adequacy concerns, ongoing Electricity Market Design discussions could yet conclude by accommodating these interventions more readily in market arrangements. Capacity mechanisms are likely to be an important feature of the European electricity landscape over the next decade.
Recognising this reality, this deep dive highlights selected drawbacks of interventions — capacity auctions feature prominently here — to shed light on how these may be mitigated. The analysis builds on criteria linked to both efficiency and competition, draws on experiences from North America, Europe and farther afield and links with RAP’s blueprint guidance on optimal resource adequacy and scarcity pricing.
Mitigations identified in this quick tour can help temper the negative effects of various capacity remuneration mechanisms. They are, however, largely inadequate in fully overcoming these effects where they pertain to capacity auctions. Some of the most fruitful mitigations involve putting in place a reserve pricing function. Although these come with their own challenges, these may be quite readily mitigated.
Overall, this points to the value of implementing the right intervention in the first place, the no-regret nature of reserve scarcity pricing functions and the value in institutionalising in network codes the implementation of administrative reserve scarcity pricing — before resource adequacy becomes a concern.
Table of Contents
Relevant Factsheets:
Interventions and European developments
CRMs that support capacity adequacy include (broadly decreasing in degree of intervention):
- Centralised forward capacity auction. The amount of capacity to be procured is set for a period, ranging from months in some cases to many years in others, by a central authority, typically the minister for energy under advice from the system operator. The system operator procures this in a competitive auction. The auction determines the price pocketed by contracted capacity, without any undertakings by buyer or seller regarding the price to pay or to be paid for energy. Auctions can be market wide (restricted to resources capable of meeting the stipulated requirements) or explicitly restricted to particular types of capacity.
- Centralised reliability options. This is a centralised forward capacity auction, with the refinement that during periods of scarcity, contracted capacity must return wholesale market rents above a predetermined strike price, usually to the system operator. Contracted capacity providers receive a revenue stream determined through the capacity market auction.
- Capacity obligation. A decentralised variation on the forward capacity auction, it delegates to retailers the decision of how much capacity to procure, subject to financial penalties, to demonstrate adequate resources under contract to cover their requirements during periods of peak demand. Penalties are set centrally, which indirectly affords the central authority the ability to influence the level of forward procurement. In some approaches, capacity auctions in advance of delivery years may be organised by the system operator, while in others the retailers may be left to conclude their own contracts.
- Capacity payments. This adds a top-up payment — administratively determined rather than by auction — to energy revenues to monetise the value of available capacity not captured in energy and ancillary service revenues. More static designs may calculate the capacity payment via an end-of-year assessment by a system operator or regulator, of rents required by the marginal resource to recover all their costs, after accounting for their revenuesafter accounting for their revenues As previously was the case in Ireland for example.. As procurement must happen through a competitive, market-based processes, capacity payment schemes are being phased out.
- Administrative reserve scarcity pricing. This more dynamic type of capacity payment provides — in each settlement period — an adder to wholesale prices, reflecting the combined demand for energy and reserves and the resulting marginal value of an additional unit of supply during periods of reserve scarcity.
- Strategic reserve. This provides for a certain amount of capacity — typically otherwise exiting the market — to be remunerated for availability and held outside the market so that it can be called upon in emergency situations. This is targeted rather than market wide.
Some jurisdictions have not implemented any intervention, choosing to rely on a market without capacity supplement (such as Netherlands or Denmark).
Table 1. Types of intervention: Capacity Remuneration Mechanisms
| Scope | Capacity volume determination | Basis of payment to resources | Examples | ||||
|---|---|---|---|---|---|---|---|
| Targeted (T) or wide (W) | Revenues available to all parties able and willing to contribute to resource adequacy | Centralised | Decentralised | MW | MWh | ||
| Capacity market — capacity auction | W (or much of market) | 🇬🇧 🇵🇱 Great Britain & Poland, proposed or under evaluation in Spain, Lithuania & Greece 🇪🇸 🇱🇹 🇬🇷 |
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| Capacity market — reliability option | W (or much of market) | 🇮🇪 🇧🇪 🇮🇹 Ireland, Belgium & Italy |
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| Capacity obligation | W | 🇮🇹 🇦🇺 France & Australia |
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| Capacity payments | W | 🇬🇧 🇮🇪 🇵🇹 Great Britain (1990-2001), Ireland (2007-2018) & Portugal |
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| Reserve scarcity pricing | W | 🇺🇸 Texas |
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| Strategic reserve | T | () | 🇩🇪 🇫🇮 🇸🇪 Germany, Finland & Sweden |
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Administrative reserve scarcity pricing can be implemented in tandem with any system, as can a strategic reserve. Indeed, following failure in Ireland of the capacity marketIndeed, following failure in Ireland of the capacity market This is linked to administrative VoLL of EUR2,500/MWh, 25% of Ireland’s estimate of actual VoLL of 10,000EUR/MWh. (reliability options) to deliver around 650MW new build by winter 2022-2023, the Member State launched an additional strategic reserve, which in turns sits on top of an administrative reserve scarcity pricing function. Similarly, Britain has a capacity (auction) market, with , and an additional strategic reserve for winter 2022-2023. Although not the chief capacity remuneration mechanismcapacity remuneration mechanism A regulatory scheme under which payments are made to generators, load and storage (and often interconnectors) to provide capacity availability during a specific time period (to top up revenues earned in energy markets) with the aim of ensuring resource adequacy. Costs are usually recovered from customer bills via retail suppliers., reserve scarcity pricing is present in some form, at least in Ireland, Britain and Italy, and is under consideration or to be implemented in Belgium, Sweden and Poland, as a condition imposed by the European Commission in accepting the capacity market. With the Electricity Regulation, Member States are now required to “consider” introducing reserve scarcity pricing in the presence of resource adequacy concerns. This regulation does not, however, explicitly require that administrative intervention ensures that real-time energy prices fully reflect the effect of demand for reserves on the likelihood of loss load and thus is relatively weak.
Desirable outcomes
Table 2 presents desirable outcomes that any intervention should support — or at the very least not impede.
Table 2. Desirable outcomes
| A. Efficiency | B. Competition | ||||
|---|---|---|---|---|---|
| A.1. Incentives to be available during scarcity Read more | A.2. Economic volume of capacity in market Read more | A.3. Balancing risk between consumers and investors — cost of capital versus driving optimal investment choices Read more | B.1. Demand-side flexibility — overcoming legacy bias against demand side resources Read more | B.2. Cross-border resources — open to participation Read more | B.3. Level playing field broadly drives optimal capacity mix (technology) Read more |
The first set of desirable outcomes links to efficiency, with a direct link to cost, and its optimal balance with system security. The second set comes under the heading of competition. This also links with cost — in that fair competition is necessary to allow the most efficient resources to provide their value to the system — and thereby also ultimately supports efficiency.
Six drawbacks and mitigations
In this section, we present drawbacks of these interventions — each with a link to one of the listed desirable outcomes — and explore the potential for mitigations to lessen these negative impacts. Concluding comments are followed by a checklist of recommended mitigations.
The history of capacity markets is littered with examples of failure to honour contracts — either failure to build new resources in a timely fashion or to ensure the built plant is available when needed.
The U.S. PJM (Pennsylvania-New Jersey-Maryland Interconnection) system, for example, which has a capacity market, saw 22% of its capacity, chiefly gas and coal, disabled during the polar vortex event of 2014. And though reforms were implemented, including steep penalties for non-performance, the 2022 Winter Storm Elliott saw 46GW (23% of the generating fleet) of capacity unexpectedly come offline on Christmas Eve, 70% of this gas fired. Another recent example is in Ireland, where 650MW of capacity that was successful in capacity auctions failed to build in time for winter 2022-2023. This led to the Irish regulator directing the system operator to secure emergency generation — anticipated to be ready by winter 2023-2024 — at a cost of EUR 350m. Finally, an analysis by ENTSO-E outlook for winter 2022-2023 that indicated system stress, most notably in the French and Irish systemsmost notably in the French and Irish systems Along with the small islands of Malta and Cyprus, and also southern Norway., suggests that the interventions enacted in these countries — among the most vocal proponents of capacity markets — have not necessarily been particularly effective in delivering the intended outcomes of policymakers.
Root causes may be found in lax prequalification requirements that enable “paper projects” (projects too early in their development to warrant confidence) to secure capacity contracts. Security deposits and penalties are often set too low — perhaps purposely so by the government in the hope that this will facilitate entry and lower costs for consumers — which diminishes incentives for plants to deliver on contractual commitments. Exacerbating this may be a perception within government in presence of a capacity market of a diminished need for reform to ensure energy prices reflect scarcity or to address loopholes in penalty regimes. These and other factors may combine to undermine security.
Mitigations
Appropriately exacting prequalification requirements are essential to ensure that only plants with the capability to deliver participate. One requirement could be that plants must be “shovel ready.” Security deposits should also be large enough to discourage plants with immature or risky projects from participating. This should be conducted in tandem with reform to address obstacles in planning and permitting.
Complementing these requirements are penalty regimes that incentivise capacity to price the risk of unavailability into their offers, whether existing buildings or those under construction, and thus motivate action to enhance availability when it matters. This may entail lifting caps on penalties to encompass a significant share of capacity market revenues collected since the last time a performance interval occurred. Sufficiently large bonds can increase confidence that penalties cannot be dodged for new build. Regulatory loopholes that allow contracted parties to evade penalties must be addressed. Supporting all this is reform to ensure energy prices reflect the full value of reserve scarcity through reserve scarcity pricing.
Whilst such steps are necessary, they may not be sufficient. The significant failure of PJM resources in 2022 followed the adoption of significantly strengthened performance bonus and penalty provisions, and during 2021 Winter Storm Uri in Texas, over 40% of planned capacity failed to perform despite very robust reserve scarcity pricing. Such examples suggest the importance of supportive regulations beyond the scope of the electricity market — for instance, in addressing vulnerability to upstream gas infrastructure such as witnessed in Texas.
Interventions that centralise the decision — typically by the minister for energy under advice from a system operator (with scrutiny from the National Regulatory Authority) — of how much capacity to procure risk institutionalising a bias towards excess capacity because these decision-makers are incentivised to overinsure against the risk of supply shortfalls. The cost of overinsuring is not borne by those same decision-makers but by consumers, which typically compounds a legacy bias towards supply rather than unlocking demand-side solutions.
This matters because excess procurement can inflate costs drastically. For example, analysis by British energy regulator Ofgem suggests that had the 2017-2018 capacity market purchased 1.5GW more capacity than procured (an increment of 3%), gross costs would have doubled by around GBP 375 million. Further, the Ofgem analysis suggests the risk that system operators may persistently overestimate peak demand, noting forecast peak demand on the transmission system exceeded actual peak demand by an average of around 1.5GW over seven winters beginning 2010-2011. Similarly, analysis shows margins in the U.S. PJM (with a capacity market) have grown steadily since the first capacity auction and today vastly exceed the reference margin — an approximation of the level of investment in planning reserves that ensures compliance with resource adequacy standards whilst also providing net value to consumers.
Mitigations
Drawing on European Resource Adequacy Assessments (ERAA) can help to ensure that volumes calculated give appropriate consideration to the possibilities offered through interconnector capacity when needed most while taking into account risks of simultaneous scarcity. This can be helpful in pushing back against excessively conservative assumptions of the contribution of cross border resources.
Engaging independent technical experts to scrutinise the target capacity volume to procure can help limit worst excesses, along with providing transparent processes for assessing the target to procure. Britain offers an example of the former, where much of the work of the Technical Panel of Experts over successive years has been to critique and push back on excessively conservative assumptions in calculation of the volume to procure. Scrutiny may help to promulgate good practice, such as to ensure resource adequacy is based on an assessment of all resources regardless of where connected on the system, and to underpin informed assessments of the contribution of renewables, demand response and interconnectors when needed. Scrutiny will likely not completely solve the issue of excessively conservative assumptions, however, as enhanced public scrutiny of the role of energy ministers and the risk of being publicly blamed in the event of blackouts can weigh heavily on their shoulders and in turn skew their final decision towards excess procurement.
Neutralising potential conflicts of interest can help — where the system operator may have integrated commercial interests that would benefit from a volume of capacity (paid for by consumers) that exceeds the system’s economic optimum and from continued neglect of demand-side resources. A first step may be to provide for an entirely independent system operator (ISO.) Decentralising the responsibility of capacity to procure offers a more direct remedy. Load-serving entities (retail suppliers) are incentivised to avoid overprocurement and to strike a cost-effective balance amongst a much wider range of options for meeting the demand for security of supply, including not just investment in central station generating capacity, but also energy efficiency, demand-side flexibility and distributed resources. In some jurisdictions, resources may be contracted and charged to those retailers that fail to procure adequately.
An argument frequently deployed in favour of capacity markets is that the alternative of relying on infrequent scarcity events to provide rents to recover fixed costs through, for instance, reserve scarcity pricing enhances the cost of capital, ultimately borne by and to the detriment of consumers. Perceptions of a weak business case with reserve scarcity pricing are further fueled by concerns that government will intervene during high price periods, further fueling uncertainty and raising the cost of capital.
Mitigations
We note first that the impact of investment costs on the delivered cost of electricity over time is determined by far more than just the project-by-project cost of capital. As discussed above, centralised resource procurement carries significant risks not only of overprocurement, but also of procurement years in advance of a suboptimal mix of resources. This is especially important in the current environment of on-going technological development and associated uncertainty. Centralised capacity auctions lower project-level cost of capital by transferring long-term risks to consumers — a trade-off that may lead to higher, not lower, delivered costs of electricity over time.
That being said, there are mitigation measures available to reduce the risk premium under this option. Adding a real-time reserve market helps propagate scarcity signals in energy prices to intraday and day-ahead trading — it does this by ensuring that those who commit reserves in day auctions ahead cannot access real time value of that reserve, and so must price the expected opportunity cost of this into their offers in advance. This enhances confidence that rents will be forthcoming — replacing infrequent bonanzas with more regular rents, and helps to limit the cost of capital premium over capacity markets. Proper pricing of supply surpluses and shortages creates the desired incentive for retail suppliers to contract with producers to hedge their mutual exposure to price and volume risks, a natural extension of a well-designed commodity market that critics habitually overlook. Energy ministries and regulators can take action to facilitate such forward contracting and encourage suppliers to engage in it.
Smart reforms that reduce the government’s incentive to intervene during high prices can help give investors confidence that market prices will support prudent investments. Regulations that protect vulnerable consumers from retail contracts with undiluted wholesale price cost reflectivity can help. A circuit breaker or “price shock absorber” can helpfully reduce cost for consumers in specific circumstance where extreme scarcity requiring, for instance, rolling blackouts over a number of days is sustained and where there is a great degree of confidence that all demand-response options have been exhausted — and that lowering price will not undo this demand response. But even better may be the use of affordability options and smart contracts for difference (CfDs) which avoid interfering in price formation and instead provide financial market solutions or derivatives that smooth bills for consumers. Accompanying this, prudent financial regulation of retailers can help protect consumers from retailer bankruptcy issues by ensuring retailer resilience and making bankruptcy less likely.
In summary, these reforms help give confidence to investors that they will recover their costs and thereby reduce any cost of capital premium associated with reliance on reserve scarcity pricing. They can mitigate political concerns associated with reserve scarcity pricing and reduce the likelihood of government intervention during periods of high prices. The broader riposte, however, is that the case for reserve scarcity pricing does not rest on enabling the lowest cost of capital than other interventions — it won’t — but that it underpins a market that is more adaptable to unexpected developments on both the supply and the demand side in an environment where the future is arguably less predictable than it’s ever been. As such, it is best tailored to underpin the least-cost delivery of power over time.
Charges on consumers to finance payments to committed capacity resources are often not well aligned with the product they are purchasing — to ensure provision of contracted capacity during scarcity. Because of this capacity market design choice, consumers who reduce their demand during scarcity are not able to appropriate the full benefit — in avoided cost — they provide to the system. This dampens market incentives to unlock demand-side flexibility and impedes establishment of a secondary market in capacity market cost avoidance.This matters because it sustains the bias against demand-side resources crucial in accommodating massive growth in variable renewables at least cost.
Mitigations
Targeting cost recovery charges so they coincide with scarcity supports efficient incentives to unlock demand-side response. British experience suggests that peak targeted charges — in this case the “triad” charge that recovered network costs in the year’s three peakiest hours — have been successful in supporting significant reductions in demand, as well as in spurring development of an industry in providing retailers and large consumers with forecasts and insights on how to align their demand response with peak moments. Applying peak charging in recovery of capacity market cost — noting Britain instead chose to recover capacity costs across around 250 winter hours — would strengthen incentives to unlock demand-side response (DSR). This reduces system costs to the benefit of all consumers through the effect of reduced capacity volumes and prices, as well as in savings on network build and reinforcement. This solution requires that participating customers are settled against actual consumption, thus necessitating the rollout of smart meters across Europe. Attention may be required to ensure that demand-side resources that secure a capacity contract are not remunerated twice for their contribution to resource adequacy.
Objections to these reform recommendations might point to the original intention of a capacity market design that spreads cost recovery over multiple periods (rather than targeting peak demand) – to hedge risks borne by consumers, thus acting as insurance. This objection misses however that consumers can opt for a retail contract which hedges this risk for them. It may be argued that it is equally unfair to deny consumers willing to exercise their flexibility the opportunity to share in the benefits of doing so to the entire system. Thus, the solution is not to deny consumers the opportunity to reduce demand for system infrastructure to the benefit of all system stakeholders, but rather to enable consumers, who are willing and able to do so, to take advantage of the opportunity.
Another objection is that these recommendations harm the energy poor, who may have less ability to flex their consumption in order to avoid contributing to the cost recovery pot. However, by lowering the capacity requirement and thereby reducing the auction clearing price, targeted cost recovery can reduce system cost and so benefit everyone including the energy poor. There are better ways to protect the energy poor than by deliberately distorting the market.
European regulations require capacity mechanisms be open to direct cross-border participation to minimise distortions, and provide common methodologies to support this. Nevertheless, centralised capacity auctions struggle to provide a fully level playing field for foreign resources (such as equivalence in rights and obligations and access to value) competing with domestic resources. For example, the Polish capacity market design allows for a lower clearing price for foreign resources. The Italian capacity market offers a financial product for foreign capacity, rather than providing for physical participation as with domestic capacity. These approaches may reflect uncertainty as to whether contracted capacity will be forthcoming during a stress event that spans two jurisdictions.
Mitigations
A first step is proper implementation of the European ‘margin available for cross-zonal electricity trade’ (MACZT) regulation – this requires that at least 70% of interconnection capacity be made available to the market — noting ACER’s assessment of a current slow rate of progress towards the target across European Member States. Fair participation of foreign resources requires the conclusion of regional and bilateral agreements amongst transmission system operators (TSOs) not to impede energy export of capacity contracted to a foreign market during a stress event that affects both the domestic and foreign market. The benefits in supporting a level playing field here extends beyond capacity markets. Mitigations previously outlined — using third party ERAA assessments and independent scrutiny by technical experts (see Section A.2.) — can also help push back on overly conservative assumptions and methods in accommodating interconnectors or foreign generation in capacity markets.
Additionally, ensuring the full value of resources is reflected in real-time markets — through implementation of reserve scarcity pricing and real time market for reserves — can help reduce the impact of any level playing field issues in capacity market design, by reducing the value going through the capacity mechanism. Effectiveness requires, however, that foreign capacity can access value without obstruction. The ideal solution — on top of bilateral agreements — is to apply scarcity adders directly to European platforms that co-optimise energy and reserves. These do not exist – European platforms remunerate energy only – thus addressing this challenge merits attention.
Many capacity markets offer long-term contracts to new capacities, financed by consumers for many years (15-year contracts are not uncommon), justified on grounds of lowering the cost of capital and ostensibly thus consumer costs. However, long contracts present an unfair advantage to technologies of today at the expense of emerging innovative technologies undergoing rapid cost declines and which may push out incumbentincumbent Market leading entity, often long standing with inherited customers or assets following privatisation/unbundling. It may also hold market power. technologies from an optimal energy mix within a few short years — so long as the incumbent technologies are not fixed in the system today for the next 15 years with a capacity market contract. They also disadvantage potentially more cost-effective solutions available today that cannot participate in the sorts of long-term contracts appropriate for traditional central station generators — most notably, demand-side and distributed measures that have completely different operational and investment characteristics. This only increases the risk of overcommitting consumers many years in advance to pay for generating capacity that is neither needed nor suitable.
In this way, the capacity market design decision to procure capacity so far in advance with long-term contracts risks delaying adoption of new technologies or alternative measures beyond the point at which they are a feature of an optimised system. This inflates consumer costs and threatens to neutralise or overwhelm the more visible cost savings of longer-term contracts from a lower cost of capital.
Mitigations
Proper carbon pricing helps (and is essential regardless). Investors competing for long-term capacity contracts know less innovative and dirtier technologies will lose competitiveness as carbon prices rise, limiting scope for profits. Fortunately, Europe has a credible carbon price in place. But carbon pricing won’t solve the problem completely, as successful bidders for capacity contracts are still guaranteed to cover at least a portion of their fixed costs for many years, limiting downside risk.
Gradual tightening of emissions standards for capacity may help — but may bring drawbacks of arbitrariness, complexity and inefficiency. Tight emission intensity standards for capacity per unit of energy generated — potentially in concert with declining total annual emission caps — may be designed to support a desired decarbonisation trajectory. Spain has implemented an emission standard in its capacity market where the cap has already gone to zero for new plantthe cap has already gone to zero for new plant Spain requires a maximum CO2 emissions limit of 550 grams per kWh for existing installations of generation participants in the mechanism, while new investments that wish to participate in the mechanism must prove that they correspond to non-emitting facilities (0 grCO2 / kWh).. The counter-argument is that they overlap inefficiently with the carbon price and introduce arbitrariness and complexity. In the presence of long-term capacity contracts, these drawbacks may be considered tolerable to assure consumers that they will not be on the hook for the carbon intensive plant for long periods as well as to push back on political pressure to dilute carbon pricing that may emerge once capacity markets have sunk already large chunks of money into new carbon-intensive plant. If emissions standards are employed, then strong political will is necessary particularly as deadlines approach for tightened standards, noting that political lobbying can be expected to ramp up the pressure to postpone deadlines, as demonstrated, for instance, by Polish derogation proposal submitted to Electricity Market Design discussions.
Exit auctions may present a solution but could be expensive given these would reflect the opportunity cost of relinquishing long duration capacity market contracts, thereby also diminishing their attractiveness politically.
The best solution may be to do away with long-term contracts altogether. The U.S. PJM capacity market restricts itself to one-year contracts. Some other U.S. system operators offer even shorter commitment periods. None offer commitments longer than eight years. This implicitly acknowledges that the case for the government to commit consumers to such long-term contracts is shaky where technologies are changing so rapidly and that an auction and — even more importantly in most of the U.S. markets —a well-designed reserve scarcity pricing regime can ensure a sufficient margin.
Conclusions and checklist
The mitigations identified in this quick tour can help temper — though not entirely eliminate — the worst effects of various capacity remuneration mechanisms.
It is notable that some of the most fruitful mitigations involve putting in place an administrative reserve pricing function in such a manner that the importance of capacity market revenues declines in significance and furthermore that drawbacks of this particular capacity remuneration mechanism may be quite readily mitigated. This points to the importance of reserve scarcity pricing functions. It also suggests the importance of avoiding more cumbersome interventions in the first place and resisting calls in the Electricity Market Design discussions to institutionalise capacity markets in regulatory arrangements.
Analysis suggests attention to codifying mitigations in European network codes should focus on further institutionalising reserve scarcity pricing before resource adequacy becomes a concern. Reform could seek to provide clarity for the mechanism to be introduced under the Balancing Regulation by the regulator or system operator without Member State involvement. Complementary reforms can address obstacles to demand-side flexibility and support competition and thereby diminish the impetus for capacity market remuneration interventions. Finally, certain design elements may also be required of CRMs where they are implemented, such as targeted cost recovery from retailers at peak, external scrutiny of target volume in the case of capacity markets and of expected contribution of renewables, demand response and interconnectors. A more comprehensive checklist of recommended mitigations to address selected drawbacks of CRMs is presented in Table 3.
Table 3: Checklist
| CRMcapacity remuneration mechanism A regulatory scheme under which payments are made to generators, load and storage (and often interconnectors) to provide capacity availability during a specific time period (to top up revenues earned in energy markets) with the aim of ensuring resource adequacy. Costs are usually recovered from customer bills via retail suppliers. | Challenge | Mitigation | Complete? |
|---|---|---|---|
| Capacity market (with and without reliability options) | A.1. Provide incentives to be available | Appropriately exacting prequalification requirements and removal of loopholes in penalty regime | |
| Penalty regimes that incentivise capacity to price unavailability risk into their offers, potentially putting at risk a significant share of capacity market revenue collected since the previous performance interval occurred | |||
| Implement reserve scarcity pricing | |||
| A.2. Ensure an economic volume of capacity | Draw on European Resource Adequacy Assessments (ERAA) and provide for scrutiny of the target capacity volume to procure by independent technical experts | ||
| Neutralise potential conflicts of interest — where the system operator may have integrated commercial interests that would benefit from a volume of capacity that exceeds the system’s economic optimum; the most effective measure may be to provide for an entirely independent system operator | |||
| Revisit choice to introduce a capacity market, recognising excess procurement is an inherent risk with a capacity market | |||
| B.1. Stimulate DSR | Target cost recovery charges to coincide with scarcity (handful of hours with greatest scarcity) | ||
| B.2. Open to cross-border resources | Implementation of the European ‘margin available for cross-zonal electricity trade’ (MACZT) regulation to make at least 70% of cross zonal capacity available for trade. Conclusion of bilateral agreements between TSOs not to impede energy export of capacity contracted to a foreign market during a stress event that affects both the domestic and foreign market | ||
| B.3. Optimal capacity mix | Discontinue long-term contracts — to provide a level playing field for rapidly developing technologies and avoid lock-in or arbitrary standards | ||
| Reserve scarcity pricing | A.3. Optimal balance of risk between consumers and investors | Add a real-time reserve market to back-propagate scarcity signals, which allows for more regular but less severe scarcity prices, which lowers investment risk and reduces the cost of capital | |
| Protect vulnerable consumers from retail contracts with undiluted wholesale price cost reflectivity | |||
| Conduct prudent financial regulation of retailers, and empower and resource regulators to monitor and address abuse of market power | |||
| Consider implementing affordability options and smart two-sided CfDs; until then implement a circuit breaker to reduce cost for consumers during stress | |||
| B.2. Open to cross-border resources | Further research into ensuring that foreign resources can access the same value from reserve scarcity pricing adders as domestic resources |
The first set of mitigations — those linking with capacity markets — is still subject to the caveat that the ideal solution may entail avoiding use of a capacity market in the first place. The second set of mitigations — on reserve scarcity pricing — is achieved not by resisting introduction of reserve scarcity pricing, but by enhancing confidence that prices will provide the value required, structurally, and by addressing outcomes that might tempt government to impede scarcity pricing.
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The authors thank Michael Hogan, Monika Morawiecka, Andreas Jahn, Sophie Yule-Bennet, and Tim Simard for comments on drafts. All errors are the authors’ own.
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- Last modified: August 13, 2024
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