Tim Schittekatte, Carlos Batlle
Europe started to go through an extremely severe energy crisis in the summer of 2021. The Brussels-based think tank Bruegel reported that governments spent billions of euros, representing several percentage points of their gross domestic product, to shield consumers and industry from high prices (Figure 1). Even when considering that substantial public support, many end users were (at the time of writing, in February 2023) still facing energy affordability issues. At that time, it was not possible to foresee the end and whether an unprecedented scenario of a period of sustained high prices could repeat itself. However, what the energy crisis showed was that although it was a gas crisis, the current regulatory power market compound proved to be fragile to political interference. In this article, we elaborate upon a proactive regulatory-driven solution with the aim to protect (certain tranches of) end users from periods of sustained high electricity prices. Thereby, political turmoil leading to potential negative consequences for the ongoing decarbonization process can be avoided. We call our proposal affordability options.
At the time of writing, political interference manifested itself in costly interventions in the functioning of power markets (e.g., revenue caps and fuel subsidies for thermal generators as the so-called Iberian exception) and in more radical calls to overthrow the regulatory compound gradually built up over the past two decades and more. It is worth starting out by pointing at the actual reason behind the current urgency to change the regulatory compound in the European Union (EU): (marginal) energy prices have reached sustained and never expected high levels, and there are reasons to think that this is not necessarily going to be an exceptional situation. Adding to this, also much earlier than expected, investment costs of renewable energy sources (RES) have been significantly reduced. RES appear now not only to be by far the cheaper alternative power generation resources but also to be capable of collecting significant income when participating in the spot market. These two factors have led to a political desire to allow end users (in some cases, specific categories of customers) to benefit from these reduced costs, even if this might imply reconsidering the rules governing power markets that have been undisputable so far.
In a theoretical market context with strictly zero entry barriers, the current crisis would be nothing less than a great opportunity. From today to tomorrow, thousands of renewable megawatts could connect. Since there would be a severe risk to new entrants of what now has been called cannibalization, they would necessarily have to rely on some sort of long-term commitments with end users. The massively entering renewables would quickly bring overall price levels down by selling their currently below-market-price energy, considering not only their operating costs but also capital expenditures and a reasonable rate of return. But the fact that the power market is far from this theoretical ideal needs little explanation, for entry barriers (technical and economical) are very significant. It is in this context that the open (and like any other marginal) market framework is severely questioned. However, the market framework is a compound of many interrelated mechanisms, and the fact that the current market outcomes might deviate from what politicians would desire does not mean that all its building blocks are malfunctioning. In this article, we discuss two of these important building blocks: spot markets and long-term markets.
Spot power markets—even though often seen as the core issue by politicians and the wider public—have been working as they were supposed to do. Spot price signals lead to the dispatch of the least-cost resources, the efficient organization of cross-border trade, and, if end-user tariffs are properly designed, the possibility for end users to optimize their consumption patterns. Importantly, due to the successful coupling of the day-ahead (and intraday) market, billions of euros are saved each year across the EU. Any change to the spot market’s price setting rules, as some radical proposals for “market reforms” apparently aim to do, risks fragmenting the European market. As discussed, for instance, in Hogan 2022, in a future with a more heavily decarbonized power mix, marginal spot pricing becomes even more important than it already is today; it is the only suitable way to coordinate increasingly volatile supply and increasingly controllable demand, storage, and grid flows. Obviously, the European spot power market design can and should be gradually improved over time. Examples are fully locational prices, less complex and more convex bidding formats, the removal of utility portfolio-based balance-responsible parties, and scarcity pricing.
What has never worked are long-term markets. More precisely, there is a total lack of sufficient electricity price hedging opportunities beyond two years in organized forward markets; i.e., long-term markets are “incomplete.” The conclusions of the EU Agency for the Cooperation of Energy Regulators’ final assessment of the EU wholesale electricity market design were also largely aligned in this respect. It is not the objective of this article to delve into the reasons behind this market flaw (e.g., vertical integration generation/retail and a lack of demand-side participation in long-term markets, partly due to transaction costs but mainly due to the trust in governmental intervention in times of stress). However, it is undisputed that long-term market incompleteness has been an issue of concern for years and that there has not been any advance along these lines. Hence, any proposal for the improvement of the existing regulatory compound should be focused on completing the long-term market rather than making any change to the short-term market.
How to complete the long-term power market is the topic of this article, particularly to provide those more sensitive end users with some sort of hedge and also to prevent politicians from panicking. We divide the article into three main parts. First, we explain the rationale behind the need for a regulatory-driven complement to the long-term market, aiming at the mitigation of affordability concerns. Second, we describe the affordability option product design. Third, we discuss the procurement of affordability options, splitting the discussion up between new and existing generators. We end with a summary.
The issue that power markets have significant entry barriers and are far from being complete has been recognized for a long time, which has led to complements to the energy-only market idea developed decades ago. Since the implementation of electricity markets worldwide, first via the design of stranded cost mechanisms and then through different sorts of subsidization tools (mainly) for nonemitting technologies as well as via capacity remuneration mechanisms (CRMs) in some contexts, policy makers have intervened with the expectation to guarantee at least a “reasonable” floor on the income of the generation capacity deemed necessary. These complements are variants of (mostly) centrally organized auctions awarding long-term contracts.
The main objective of CRMs is to complete the market by reducing uncertainty in future revenue streams of resources that are deemed necessary to continuously guarantee a sufficient level of resource adequacy. None of the existing CRMs lead to a (significant) transfer of income from the generators to consumers during periods of sustained high spot prices. In the current European context, capacity is not the problem: no blackouts and rolling brownouts are witnessed. There is still a lot of work to do to improve the design of these mechanisms. Although this discussion is of utmost importance, we deem it out of the scope of this article.
The aim of support schemes for RES is to provide revenue certainty for new investments in carbon-free generation technologies. RES support schemes are also not designed to protect against affordability issues, but some types of RES support do, rather by coincidence than by design. For example, under contracts for differences (CFDs), RES generators sell their production in the spot market and receive/pay the difference between the preagreed strike price and the reference price. Currently, strike price levels are typically under the average spot prices witnessed in the past year. Consequently, significant income is transferred from CFD holders to their counterparties, which indirectly (depending on the tariff regulation) transfer (or should transfer) this income to end users.
However, apart from a few cases in South America (e.g., Peru and Brazil), these regulatory mechanisms are mainly focused on promoting adequate investment on the generation side, and thus, they do not necessarily hedge future electricity bills. In the current context, the difficulty for politicians and, in general, the wider population is to understand how it is possible that some sort of hedge for demand in case prices could skyrocket was not equally envisaged. Implicitly trusting in governmental protection in case of need (as the EU energy crisis has confirmed), end users have evidenced their relentless insufficient participation in forward markets. The crisis also shows that the same is true for several retailers. In any case, there is no doubt that the direct impact of the current price levels on the financial health of certain tranches of consumers is a major issue that needs to be tackled. Beyond that consideration, this scenario of electricity prices reminds us of a higher-order threat: the potential loss of trust (and patience) in the political class (and the mass media) in the whole market compound. The probability of overreaction after a price shock of this nature, potentially leading to a major step back in the decarbonization process, can no longer be seen as a risk: it is a fact. The Australian market suspension that took place in summer 2022 can be taken as another illustrative example.
Risk-averse governments cannot directly hedge themselves against that risk unless they have a stake in the electricity generation companies and redistribute their inframarginal rents. However, doing so would, in some countries, imply the (forced) divestment of privately owned companies. Also, in the EU, the direct redistribution of any rents to electricity consumers would have been a violation of State aid rules in force until the crisis took place. The only reasonable way to hedge that risk, at least in that context, is to introduce a hedge on behalf of the consumers that are deemed in need of bill protection. The introduction of such a hedge would be welfare enhancing. The risk for sustained high prices would be transferred from risk-averse consumers (and, indirectly, the risk-averse government) to less risk-averse market parties that can better manage this risk. The transferred risk would create an incentive for those market parties to hedge themselves by investing in generation assets (e.g., RES plus storage) and/or the purchase of long-term gas contracts. A chain of long-term hedging contracts would possibly be “ignited,” which would lead to a more efficiently functioning power system. So far, the need for generators to hedge themselves against very high gas prices, at least in the middle to longer term, is limited, as they can directly pass through the costs of high gas prices via high electricity prices.
An important question is whether each of these desirable policy goals that the so-called energy-only markets have very rarely shown to deliver in their current shape (resource adequacy, decarbonization, affordability, and others that we do not discuss) requires its own procurement mechanism and long-term product. Even though politically harder to pursue due to additional complexity, the stance we take is that it seems more appropriate to tackle each goal separately. However, it is hard to deny that there are spillovers. These spillovers can be positive or negative; e.g., RES support aimed at decarbonization potentially mitigates affordability issues but can worsen adequacy concerns (especially when RES support schemes are ill designed). In this article, we focus on the affordability concern.
The aim of the regulatory-driven long-term complement is to protect at least some categories of consumers (e.g., those consumers considered particularly vulnerable) during periods of sustained high energy prices. At the same time, the product must not distort incentives provided by spot markets for both generation and load. In short, what an affordability option does is introduce a preagreed transfer of the gains of generators that are profiting from periods of sustained high prices to consumers suffering affordability issues. This protection does not come for free; consumers pay a fee for this “insurance” (such as a regulated RES levy in the bill), while generators exchange part of their uncertain future revenues for a regular payment. In what follows, we discuss in more detail how three key design choices of affordability options are determined to comply with the original aim: the choice for an option product and not an obligation, the settlement frequency, and the level of the strike price. We also provide a brief discussion on the difference with reliability options and a numerical example.
First, the introduction of a financial option is more suitable than an obligation (i.e., a two-sided CFD), as the objective is to protect end users from periods of sustained high prices, rather than to entirely fix the price paid for electricity under any scenario. It can be argued that a CFD would also hedge end users in the long run, without necessarily minimizing their incentive to respond to short-term signals; this is partially true, but we consider that an option would be a less intrusive solution. More precisely, when covered by an option, the electricity bill would remain unaltered during periods of “normal electricity” prices, while a CFD would have an impact under any price scenario.
Second, the objective of the hedge provided by the affordability options is not to protect consumers from sporadic price spikes. Instead, the objective of the hedge is to prevent sustained high prices from threatening the financial health of certain categories of end users. What eventually matters for end users are not a few hours of very high prices (which can have a moderate impact on the monthly bill) but months with very high bills. In this regard, an Asian option for which the payoff depends on the average of all prices over a specific period seems to be a suitable product design, as opposed to vanilla European and American options, where the payoff is determined at a single expiration date. We propose that affordability options have a monthly fixing to be aligned with typical bill cycles. A “strip” of affordability options should last sufficiently long; we propose a duration of five to 10 years (respectively, 60 to 120 “bill cycles”).
Third, the level of the strike price can be interpreted as the maximum average electricity price (arithmetic or load weighted) that is deemed sustainable over the given settlement period. What that exact price level will be is at the discretion of the regulator (e.g., an average day-ahead electricity price of €100/MWh over a month). Obviously, the lower the strike price, the higher the option premium and vice versa.
Affordability options are not to be confused with reliability options that have been introduced to mitigate adequacy concerns in, for example, Colombia, Ireland, and Italy. The idea of reliability options is to induce investment (and retain installed capacity) that is flexible enough to support the power system when it is very tight. Moments of high stress are reflected by scarcity prices. This reasoning behind the design of reliability options leads to different design choices: an hourly settlement and a relatively high strike price. Table 1 shows the interactions between the choices for the settlement frequency and strike prices.
Table 1. The tradeoffs and opportunities for the design parameters of the auctioned-off call options and the impact on the cost of the option premium.
Figure 2 provides an illustration of the functioning of affordability options. Figure 2(a) shows the hourly prices in the Spanish day-ahead market in 2020 and 2021. Two different abnormal price scenarios are highlighted in different colors. In cyan, January 2021: in the second week of that month, a persistent blizzard affected half of the country and led to the occurrence of some hours with high prices. In red is December 2021, a month in the middle of the ongoing energy crisis. Figure 2(b) and (c) provides greater detail of the prices resulting in these two months.
If the regulatory decision would have been to hedge, for instance, vulnerable customers with an affordability option at a strike price of, for example, €100/MWh and a flat load profile, the impact in both cases would have been radically different. In January, even though spot prices were above €100/MWh 51 times during the month, the average price was €60/MWh. Therefore, the affordability option would not have been exercised (“out of the money”). Conversely, the average price in December was €239/MWh, and the electricity bills of vulnerable customers would have been beyond the acceptable range. The affordability option would have been exercised, resulting in a payout of €139/MWh. Imagine that, on behalf of each vulnerable consumer, 300 kWh were contracted per month. In that case, each vulnerable consumer would receive €41.70 per month to compensate for the high electricity costs. However, the same customers would still be incentivized to consume more when prices were low and vice versa.
In this section, we go into more detail on how we see the completion of the long-term market to avoid affordability concerns. We divide the discussion between new entrants and existing generators.
The crisis has woken the demand side. In contrast to the situation before the crisis began, there is currently an increased eagerness to sign long-term contracts with new entrants. The developers that were recently granted access to the network on a first come, first served basis can benefit from their application. At current spot price levels, these developers of renewable power plants can go merchant or sign lucrative long-term contracts, in most cases collecting a higher income than the levelized cost of energy of their investments. It might take some time for spot price levels to go down. Also, the pace of connecting renewables seems to have slowed down in several countries, mostly due to administrative issues (permitting and the like), a lack of or limited availability of physical grid connections, and, more recently, supply chain bottlenecks. Two questions arise when thinking about new entrants, as summarized in Table 2: how to deal with the network connection and how to deal with exposure to price risk.
Table 2. A stylized summary of key choices to make about new entry.
Regarding the network connection, the lesson learned should be: no more granting network access for free, not for any resource, renewable, or other (at least not at the transmission level). A more adequate mechanism to allocate scarce connection opportunities is the introduction of auctions for granting network access. Auctions for granting network access are not a new idea, but it has not been generalized, so far. Examples are auctions of offshore wind sites in North Sea countries and the United States. The ability to auction the right to connect not only allows leveraging the benefits of competition for access to the system but also makes more efficient coordination of generation and transmission capacity expansion possible, which is a major challenge today.
Regarding the exposure to price risk, the question becomes how to auction scarce network capacity. As in current Portuguese auctions, there are two extreme alternatives: auctioning an annual fee for access and auctioning network access bundled with a long-term contract. In the case of an annual access fee, the choice between selling electricity in the spot market and signing long-term contracts with private entities is up to developers. Shortly before the crisis began, incumbents claimed that there was no longer a need for governments to grant RES support in the form of any sort of long-term contracts. The main argument was that the levelized cost of renewables was reaching market value levels. The counterargument for keeping auctions awarding long-term contracts for RES in place was that new entrants could not easily find counterparties for power purchase agreements (PPAs). New entrants are in a significantly worst position than vertically integrated incumbents, which already have direct access to counterparties thanks to their historically inherited portfolio of customers. To that extent, RES auctions for mature technologies gradually became nothing more than a sort of CRM, of which the objective was “to complete” the long-term market and thus level the playing field between incumbents and often nonvertically integrated new entrants.
Following that reasoning, auctioning network access bundled with long-term contracts could lead to higher competitive pressure. Competition would push the price levels awarded in the long-term contracts closer to the levelized cost of new entrants and thus further from the market value of the generated electricity. At the same time, the feasibility of massively deploying RES generation to reach decarbonization targets would not be impacted. Another important advantage, in this context of auctioning long-term contracts jointly with network access, is that counterparties could be protected against periods of sustained high prices. So far, counterparties in these centralized auctions have always been (directly or indirectly) the government, at least in the EU. In addition to having the possibility to sign bilateral PPAs, there might be good reasons to allow suppliers and large consumers, such as industrials, to voluntarily participate on the buyer side. Such an arrangement would basically imply a sort of centralization of the procurement of standardized PPAs. However, in periods of sustained high prices, only those who are on the buyer side would be hedged. In case the government is the counterparty, the decision of who should enjoy the value of the hedge in times of sustained high prices is in the hands of the government. In case the counterparties are mostly third parties, depending on who those third parties are, residential and small consumers might be less protected against affordability concerns.
We focus on intermittent RES as new entrants, as they represent the bulk of expected newly entering capacity. The prime consideration of long-term contracts is that they reduce risks for project developers while keeping short-term incentives for efficient operation by exposure to the spot market (at least) on the margin. Risk mitigation is key to lower financing costs, which are crucial, as these assets are capital intensive. In that regard, the best contract design would likely be a CFD (obligation) since it provides more revenue certainty for the developer over (one-sided) call options.
CFDs are not new; they have been auctioned for many years for RES projects in Europe. What is important is that the exact contract design evolves as more RES enter the power system. We advocate for a contract format that resembles a standard CFD but keeps dispatch incentives intact without significantly increasing investment risk. More precisely, we recommend a capacity-based support mechanism complemented with ex-post compensations and penalties resulting from a plant’s performance compared to a reference plant. Such a mechanism was implemented in Spain via royal decree 413/2014. A detailed discussion of the exact design of well-functioning CFDs, of which the appropriate format could depend on technology characteristics, while incredibly important, is beyond the scope of this article.
What is key for the discussion in this article is that new RES entrants via centralized auctions for government-backed CFDs can slowly soften the medium- to long-term volatility of certain categories of end user prices. However, this solution can be only partial. In the short to medium term, we cannot expect that new RES alone can solve the affordability concern. For at least a decade, the total volume of new RES electricity production is going to have a relatively limited impact on final bills. Moreover, unfortunately, in the absence of abundant storage, not just short-term but also seasonal, the market price that consumers pay will increasingly diverge from the price that new renewables receive in the market. This divergence happens due to the mismatching of end users’ consumption and RES production profiles and is especially an acute problem for solar. As discussed in the following section, in this context, only large, and maybe even more important, fully diversified, generation portfolios provide the opportunities to truly address the affordability issue.
In case the crisis continues longer than expected, the current affordability issue will remain active, while in case the crisis winds down, an affordability issue will resurface when a period of sustained high prices returns.
A very tempting option for governments to lower prices in the short run would be to hurry and negotiate some sort of long-term contracting with specific generators (e.g., nuclear plants) and incumbents. The current context of abnormally and sustained high market prices would be the worst moment to enter into such a commitment, particularly if there were no way (time and manner) to fully open the negotiation to every potential (existing, i.e., already installed or future) counterparty to maximize competition. A bilaterally negotiated price, absent competitive pressures, would necessarily end up being a bad deal for consumers in the medium to long run. Governments could be relieved by seeing a decrease of prices in the short run, but consumers would pay higher bills in the middle to long term when prices normalized again.
A preferred alternative approach is to levy a nondistortive windfall profit tax on generators, as long as there is the political urge to do so, and use these revenues to mitigate affordability concerns. When the crisis calms down, we propose the organization of regulatory-driven auctions for affordability options. The regulator must decide about the volume of affordability options it will procure. This decision will be based on which end users are deemed to need (or want) protection from sustained high prices and the total volume of production already under CFDs (existing and new entrants). Such an assessment is not very different than, for example, resource adequacy forecasts that regulators perform.
To limit regulatory interference in the market and increase competitive pressure, we recommend minimizing the volume of affordability options and opening auctions to all generation technologies. Also, a reserve (maximum) price should be considered. Protected end users might be only “standard” vulnerable consumers, i.e., consumers facing energy poverty in normal price scenarios, or a larger share of residential and commercial consumers that would suffer significantly from periods of sustained high prices. End users that are not, by default, covered by affordability options (e.g., industrial consumers) should have the right to opt in and participate in auctions, with the same rights and future obligations. Besides all existing generation, new generation should be able to participate to add competitive pressure. In that regard, the auction lead time needs to be sufficiently long. New generators can be generators that do not enter via centralized auctions, for example, wind colocated with sufficient storage capacity. Maximizing competitive pressure is much needed, considering that large diversified electricity generation portfolios are often concentrated.
To ensure that generators have a natural hedge, they are required to prove that they can honor option contracts. Thus, having only sufficient generation capacity (in megawatts) is not enough. Also, proof of being able to deliver the energy is needed (e.g., a long-term gas contract for a gas-fired power plant and historical production time series for RES with storage). The exact implementation of these requirements and possible penalty schemes need to find a balance between minimizing financial risk for option buyers and minimum entry barriers for option sellers.
The ongoing scenario of sustained high electricity prices in Europe exposes a higher-order threat: the potential loss of trust (and patience) in the political class (and the mass media) in the whole power market compound. The risk of an overreaction after a price shock of this nature, potentially leading to a major step back in the decarbonization process, is not irrelevant. It is currently not possible to foresee when this crisis will end and whether this unprecedented scenario of a period of sustained high prices could repeat itself.
Even though spot power markets are blamed, what Europe has been facing is a natural gas crisis. Marginal spot pricing of electricity will become even more vital in the future. The current affordability issues stem from power market incompleteness, i.e., a lack/insufficient availability of long-term hedges. The solution, thus, must also be sought in that direction. We discussed the rationale behind complementing the long-term market, with the aim to proactively mitigate affordability concerns. We described our proposal to complete the long-term market: affordability options. Affordability options are a financial product that works as market-based “bill insurance” and is procured by the regulator/government on behalf of (tranches of) consumers, while not distorting spot prices signals. We explained how affordability options can be procured within the current regulatory framework.
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Tim Schittekatte is with the Massachusetts Institute of Technology Energy Initiative, Cambridge, MA 02142 USA, and Florence School of Regulation, 50133 Firenze, Italy.
Carlos Batlle is with the Massachusetts Institute of Technology Energy Initiative, Cambridge, MA 02142 USA; Florence School of Regulation, 50133 Firenze, Italy; and Comillas Pontifical University, 28015 Madrid, Spain.
Digital Object Identifier 10.1109/MPE.2023.3269540
Date of current version: 21 June 2023
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