In countries with energy only wholesale power markets, the rise of variable renewable energy production with zero margin costs—and, in some cases priority despatch—is depressing wholesale market prices and displacing marginal thermal power producers which cannot meet their fixed operating costs with reduced operating hours. As a result, an increasing number of conventional power stations are being retired, thereby removing large quantities of firm capacity from the system. At the same time, the variable or intermittent nature of renewable energy requires more firm capacity to be available on a stand-by basis to cover shortfalls in renewable energy production due to weather conditions.
Furthermore, in the EU, US and other developed markets, the impact of environmental regulation such as the Large Combustion Plant Directive and US EPA regulation has hastened the closure or limited the running of coal- fired power stations and this will only be accelerated by the forthcoming application of the EU Industrial Emissions Directive. Moreover, the delay in the commercialization of CCS technology has meant that there has been little or no recent investment in new coal-fired capacity in many EU Member States or in the US. Similarly, several countries, such as Germany, have announced the closure of their nuclear power stations and others, such as the UK, will be unable to commission new nuclear capacity before the scheduled closure of existing capacity. At the same time, the unattractive economics of operation in many EU electricity markets of gas-fired plant relative to coal-fired plant due to higher fuel costs and lower CO2 values has led to the displacement of the former by the latter in the merit order and the withdrawal of considerable amounts of gas-fired capacity, including those with high efficiency and lower CO2 emissions such as newly built CCGT plants.
These factors have led to a marked reduction of investment in replacement conventional power plants such that there is now a perceived risk in many EU Member States of substantially reduced reserve margins so that long- term generation adequacy (i.e. access to sufficient firm generation capacity to meet the highest projected demand) may be jeopardized.
Moreover, increasing levels of intermittent renewable energy production creates an additional requirement for conventional generation plants that are able to operate flexibly in back-up mode, since renewable energy cannot be relied upon as a capacity provider (given imputed firm capacity values in the order of five to ten percent of rated capacity) and therefore can only make a minimal contribution to required reserve margin levels. However, because renewable energy has a high variability, the conventional plant that has to provide the reserve margin must be capable of following a much more volatile and unpredictable demand profile than has previously been required, which calls for more technically competent plant capable of much greater flexible operation in order to provide system stability.
Energy only markets such as those currently operating in Germany and the UK do not incentivize investment in new capacity as they do not explicitly value it, rather compensation for capacity is implicit in the price of energy. For low load factor conventional plant, scarcity prices (i.e. above marginal operating costs) are required to cover fixed costs, but these price spikes have to be sufficiently frequent to attract new investment in new capacity or to prevent existing capacity from leaving the market. Such revenue streams are unpredictable and may also be restricted through market distortions such as capping measures to control the level of price spikes and are therefore unlikely to provide sufficient certainty to encourage investment in the required level of firm capacity to ensure generation adequacy. Accordingly, many countries have turned to capacity payment mechanisms to stabilize wholesale energy prices and to reward investors in firm capacity explicitly through the payment of more certain and more stable revenues over pre-determined periods in the expectation that this will encourage the required levels of investment. The increased certainty of the revenue stream should also lower financing costs for such investment.
Capacity payments are paid in addition to revenues that the generator may earn in the energy market. Logically, wholesale electricity prices should fall due to the removal of the scarcity value from such prices which are now recovered through the capacity market. Notwithstanding the academic theory, experience of the operation of capacity markets in the US shows that claw back and other anti-gaming mechanisms may be required to avoid over compensating generators in circumstances where scarcity market pricing continues despite separate capacity remuneration.
Historically, capacity payment mechanisms have been designed to secure generation adequacy at the lowest cost. This has typically resulted in investment in cheaper, less flexible plant rather than more expensive plant with enhanced operational capacities. Many commentators argue that the design of capacity mechanisms must change so as to incentivize investors to invest or to sustain investment in the more flexible plant that will be required to support the rising share of variable renewable generation. Moreover, in the EU many of the existing capacity mechanisms have been developed on the basis of the needs of the particular national market without regard to their impact on neighboring, interconnected markets. This has led to calls for minimum EU harmonization requirements for capacity mechanisms and their co-ordinated adaptation so as to ensure compatibility with the process of EU market integration in general and the target model of market coupling in particular.
The evolution of national capacity markets raises important questions of EU law, in particular whether a particular capacity payment mechanism may constitute illegal state aid and whether such mechanisms may act as a barrier to free movement of goods and therefore be inconsistent with single market competition rules. Any proposed new capacity mechanism must now meet the European Commission Guidelines on State Aid for Environmental Protection and Energy of April 2014. These Guidelines emphasize demand-side participation and the contribution of capacity providers from other Member States where such capacity can be physically provided and also that the proposed capacity mechanism should not impact negatively on the development of the internal market by undermining the operation of market coupling, including balancing markets, and should not reduce incentives to invest in interconnection capacity.
To date, some 14 EU Member States have in place—or are considering— some form of capacity payment mechanism. There are a number of different designs including short-term targeted strategic reserves, capacity obligations, capacity payments and long-term market wide, volume based capacity auctions. A brief review of some of these arrangements will show that few, if any, address fully the challenges of rising renewable market share or the requirements of EU harmonization.
Under the strategic reserve model a determined amount of capacity is set aside to ensure the required level of generation adequacy—it is effectively a peak load reserve only— and despatched whenever required. The level of payment is set through a competitive tendering process and recovered from network the users. Typically, capacity providers receive the market price for the electricity generated (marginal fuel cost) plus a small premium. It effectively works as a price cap. This is the model used in Germany, Finland, Poland and Sweden. For example, in Poland as of the end of March 2014, the grid operator has procured 830 MW of cold reserve capacity via two consecutive tenders effective from 2016 for a period of two to four years. This is also the model for the recent UK grid operator’s proposal for a Supplemental Balancing Reserve for winters 2014/5 and 2015/6. This model has the least distortion on energy markets as it should only operate in peak conditions. Typically, any plant providing this service is excluded from participation in the markets for energy and balancing services. It is straightforward and flexible in duration, although it is mainly purchased on a short term basis through a one or two year ahead tender from a thermal plant that would otherwise close or be mothballed (mothball reserve). However, there is a risk that such capacity would not have been decommissioned but is removed from the energy only market simply because the strategic reserve offers more favorable terms such as firm pricing in contrast to uncertain revenues in the energy only market.
It is doubtful whether such a model provides sufficient incentive to investors in new firm capacity of any kind let alone enhanced capability resource.
Another mechanism is the capacity obligation scheme, which is a decentralized arrangement that imposes on suppliers and other market participants an obligation to purchase a certain level of capacity linked to an assessment of their future consumption (three to four years ahead) at peak load in the relevant delivery year. The overall capacity to be contracted in a delivery year is typically higher than the aggregate future expected consumption by a reserve margin set by the regulator or the system operator. The capacity obligation can be met through ownership of plant, contracting with generators or providers of demand response capability and/or purchasing tradable capacity certificates. Contracted generators/demand response operators are required to make the contracted capacity available in periods of shortages or face penalties. Suppliers pay a buyout price or a penalty if insufficient capacity is contracted. The cost of providing the capacity obligation is recovered from customers through retail prices. One of the theoretical advantages of a capacity obligation mechanism is that it offers a market oriented solution and so is less likely to incentivize an over-supply of capacity than centrally procured mechanisms.
France has recently announced such a capacity obligation scheme through Law no. 2010-1488 and Decree no. 2012-1405. Under the French system, which is scheduled to commence in 2016, suppliers are required to meet their capacity obligations by holding a specific amount of capacity certificates that are issued by the system operator based upon data declared by suppliers within the four years prior to the relevant delivery year and following an assessment of the reliability of the declared capacity. The supplier and the system operator enter into a certification agreement regulating the availability of the certified capacity. The system permits the trading of certificates either directly or in a secondary market with the consent of the system operator.
Capacity certificates have a duration of one year. For each year, two deadlines are set; namely, the deadline for the transfer of certificates and the deadline for the collection of certificates. After the first date the system operator calculates any shortfall between the amount of certificates owned and the amount required to meet the supplier’s capacity obligation. A shortfall gives rise to an obligation to make a financial contribution to a fund managed by the system operator. If the supplier holds more certificates than required to meet its obligation, it receives a corresponding payment from the fund. Following the second deadline, if a supplier has a shortfall between the amount of certificates owned and the amount required to meet its adjusted capacity obligation (after accounting for any contribution previously paid by that supplier) it is liable to pay a penalty imposed by the French energy regulatory authority (CRE) in an amount not exceeding 120,000€/MW of the capacity shortfall.
Supplier payment shortfalls can be mutualized across several suppliers through the use of certification perimeters under which an agreement is included between the system operator and a creditworthy entity which assumes liability for the capacity obligations of all suppliers within a particular perimeter. The French capacity market is designed to be compatible with EU market integration, and interconnected capacity located in other Member States will eventually be eligible to participate. It will be interesting to see how the French regulator addresses the concern voiced by several commentators regarding the potential for over-compensation of generators in receipt of capacity payments that could arise as a result of France being connected with energy only markets such as Germany, with a coupled market clearing price that may be driven higher in periods of scarcity by generators not in receipt of capacity payments seeking to secure scarcity rent. Consistent with the European Commission State Aid Guidelines, an affected capacity market may include offset mechanisms to neutralize such risk of windfall profits, but this could complicate the system design significantly.
Capacity payments remain the simplest and most flexible capacity remuneration mechanism. They are typically paid to all generators based on their availability to run and will automatically cease when the required reserve margin is reached. Payments are determined by the regulator, but are not always transparent and are consequently more exposed to regulatory risk. The short term nature of payments (in some jurisdictions these can be determined on an annual basis only) means that they may not be supportive of long term financing for investors. Capacity Payments are used in Ireland, Greece, Italy, Spain and Portugal.
A more complex design is the capacity auction. This is a scheme in which the total required capacity at peak demand is set centrally by the regulator or system operator several years in advance of supply (one to four years) and is procured by a central buyer through a competitive forward auction. The auction disburses to any generator on the system (existing, refurbished or new) as well as demand side operators (demand response, storage and embedded generation) whose bids are accepted (clear the auction) a payment for the firm capacity that they commit to make available to the system operator in the relevant delivery year(s). Failure to meet their contractual commitment results in penalties. The costs of the central buyer are charged to suppliers based on their offtake profile.
As part of its Electricity Market Reform program, the UK announced the introduction of a capacity market in 2014. Features of the UK scheme include a pay-as-clear descending clock auction four years ahead of the delivery year with a secondary year ahead auction to enable adjustments to capacity positions and to permit participation of demand side operators. Participants receive the clearing price set by the marginal bidder; a distinction is made between price takers (existing generation) whose bids are restricted and price makers (new and refurbished generation and demand side operators) whose bids are not. However, there is no restriction on the amount a single bidder can bid into the auction nor on the amount that it can win at the auction, as dilution of market concentration is not one of the objectives of the UK capacity market.
In order to protect consumers from excessive costs, the auction is capped at £75 kW year gross capacity price. This is an administratively set level that reflects a multiple of the Net-CONE (the net cost of new entry – being the gross cost of construction of new open cycle gas turbine plant less expected electricity and ancillary services market earnings, although there has been particular criticism of the underlying assumptions and methodology used to calculate these concepts). The auction is technology neutral and the only ineligible plant is low carbon plant that is in receipt of other forms of financial support, plant that currently participates in the existing short term operating reserve and currently interconnected capacity located in another Member State.
There is no suggestion that more flexible plants will receive a higher price than less capable plants although new build capacity will be offered 15 year capacity agreements with existing capacity being offered rolling one year agreements and three year agreements for refurbished plants. It remains to be seen whether the auction price cap is set sufficiently high to incentivize investors to invest in more flexible new generation CCGTs (which should capture more energy revenues due to their flexibility despite higher capital costs) or whether it will deliver cheaper but less efficient OCGTs. Alternatively, will the major beneficiaries of the capacity payment mechanism be the owners of existing plants or refurbished plants that would otherwise have closed or remained unchanged?
It will be interesting to see the impact of the capacity market on the valuation of existing gas fired plant. Given predicted coal plant retirements (unless these can be postponed through refurbishments funded by capacity payment revenues), capacity prices can be expected to increase in a somewhat predictable manner, and consequently values should firm up. The eligibility of a plant to participate in the capacity market and to capture the clearing price or its ability to access unavailability risk mitigants (see below) should become key drivers in asset valuations of the plant.
Capacity payments will be paid to generators by a settlement body from payments received from licensed suppliers under a supplier levy imposed as a license condition. The settlement body can mutualize any funding shortfall from a particular supplier across all licensed suppliers. The settlement body is not the system operator but a special purpose vehicle that is intended to be bankruptcy remote. It will achieve this objective by only being liable to pay capacity payments when it has collected sufficient funds from the suppliers to make such payments. A similar arrangement has been proposed under the CfD support mechanism, which is part of the same electricity market reform program as the capacity market. However, the current proposal for the capacity market payment mechanism lacks a number of additional protections that were added to the CfD support mechanism at the insistence of financiers. It remains to be seen whether this will adversely impact the bankability of projects supported by a capacity agreement.
Failure to generate when required will result in penalties capped at 200 percent of a generator’s monthly capacity payment revenues and 100 percent of annual revenues. This unavailability risk is a much greater concern for new entrants with a single plant or small portfolio than for the vertically integrated generators with large portfolios who can better manage such risk. There is no allowance for planned maintenance or forced outages within the design, and force majeure relief is limited to failures in the power transmission system only. Further, providers of demand side response are particularly sensitive to penalty rates given that there is no limit on the number of incidents that DSR capacity can be required to respond to.
Unavailability risk mitigants include secondary market trading where an outage is foreseeable and the load following nature of the capacity obligation that can reduce the exposure of a single plant operator. Also, over-delivery payments at the negative rate of under-delivery penalties may help to reduce the net exposure of a generator to a single stress event. The Government is encouraging the development of insurance and other financial products to cover such unavailability risk and, if these products emerge, it is likely that financiers will require developers of new build single plant to procure such support, although the cost of such support could render such plant uncompetitive in the capacity auction relative to existing plant owned by portfolio generators. Several commentators have noted that the treatment of unavailability risk under the capacity market compares unfavorably with the equivalent arrangements under comparable energy infrastructure regimes such as the Offshore Transmission Owners (OFTOs). Again, this may disincentivize investors and funders of conventional plant that rely on a capacity payment revenue stream.
Further, there is no separate change of law mechanism to address supervening regulatory change that was unforeseeable and which occurs between the date of the relevant auction and the relevant delivery year that could render performance uneconomic unless the cost of compliance is reflected in adjusted capacity payments. It is proposed that this concern could be mitigated by “grandfathering” key terms of the capacity agreement by embedding them in the regulations so that they have legislative effect. Clearly, this would not offer any protection if the regulations themselves were subject to change. Failure to address fully these concerns could mean that new entrants will be unable to secure adequate levels of funding to compete with existing plant.
At present interconnected capacity is ineligible to participate in the 2014 capacity auction mainly due to the operation of interconnector capacity rules under the EU Target Model for market coupling. However, the Government is mindful of the importance placed on the participation of interconnected capacity in any consideration by the European Commission of Member States’ capacity payment mechanisms for state aid purposes and is committed to finding a solution to this problem. Nevertheless, before cross-border capacity is admitted, further safeguards to the design of the UK capacity market may be required to monitor the actual availability of the capacity resources committed by the foreign provider and to ensure that it will be permitted to make such committed capacity available in circumstances where there are stressed situations either side of the interconnector.
Lessons Learned from US Capacity Markets
In the US, there are six mature organized electricity markets characterized by locational marginal pricing with an independent system operator (ISO) functioning as the market administrator for the clearing price markets (ISO-New England, the New York ISO, PJM Office of Interconnection (Mid-Atlantic states), Mid-Continent ISO (formerly the Midwest ISO), the California ISO and the Electric Reliability Council of Texas). The three north-eastern ISOs have somewhat mature but evolving capacity markets. The lessons learned from these markets can help to avoid repeating mistakes.
US capacity markets used to involve little more than confirmation that each load serving entity (LSE) had sufficient generation under ownership or contract to satisfy peak demand plus reserve margin accompanied by generator dependable capability testing. In the early days of these markets (1998- 2003), if there was a surplus, capacity prices tended to plummet because all suppliers would rather have some revenues than become the one that was priced out. In parallel, in times of relative shortage, prices would jump to the penalty an LSE would have to pay if it was deficient – two to three times the all-in cost of a peaking unit. This resulted in a naturally occurring vertical demand curve with prices plummeting with relatively small surplus and prices sky- rocketing in times of slight shortage. Meanwhile, energy prices following the fallout from the California energy crisis were substantially mitigated. With limited scarcity pricing, and a boom- bust cycle in the capacity markets, there was significant concern that capacity was not being built where and when needed. There was little political will to ease mitigation so as to let energy prices reflect scarcity conditions in more hours and in greater magnitude than market power mitigation would allow. In order to shore up the revenues and price signals to facilitate new development, restructured capacity markets commenced about ten years ago. The NYISO was the first to use a demand curve structure. All supply would have to bid into the capacity market. The ISO, subject to the US Federal Energy Regulatory Commission’s (FERC) review would determine the price of capacity based on the all-in cost of new entry (CONE) of a peaking unit less the margins the unit could expect from sales of energy and ancillary services to form net CONE. This price was the theoretically economic efficient price when the market had just enough capacity to satisfy peak load plus reserve margin. The ISO would then establish a zero crossing point – an amount of capacity surplus at which the price should be set to zero; and a maximum capacity price at which the prices would be high and level off. With these three points, a linear curve can be formed to guide capacity auctions. All units that bid in below the curve would clear and receive the price at which the amount of supply below the curve crossed the curve.
The demand curve structure sent price signals so that in times of surplus prices would decrease, but not vertically so and in times of shortage, prices would increase without immediately jumping to the penalty level. The demand curve also recognized that there was value in capacity in excess of the installed reserve margin.
All capacity had to participate in the auction. In zones that were import restricted, a certain amount of capacity had to be procured within the zone. Before long, concerns arose that large or critical suppliers in such zones could withhold some of their capacity to ensure prices were higher on the capacity that cleared. In response to this threat, ISOs adopted critical supplier screens and required them to bid into the capacity market as price-takers so they could not withhold. ISO market monitoring units started monitoring for physical and economic withholding as well.
After a period of time, the opposite concern arose – buyer market power or monopsony power. Some large load serving entities that had divested generation to non-affiliated entities were substantial buyers in the ISO capacity auctions. If such buyers entered into power purchase agreements at above market clearing levels they could stimulate new investment even when it was not needed. If the uneconomic entry causes the capacity prices to drop enough, then the load serving entity might pay too much on 1,000 MW, but reap much greater savings on the other 9,000 MW it purchased in the auction. Uneconomic entry had the effect of causing volatile crashes in capacity prices. In response, FERC required the three eastern ISOs to develop buyer- side mitigation to prevent uneconomic new entry from resulting in artificially low capacity prices. The rules are evolving now. In the NYISO market, a new entrant is subject to a unit-specific net CONE determination by the ISO. If the ISO determines that the unit would clear the ISO’s forecast of the capacity market prices, then it would not be mitigated and may bid as a price taker. In contrast, if the ISO determines that the net CONE is above market clearing levels, the unit must bind in to the market with an offer floor.
In PJM, only gas-fired units are subject to buyer side mitigation (a/k/a the Minimum Offer Price Rule or “MOPR”). PJM calculates each new entrant’s net CONE which forms an offer floor.
If the unit clears an annual capacity auction, then it is not to be mitigated. If the unit’s costs result in an offer floor above the clearing price, the unit will not clear the auction, will not receive capacity revenues and will not contribute to lowering capacity prices. This state can continue indefinitely.
Needless to say, there are a number of contentious issues going into the ISO demand curve – assumptions about the reference CT capital structure, cost of capital, margins on energy and ancillary service sales, the slope of the curve, the zero crossing point and other issues. Implementing the capacity markets as structured is in some requests a throwback to ratemaking in a quasi-market context. It is at best regulated competition.
All of these quasi-regulatory patches on patches are a result of energy only price signals that were constrained by supplier side mitigation measures which tended to over-mitigate. Rather than lifting energy mitigation the regulator thought capacity markets with evolving critical supplier mitigation followed by buyer side mitigation and actual offer floors were the way to go.
The capacity markets range from a year-ahead auction market to a three-year ahead market, but each auction produces prices for only one year. The capacity market revenues are not liquidated for any length of time, making the revenue streams less effective to bring down the cost of non-recourse project financing.
In addition to the mitigation of energy prices, over the last decade of capacity markets, the growth of intermittent renewable energy sources has been substantial in some markets. This further reduces energy market revenues which a new CCGT unit may expect. In some instances, energy prices go negative when the wind is blowing and the ISO needs to curtail or back down supply. Negative prices can result in financial obligations for some economic supplies.
Additional flux surrounds evolving rules by which demand response (DR) may participate in the capacity markets. The rules were different for generation and DR. For example, generators must offer supply into the ISO Day-Ahead market in an amount equal to or greater than the amount of capacity which the generator has cleared in the applicable auction.
If the generator were not available when needed, its equivalent forced outage rate would suffer, and the amount of capacity it could sell in the future would decrease. In contrast, DR resources were treated as an emergency resource and did not have a day-ahead offer requirement. If DR resources, however, were not available when called in some markets, they would lose half of their capacity revenues on the year, and if they failed to respond a second time, they would lose all capacity revenues on the year. Other rules affect the incentives for DR resources to participate in the capacity market. For example, there is current litigation over the mandatory response time for DR resources.
On rare occasions, DR suppliers have been found to game the system. Both FERC’s Office of Enforcement and ISO market monitoring units have stepped up review of compliance and verification efforts. The potential to lose 50 to 100 percent of the annual capacity revenues by not responding— curtailing load or bringing up on-site generation—is also an incentive to achieve and maintain compliance.
To conclude, capacity markets, once introduced, should not necessarily be regarded as permanent features and in theory should be phased out once generation adequacy can be permanently ensured by the energy market offering a sufficient level of pricing to deliver the appropriate investment incentives. In practice, and based on the US experience, this is unlikely to happen unless the predictability of capacity payment pricing that may be realized under a well-designed capacity market can be replicated in the energy market. Indeed, even if such a level of pricing predictability could be achieved, the pace of phase-out of any capacity payment mechanism needs to be carefully considered, particularly if one of the market design objectives is to stimulate new build plant rather than simply to delay the decommissioning of existing plant. As it is likely that longer duration arrangements will need to be offered to incentivize investors and to ensure the bankability of such arrangements, there should be no suggestion that existing commitments can be prematurely curtailed if the required level of generation adequacy is achieved earlier than anticipated.
In the EU context, a tension exists between national capacity markets that are deploying increasingly sophisticated payment mechanisms to achieve generation adequacy targets and EU regulations that support the development of the internal energy market. The new State Aid Guidelines should ease this tension, although a co-ordinated approach to the introduction of capacity mechanisms by Member States is still required to ensure their compatibility with the process of EU market integration. However, for some Member States, the more pressing requirement to meet security of supply concerns at the national level may overrule such an approach.