Markets that exist to keep dispatchable generating capacity online to counter reliance on variable supplies of renewable energy face an uncertain future. In Britain the need for its capacity market and its legality are being questioned. Elsewhere, flexible energy market products are a hotter commodity than capacity for achieving security of supply. Texas and Australia are prime examples
The issue:
In countries increasingly reliant on variable supplies of energy from renewable sources can we trust in the forces of supply and demand alone to keep the lights on? Experts say:
Yes, with good market design. It is cheaper to secure supply in times of renewables scarcity by paying high prices for peak generation, or reductions in demand, than to pay generators to maintain capacity in case it is needed Wake-up call:
Fossil fuel generators are earning windfall profits from availability payments, despite providing no added-value for electricity consumers Key quote:
“Capacity markets could just fade off into irrelevance.” Bottom line:
The cost of the energy transition will be higher and its speed slower if poor market design keeps fossil fuel capacity online unnecessarily
Poor electricity market design will slow the energy transition. Offering incentives that keep polluting generators online unnecessarily makes little sense. Discouraging investments in flexibility resources like demand response and beefed-up transmission grid interconnections jeopardises future security of supply. Such flexibility will be increasingly crucial as reliance on variable supplies of renewable energy grows. For evidence of the risk of bad market design look no further than the UK, where the power capacity market was under fire for working against the energy transition even before its future was thrown into doubt by a recent EU court ruling. The UK capacity market has “essentially been enabling fossil fuel plants to keep operating longer than they would otherwise”, says Frank Gordon from the UK’s Renewable Energy Association. And it has done so without a value-for-money safeguard for citizens, such as the claw-back clause used in the contracts for difference system that incentivises renewable energy. It limits payments to generators when the market reference price goes above a strike price, Gordon points out. Criticism is widespread that capacity payments to fossil fuel generators for simply being available to supply electricity — paid in addition to any revenue from energy sales — are handed over to companies for doing what they would have done anyway, resulting in windfall profits. The UK’s power capacity market was introduced for fear that lack of generation during times of peak winter demand could mean blackouts. It was seen by the government as the best way to ensure adequate capacity at a time when old fossil fuel stations were being taken offline and reliance on the variable output of renewable energy capacity was increasing. In November 2018, the General Court of the EU ruled that the European Commission, the EU executive body, had not adequately vetted the UK’s chosen capacity mechanism as non-discriminatory before clearing it back in 2014. The judgement concluded the Commission failed to properly assess that paying electricity customers to shift demand for electricity to another time, called demand response (DR), could play a role in the market. Demand response provider Tempus Energy brought the case on the grounds fossil fuel generators were being given an unfair advantage. The entire UK capacity market is now on hold while the government works with the Commission to get it re-approved. Britain’s system operator National Grid has reassured the country that security of supply is not at risk this winter and market observers say capacity auction results indicate there is no pressing need to secure capacity in the immediate future. In the UK’s last T-4 auction, the base auction for contracting power capacity for delivery four years in the future, the clearing price tumbled to £8.40, down from what was already seen as a low £22.50 the previous year. Some 86% of contracts went to existing generation. The capacity market has noticeably not achieved the objective of new investment in large combined-cycle gas turbines (CCGTs), seen by policymakers as efficient, flexible, less-polluting and reliable replacements for old fossil-fuel capacity coming offline.
Fundamental mistakes
Alastair Martin of demand response operator Flexitricity sees the current standstill as an opportunity for correcting some fundamental mistakes in the UK capacity market. “The first large error was to fail to apply the emissions standard to everyone seeking new-build contracts,” he says. As a result, capacity contracts were awarded to some 4 gigawatts (GW) of small-scale gas. In the first two auctions, even power plants running on diesel, brought on line when demand is high, were able to sidestep emission requirements due to their small size. “The second big mistake was to allow different contract lengths to be given to different parties with a significant disparity of treatment between participants,” Martin says. The UK’s capacity market gives a clear advantage to new-build power generators, which may secure 15-year contracts, over demand response providers, for which only one-year contracts are available. A basic premise behind capacity markets like that in the UK is that power markets based entirely on the buying and selling of energy, including the provision of grid support services, do not on their own give the right price signals to ensure sufficient capacity is available, either through new investments or by keeping existing power plants online. Also, the low marginal cost of renewable energy means that it will increasingly depress wholesale energy prices as the energy transition progresses, making it even more difficult for generators to recover investment costs through sales of energy alone. Critics of capacity markets, however, insist they distort the efficient functioning of energy markets by exacerbating costly power overcapacity still seen throughout the US and the EU, depressing prices and thwarting the ability of energy markets to transmit price signals to drive investment. Governments have demonstrated a tendency to overestimate capacity needs, says Manon Dufour from the Brussels office of climate change think-tank E3G. The distortive impact of capacity markets on wholesale energy market prices can be seen from the way power prices reacted when the UK capacity market spun into a standstill. “Prices for electricity to be delivered in 2019 and 2020 shot up,” says Mike Hogan, senior adviser with the Regulatory Assistance Project (RAP). “Generators can still earn money, not in the capacity market, but in the energy market, where they should have earned it in the first place,” he says. “At some point, new investment will be required to replace ageing and polluting fossil-fired plants,” stated Philip Baker, also with RAP, in feedback to the UK government in a review underway before the EU court ruling. But he believes the best way to ensure this investment is by continuing and accelerating market reforms proposed by the UK energy regulator Ofgem, particularly those aimed at the balancing market run by National Grid. Key balancing market reforms include increased charges for electricity suppliers and utilities that fail to meet forecast supply and demand and the opening up of the market to aggregators of small-scale renewables and demand response providers with as little as 1 megawatt (MW) of capacity, according to Gerard Wynn, an energy finance consultant with the Institute for Energy Economics and Financial Analysis (IEEFA). The reforms are intended to cut the cost of matching supply and demand in real time. They could also help foster innovative solutions to the security of supply challenge, efficiencies and flexibility without the extra cost to consumers of setting up a capacity mechanism outside of the energy market, he says.
Flexibility versus capacity
Falling prices in UK capacity auctions have shown the issue is no longer one of resource adequacy, but of flexibility adequacy, argues Aris Karcanias of FTI Consulting. He believes the existing UK capacity market design is ill-suited to meet the flexibility needs of a future energy system required to be “more dynamic, diverse and coupled with a more active demand profile”. Favouring legacy assets, the capacity market has not provided the right price signals to drive investments in flexible solutions, he believes. Karcanias says this should be remedied, ideally by using auctions to procure demand suppression and reward flexibility. “Ultimately, you need both capacity and flexibility, but in different quantities and forms, and you need to price them differently.” Others also see the balance increasingly tipping towards flexibility and away from capacity in meeting security of supply needs. The biggest challenge for security of supply in the British market is “providing flexibility rather than the overall level of capacity”, stated consultants KPMG after the UK’s last T-4 auction. “The challenge for policy makers is to consider if procuring flexibility (interconnectors and demand side response) can offer the same levels of security of supply as procuring large-scale generation capacity.” In discussions about market design and capacity markets in the UK and elsewhere, Ulrik Stridbæk, head of regulatory affairs at Denmark’s Ørsted, a major renewable energy supplier in Europe, says there are a number of important elements to keep in mind. “We must be careful not to try to solve problems that might occur in a few years, we shouldn’t speak about renewables as a problem,” he says.
PJM experience
On the other side of the Atlantic, PJM Interconnection, which runs the capacity market known as the Reliability Pricing Model (RPM) for 13 US states from New Jersey to Illinois, is often viewed as being more open to demand response and to renewable energy sources like wind and solar. The entire PJM system is increasingly seen as a source of security of supply in its own right. In recent years, though, PJM has made it more difficult for renewables to compete in the capacity market, says Mike Jacobs from the Union of Concerned Scientists, a US not-for-profit. Ironically, the seeds of the problem date back to the so-called polar vortex in the winter of 2014, when many fossil-fuel power stations were unable to run because of frozen pipes, a lack of fuel and other shortcomings. Wind energy and demand response helped fill the gap. PJM subsequently introduced a year-round performance requirement and penalties for non-performance. Since the contribution from wind, solar and demand response varies on a seasonal basis, their potential continues to be under-recognised. PJM’s actions means we will just keep building gas plants, says Jacobs. He adds that the setting of the delivery procurement period to three years ahead of need: “Pretty much matches the construction time for natural gas, but wouldn’t suffice for nuclear and is too long for the providers of demand response, solar or storage.” The more-gas-is-better approach has been an obstacle to reducing carbon emissions and establishing a diverse fleet of complementary power providers. Like National Grid in the UK, PJM has also postponed its next capacity auction, in its case by three months to August 2019, amid a heated and often confusing debate about the treatment of subsidies in the capacity market. PJM in 2018 requested permission from the Federal Energy Regulatory Commission (FERC) to adjust bid prices for nuclear and renewable generation that receive out-of-market payments, but FERC rejected the proposal. It argued that PJM should root out all out-of-market payments to all generators, and could not rely on existing rules, explains Jacobs. And new rules, which could potentially radically alter the way the PJM’s capacity market works, have not yet been approved. A FERC decision on the latest capacity market proposals from PJM and its stakeholders is expected soon. One possibility, thrown out for discussion by FERC itself, could see the expansion of PJM’s little used Fixed Resource Requirement (FRR). This allows a utility to opt out of the capacity market and take responsibility for assuring 100% of its own resource capacity needs. Under an alternative resource-specific FRR suggested by FERC, a utility could procure part of its capacity requirement bilaterally with a wind farm, for example, and secure the rest on the capacity market. Hogan says that PJM is also taking steps to improve the functioning of energy and ancillary services markets, which will reduce the importance of capacity market revenue and the capacity market itself. In the end, “PJM’s capacity market could just fade off into irrelevance”, he says.
The strategic reserve option
Back in Europe, several countries have shied away from the complexities of running competitive capacity markets alongside their energy markets, choosing instead to establish strategic capacity reserves. Germany’s strategic reserve, operated outside the market, is a typical example. It is made up of 2.7 GW of lignite coal capacity, the last of which is slated to be shuttered by 2023. This reserve will be activated only once all balancing market mechanisms have been exhausted. Should the system operator be required to tap those reserves, balancing responsible parties would have to pay €20,000 per megawatt hour for that electricity, double the maximum price on the intraday energy market. The idea is that if a company sees a high risk that would mean paying such prices, it “will do other things such as reduce demand provided it is economically viable or invest in other flexibility resources”, says Thorsten Lenck of German energy policy think-tank Agora Energiewende. Looking ahead to after 2021, Germany in 2018 received European Commission approval for a 2 GW capacity reserve to be used only after all market-based solutions are used. This is set to be in place for two consecutive two-year periods, from 2021 to 2025. The first auction for supply of reserve capacity will be held in 2019 and be open to generators and demand response suppliers. “Germany does not expect structural capacity shortages in the future, but the capacity reserve aims to safeguard against extreme and unforeseen developments during the ongoing reform of the German electricity market (Energiewende) and to manage the phase-out of nuclear electricity generation,” the Commission said when announcing its approval. Stridbæk concurs that a strategic reserve like that in Germany is easier to phase out than a full-fledged capacity market. “Strategic reserves are less intrusive and this might be a transitional solution,” he says. If designed correctly, a strategic reserve has the advantage of not interfering with the workings of energy and balancing markets, although it may be a pricey way to pay for what could be an almost imperceptible increase in security of supply, says Hogan. “They are smaller, kept out of the market and usually better accepted, but strategic reserves can also be designed in a way that creates problems,” states Dufour. “You really need to trust the TSO [transmission system operator] to use this capacity when it is strictly necessary, rather than when it is simply easier.”
Texas example
Those worried about security of supply with growing shares of renewable energy, but unhappy about the potential pitfalls of capacity markets and strategic reserves, could look for reassurance to the examples of Texas and Australia. Both the Electric Reliability Council of Texas (ERCOT) and the Australian National Electricity Market operate energy-only markets with a significant and growing share of renewables without resorting to capacity mechanisms. “The whole idea of setting up capacity markets was due to the decision to put a cap on energy prices, so shortages are never transmitted to the market,” says Jacobs. ERCOT, however, allows prices to jump as high as $9000 a megawatt hour. As a result, generators are generously remunerated for their energy supply in scarcity situations, but that still costs the consumer less than securing the same reliability through a capacity mechanism. Despite record temperatures in summer 2018, ERCOT did not cut supplies to any consumers and never had to declare an emergency, says Hogan, all the while getting 20% of power from wind and growing quickly in solar. “They’re getting a lot of price-responsive demand,” he adds. “The system is working just like it should.”
TEXT
Heather O’Brian