Giant batteries drain economics of gas power plants
Banks are focused on financing plants that have guaranteed revenues, three bankers involved in energy project finance said, asking not to be named because they were not authorised to speak to the press.
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Giant batteries that ensure stable power supply by offsetting intermittent renewable supplies are becoming cheap enough to make developers abandon scores of projects for gas-fired generation worldwide. The long-term economics of gas-fired plants, used in Europe and some parts of the United States primarily to compensate for the intermittent nature of wind and solar power, are changing quickly, according to Reuters' interviews with more than a dozen power plant developers, project finance bankers, analysts and consultants. They said some battery operators are already supplying back-up power to grids at a price competitive with gas power plants, meaning gas will be used less.
The shift challenges assumptions about long-term gas demand and could mean natural gas has a smaller role in the energy transition than posited by the biggest, listed energy majors. In the first half of the year, 68 gas power plant projects were put on hold or cancelled globally, according to data provided exclusively to Reuters by U.S.-based non-profit Global Energy Monitor. Recent cancellations include electricity plant developer Competitive Power Ventures decision announced in October to abandon a gas plant project in New Jersey in the United States. It cited low power prices and the absence of government subsidies without giving financial detail.
British independent Carlton Power dropped plans for an 800 million pound ($997 million) gas power plant in Manchester, northern England, in 2016. Reflecting the shift in economics in favour of storage, this year it launched plans to build one of the world's largest batteries at the site.
TRENDING NOW
"In the early 1990s, we were running gas plants baseload, now they are shifting to probably 40% of the time and that's going to drop off to 11%-15% in the next eight to 10 years," Keith Clarke, chief executive at Carlton Power, told Reuters.
Without providing price detail, which companies say is commercially sensitive, Clarke said Carlton had struggled to finance the planned gas plant in part because of uncertainty over the revenues it would generate and the number of hours it would run.
MODELS UNDER SCRUTINY
Developers can no longer use financial modelling that assumes gas power plants are used constantly throughout their 20-year-plus lifetime, analysts said.
Instead, modellers need to predict how much gas generation is needed during times of peak demand and to compensate for the intermittency of renewable sources that are hard to anticipate.
"It does become more complex," Nigel Scott, head of structured trade and commodity finance at Sumitomo Mitsui Banking Corporation, said.
Investors are putting increased scrutiny on the modelling, he added.
Banks are focused on financing plants that have guaranteed revenues, three bankers involved in energy project finance said, asking not to be named because they were not authorised to speak to the press.
Many countries world-wide, but especially in Europe, provide payments for standby power plants through capacity markets. In these markets, power producers bid to be back-up suppliers.
The system has long been criticised by environmental campaigners on the grounds it can amount to a subsidy to fossil fuel. Its advocates say it is necessary to ensure the smooth integration of renewable power and that the payments can also reward batteries.
Those selected to provide back-up generation are paid to keep plants ready to come online at short-notice to meet peak demand, or to cover for outages at other plants, or to compensate for variance in wind or solar power generation.
These payments can improve the economics for gas-fired plants, but are insufficient to guarantee long-term profits.
Carlton Power secured a capacity auction contract for its planned UK gas plant, but had to relinquish it because of delays in securing investment due to uncertainty over the project's future revenues.
The UK first introduced a capacity market in 2014, and more than a dozen countries followed with similar schemes.
Battery and interconnector operators are also participating in these auctions, and have begun to win contracts.
The cost of lithium-ion batteries has more than halved from 2016 to 2022 to $151 per kilowatt hour of battery storage, according to BloombergNEF.
At the same time, renewable generation has reached record levels. Wind and solar powered 22% of the EU's electricity last year, almost doubling their share from 2016, and surpassing the share of gas generation for the first time, according to think tank Ember's European Electricity Review.
"In the early years, capacity markets were dominated by fossil fuel power stations providing the flexible electricity supply," said Simon Virley, head of energy at KPMG. Now batteries, interconnectors and consumers shifting their electricity use are also providing that flexibility, Virley added.
RISING RISKS
The start-up in March of UK energy company SSE's Keadby 2, a gas power plant in eastern England, was supported by a 15-year government contract signed in 2020 to provide standby electricity services to the grid from 2023/24. The plant was financed by the company before it had the standby contract, and took four-and-a-half years to build.
The economics for such a plant would look different now, said Helen Sanders, head of corporate affairs and sustainability at SSE Thermal.
"I don't think we'd be taking an investment decision without revenue security through some sort of mechanism now because of the inherent risk associated with revenue security," Sanders said.
"If you're investing in something purely based on merchant market exposure, you're really going to have to see very, very high power prices, if you're only running for a lower number of hours."
Efforts to cut carbon emissions may add another cost to fossil-fuel plants: countries including the UK and the United States are considering requiring operators to retrofit plants with carbon capture infrastructure.
European Union rules introduced in January require gas plants seeking to access green finance to be built with carbon capture or be able to switch to using low carbon gases such as hydrogen from 2035.
OFF SWITCHES, EVs
As the energy transition gathers pace, other developments may reduce the need for back-up plants.
UK energy retailer Octopus Energy last year ran trials that offered to pay households a small fee to stop using electricity for an hour at a time during periods of strong demand.
The trials covered the equivalent amount of power demand that a small gas plant would meet, or what could be saved by turning off more than half of London for an hour.
Electric vehicles are a further disrupter as they can be charged when demand is weak and then power homes or send power back to the grid during peak demand periods.
A typical EV sits parked 90% of the time with a battery capable of storing enough energy to power the average modern home for two days, energy software platform Kaluza said in a report published in December.
In Europe, 40 million electric vehicles are expected by 2030, capable of displacing around one third of the region's gas power capacity, according to Kaluza.
"There are lots of things the grid can look to when it starts to look away from conventional generation," Carlton's Clarke said.
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