Drax looks to gas to complete its low-carbon transition

Drax is convinced that gas would be the perfect complement to its three biomass units, but government policy is proving frustratingly lukewarm about the technology. Tom Grimwood reports.

When Drax was formed in 2005, the company faced a major problem. Even then it was already clear that, with the momentum towards decarbonisation starting to build, the colossal 3.8GW power station that the company was created to operate could not continue to burn coal unabated over the long term.  

Since then Drax has headed down several different avenues in an attempt to find its place in a low-carbon future, but on multiple occasions has found its path blocked.  

The company spent millions of pounds developing proposals to retrofit the plant with carbon capture and storage but its plans were scuppered when, without warning, the government axed its £1 billion commercialisation competition in late 2015.  

Drax has also ploughed time and money into converting the plant to run on biomass, and not without success. Three of the six units at the power station are now running entirely on biomass and the plant accounts for huge proportion of low-carbon generation in the UK. Indeed, Drax still hopes to convert a fourth unit to run on the fuel.  

However, government support for biomass appears to have waned over recent years, chiefly due to concerns over cost. As a result, Drax has shifted its focus towards another potential opportunity – providing the ancillary services and flexibility which will be needed to accommodate a growing volume of intermittent wind and solar generation.

On a visit to the power station in Yorkshire last week, Drax head of ancillary services Ian Foy told Utility Week the technologies that have been most attractive to investors in recent years – wind, batteries, and gas and diesel reciprocating engines – will not be able to provide the full range of services that system operator National Grid will require.  

Large thermal plants will have an essential role to play, he argues. With coal out of the picture, and possibly biomass too, that means gas.  

“Gas, we think, is going to be the future,” says Foy. “We think CCGTs [combined-cycle gas turbines] are going to have to be built, even though nobody’s building them at the moment. Therefore, we’re going down that route.”

He says that although open-cycle gas turbines will have a part to play, ultimately the power system will need more expensive-to-build but also more fuel-efficient CCGTs because many gaps in renewable generation will last for “days and weeks” rather than minutes and hours.  

Drax acquired four OCGT projects earlier this year and plans to create two new CCGTs at Drax power station by repurposing steam turbines currently used in its remaining coal units.  

However, large gas plants, and CCGTs in particular, have so far struggled to win contracts in the capacity market. The only new- build CCGT project to secure an agreement later reneged on the contract after failing to tie down financing.  

Visibility

Foy says this is partly down to a lack of long-term visibility about potential revenues from the provision of ancillary services.  

He highlights a particular issue over the procurement of reactive power – the “unproductive” power used to push “productive” power around the grid. Reactive power can be absorbed or produced by generators to control voltage, but its impact diminishes over distance “like ripples in a pond”.  

Foy says the closure of large thermal plants means there is a growing need for voltage control in the North. But, because there is little clarity about the revenues that will be up for grabs, he says new-build capacity contracts have instead gone to distributed peaking plants in the South, where their revenues are boosted by reduced transmission charges.  

“It’s difficult to build anything in the right place,” he complains. “There is not a single thermal plant, or a single controllable plant, being built north of Drax.”

Drax Power chief executive Andy Koss argues that in general National Grid needs to provide more visibility on the prospects for ancillary services, by overhauling procurement mechanisms, offering long-term contracts, or at least clarifying how much they expect to spend. “There are all these ancillary services but there’s no transparency about what they are and how much you’re going to make,” he says.

In fairness to National Grid, the system operator has already taken a step in this direction with the publication of a “System Needs and Product Strategy” earlier this summer. The document acknowledged the failure of the current arrangements to properly value reactive power capability and included proposals to design and implement a new reactive power market by 2018/19.

Foy also has major concerns about the provision of system inertia – the resistance of the power grid to sudden changes in frequency when there is a loss of load. System inertia is provided by synchronous generators, which feature large rotating masses spinning in sync with the frequency of the power grid. The closure of such plants has already led to a reduction inertia – a trend that is set to continue.  

Wind, solar and interconnectors are all asynchronous sources of power and therefore unable to provide inertia.  

Although nuclear generation is synchronous and can provide inertia, Foy says it can actually be a hindrance rather than a help. When Hinkley Point C comes online in the late 2020s, its two massive 1.6GW reactors will represent the largest potential load losses on the grid, and will therefore increase the need for system inertia, he argues. Accordingly, National Grid has forecast an increase in balancing costs around this period.  

Foy says the peaking plants being built in the South can also contribute to instability in the grid because many automatically disconnect in response to sudden changes in frequency.  

National Grid intends to tackle the problem of declining inertia by removing the largest potential losses from the system during periods of low system inertia and effectively creating artificial inertia through the procurement of fast-acting frequency response.  

Koss is unconvinced, believing some synchronous generation will need to stay on the grid to act as a pacemaker for the rest of the system. “We think National Grid should create a market for inertia. Given it is such a vital service, it would give the market more visibility and allow providers to price it into their running costs, in turn bringing down the costs of balancing services for consumers,” he adds.

Foy says the absence of predictable revenues for a whole range of ancillary services, including black start capability and frequency response, has now led to a situation in which investment in dispatchable generation is determined largely on the basis of capital costs, with little regard for whole-system benefits. Hence the proliferation of reciprocating engines in the capacity market.  

If these revenues were safer or more predictable, Koss says large gas plants would be able to bid into the capacity market at a lower price and finally find success. “Transparency, predictability and certainty is what’s going to make the market work,” he adds.  

He will have to pray that these pleas don’t fall on deaf ears. Otherwise, Drax could once again find that the route ahead is blocked.

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