Space, time and electricity (part 1)
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Space, time and electricity (part 1)
DEEP DIVE: How should power prices be formed on a grid that is constraining renewables?
Not all energy is made equal. As a general rule, the more obstacles that lie between a unit of energy and its end-user, the less value it has. A molecule of gas is often a liability at the wellhead, but commands an eye-watering premium once in a pipeline network in Europe or Asia. Location is hard-wired into gas markets. Price differentials signal a need to send volumes from producing regions to demand centres and, if necessary, build infrastructure to facilitate the trade.
That’s not often the case in electricity. Wholesale prices in many liberalised power markets do not fully reflect inherent value. Due to the ephemeral nature of electricity, value is tied not only to the electron’s physical whereabouts within a power grid, but also to its time of generation and the predictability of that timing.
Wind and solar — clean power sources with zero marginal costs and variable output profiles that must be produced in specific resource-rich locations — have a very different value proposition to conventional generation. For this reason, countries that are decarbonising their power grids are finding their legacy systems of price discovery are no longer fit for purpose.
The UK, a world leader in renewables integration, is a case in point. UK wholesale electricity prices have a temporal dimension but not a spatial one.
Contrary to popular understanding, the UK does not have a single clearing price but rather various indexes which each represent a basket of trades, e.g. month-ahead, day-ahead, intra-day prices etc. This is why the UK could not easily institute an Iberian-style cap on the price of gas-fired electricity: there is no single pool clearing price to fix. Yet each of these indexes applies across the whole of the UK regardless of location.
The growing dominance of renewables is prompting calls for that to change. Power derived from the wind, sun and rain hit a record high of 43% of total UK generation in 2020. Penetration will grow further as the UK strives to achieve 50 GW of offshore wind installed capacity by 2030 and reverses a de-facto ban on onshore wind development.
Wind must be harvested where it is most abundant and where turbines have the lowest environmental and visual impacts. This rarely correlates with where the electricity is required, i.e. near built up areas or industrial complexes. National Grid ESO, the UK energy system operator, must overcome this spatial challenge as well as wind’s inherent temporal variability.
Fixing the mismatch between electricity supply and demand over four dimensions is becoming an increasingly costly endeavour due to transmission constraints. If a glut of wind power in the North Sea or rural Scotland can’t be matched with demand in south-east England due to a lack of network capacity, it must be constrained. The wind farm is paid to shut down, and an alternative generator — often gas — is paid to fire up on the other side of the pinch-point.
Constraint payments are ballooning, driving up the overall cost of balancing the UK power system. Balancing costs were already rising in tandem with renewables penetration before last year’s global gas shock. They spiked in September 2021 when wholesale prices surged and are forecast to be £232 million this July — 78% higher than July 2021. And because unabated gas is typically called upon to replace curtailed renewables, roughly 2% of total UK power sector CO2 emissions are attributable to curtailment.
The rising financial and environmental burden of grid balancing is fuelling a debate in the UK about how best to price the value of intermittent electricity generated in far-flung parts of the network. The discussion is highly technical and almost esoteric at times, but well worth understanding because the outcome will determine infrastructure investment flows worth many billions of pounds. (It could also influence other countries; Britain’s many post-privatisation regulatory experiments have become a global reference.)
The debate centres on whether introducing a locational dimension to UK power prices would fix or worsen the constraints problem. Put simply, locational marginal pricing (or LMP, as it is known) means establishing electricity prices at numerous points across one grid. Prices vary between either geographical ‘zones’ or specific ‘nodes’ on the physical network. These variations arise from constraints preventing the free flow of electricity between two locations.
LMP is a step-change in complexity; it means replacing the current one-dimensional wholesale model with numerous regional or node-specific prices at key points across the grid, in real-time. At the risk of over-simplifying matters, it is a bit like playing four-dimensional chess with quadrillions of electrons.
There are two main camps in the LMP debate:
The ‘anti-locational pricing’ crowd is calling for regulatory stability to attract investment, and believes there are easier / less disruptive solutions such as building more transmission capacity and encouraging dynamic demand response
The ‘pro-locational pricing’ crowd advocates fundamental redesign of UK electricity pricing to reflect the ‘where’ and ‘when’ of power generation relative to fluctuating demand, pushing geographical network risks onto generators in the hope of improving overall system efficiency
The British renewables industry and the Scottish government sit firmly in Camp 1: ‘Keep it simple, build more transmission lines’. Wild, remote Scotland is home to the lion’s share of the UK’s exploitable wind, wave and tidal resources and is a net exporter of green electrons to England. The devolved administration in Edinburgh has for years been calling for a transmission charging regime that does not discriminate generators on the basis of location because this would be bad for jobs and investment in Scotland.
The view from Camp 2 is quite different. Some big utilities and influential consultancies are pushing to tear up market rules, claiming consumers will be the beneficiaries of a more efficient system. The philosophy underpinning this is as follows:
consumers should come first, not renewables investors
costly supply-demand imbalances should be minimised without inconveniencing them
proximity to demand centres should be a primary factor in capital allocation decisions
therefore, wholesale prices need to reflect the locational value of electricity
These arguments are starting to resonate within parts of National Grid ESO. The allure of a technology-agnostic pricing system that rewards efficiency without relying solely on infrastructure upgrades is proving irresistible to some free marketeer policy wonks.
Those in Camp 1 are pushing back, arguing that it makes no sense to reward investors for putting wind turbines in built-up areas where there’s less wind. They are also questioning whether the upheaval is wise at a time of extreme market uncertainty. What about unintended consequences?
The UK energy sector is seeking unprecedented investment sums at a critical moment. Britain faces vanishingly thin winter capacity margins and a deepening energy-driven cost of living crisis following a wave of supplier bankruptcies. Consumers are paying a hefty price for regulatory failings, with the worst impacts yet to come. But instead of formulating an adequate policy response, ministers pursued dubious knee-jerk measures that could easily backfire.
The UK spent the decades since privatisation in a state of almost perennial regulatory flux. With prolonged crises ahead, are ministers about to corral the country towards another huge and tortuously complicated energy market revamp with highly uncertain outcomes? Or will locational pricing prove to be the ‘silver bullet’ to the knotty question of wind farm constraint payments?
In a new mini-series, Energy Flux will explain in depth what locational marginal pricing is, how LMP differs from the current setup, the problems it is trying to solve, and the lessons to learn from international markets with LMP. Finally, it will attempt to weigh up whether LMP is indeed the ‘least bad’ way to reconcile the UK’s energy transition contradictions.
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