History of GB Energy

This moment marked the birth of centralised electricity generation. Rather than individual buildings generating their own power, Holborn Viaduct introduced the concept of a central plant supplying multiple customers. The station used six steam engines driving dynamos to generate direct current. Though it served only central London and was eventually superseded by alternating current technology, this was the founding principle of the grid we still rely on today: centralised generation, distributed supply.

By 1926, Britain had hundreds of small, isolated power stations, many using different frequencies and voltages. This was economically wasteful. The CEB standardised the system at 50 Hz alternating current and began building what would become the National Grid. This was a radical centralisation of what had been a fragmented industry, and set the template for how modern energy systems operate: planned, coordinated, national in scope.

The completed Grid was about 4,000 miles of high-voltage cable. It meant that a power station in Yorkshire could supply factories in the Midlands, and surplus power from one region could be rerouted to cover demand in another. During World War II, this flexibility proved crucial to maintaining supply during air raids and prioritising military production. The principles remain embedded in how the Grid operates today.

Nationalisation reflected the post-war consensus that utilities should be publicly owned. It also reflected the belief that coordinated national planning would deliver efficiency and universal access. The BEA structure remained largely intact until 1989. The period remains relevant because it set long-lived expectations around universal access, affordability, and coordinated delivery, even as later reforms changed the institutional model.

The CEGB's approach reflected the economic logic of the 1950s and 1960s: larger power stations were more efficient per megawatt. Coal was plentiful and pit closures had not yet begun. The CEGB built stations with names that suggested permanence and scale: Drax, Cottam, Ironbridge. This centralised model worked for three decades, but it also created path dependencies that constrained flexibility decades later. Once you've invested in a 2 GW coal station with a 40-year lifespan, you need coal at predictable prices for the next 40 years. That made the system brittle.

Calder Hall was both triumph and symbol. Triumph because it proved nuclear could generate large amounts of low-carbon electricity. Symbol because it embedded in British energy policy the idea that the state would provide baseload power via large centralised plants. This narrative lasted until 2008 at least. It also created constituencies (unions, supply chains, political constituencies in Cumbria and elsewhere) with strong incentives to support nuclear expansion. We're still untangling the relationship between that post-war vision and modern grid needs.

The discovery of North Sea gas was transformational. It gave Britain an energy windfall at exactly the moment concerns were rising about coal's future (the miners' strike was on the horizon). Gas was cleaner, easier to extract and transport, and could be monetised at high prices. For heating it replaced coal and town gas almost completely by the 1980s. For electricity it never quite took over as planned, but it became the residual fuel. The legacy is that Britain's residential heating remains profoundly dependent on gas, and when gas prices spike (as they did in 2021-2022), households feel it immediately.

This programme succeeded through coordination between government, the Gas Council, local authorities, and manufacturers. Every appliance had to be recalibrated because natural gas burns at different pressure and with different flame characteristics than town gas. The feat was technically impressive and logistically audacious. It reminds us that large-scale energy transitions require not just new generation, but coordinated replacement of end-use equipment. Today's heat pump rollout or EV charging infrastructure faces the same logic but with more decentralised decision-making.

The three-day week was a watershed moment. It showed that a centralised system could be brought to its knees by a single fuel source becoming unavailable. It also demonstrated that energy supply cannot be separated from labour relations and political economy. The miners' strike made clear that coal's role in the UK system was unsustainable: the coal industry was declining, costs were rising, and the political price of maintaining it was becoming untenable. This crisis directly prompted the investment in North Sea gas and accelerated nuclear plans. It also foreshadowed the miners' strike of 1984-85 that would eventually destroy the British coal industry.

The completed gas network represented a massive capital investment. Once built, it became economically rational to use it for decades. Today, 80% of British homes use gas for heating. That network remains largely unchanged since 1976. The permanence of that infrastructure now poses a challenge to decarbonisation: replacing gas heating with heat pumps means not only changing appliances in 20 million homes, but eventually retiring or repurposing a trillion-pound national asset. This is one of the hidden constraints on how fast the energy transition can move.

Privatisation was ideologically driven: the government believed that competition would reduce costs and drive efficiency better than state ownership. The structure they designed (separate generators bidding into a daily trading pool, with the Grid balancing supply and demand) was novel and influential. It did reduce some costs and increased efficiency. But it also created new problems: investment became shorter-term, concentration of ownership in a few large generators created market power, and the separation of generation from supply meant nobody was responsible for long-term adequacy. These tensions defined the next 35 years of energy policy.

The Pool was supposed to be a wholesale market that would drive competition and efficiency. In some respects it did: it introduced price signals and cost discipline that had never existed under state ownership. But it also created volatility. Generators could bid strategically; the two largest players (National Power and PowerGen) could influence prices by changing their bids. Consumers saw electricity bills rise despite efficiency gains. And the market focused on short-term arbitrage rather than long-term investment in generation capacity. By 2001, the Pool was seen as broken and was replaced.

Gas liberalisation was less disruptive than electricity privatisation because the pipeline infrastructure remained regulated (just like the electricity networks). What became competitive was supply: customers could choose which company sold them gas, and different companies could negotiate different prices and contract terms. In the late 1990s, this drove real bill reductions. But it also meant that gas companies would shop for the cheapest supplies, leading to a financialised gas market. That market design, when combined with geopolitical shocks and Russia's weaponisation of gas supply, created the crisis of 2021-2022.

NETA reflected lessons from the Pool's problems, but it also reflected the globalisation of energy markets. Electricity was no longer just bought and sold in a domestic market; it was hedged in international financial markets against gas prices, weather, and geopolitical risk. This made the system more sophisticated and in some ways more efficient (long-term contracts replaced daily volatility), but it also made it less transparent and more susceptible to financial flows. A bank's decision to reduce exposure to European gas futures could ripple through electricity pricing weeks later.

BETTA mattered less for market efficiency than for political economy. Scotland had its own electricity companies (Scottish Power and Scottish Hydro-Electric) and its own traditions. Unifying the markets meant Scottish hydro generation (flexible, low-carbon) could be deployed across the UK, but it also meant English and Welsh thermal plants competed directly in Scotland. It reflected the logic of integration, but it also created Scottish concerns that energy policy was being determined in London. That resentment has grown as Scotland decarbonises faster than England and encounters constraints on grid connection.

The Climate Change Act was unprecedented. It said: the government cannot decide later to abandon decarbonisation. The targets are legally binding. Governments that miss them face legal action. This was also the moment the energy system became openly political in a new way. Before, energy was about managing costs and reliability. Now it was explicitly about managing carbon. That required the government to take an active role in steering investment and managing the transition away from coal and fossil gas.

EMR reflected the view that market arrangements alone would not deliver decarbonisation targets at the required pace. Renewables needed revenue stabilisation, and nuclear required long-duration price certainty. The result was a return to more active government intervention through contracts, auctions, and price guarantees, while leaving open longer-term questions about how strategic technology choices should be governed.

The 2014 auction was a turning point. It showed that competitive bidding among renewables developers could achieve cost reductions that nobody predicted. Onshore wind at GBP 100/MWh was already competitive with existing coal plants. Over the next decade, costs fell even further. Offshore wind dropped from GBP 150/MWh in 2014 to GBP 40/MWh in 2024. Solar dropped from GBP 120/MWh to GBP 25/MWh. This cost trajectory changed everything. Renewables went from subsidised niche to cheapest source of new generation. That fundamentally altered the energy transition's economics.

This was symbolic not just for Britain but globally. If the world's first industrial nation could eliminate coal from its electricity grid, perhaps decarbonisation was possible. That said, it was easier for Britain than most countries: we had North Sea gas to fall back on, we were already nuclear-heavy, and we had offshore wind resources. Most of the world doesn't have that combination. Still, 2017 represented the moment when coal stopped being infrastructure and became history.

The 2050 net zero target was far more ambitious than the 2008 target. It covered aviation fuel, shipping, agriculture, and cement. It required not just switching power plants, but fundamentally restructuring how people heat homes, how goods are transported, and how industry operates. It also created winners and losers: steel makers would need to invest in electric arc furnaces, oil workers faced displacement, heat pump installers would become a major industry. The scale of the transition becomes clear when you move beyond electricity.

The price crisis revealed the system's fragility. Despite decarbonisation progress, Britain remained fundamentally dependent on fossil gas: 40% of electricity, 80% of heating, and most generators still used gas as the marginal fuel that set prices. When global gas supply tightened, British bills reflected that instantly. The crisis proved that decarbonisation wasn't just an environmental necessity; it was an economic necessity. A fully renewable system would not have been exposed to these shocks. The crisis also showed that energy prices were geopolitical: Russia's decision to reduce supply was deliberate leverage against Europe.

The Price Guarantee was necessary: without it, bills would have hit GBP 4,500. But it was also expensive and economically distorted. It subsidised gas consumption when the goal was to reduce it. It was regressive (did less for low-income households than for wealthy ones). And it was temporary: it couldn't last indefinitely without bankrupting the Treasury. The deeper point was that energy had become too important to leave to markets alone. Government had to step in, but governments are bad at managing prices because politics always takes over. The old question returned: should energy be a commodity traded in markets, or an essential service managed by the state?

NESO's creation marked admission that energy transitions cannot be managed through markets and regulation alone. Someone needs to take a strategic view across the entire system: where will demand be in 2035? Which technologies should be deployed where? What are the constraints on grid capacity and supply chains? Ofgem regulates price and access, but doesn't do strategy. NESO was meant to fill that gap. The independence was meant to depoliticise decisions, but that's impossible: energy is inherently political. Still, NESO's formation was a return to the idea of coordinated national energy planning that had been abandoned in 1989.

The 2030 target was ambitious: from roughly 50% low-carbon in 2024 to 95% by 2030. It required wind farms to be built, solar deployments to accelerate, and grid infrastructure to be upgraded. It also raised questions about feasibility: could supply chains deliver enough turbines and panels? Could communities accept wind farms in sufficient numbers? Could the grid handle that much variable renewable generation? Clean Power 2030 was a statement of intent, but the implementation challenges were substantial.

The LTDS Direction is easy to overlook, but it may prove to be one of the most consequential decisions for the energy transition's pace. Until 2024, distribution network data was locked in PDFs, spreadsheets, and proprietary formats. Each DNO used different conventions. If you wanted to understand where a new solar farm could connect, you had to read hundreds of pages of PDF tables and hope the data was current. CIM-format data changes that: it makes network topology, capacity, and constraints machine-readable and comparable across all 14 licence areas. This is the foundation for automated connection assessments, digital twins of the distribution network, and spatial energy planning. Without it, the connection queue cannot be cleared. With it, network planning moves from artisanal to industrial.

GB Energy's creation was politically significant: it reversed the logic of 1989 that said the state should not own generation assets. The rationale was pragmatic rather than ideological. Private investors require returns within 10-15 years, but energy infrastructure has 30-50 year payback periods. The state can afford to be patient capital. GB Energy was designed to invest in projects that private capital wouldn't touch: early-stage marine energy, community wind schemes, floating offshore wind. Its headquarters in Aberdeen was deliberate: a signal that the energy transition would create jobs in communities that had depended on oil and gas. Whether GB Energy will be operationally effective remains to be seen, but the institutional shift it represents is real.

GB Energy marked a fundamental shift: the state, which had exited generation in 1989, re-entered it in 2025. This was driven by urgency: the transition needed to move faster than private investment alone could deliver, and the state had balance sheet capacity to absorb long-term returns that private investors wouldn't wait for. Connections reform was equally important: the system for connecting new wind farms and solar farms to the grid had become a major bottleneck. The connection queue exceeded 700 GW of projects waiting for grid access, many with estimated connection dates in the 2030s. The new LTDS data regime and reformed queue management aimed to clear this backlog by making network capacity visible and automating assessment of connection applications.

MHHS represents the infrastructure for a genuinely intelligent grid. With half-hourly metering, time-of-use pricing, and flexibility markets, demand can respond to supply in real time rather than the reverse. The Strategic Spatial Energy Plan is the complement: it maps where the bottlenecks will be, which regions will have generation surplus or deficit, where storage needs to go, and what network upgrades are required. Together, they enable the transition from centralised planning (CEGB 1957-1989) to decentralised generation with strategic coordination. Neither pure markets nor pure planning; something hybrid.